Text

Oct. 2006 Exam - Draft RO & SRO Written (Folder2)
	ML063060323
Person / Time
Site:	Oyster Creek
Issue date:	09/05/2006
From:	; AmerGen Energy Co
To:	D'Antonio J; Operations Branch I
	Sykes, Marvin D.
References
	50-219/06-301 50-219/06-301
	Download: ML063060323 (465)
	v • d • e

NRC Exam 2006-1 Senior Reactor Operator Key

1. The plant was at rated power with all systems normally aligned and no equipment out of service. An event occurred that resulted in a reactor

-4 scram. The following annunciators are noted as in alarm:

41 60 STATION POWER BUS 1B - MN BRKR 1B 86 LKOUT TRIP (T2c) 41 60 STATION POWER BUS 1B - BUS 1B UV ( T ~ c )

0 4160 STATION POWER BUS 1D - MN BRKR 1D TRIP (Tle) 41 60 STATION POWER BUS 1D - MN BRKR 1D 86 LKOUT TRIP 0 4160 STATION POWER BUS 1D - BUS 1D VOLTS LO (T3e)

Which one of the following explains the condition of Bus 1D?

a. Bus 1D has experienced a loss of voltage and Emergency Diesel Generator #2 has failed to pick-up Bus 1D, IAW RAP-TIe

b. Bus 1D has experienced a fault which has prevented Emergency Diesel Generator #2 from picking up Bus 1D, IAW RAP-T2e

c. Bus 1B has experienced a fault which has prevented Emergency Diesel Generator #2 from picking up Bus 1D, IAW RAP-T2e

d. Bus 1B has experienced a fault and Emergency Diesel Generator

2 has failed to pick-up Bus 1D, IAW RAP-T2e

.~

-- Answer: b Handouts: None Justification: RAP-T2e describes a fault on Bus D. Breaker 1D opens on the fault and EGD2 is prevented from loading onto a faulted bus. Answer b is correct.

RAP-T1e, by itself, describes a condition where Bus D breaker 1D has opened.

Should breaker 1D open under non-bus fault, then EDG2 would fast start and load onto the bus. Since there is a fault, this does not occur. Answer a is incorrect.

Rap-T2c describes a fault on Bus 1B, which normally supplies power to Bus 1D.

A fault of Bus 1B will open its feeder breaker, de-energize Bus 1D, and EDG2 should fast start and load onto Bus 1D. Since there is also a fault on Bus 1D, this will not occur. Answer c and d are incorrect.

295003 AA2.01 Ability to determine and/or interpret the following as they apply to PARTIAL OR COMPLETE LOSS OF A.C. POWER : Cause of partial or complete loss of A.C.

power (CFR: 43.5)

NRC SRO Exam 2006-1 Key Page 1 of 46

NRC Exam 2006-1 Senior Reactor Operator Key OC Learning Objective: 2621.828.0.001 2 (262-10444: Describe the interlock signals and setpoints for the affected system components and expected system response including power loss or failed components.)

Cognitive Level: Comprehension or Analysis Question Type: New NRC SRO Exam 2006-1 Key Page 2 of 46

4160V STATION POWER BUS I D MN BRKR I D 86 LKOUT TRIP CONFIRMATORY ACTIONS:

NOTE Lockout of Bus 1D will prevent the fast start of DG-2 and Diesel Generator Breaker closure on faulted Bus 1D.

o CHECK 1D Bus voltage and current.

(8F19F) [ I o VERIFY trip of 4160V Breaker 1D. [ I o VERIFY 4160V Bus Tie Breaker ED (if closed). [ I AUTOMATIC ACTIONS:

Trip of 4160V Breaker I D , 4160 V Bus Tie Breaker ED (if closed)

As a result of the trip of these breakers the following Trips will occur:

Emergency Service Water Pumps C and D (if running) 0 Core Spray Pumps B and D (if running) 0 Traveling Screens Pond Pump 0 480V Substation load fed by Bus ID.

Subject Procedure No.

ELECTRICAL RAP-T2e Page 1 of 2 T-2-e Alarm Response Procedures Revision No: 0

NRC Exam 2006-1 Senior Reactor Operator Key

2. The plant is 80% power and is recovering to 100% power following a 0 down-power to remove Reactor Recirculation Pump (Pump 1C). The Feedwater and Condensate Systems are aligned for rated power. An event occurred resulting in several annunciators, and the following indication is noted:

Bus 1A ammeter indicates 0 amps Which of the following states the condition of the reactor following manual operator actions?

a. The reactor was manually scrammed due to loss of feedwater pumps, IAW ABN-17, Feedwater System Abnormal Operation

b. Reactor recirculation flow was lowered to 8.5 E4 gpm, IAW ABN-2, Recirculation System Failures

c. The reactor was manually scrammed due to the loss of reactor recirculation pumps, IAW ABN-2, Recirculation System Failures

d. A manual rapid power reduction has occurred due to the loss of a feedwater pump, IAW ABN-17, Feedwater System Abnormal Operation Answer: c Handouts: None v

Justification: The loss of Bus 1A results in the loss of feedwater pump 1A, condensate pump 1A, and reactor recirculation pumps A and E (recirculation pump C is also on this bus, but it was secured in the question stem). The loss of a single feedwater or condensate pump would require the crew to perform a rapid power reduction IAW ABN-17. Multiple feedwater or condensate pumps would require a manual scram. The loss of a single recirculation pump (in 4-loop or 5-lOOp operation) requires that recirculation flow either lower flow or to insert cam rods IAW ABN-2. For multiple pump trips (in 4/5 loop), a manual scram is required. Answer c is the correct answer. All other answers are incorrect since they give an inappropriate action for the given conditions. (Also see procedures 317 and 301.2) 295006 AA2.06 Ability to determine and/or interpret the following as they apply to SCRAM :

Cause of reactor SCRAM (CFR: 43.5)

OC Learning Objective: 2621.828.0.001 7 (10450: Describe and interpret procedure sections and steps for plant emergency or off-normal conditions that involve this system including personnel allocations and equipment operation in accordance with applicable ABN, EOP & EOP Support Procedures.)

j I u.

NRC SRO Exam 2006-1 Key Page 3 of 46

NRC Exam 2006-1 Senior Reactor Operator Key Cognitive Level: Comprehension or Analysis Question Type: Modified Bank NRC SRO Exam 2006-1 Key Page 4 of 46

d her-,dn Exelmi Company I

I OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-2

.4 Title Revision No.

Recirculation System Failures 6 H. MONITOR the following parameters for indication of Fuel Element Failure:

Off-Gas Activity [ I Main Steam Line Radiation [ I Reactor Coolant Activity t l I. NOTIFY the System Owner/Dispatcher of power limitations. [ I J. If power changed by 2289.5 MWth in one hour, Then NOTIFY Chemistry to sample the reactor coolant in accordance with Technical Specification 3.6.A.4. [ I K. NOTIFY Reactor Engineering. [ I

--- 3.2 Multiple Recirculation Pumps Trip

1. SCRAM the reactor and ENTER ABN-1, Reactor Scram. [ I

2. NOTE Procedure 301.2, Section 9.0 contains guidance for local manual operation of a Recirculation Pump MG-Set Pneumatic Drive Control, including operation with a disconnected linkage rod.

CONFIRM operating Recirculation Pump speed reduced to 20 to 30 Hz. [ I

3. If Any Recirculation pumps are operating, Then PERFORM the following:

A. CONFIRM open the DISCH BYPASS valves for the tripped pumps. [ I 13.0

AmerGen-A n txeion tmpay I OYSTER CREEK GENERATING STATION PROCEDURE 1I Number 317 W Title Revision No.

Feedwater System (Feed Pumps to Reactor Vessel) 74 ATTACHMENT 317-3 FEEDWATER SYSTEM PRE-STARTUP ELECTRICAL LINEUP POWER BREAKER SUPPLY EQUIPMENT LOCATI0N POSITION PERFORMNERIFY 4160V 1A Feed Pump 1A TB 4160V RM Close I 4160V 1B Feed Pump IB TB 4160V RM Close I 4160V 1B Feed Pump I C TB 4160V RM Close I 1811A A String Heater (V-2-10} TB MEZ Close I Bank Outlet Valve IBIIA B String Heater (V-2-1I) TB MEZ Close I Bank Outlet Valve 1B11A C String Heater (V-2-12) TB MEZ Close I Bank Outlet Valve 1A12A MFRV A Block Valve V-2-740 TB MEZ Close I 1B12A MFRV C Block Valve V-2-741 TB MEZ Close I DC-E ROPS (Panel 14XR) Lower Cable Close f Bkr. 15 Spreading Rm IP-4B ROPS (Panel 14XR) 480V Room Close f Bkr. 1 Performed By: Date: Time:

Verified By: Date: Time:

Approved By: Date: Time:

os E3-1

--4 Title AmerGenl An l x m n Company I OYSTER CREEK GENERATING STATION PROCEDURE Number 301.2 Revision No.

Reactor Recirculation System 46 DCC# 20.1704.0010 ATTACHMENT 301.2-3 (continued)

RECIRCULATION PUMP ELECTRICAL LINEUP 41 60V SWITCHGEAR ROOM Power Breaker Initials Component SUPPlV Number Position ChecWerifv RCP A M-G Motor NGOIA 4 16OV-1A Racked Up Charged - I -

69 Permissive SW. Closed I RCP C M-G Motor NGOIC 4160V-1A Racked Up -I-Charged -I-69 Permissive SW. Closed -I-

~..- RCP E M-G Motor NGOIE 4160V-1A Racked Up I Charged 69 Permissive SW. Closed -I-RCP B M-G Motor NGOIB 4 16OV-1B Racked Up I Charged 69 Permissive SW.Closed RCP D M-G Motor NGOID 416OV-1B Racked Up -I-Charged -I-69 Permissive SW. Closed -I-RCP Drive Motor DC Cont. 125 VDC 8 C Pwr. Bus 1A Panel C Checked By: Date: Time:

Verified By: Date: Time:

Approved By: Date: Time:

os

\---

E3-3

NRC Exam 2006-1 Senior Reactor Operator Key

3. The plant was shutting down for an outage, with the following conditions:

0 RPV coolant temperature is 320 F and is cooling down Shutdown Cooling pumps A and B are in service with a total SDC system flow of 4000 GPM RBCCW flow through each of the in-service SDC heat exchangers is 1000 GPM Shutdown Cooling pump C is tagged out for repair All Reactor Recirculation pumps are running RPV water level is being maintained at 155 TAF The following annunciator came into alarm:

SHUT DN CLG - PUMP B TRIP The new plant conditions are as follows:

Shutdown Cooling flow has been verified at 2000 GPM Investigation shows that the SDC pump B tripped on over-current Which of the following lists the required action to increase RPV cooling?

a. Maximize RBCCW cooling water flow through the SDC loop A heat

-..-.,- exchanger to no more than 2000 GPM IAW procedure 309.2, Reactor Building Closed Cooling Water System

b. Maximize SDC loop A flow to no more than 3400 GPM IAW procedure 305, Shutdown Cooling System Operation

c. Increase RPV water level to above 170 TAF IAW procedure 305, Shutdown Cooling System Operation

d. Initiate alternate RPV cooldown IAW ABN-3, Loss of Shutdown Cooling Answer: b Handouts: None Justification: Initial conditions indicate a partial loss of shutdown cooling flow. The RAP for the tripped SDC pump directs another pump be started if possible (which is not possible).

In both procedures 309.2 and 305, it stipulates that RBCCW cannot exceed 1500 GPM through a SDC heat exchanger. Answer is a incorrect.

Procedure 305 explains how to place SDC in service. The SDC pump discharge valves are throttled to establish the desired cooldown rate. The same procedure

.Ll sets a limit on SDC flow of 3400 GPM through a heat exchanger. Since current NRC SRO Exam 2006-1 Key Page 5 of 46

NRC Exam 2006-1 Senior Reactor Operator Key SDC flow is only 2000 GPM, then SDC flow can be increased up to 3400 GPM.

'-' Answer b is correct.

IAW procedure 305, with reactor recirc pumps running, RPV water level should be maintained within the normal band. Raising water level is only required during a partial SDC flow loss when no reactor recirc pumps are running. Answer c is incorrect.

Initiating alternate cooling through the cleanup system is only performed when SDC flow is lost or cannot be established, IAW ABN-3. Answer d is incorrect.

295021 AA2.02 Ability to determine and/or interpret the following as they apply to LOSS OF SHUTDOWN COOLING: RHWshutdown cooling system flow (CFR: 43.5)

OC Learning Objective: 2621.828.0.0045 (02602: Identify and interpret procedures for plant emergency or off-normal situations which involve the SDC System, including personnel and equipment allocations.)

Cognitive Level: Comprehension or Analysis Question Type: New NRC SRO Exam 2006-1 Key Page 6 of 46

D 1

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OYSTER CREEK G E N s b e r An Exelon company STATION PROCEDURE 1 3092 Revision No.

u Title Reactor Building Closed Cooling Water System 69 4.0 PRECAUTIONS AND LIMITATIONS 4.1 NOTE A maximum pump flow of 4500 GPM corresponds to a minimum pump discharge pressure of approximately 75 PSIG.

Limit RBCCW Pump flow to a maximum of 4500 GPM as indicated on FI-5-1 for 1-1 Pump or FI-5-2 for 1-2 Pump.

4.2 When RBCCW HX 1-1 & 1-2 BY-PASS Valve V-5-136, RBCCW HX 1-1 &

1-2 By-Pass Valve is open, maintain RBCCW temperature within the range of 70°F to 105°F using TI-541-5 and TI-541-7, Fuel Pool Heat Exchangers Inlet temperatures. TE-43 and TE-108 will @ provide accurate indication with V-5-136, RBCCW HX 1-1 & 1-2 By-Pass Valve open.

4.3 During normal operation V-5-136, RBCCW HX 1-1 & 1-2 By-Pass Valve is closed, RBCCW temperature should be maintained within the range of 70°F to 105"F, as indicated on TE-108 (Recorder IA55 Panel 8R) at the inlet to the drywell.

4.4 Maximum allowable RBCCW temperature at the RBCCW pump suction is 250°F as indicated on TI-541-9 Pump 1-1 and TI-541-10 Pump 1-2 on the pump suction header to prevent exceeding the design temperature rating of this system. However, temperature should be maintained below 190°F during all modes of operation.

4.5 RBCCW flow through an individual RBCCW Heat Exchanger shall be limited to less than 3700 gpm except while swapping RBCCW Pumps to prevent damage to the Heat Exchanger due to flow induced vibration. To meet this requirement only one RBCCW pump may run when only one RBCCW Heat Exchanger is in service.

4.6 RBCCW flow through an individual Shutdown Cooling Heat Exchanger shall be limited to 1500 gpm during all modes of operation to prevent damage to the Heat Exchanger due to flow induced vibration. This is monitored by differential pressure gauges DPI-57, DPI-58 and DPI-541-2 located on the 51' elevation of the reactor building. Calculate RBCCW 4 flow by converting the measured dp to flow using Attachment 309.2-7.

8.0

AmerGm_

A n Izekur Company 1

I OYSTER CREEK GENERATING STATION PROCEDURE 1 umber 305

--4 Title Revision No.

Shutdown Cooling System Operation 90 4.2.3 Due to Yarway level indication inaccuracies at lower reactor temperatures and pressures, GEMAC Narrow Range instrumentation should be used as the primary indication of Reactor water level.

4.2.4 RBCCW System flow reduction will alleviate excessive vibration or noise at the RBCCW Heat Exchangers.

4.2.5 If an automatic isolation occurs, do attempt to restart the SDC System until available indications have been checked and found to be normal.

4.2.6 The maximum allowed RBCCW flow through a SDC Heat Exchanger is 1500 gpm.

4.2.7 Always attempt to maintain equal RBCCW flow through any operating SDC Heat Exchangers by keeping the shell side differential pressures as close as possible.

4.2.8 Maximum SDC System flow (tubeside) through a heat exchanger is 3400 gpm (assuming 10% of tubes are plugged).

4.2.9 In the case of system degradation due to a fire or a control room evacuation, steps that are goJ absolutely necessary for system operation may be omitted.

4.2.1 0 To ensure full closure of MOVs V-I 7-55, V-17-56 and V-I 7-57, the control switch must be held in CLOSE for approximately 3 seconds after the red OPEN light (Panel 11F) extinguishes. This action is necessary since these valves do not have a seal-in circuit in the close direction.

4.2.11 To prevent SDC System flow from short-cycling the core, the E Recirc Loop Discharge Valve must be CLOSED the E Recirc Pump running.

4.2.12 If the Cleanup System is in service, the B Recirc Loop should not be the selected loop in those instances where one loop is required to be fully open.

4.2.1 3 Section 4.3 of this procedure is written to startup the SDC System in order to cooldown the Reactor. If system startup is to be done after cooldown, as when maintaining a temperature band during outages, those steps applicable only to startup for a cooldown may be omitted at the discretion of the Operations Supervisor.

20.0

Title Revision No.

Shutdown Cooling System Operation 90 42.2 To prevent temperature stratification and maintain circulation within the Reactor core, plant conditions shall be maintained in one of the following conditions until the steam separator and dryer have been removed from the vessel. (

Reference:

GE SIL 357).

CONDITION I Reactor Recirculation System in service with a minimum of one Reactor Recirculation Pump in operation. All non-operating Recirc Loops in the idle or isolated condition.

Reactor water level maintained in the normal band (Gemac).

SDC System is operated as required for cooldown and decay heat removal.

CONDITION 2 One Recirc Loop fully open (not BRecirc Loop if Cleanup System in service).

The other four Recirc Loops are in the idle or isolated condition.

-IF Reactor water level is maintained at or above 160 TAF (Gemac)

THEN MAINTAIN SDC System flow >7500 gpm.

-IF Reactor water level is maintained at or above 165 TAF (Gemac) ,

THEN MAINTAIN SDC System flow between 6500-7500 gpm.

E Reactor water level is maintained at or above 1 7 0 TAF (Gemac),

THEN MAINTAIN SDC System flow between 6000-6500 gpm.

NOTE Condition 3 is the Appendix R scenario utilizing the Alternate Shutdown Equipment (Remote and Local Shutdown Panels).

CONDITION 3

____- *--A-firehasdisabled the controls of R e a c t r x - R ~ c i r c u l ~ t i V

~ anl-v~a ~-

e All Reactor Recirc Pumps tripped with the ERecirc Loop idled (Discharge Valve closed).

SDC flow 26000 gpm.

RPV level >I 85 TAF (Gemac)

. 19.0

, I herGen,. . .~

An ExelonlBiitish Energy Company 1

I OYSTER CREEK GENERATING STATION PROCEDURE I

Number ABN-35 I

d Ti tie Usage Level Revision No.

LOSS OF iNSTRUMENT AIR 1 0 Prior Revision N/A incorporated the This Revision 0 incorporates the following Temporary Changes: following Temporary Changes:

N/A -

NIA List of Pages 1.0 to 9.0 I .o

I 1 d

Tille AtTBerGm,.. __-

~n ExelonlB6tich Energy Company I

OYSTER CREEK GENERATING STATION PROCEDURE I Number ABN-35 Revision No.

LOSS OF INSTRUMENT AIR 0 I .

LOSS OF INSTRUMENT AIR I.o AP PLlCAB1LlTY This procedure is applicable to a loss of instrument air in the plant.

2.0 IN DICATlONS 2.1 Annunciators Enqravinq Location Setpoint

~

RCVR 1 PRESS LO M-3-a 95 psig RCVR 2IlNSTR AIR PRESS M-3-b 80 psig I 8 5 psig LO d

RCVR 3 PRESS LO M-3-c 85 psig CONTROL AIR PRESS LO H-I -a 75 psig SVC AIR DISCH VLV CLOSED M-2-b V-6s-2 Shut

~~~

COMPR IBREAKER TRIP M-4-a Breaker open COMPR 1 TRIP M-5-a various COMPR 2 BREAKER TRIP M-4-b Breaker open COMPR 2 TRIP M-5-b various COMPR 3 TRIP M-4-c 32OoF or 18 psig lube oil pressure INST AIR DRYER FAIL M-7-b Both in-service towers pressurized or depressurized 2.0

herGenm -

OYSTER CREEK GENERATING STATIOR PROCEDURE Number ABN-35 An Exelcn/British Energy Company d Title Revision No.

LOSS OF iNSTRUMENT AIR 0 2.2 Plant Parameters 1~

Parameter 1 Location 1 Change Instrument air supply pressure Panel 7F lowering 2.3 Other Indications - None 3.0 OPERATOR ACTIONS If while executing this procedure, an entry condition for any EOP occurs, then EXECUTE this procedure concurrently with the appropriate EOP.

3.1 If Service Air pressure drops to 95 psig, d then CHECK the following:

0 Air Dryer malfunctions 0 Valve lineup errors 0 Air leaks in the system 0 Malfunction of the loading switch on the operating air compressor NOTE: If either #I or #2 compressor is the lag compressor, then the compressor will load 10 seconds after starting.

3.2 If Service Air pressure drops to 90 psig, c i then CONFIRM the !ag compressor has started.

3.3 If Service Air pressure drops to 85 psig, and #3 compressor is the lag compressor, f l then CONFIRM $3 air compressor begins to load 3.0

, a AmerGen,. .

An trelon/British Cncrgy Company I

I I

OYSTER CREEK GENERATING STATION PROCEDURE I

Number ABN-35 Title Revision No.

LOSS OF INSTRUMENT AIR 0 3.4 If Service Air pressure drops to 80 psig, then PERFORM the following:

1. START the third air compressor. I 1

2. BYPASS the Air Dryers, Pre-filters, and Post-filters. [ I

3. VERIFY all air compressors are operating normally. [ I 3.5 If Instrument Air pressure drops to 75 psig, then PERFORM the following:

1. CONFIRM Service Air Valve V-6s-2 has isolated and is not bypassed. I 1

2. ANNOUNCE the following:

Attention all personnel, anyone presently utilizing the [ I Service Air system shall secure all work at this time.

3. DETERMINE and ISOLATE the source of the air loss. [ I 3.6 If Instrument Air pressure drops to 55 psig, or two or more control rods begin to drift into the core,

[ I then SCRAM the Reactor in accordance with ABN-1, Reactor Scram.

3.7 EXECUTE the operator actions listed in Attachment ABN-35-1, Major Systems Affected by Loss of Instrument Air. [ I 3.8 REFER to Attachment ABN-35-2, Other Plant Systems Affected. [ I

4.0 REFERENCES

4.1 ABN-1, Reactor Scram 5.0 ATTACHMENTS 5.1 ABN-35-1. Major Systems Affected by Loss of Instrument Air e

5.2 ABN-35-2, Other Plant Systems C\.fTected 4.0

I I erGerr, An Euelon/BTitish Energy Company OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-35 I

e Title Revision No.

LOSS OF iNSTRUMENT AIR 0 Attachment ABN-35-1 Major Systems Affected by Loss of Instrument Air 0PERAT0R SYSTEM EFFECT OPERATOR ACTION ACTION BEFORE AIR IS RESTORED Circulating Lossofraveling screen dP Screens should operate on None Water control timed cycle. Cycle manually as required Condensate Spill valves V-2-15, -17, CAUTION If instrument air will and makeup valves V-2-16 If the CST is allowed to drain to -not be restored within and V-2-235 open. the hotwell, the Condensate one-half hour, CST drains to the hotwell. Transfer System will be then CLOSE V-2-90.

inoperable. If the Condensate pumps are subsequently tripped, the CRDH System will then be inoperable.

Maintain hotwell level between 33 and 51 inches using V-2-90.

CRDH Loss of air to scram inlet If air pressure drops to 55 psig, None and scram outlet valves. or two or more control rods begin to drift into the core, SDV isolates.

Flow Control Valves then SCRAM the reactor in NC30A and NC30B (V-I5- accordance with ABN-1.

128 and -129) close. RPV inventory must be carefully monitored due to failure of RWCU valves (lose ability to let down from the reactor.)

Drywell purge Supply and exhaust None None and inerting dampers close Drywell and Reactor Building-to-Torus None If all alarmsGre Suppression Vacuum Breakers (V cleared, 16 and -1 8) open. then PLACE control switch for V-16-16 and -18 to the desired position (open 3 r closed.)

5.0

I I h e __r G e m - -

OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-35 An Exe1on:BTit;sh Energy Company Title Revision KO.

d LOSS OF INSTRUMENT AIR 0 Attachment ABN-35-1 Major Systems Affected by Loss of Instrument Air 0PERAT0R SYSTEM EFFECT OPERATOR ACTION ACTION BEFORE AIR IS RESTORED Feedwater Feedwater Control Valves 1. Place feedwater control None lock up (but may slowly valves in local-manual drift open or closed) control in accordance with Procedure 317.

2. Perform the following actions as needed to control RPV water level:

0 throttle Heater Bank Outlet Valve(s) V-2-10, -

11, -12 0 Trip feedwater and condensate pumps as necessary Fuel Pool Filter isolates None None Cooling Pumps trip k2 Heating Feed reg valve closes None None Boiler Isolation IC Vent Valves V-14-1, -5, 1. V-I 1-34 and V-I 1-36 None Condensers -19 and -20 close. eachhavean accumulator sized for 5 IC Makeup Valves V-I 1-34 strokes of its respective and -36 close. valve.

Makeup capability from 2. After depleting the Condensate Transfer accumulators, operate System is lost if the CST is V-I 1-34 and V-I 1-36 drained. manually at RB 95 el.,

or recharge the accumulators using Procedure 307.

6.0

a ,

AmerGen.

- -_ - OYSTER CREEK GENERATING STAT10N PROCEDURE Number ABN-35 An ExelonlSritish Enersy Company I

e Title Revision No.

LOSS OF INSTRUMENT AIR 0 Attachment ABN-35-1 Major Systems Affected by Loss of instrument Air 0 PERAT0R SYSTEM EFFECT OPERATOR ACTION ACTION BEFORE AIR IS RESTORED Main Steam MSlVs NS04A and NSO4B Control RPV pressure using Place NS03A, close. Isolation Condensers and/or NS03B, NSO4A, and NS03A, NS03B, and V EMRVs in accordance with NS04B control 395 will close if being ABN-1 and/or the EOPs. switches to CLOSE.

supplied by instrument air.

Main Turbine Backup Turning Gear Engage the Turning Gear None cannot be remotely manually.

engaged.

Off-Gas SJAE Air Inlet Valves V None None 17 through -28 open.

d Offgas Outlet Valves V-7-1 through -6 close.

Main Condenser vacuum will degrade.

Radwaste DWEDT discharge valve 1. Trip the radwaste If an overboard closes. discharge pumps. discharge is in Drywell Floor Drain Sump 2. Confirm CLOSED the progress, discharge valve closes. Radwaste discharge then SECURE the Radwaste discharge valve valve HP-AOV-029. discharge until HP-AOV-029 closes. instrument air is restored.

Reactor The following isolation solate normal Reactor Building None Building valves FAIL-AS-IS: rentilation and Initiate SGTS.

ventilation V-28-1 thru -16 V-28-21 and -22 V-28-36 thru -39 e V-28-42 and -34 Supply fan outlet dampers 3M-28-0041, -42, and -43

=AIL CLOSED.

W -. __

7.0

~ AmerGew,,

An Cxelon/Britich Energy Company OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-35 I

d Title Revision No.

LOSS OF INSTRUMENT AIR 0 Attachment ABN-35-1 Major Systems Affected by Loss of Instrument Air 0PERAT0R SYSTEM EFFECT OPERATOR ACTION ACTION BEFORE AIR IS RESTORED Reactor MG fluid couplers lock up Place the Recirc Pumps in None Recirculation local-manual control in System accordance with Procedure 301.2 RWCU FCV ND16 and PCV NDI 1 Limit makeup to the RPV until None close discharge capability is restored.

RWCU isolates on low flow Letdown FCV ND22 closes RPV letdown capability lost Filter inlet ND27, outlet ND28, and bypass V-16-83 close SDC Minimum flow valves V None None 58, -59, and -60 open I

SGTS V-28-23, -26, -27, and -30 I Accumulators will maintain remain AS-IS until valve position for a required accumulators are depleted, three strokes of the valve.

then fail CLOSED Continued operation requires a v-28 28, -48Jand -I9temporary air supply be.

fail OPEN installed on V-28-26 and -30.

This will prevent short circuiting through the standby train by maintaining the valves in the desired position.

Immediate maintenance is needed to implement Procedure 2400-EAS-3810.01 nd of Attachment ABN-35-1 8.0

OYSTER CREEK GENERATING Number

~. -_ STATION PROCEDURE ABN-35 An ExelonlBritisli Energy Company

~~ , Title Revision No.

LOSS OF lNSTRUMENT AIR 0 Attachment ABN-35-2 Other Plant Systems Affected by Lass of Instrument Air Auxiliary Steam System Bleed Steam System Containment lnerting System Core Spray System HVAC Systems:

A & B Battery Room and MG Set Room 0 Control and Cable Spreading Room Office Building Turbine Building Mechanical Vacuum System 4

Post Accident Sampling System Reheat Steam System Shutdown Cooling System Turbine Building Closed Cooling Water System End of Attachment ABN-35-2

NRC Exam 2006-1 Senior Reactor Operator Key

4. The plant was at 90% power in preparation for recovering a control rod that was manually scrammed for testing purposes. An electrical grid

.u disturbance occurred resulting in a turbine trip. The following plant conditions exist:

0 RPV water level is 1 5 0 TAF and steady (up from a low of 112" TAF) 0 RPV pressure band is 900 - 1000 psig, being controlled with Isolation Condenser B Drywell pressure is 3.2 psig and rising slowly Drywell temperature is 180" F and rising slowly Torus water temperature is 91 " F and steady All control rods indicate full-in The following annunciator came into alarm:

ISOL COND - SHELL B LVL HVLO The Control Room Operator reports that Isolation Condenser B shell water level is 8' and rising slowly, and that makeup is secured. Chemistry reports that their sampling of the shell water indicates greater than the expected radionuclide concentrations for the given plant conditions.

Which of the following actions is required?

W'

a. Initiate containment spray in the torus cooling mode

b. Close the Isolation Condenser DC valves

c. Emergency Depressurize

d. Isolate Isolation Condenser B Answer: d HANDOUT: EOPs Justification: Even though the Primary Containment Control EOP has been entered, torus water temperature is below the entry condition and is stable. The first action step in the EOP says to maintain torus water temperature less than 95" F and to initiate torus cooling. The EOP Users Guide says to maintain temperature and to initiate torus cooling as required. In this case, with temperature all ready less than 95" F and not rising, torus cooling is not required Answer a is incorrect.

The RPV Control - No ATWS EOP directs closing of the isolation condenser DC valves when RPV water level reaches 180. Since water level was given as 150" and steady, this action is not required. Answer b is incorrect.

NRC SRO Exam 2006-1 Key Page 7 of 46

NRC Exam 2006-1 Senior Reactor Operator Key An emergency depressurization IAW Radioactivity Release Control EOP is required when a General Emergency (from off-site dose) is declared. There is no

-4' indication that this has been reached. Therefore, answer c is incorrect.

One entry condition into the Radioactivity Release Control EOP (EMG-3200.12) is an isolation condenser tube leak. The indications of this have been provided in the question stem. The first action step in this EOP is to isolate primary systems discharging outside the primary and secondary containment (such as the isolation condenser vent lines), except for systems required by EOPs. Even though isolation condenser B is being used IAW EOPs, there are several other RPV pressure control methods available to take the place of isolation condenser B when it gets isolated (IC A, EMRVs). Therefore, IC B should be isolated IAW the Radioactivity Release Control EOP, and another pressure control method utilized. Answer d is correct.

295038 2.4.6 High Off-site Release Rate Knowledge symptom based EOP mitigation strategies. (CFR: 43.5)

OC Learning Objective: 2621.845.0.001 2 (02483: Using procedure EMG-3200.1 2, evaluate the technical basis for each step and apply this evaluation to determine the correct course of action under emergency conditions.)

Cognitive Level: Comprehension or Analysis Question Type: New NRC SRO Exam 2006-1 Key Page8of 46

EOP USERS GUIDE RADIOACTIVITY RELEASE CONTROL A general overview of the major steps of the Radioactivity Release Control procedure is shown below:

ENTRY CONDITIONS OFF-SITE RADIOACTIVITY RELEASE RATE ABOVE THE ALERT LEVEL ISOLATION CONDENSER TUBE LEAK THAT CANNOT BE ISOLATED ISOLATE PRIMARY SYSTEMS DISCHARGING OUTSIDE OF PRIMARY AND SECONDARY CONTAINMENTS EXCEPT SYSTEMS NOT REQUIRED BY EOPS MONITOR REACTOR FOR CORE DAMAGE ENTERRPVCONTROL IF CORE DAMAGE IS INDICATED TO ENSURE THE REACTOR IS SHUTDOWN MONITOR THE OFF-SITE RADIOACTIVE RELEASE RATE EMERGENCY DEPRESSURIZE THE RPV IF A PRIMARY SYSTEM IS DISCHARGING OUTSIDE THE PRIMARY AND SECONDARY CONTAINMENTS AND THE OFF-SITE RELEASE RATE REACHES THE LEVEL FOR A GENERAL EMERGENCY

-.,-J REVISION 7 12-2

NRC Exam 2006-1 Senior Reactor Operator Key

5. The plant is at 15% power during a startup. lnerting of the drywell and power ascension is in progress.

- 4' Which of the following (1) would reauire a notification, and (2) to whom this notification must be made?

a. (1) An inadvertent primary containment isolation (2) Duty Station Manager

b. (1) The failure of a single LPRM, with all others operable (2) Duty Station Manager C. (1) A contractor reported to the site nurse after a slip/falI, and was released back to work (1) PA announcement to plant personnel

d. (1) Stopping the Nitrogen System Ambient Vaporizer Fan per procedure while inerting (2) PA announcement to plant personnel Answer: a HANDOUTS: OP-AA-104-101, Communications; OP-AA-106-101,Significant Event Reporting, OP-OC-106-101, SIGNIFICANT EVENT NOTIFICATION AND

..J*

REPORTING.

Justification: OP-AA-106-101 requires the SM notify the Duty Station Manager of any event that proceeds in a way significantly different than expected. The primary containment isolation is significant and was not expected. The isolation also halted the primary containment inerting process, which could impact the reactor startup. IAW TS 3.5.A.6, the primary containment must be inerted within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of placing the mode switch in RUN. The same requirement is also found in OP-OC-106-101.Answer a is correct.

OP-AA-106-101,and OP-OC-106-101 requires the SM notify the Duty Station Manager of any forced entry into a 72-hour (or less) TS shutdown LCO. IAW TS 3.2.B.2, the loss of a single LPRM does not cause any APRM to be inoperable, and thus no TS entry. Answer b is incorrect.

OP-AA-104-101 requires a PA announcement if there is an injury. OP-OC-106-101 requires notification if an injury results in offsite medical assistance. Answer c is incorrect.

OP-AA-104-101 requires a PA announcement prior to energizing/de-energizing major electrical switchgear or buses. The Ambient Vaporizer Fan is neither. No PA announcement is required. Answer d is incorrect.

Ll' NRC SRO Exam 2006-1 Key Page9of 46

NRC Exam 2006-1 Senior Reactor Operator Key

~I b e '

295020 Inadvertent Containment Isolation 2.1.14 Knowledge of system status criteria which require the notification of plant personnel. (CFR: 43.5)

OC Learning Objective: 2621.830.0.0005 (01638: Given a description of an event, describe the following: 1) what category the event belongs in; 2) who must be notified; 3) time limit; 4) any follow-up reports.)

Cognitive Level: Comprehension or Analysis Question Type: New NRC SRO Exam 2006-1 Key Page 10 of 46

OP-AA-I06-101 Revision 7 Page 3 of 7

.4

4. MAIN BODY 4.1. Declaration of Emerqency Plan (EP) Classification 4.1. I . For declarations of any EP classification, notifications shall be made in accordance with applicable site emergency plan procedures.

1. Initial notification to the NDO shall be made by the Duty Station Manager or Transmission Operations dispatcher/System Operations dispatcher.

2. The NDO should immediately call the affected station to obtain plant status.

3. The NDO shall promptly report any EP event classification to the Duty Executive and the Chief Nuclear Officer.

4. The CNO shall notify the CEO of an EP emergency declaration in a timeframe consistent with the impact of the event.

4.2. Other Events Requirinq Resulatorv or Offsite Notification 4.2.1. The Shift Manager will notify station Security to perform an assessment of the potential tampering event in accordance with SY-AA-101-108 (Response to Suspicious Activity and Maliciously Directed at Plant safety or Security).

4.2.2. The Shift Manager will notify the Duty Station Manager for any of the events listed in Attachment 1.

1. If the Duty Station Manager cannot be reached, then the Shift Manager shall ensure notifications are made in accordance with Attachment 1.

4.2.3. The Duty Station Manager shall use Attachment 1 in determining communication requirements.

4.2.4. The Duty Station Manager is responsible for initial coordination of site response to the event or occurrence, including notification to station senior management, the NDO, and the Chief Nuclear Officer as described in step 4.2.3.5 below.

1. The Duty Station Manager is responsible to ensure that the Nuclear Duty Officer has been notified and has adequate information for communication.

2. The Duty Station Manager will mobilize onsite and offsite personnel to support the needs of the Shift Manager.

3. The Duty Station Manager will mobilize the Station Duty Team personnel upon entry into a 24-hour or less unplanned shutdown LCO. The Duty Station Manager should consider mobilizing the Duty Team upon entry into a 72-hour or less unplanned shutdown LCO.

OP-AA-I 06-101 Revision 7 Page 6 of 7 ATTACHMENT 1 Notification Requirements Page 1 of 2 EVENT NOTIFY Reactivity Event, including any mis-positioned Control Rod events. 0 SiteVP Hazardous Material Incident.

Shutdown Risk Classification > Scheduled) or Online Risk Classification 0 Plant Manager

> Orange Fitness for Duty Event 0 Operations Director Injury requiring offsite medical attention or transportation via ambulance to an offsite medical facility. See Note I in "Notify" column.

Major enforcement actions, fines or other sanctions or a serious 0 Nuclear Duty Officer operating event that could lead to this action, including events, which have been, or may be, brought to the attention of NRC upper management. 0 Senior Resident Inspector Non-routine communications to/from NRC management, e.g. requests for Enforcement Discretion or Temporary Waiver of Compliance. 0 Site Oversight Manager Action Level II or greater chemistry parameters that lead to a plant derate or shutdown.

Site Medical (injuries only)

An event of potential tampering in which Station Security is coordinating investigations for confirmation of "Confirmed Tampering " in accordance Note 1:

with SY-AA-101-108. Transport of a potentially contaminated injured worker to an Any event or operating condition that occurs that is not enveloped in the 3ffsite medical facility requires plant design basis notification to; Any event that proceeds in a way significantly different than expected; 7 Emergency Communications for example: Dispatch Center IEMA (800 -782-7860 MW Stations only) and 0 Unexpected % scram is received; 7 Iowa HSEMD (515-323-4360) if oeing transported from Quad Cities.

0 Any unexpected significant plant transient; 0 LCO action that will not be met within allowed time requirement; Initiation of a prompt investigation or similar (OP-AA-106-101-1001).

Events of potential public interest.

ENS 7 SiteVP 7 Plant Manager 7 Operations Director 7 Nuclear Duty Officer J Experience Assessment /

Regulatory Assurance Manager 7 Senior Resident Inspector 7 Site Nuclear Oversight Manager

NRC Exam 2006-1 Senior Reactor Operator Key "Sj

6. The plant is in SHUTDOWN following a loss of condenser vacuum event (which is still being investigated). The following conditions currently exist:

0 Shutdown Cooling loop A is in service, with all reactor recirculation pumps in service RPV water level is in the normal band Unit Substation 1B2 is de-energized for emergent maintenance (it is expected the bus will be returned to service in 30 minutes)

RPV coolant temperature is 220" F and is trending down slowly The following annunciator has cleared:

SHUT DN CLG - ISOL VALVES OPEN Investigation has revealed that TE-31J (Reactor Recirculation Pump E suction temperature element) has failed upscale Which of the following states (1) the effect on the plant and (2) the required actions?

a. (1) Shutdown Cooling Pump A has tripped due to high SDC Pump A suction temperature (2) Start SDC Pump B or C to restore SDC System flow IAW

.~

-- procedure 305, Shutdown Cooling System Operation

b. (1) Shutdown Cooling Pump A has tripped due to isolation valve closure (2) Bypass the failed temperature element and restore SDC Pump A IAW ABN-3, Loss of Shutdown Cooling

c. (1) Shutdown Cooling Pump A has tripped due to isolation valve closure (2) Initiate Alternate Shutdown Cooling Using EMRVs and Core Spray IAW ABN-3, Loss of Shutdown Cooling

d. (1) Shutdown Cooling Pump A has tripped due to high SDC Pump A suction temperature (2) Initiate Alternate RPV cooldown (cleanup system letdown) per procedure 303, Reactor Cleanup Demineralizer System Answer: b Handouts: None NRC SRO Exam 2006-1 Key Page 11 of 46

NRC Exam 2006-1 Senior Reactor Operator Key Justification: A high temperature sensed on any reactor recirculation loop (350")

will isolate SDC. When SDC IV V-17-19 closes, all SDC pumps trip. Because it has been determined that the recirculation temperature sensor has failed, ABN-3 allows bypassing the sensor and restoring SDC flow. Answer b is correct.

It is true that 350" F SDC suction temperature will isolate SDC and trip the SDC pump, this is not what was given in the question. Also, SDC Pumps B and C are powered by USS 1B2, which is de-energized. Answer a is incorrect.

As stated, the SDC IVs close on high recirc. temperature. ABN-3 directs that the failed temperature sensor be bypassed and SDC restored in step 3.2.2. Later, in step 3.2.8, it directs alternate cooling with core spray and EMRVs. Since step 3.2.2 can be performed, there would be no reason to perform step 3.2.8. Answer c is incorrect.

As stated, SDC pump trips from IV position, not SDC loop temperature. Also, cleanup letdown as an alternate path is not available since the condenser is not available (given in the question stem). Answer d is incorrect.

205000 A2.05 Ability to (a) predict the impacts of the following on the SHUTDOWN COOLING SYSTEM (RHR SHUTDOWN COOLING MODE) ; and (b) based on those

'*I--

predictions, use procedures to correct, control, or mitigate the consequences of those abnormal conditions or operations: System isolation (CFR: 41.5 / 43.5)

OC Learning Objective: 2621.828.0.0045 (02602: Identify and interpret procedures for plant emergency or off-normal situations which involve the SDC System, including personnel and equipment allocations.)

Cognitive Level: Comprehension or Analysis Question Type: New NRC SRO Exam 2006-1 Key Page 12 of 46

her-_

~~

an C x e h Covpany 1 OYSTER CREEK GENERATING STATION PROCEDURE I umber 305

/ Title Revision No.

Shutdown Cooling System Operation 90 ATTACHMENT 305-3 ELECTRICAL CHECKOFF LIST Power Bkr.

Supplv Location poS. PerformNerifv MCC 1AB2 V-I 7-19 Motor Operator RB 23 NW ON /

MCC DCI V-17-1 Motor Operator RB 23 SE ON /

MCC DCI V-17-2 Motor Operator RB 23 SE ON /

MCC DCI V-I 7-3 Motor Operator RB 23 SE ON /

VACP-1 Solenoid V-6-465 for V-17-58 RB Bkr 19 Valve V-6-466 for V-I 7-59 460V ON /

V-6-467 for V-I 7-60 Room Inst. Panel RB 4 Bkr 17 PT RVO6A; RBOGB, RVO6C 460V Room ON /

DC Panel Battery "D" Bkr 4 PNL 1F/2F (Emer Cond Sys I) Room A ON /

L Misc. Power Turb. Bldg.

Pnl-lB Bkr 14 TR/RV08 (Temp Recorder) North Mezz. ON /

MCC RB 74- USSIA2 NU02A Pump 460V Room ON I MCC RB r USS lB2 NU02B Pump 460V Room ON I MCC RB 4 USS 182 NU02C Pump 460V Room ON /

MCC DCI V-I 7-55 Motor Operator RB 23 SE ON /

MCC DCI V-I 7-56 Motor Operator RB 23 SE ON /

MCC DCI V-I 7-57 Motor Operator RB 23 SE ON /

MCC 1AB2 V-I 7-54 Motor Operator RB 23 NW ON /

Completed By:

Signature Date Time Verified By:

Signature Date Time Reviewed and Approved By:

L,' OS Signature Date Time E3-1

her-_

An x e b Company 1 OYSTER CREEK GENERATING STATION PROCEDURE II umber 305

.-i/ Title Revision No.

Shutdown Cooling System Operation 90 4.2.14 When initially placing the SDC System in service, monitor the RBCCW Pump suction temperature TI-541-9 (Pump 1-1) and TI-541-10 (Pump 1-2) closely to ensure the limits of Procedure 309.2 are not exceeded. RBCCW temperature out of the SDC System Heat Exchangers may initially be greater than 190°F, due to water already contained in the heat exchangers when the RBCCW outlet valve is opened, but shall be limited to less than 190°F once flow has stabilized.

- 7 4.2.15 The following trips are associated with SDC System operation:

V-I 7-19 and V-I 7-54 will close if any Recirc Loop temperature exceeds 350°F.

0 SDC Pumps will trip if individual pump suction pressure drops below 4 psig (with a 1.5 sec time delay).

0 SDC Pumps will trip if the suction temperature for the pump rises above 350°F (with a 1.5 sec time delay).

0 SDC Pumps will trip if V-17-19 closes.

-- 4.2.16 The following valves are defined as Primary Containment Isolation Valves by Procedure 312.9 and FSAR Table 6.2-12 and are operated in this section:

V-17-1 V-17-56 V-17-2 v-17-57 V-17-3 V-17-19 V-17-55 v-17-54 4.3 Procedure - Svstem Startup for Cooldown Operation 4.3.1 I NOTE Guidance for the need to perform lineups and checkoffs is contained in Procedure 108.9.

DETERMINE the need to perform Valve, Instrument, and Electrical checkoffs.

IF Operations Management determines performance of Attachment(s) 305-1, 305-2, or 305-3 is required, THEN PERFORM the applicable Attachment(s) as directed by the OS.

0 305-1, Valve Check-off List [ I

'-4' 0 305-2, Instrument Valve Check-off List [ I 0 305-3, Electrical Check-off List [ I 21.o

SHUT DN CLG PUMP A TRIP AANUAL CORRECTIVE ACTIONS: (continued from Page 2 of 3)

I K there is a loss of control power, THEN RESTORE 125 VDC power in accordance with Procedure ABN-55, Loss of DC Distribution Center C.

I

AUSES: SETPOINTS: ACTUATING DEVICES:

3reaker trip Breaker tripped Relay 301

-rip Function: Drive motor overload 340 amps Solid State Trip Device Low suction pressure 4 psig, TD=I .5s PSL-43A through TDR-214-001 relay Inlet water temperature 35OoF,TD=I 5 s TSH-42A through high TDR-214-001 relay

---3 V-17-19 SDC Inlet Not fully open SW 201C through 6x16 Isolation Valve closed Reference Drawings:

BR E1129 GE 148F711 GU 3E-611-17-005 Sh. 1

u bject Procedure No.

RAP-CZd Alarm Response Procedures Revision No: 0

Sroup Heading SHUT DN CLG C-7-d ISOL VALVES OPEN ZAUSES: SETPOINTS: ACTUATING DEVICES:

Shutdown Cooling Inlet Isolation valve, Valve not fully Position switches for d-I 7-19, Outlet Isolation valve, closed V-17-19 and V-17-54 d-17-54, not in the fully closed position, through relays 6K16 Pushbutton 6K17, PB-214-001 engaged SDC pumps trip bypass pushbutton mergized.

Reference Drawings:

GE 0157B6350 Sht. 157A Sht. 158B GU 3E-611-17-005 Sh. 2 Subject Procedure No.

Page 2 of 2 I

NSSS RAP-C7d C-7-d Alarm Procedures Response Revision No: 1

AmerGm OYSTER CREEK GENERATING Number ABN-3 An Ere:mCompany STATION PROCEDURE Title d Revision No.

LOSS OF SHUTDOWN COOLING 0 2.2.4 Valid or inadvertent Shutdown Cooling System isolation evidenced by V-17-19 and V-I 7-54 position indication on Panel 11F being closed and annunciator C-7-d, ISOL VALVES OPEN, in a cleared state when Shutdown Cooling is required.

3.0 OPERATOR ACTIONS If while executing this procedure an entry condition for any EOP occurs, then EXECUTE this procedure concurrently with the appropriate EOP.

3.1 E a total loss of Shutdown Cooling occurs and an uncontrolled temperature rise causes RPV coolant temperature to approach or exceed 21Z0F, THEN REFER to the Emergency Plan. [ I 3.2 DETERMINE cause for loss of Shutdown Cooling. [ I 3.2.1 -

IF an inadvertent isolation caused the loss of Shutdown Cooling and the inadvertent isolation is no longer present, THEN RESTORE Shutdown Cooling in accordance with Procedure 305. [ I

,/+ 3.2.2 -

IF Shutdown Cooling isolation has occurred due to a failed Recirculation loop thermocouple, THEN PERFORM the following:

3.2.2.1. BYPASS the temperature interlock in accordance with Procedure 305 Section 9. [ I 3.2.2.2. RESTORE Shutdown Cooling in accordance with Procedure 305. [ I 3.2.3 -

IF Shutdown Cooling System isolation signal has occurred and cannot be bypassed, THEN PERFORM the following:

3.2.3.I. RE-ESTABLISH conditions required to place Shutdown Cooling in service. [ I 4.0

NRC Exam 2006-1 Senior Reactor Operator Key

7. Which of the following lists the basis for Technical Specification 3.4.8.3?

i j At the reduced RPV pressure of 110 psig, .....

a. a small break LOCA will not result in a primary containment temperature of 281 " F, which would require emergency depressurization

b. core spray flow into the RPV during a small break LOCA is sufficient to ensure that peak fuel centerline temperature does not exceed 2200" F

c. there is no credible event in which an RPV over-pressure condition would challenge the reactor coolant system pressure safety limit, requiring the use of the ADS valves

d. core spray flow into the RPV during a small break LOCA is sufficient to ensure that cladding oxidation will not exceed 0.17 times the total cladding thickness before oxidation Answer: d HANDOUT: TS 3.4 Justification: The relief valves of the ADS System enable the core spray system to provide protection against the small break LOCA in the event feedwater system is not available. Under the conditions of a small break LOCA at high RPV pressures and no feedwater available, the ADS valves will open to depressurize the RPV to allow core spray to inject for core cooling. At an RPV pressure of 110 psig, core spray can provide the design flow necessary to maintain adequate core cooling. Thus if the small break LOCA occurred at or less than this pressure (1 10 psig), the ADS valves are not required to depressurize the RPV to allow core spray injection. The Emergency Core Cooling System design must meet the criteria of 10CFR50.46 (Acceptance Criteria for Emergency Core Cooling Systems for Light Water Nuclear Power Plants). Two of these criteria is that ECCS will maintain peak cladding temperature (not fuel temperature) less than 2200" F, and maximum cladding oxidation of 0.17 times the total cladding thickness before oxidation. Answer d is correct, and answer b is incorrect.

All other answers are credible but are not correct ISW TS 3.4.8.3 basis.

21 8000 2.2.25 (ADS)

Knowledge of bases in technical specifications for limiting conditions for operations and safety limits. (CFR: 43.2)

OC Learning Objective: 2621.850.0.0090 (01658: State requirements associated with given areas of Technical Specifications (safety limits, LSSS, etc.).)

NRC SRO Exam 2006-1 Key Page 13 of 46

NRC Exam 2006-1 Senior Reactor Operator Key Cognitive Level: Comprehension or Analysis Question Type: New NRC SRO Exam 2006-1 Key Page 14 of 46

Bases:

This specification assures operability of the emergency core cooling system to provide adequate core cooling. The Oyster Creek ECCS has two core spray loops (system 1 and system 2); each containing a core spray sparger and redundant active loop components consisting of two main pumps, two booster pumps, two parallel isolation valves (outside the drywell) and two check valves in parallel (inside the drywell). Specification 3.4.A.1 insures the availability of core cooling to meet the ECCS acceptance criteria in 10 CFR 50.46 utilizing the MAPLHGR limits provided in Section 3.10. These limits are from calculations(') that include models and procedures which are specified in 10 CFR 50 Appendix K. A core spray flow of at least 3400 gpm (1 main and 1 booster pump) from 1 loop plus 2200 gpm (1 main pump) from the other loop at a vessel pressure of 1 10 psig is used in the calculation. Core spray loop 2 would be required to deliver 3640 gpm if loop 2 is relied upon as the two pump contributor and 2360 gpm if loop 2 is the single pump contributor, since loop 2 has flow losses through cracks in the core spray sparger.

Table 3.4.1 allows continued operation with one core spray loop inoperable for a limited period of time. An evaluation of data presented in Reference 5 shows that flow from a single core spray sparger, main and booster pumps delivering 3400 gpm (3640 gpm for loop 2) at a vessel pressure of 1 10 psig, will meet 10 CFR 50.46 criteria with a 10% reduction in MAPLHGR Limits specified in Section 3.10. At 90% of the APLHGR, each core spray system is capable of supplying the required minimum bundle flow rate to ensure core cooling (References 6 and 7).

Two hours is allowed for a reduction in the APLHGR limit which is consistent with two hours provided by Specification 3.10.A.3 to return an exceeded APLHGR to within the prescribed limit.

Under the APLHGR operational constraints of specification 3.4.A.3 the operable core spray loop meets all Appendix K requirements except for the case of a core spray line break inside the drywell in the operable loop. As a result, reactor operation is permitted for a period not to exceed seven days. The allowed time out of service for the redundant core spray loop is justified based on the low probability of the event, the direct operator indication of a Core Spray System pipe ij break, and emergency procedures which provide for additional cooling water through the fire system.

The probability of a pipe break between the reactor vessel and the core spray check valve in the operable core spray loop (approx. 28 feet of 6 inch pipe) compared to the total pipe in the reactor coolant pressure boundary is very small. The probability of a core spray line break in conjunction with the other core spray loop out of service, which in itself is a low probability, is so small that it does not constitute an unacceptable risk. In the extremely unlikely event that this LOCA scenario were to occur, the operators are provided with a specific visual and audible alarm alerting them of a "Core Spray System I (IT) Pipe Break" (one for each core spray loop). These alarms are initiated by differential pressure detectors on each core spray loop. In such a case the core spray line break would occur above the top of the active fuel allowing the core to be re-flooded from the fire protection system through the intact core spray loop.

In addition, a small break LOCA in the operable core spray loop prior to a larger break will be detected by the drywell unidentified leakage system (drywell sump) even before it is detected by the core spray alarm system. This will provide the operators with additional time to respond.

Therefore, the out-of-service time for one of the two core spray loops, as evaluated as per the guidelines in Reference 8, has been conservatively selected to be 7 days.

OYSTER CREEK 3.4-7 Amendment No.: 75+%,247

10 CFR 50.46 Acceptance criteria for emergency core cooling systems for light-water nuc... Page 1 of 2 e

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_ > Document Collections > NRC Regulations (10 CFR) > Part Index > 3 Public Involvement 50.46 Acceptance I emergency core cooling systems for light-water nuclear power reactors.

5 50.46 Acceptance criteria for emergency core cooling systems light-water nuclear power reactors.

(a)( l)(i) Each boiling or pressurized light-water nuclear power reactor fueled with uranium oxide pellets within zircaloy or ZIRLO cladding must be provided with an emergency core cooling system (ECCS) that must be desi its calculated cooling performance following postulated loss-of-coolant accidents conforms to the criteria set fo paragraph (b) of this section. ECCS cooling performance must be calculated in accordance with an acceptable I model and must be calculated for a number of postulated loss-of-coolant accidents of different sizes, locations, properties sufficient to provide assurance that the most severe postulated loss-of-coolant accidents are calcula as provided in paragraph (a)(l)(ii) of this section, the evaluation model must include sufficient supporting just show that the analytical technique realistically describes the behavior of the reactor system during a loss-of-cc accident. Comparisons to applicable experimental data must be made and uncertainties in the analysis methoc must be identified and assessed so that the uncertainty in the calculated results can be estimated. This uncert.

accounted for, so that, when the calculated ECCS cooling performance is compared to the criteria set forth in F of this section, there is a high level of probability that the criteria would not be exceeded. Appendix K, Part I1 f Documentation, sets forth the documentation requirements for each evaluation model. This section does not a nuclear power reactor facility for which the certifications required under 5 50.82(a)( 1) have been submitted.

(ii) Alternatively, an ECCS evaluation model may be developed in conformance with the required and acceptab appendix K ECCS Evaluation Models.

' / ,=

(2) The Director of Nuclear Reactor Regulation may impose restrictions on reactor operation if it is found that 1 evaluations of ECCS cooling performance submitted are not consistent with paragraphs (a)(l) (i) and (ii) of thi (3)(i) Each applicant for or holder of an operating license or construction permit shall estimate the effect of an or error in an acceptable evaluation model or in the application of such a model to determine if the change or i significant. For this purpose, a significant change or error is one which results in a calculated peak fuel claddins temperature different by more than SOF from the temperature calculated for the limiting transient using the la model, or is a cumulation of changes and errors such that the sum of the absolute magnitudes of the respecti\

temperature changes is greater than 5OOF.

(ii) For each change to or error discovered in an acceptable evaluation model or in the application of such a mc affects the temperature calculation, the applicant or licensee shall report the nature of the change or error anc effect on the limiting ECCS analysis to the Commission at least annually as specified in 5 50.4. If the change o signficant, the applicant or licensee shall provide this report within 30 days and include with the report a propc for providing a reanalysis or taking other action as may be needed to show compliance with 5 50.46 requiremc schedule may be developed using an integrated scheduling system previously approved for the facility by the I those facilities not using an NRC approved integrated scheduling system, a schedule will be established by the within 60 days of receipt of the proposed schedule. Any change or error correction that results in a calculated I performance that does not conform to the criteria set forth in paragraph (b) of this section is a reportable ever described in 55 50.55(e), 50.72 and 50.73. The affected applicant or licensee shall propose immediate steps c t demonstrate compliance or bring plant design or operation into compliance with 5 50.46 requirements.

- 7 (b)( 1) Peak cladding temperature. The calculated maximum fuel element cladding temperature shall not excef

( 2 ) Maximum cladding oxidation. The calculated total oxidation of the cladding shall nowhere exceed 0.17 time

',..-; cladding thickness before oxidation. As used in this subparagraph total oxidation means the total thickness oft metal that would be locally converted to oxide if all the oxygen absorbed by and reacted with the cladding locz http://www.nrc.gov/reading-rm/doc-collections/cfr/part05O/part050-0046.html 8/2/2006

10 CFR 50.46 Acceptance criteria for emergency core cooling systems for light-water nuc ... Page 2 of 2 converted to stoichiometric zirconium dioxide. I f cladding rupture is calculated to occur, the inside surfaces of shall be included in the oxidation, beginning at the calculated time of rupture. Cladding thickness before oxidai the radial distance from inside to outside the cladding, after any calculated rupture or swelling has occurred b i significant oxidation. Where the calculated conditions of transient pressure and temperature lead to a predictic

. d '

swelling, with or without cladding rupture, the unoxidized cladding thickness shall be defined as the cladding c area, taken at a horizontal plane at the elevation of the rupture, if it occurs, or at the elevation of the highest I temperature if no rupture is calculated to occur, divided by the average circumference at that elevation. For ru cladding the circumference does not include the rupture opening.

(3) Maximum hydrogen generation. The calculated total amount of hydrogen generated from the chemical real cladding with water or steam shall not exceed 0.01 times the hypothetical amount that would be generated if i metal in the cladding cylinders surrounding the fuel, excluding the cladding surrounding the plenum volume, \n, (4) Coolable geometry. Calculated changes in core geometry shall be such that the core remains amenable to (5) Long-term cooling. After any calculated successful initial operation of the ECCS, the calculated core tempet maintained at an acceptably low value and decay heat shall be removed for the extended period of time requir long-lived radioactivity remaining in the core.

(c) As used in this section: (1) Loss-of-coolant accidents (LOCA's) are hypothetical accidents that would result of reactor coolant, at a rate in excess of the capability of the reactor coolant makeup system, from breaks in p reactor coolant pressure boundary up to and including a break equivalent in size to the double-ended rupture (

pipe in the reactor coolant system.

(2) An evaluation model is the calculational framework for evaluating the behavior of the reactor system durin postulated loss-of-coolant accident (LOCA). It includes one or more computer programs and all other informati for application of the calculational framework t o a specific LOCA, such as mathematical models used, assumpti in the programs, procedure for treating the program input and output information, specification of those portic not included in computer programs, values o f parameters, and all other information necessary to specify the c, procedure.

-- /

(d) The requirements of this section are in addition to any other requirements applicable to ECCS set forth in t criteria set forth in paragraph (b), with cooling performance calculated in accordance with an acceptable evalu.

are in implementation of the general requirements with respect to ECCS cooling performance design set forth i including in particular Criterion 35 of appendix A.

[39 FR 1002, Jan. 4, 1974, as amended at 53 FR 36004, Sept. 16, 1988; 57 FR 39358, Aug. 31, 1992; 61 FR 29, 1996; 62 FR 59726, Nov. 3, 19971 Privacy Policy I Sit.e Disclaimer fast revised Wednesday, August 02, 2006

'-d http://www.nrc. gov/reading-nn/doc-collections/cfr/part05 O/partO50-0046.html 8/2/2006

NRC Exam 2006-1 Senior Reactor Operator Key

8. The plant was at rated power with all systems normally aligned, except LJ that service air compressor 2 is tagged out for repair. The following annunciators came into alarm:

SERVICE AIR - RCVR 1 PRESS LO SERVICE AIR - RCVR 2ANST AIR PRESS LO SERVICE AIR - RCVR 3 PRESS LO SERVICE AIR - COMPR 1 BREAKER TRIP The INSTR AIR SUPPLY PRESS indicator shows 82 psig and lowering.

ABN-35, Loss of Instrument Air, has been entered. The SRO directed a manual reactor scram IAW the ABN.

All control rods indicate full-in Which of the following is correct?

a. Establish and maintain RPV water level 138 to 175 TAF with the LRFV in MANUAL IAW ABN-1, Reactor Scram

b. Establish and maintain RPV pressure 800 - 1000 psig with the Main Turbine Bypass Valves IAW EMG-3200.01A, RPV Control -

No ATWS

c. Establish and maintain RPV water level 138 to 175 TAF using letdown from the RPV with the Cleanup System if required, IAW ABN-1, Reactor Scram d Establish and maintain RPV pressure 800 - 1000 psig with Isolation Condensers IAW EMG-3200.01A, RPV Control - No ATWS Answer: d Handouts: None Justification: The first alarm (M3a) comes in at 95 psig in service air receiver 1-1.

The second alarm (M3b) comes in at either 80 psig in service air receiver 1-2 or 85 psig in the air header. The third alarm (M3c) comes in at 85 psig in the service air receiver 1-3. This indicates a system-wide air loss. As provided in the question stem, ABN-35, Loss of Instrument Air, has been entered. It directs a manual reactor scram when instrument air pressure drops to 55 psig (or if control rods begin to drift into the core). It is apparent that the instrument air pressure continues to lower.

The feedwater flow regulating valves are air-operated and lock-up on loss of air (even though they might drift). With these valves locked-up, the valve LFRV controller in MANUAL will not function to operate the valves. Answer a is incorrect.

. d NRC SRO Exam 2006-1 Key Page 15 of 46

NRC Exam 2006-1 Senior Reactor Operator Key

--4 With instrument air pressure lowering, the air-operated outside MSlVs will auto close. With these valves closed, the TBV are no longer available to control RPV pressure. Answer b is incorrect.

ABN-1 does direct to letdown through the Cleanup System if necessary, but with the air loss, the Cleanup System letdown path is not available (cleanup will isolate). Answer c is incorrect.

Isolation condensers are available for use (even though shell makeup must be performed locally). RPV pressure control below 1045 psig is directed by EMG-3200.01A. Answer d is correct.

300000 2.4.6 (Instrument Air)

Knowledge symptom based EOP mitigation strategies. (CFR: 43.5)

OC Learning Objective: 2621.828.0.0043 (10450: Describe and interpret procedure sections and steps for plant emergency or off-normal conditions that involve this system including personnel allocation and equipment operation in accordance with applicable ABN, SDRP, EOP and EOP support procedures and EPIPs.)

Cognitive Level: Comprehension or Analysis Question Type: New NRC SRO Exam 2006-1 Key Page 16 of 46

EOP USERS GUIDE RPV CONTROL -NO ATWS Y A R ~ A YLE@L INSTRUMENTS SHALL NOT BE USED TO DEERMINE RPV WATER LEVEL DURING RAPID DEPRESSURIZATION STABILIZE RPV PRESSURE BELOW 1045 PSlG USING THE MAIN TURBINE BYPASS VALVES e---

PRESSURE CONTROL MAY BE AUGMENTED BY ONE OR MORE OF THE FOLLONNG SYSTEMS:

-ISOLATION CONDENSERS (ONLY IF RPV WATER LEVEL IS BELOW 160 IN.)

(SUPPORT PROC 11 ) -

-EMRVS (ONLY IF TORUS WATER LEVEL IS ABOVE 90 IN.)

(SUPPORT PRO& 12)

.CLEANUP IN RECIRC MODE PER SUPPORT PR0C.- 13 C L E A N U P IN LETDOWN MODE PER SUPPORT PROC.- 14

.ISOLATION CONDENSER VENTS PER SUPPORT PRO& 15 DEPRESSURIZE ME

.RPV, MAlNfAlN THE COOLDOW RATE BELOW

.. I This step directs the operator to control RPV pressure Once a band for pressure control is established (i-e.:800 below the high pressure scram setpoint. Controlling - 900 psig), the RPV should not be purposefully re-pressure below the scram setpoint allows the scram pressurized above 900 psig. Every attempt should be logic to be reset (provided no other scram signals exist) made to maintain pressure at or below the pressure to and avoids EMRV actuation since the lowest EMRV which the RPV was stabilized.

lifting pressure is above the 1045 psig scram setpoint.

The Turbine Bypass valves are the preferred choice for If the Bypass valves are unavailable, or are insufficient controlling RPV pressure because heat is passed outside for controlling RPV pressure as desired, one or more of of Primary Containment and the Turbine Control the alternate RPV pressure control systems may be System provides relatively fine control of Reactor implemented. Since symptom-oriented procedures must pressure. accommodate a full spectrum of Plant conditions and events, no prioritization regarding use of the alternate A low end pressure is purposely not listed because, RPV pressure control systems is specified by this step.

depending on the transient, RPV pressure may start out The LOS should choose the pressure control system(s) much lower than the 1045 psig specified maximum. The based on system capacity, degree of pressure control, intention of the step is to gain control of pressure as heat sink availability, and potential for release of soon as possible. A stabilized, relatively constant RPV radioactivity to the environment. A brief summery of pressure will make control of RPV water level less the more significant advantages, limitations, and other difficult. Note that even if the operator stabilizes the pertinent factors associated with each system is given RPV at high pressures, this procedure and other EOP on the following pages.

procedures will direct control of RPV pressure to the appropriate band for available water injection systems

.-: to assure adequate core cooling.

REVISION 7 IA-52

AmerGen, OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-35 An Exelon/British Energy Company I

Title Revision No.

LOSS OF INSTRUMENT AIR 0 Attachment ABN-35-1 Major Systems Affected by Loss of Instrument Air OPERATOR SYSTEM EFFECT OPERATOR ACTION ACTION BEFORE AIR IS RESTORED Reactor MG fluid couplers lock up Place the Recirc Pumps in None Recirculation local-manual control in System accordance with Procedure 301.2 RWCU FCV ND16 and PCV N D l l Limit makeup to the RPV until None close discharge capability is restored.

RWCU isolates on low flow Letdown FCV ND22 closes RPV letdown capability lost Filter inlet ND27, outlet ND28, and by pass V-I 6-83 close SDC Minimum flow valves V None None 58, -59, and -60 open SGTS V-28-23, -26, -27, and -30 Accumulators will maintain remain AS-IS until valve position for a required accumulators are depleted, three strokes of the valve.

then fail CLOSED Continued operation re quires a temporary air supply be V-28 28, -48, and -19 installed on V-28-26 and -30.

fail OPEN This will prevent short circuiting through the standby train by maintaining the valves in the desired position.

Immediate maintenance is needed to implement Procedure 2400- EAS-38 10.01 End of Attachment ABN-35-1 8.0

OYSTER CREEK GENERATING Number AmerGen.

An ExelonlBritish Energy Company I

STATION PROCEDURE ABN-35

-d Revision No.

Title LOSS OF INSTRUMENT AIR 0 Attachment ABN-35-1 Major Systems Affected by Loss of Instrument Air OPERATOR SYSTEM EFFECT OPERATOR ACTION ACTION BEFORE AIR IS RESTORED Main Steam MSlVs NS04A and NS04B Control RPV pressure using Place NS03A, close. Isolation Condensers and/or NS03B, NS04A, and EMRVs in accordance with NS04B control NS03A, NS03B, and V ABN-1 and/or the EOPs. switches to CLOSE.

395 will close if being supplied by instrument air.

Main Turbine Backup Turning Gear Engage the Turning Gear None cannot be remotely manually.

engaged.

Off-Gas SJAE Air Inlet Valves V None 17 through -28 open.

Offgas Outlet Valves V-7-1 through -6 close.

Main Condenser vacuum will degrade.

Radwaste DWEDT discharge valve 1. Trip the radwaste If an overboard closes. discharge pumps. discharge is in progress, Drywell Floor Drain Sump 2. Confirm CLOSED the discharge valve cI oses. Radwaste discharge then SECURE the valve HP-AOV-029. discharge until Radwaste discharge valve instrument air is HP-AOV-029 closes.

restored.

Reactor The following isolation Isolate normal Reactor Building None Building valves FAIL-AS-I S: ventilation and Initiate SGTS.

ventilation 0 V-28-1 thru -16 V-28-21 and -22 V-28-36 thru -39 V-28-42 and -34 Supply fan outlet dampers DM-28-0041, -42, and - 4 3 FAIL CLOSED.

7.0

AmerGen_ OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-35 An ExelonIBritish Energy Company Ll' I Title Revision No.

LOSS OF INSTRUMENT AIR 0 Attachment ABN-35-1 Major Systems Affected by Loss of Instrument Air OPERATOR SYSTEM EFFECT OPERATOR ACTION ACTION BEFORE AIR IS RESTORED Feedwater Feedwater Control Valves 1. Place feedwater control None lock up (but may slowly valves in local-manual drift open or closed) control in accordance with Procedure 317.

2. Perform the following actions as needed to control RPV water level:

0 throttle Heater Bank Outlet Valve(s) V-2-10, -

11, -12 0 Trip feedwater and condensate pumps as necessary Fuel Pool Filter isolates None None Cooling Pumps trip

2 Heating Feed reg valve closes None None Boiler Isolation IC Vent Valves V-14-1, -5, 1. V-I 1-34 and V-I 1-36 None Condensers -1 9 and -20 close. each havean accumulator sized for 5 IC Makeup Valves V - I 1-34 strokes of its respective and -36 close.

valve.

Makeup capability from

2. After depleting the Condensate Transfer accumulators, operate System is lost if the CST is V-I 1-34 and V-I 1-36 drained.

manually at RB 95' el.,

or recharge the accumulators using Procedure 307.

6.0

NRC Exam 2006-1 Senior Reactor Operator Key

9. The plant was starting up after a refuel outage, which included having u

replaced 14 control rods. Reactor power is low in the source Range Monitors. The Reactor Operator was withdrawing control rods, when the control rod position indication goes dark for the control rod being withdrawn.

Control rod motion was halted and discussions with Reactor Engineering and Shift management began, They decided to move the control rod one notch to see if position indication was regained. This action produced no change in control rod position indication. It was then determined to fully insert the control rod, and this was attempted by the Reactor Operator.

Neutron monitoring showed no change in counts as the control rod was inserted and the SRO concluded that it was not possible to verify that the control rod was fully inserted. He then directed that the control rod be valved out of service so that its current position will not change.

With the control rod valved out of service and control rod position not known, which of the following Technical Specifications actions is required?

a. The SHUTDOWN MARGIN must be verified within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , including the effects of the unknown-positioned control rod

b. The reactor must be placed in the SHUTDOWN CONDITION within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

c. Immediately initiate action to fully insert all insertable control rods

d. Verify there are no more than 8 inoperable control rods valved out of service, prior to continuing with control rod withdrawals Answer: a HANDOUT: TS 3.2 Justification: Shutdown margin is determined with the strongest reactivity control rod assumed fully withdrawn and all other control rods fully inserted. But since the control rod in the question has no position indication, and they are unable to verify that the control rod is fully inserted, its position is unknown. Because of this, shutdown margin must be verified with this control not fully inserted. This is required IAW TS 3.2.A.2. Answer a is correct.

Only if the SDM cannot be verified within the time allowed (6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ), the plant must be placed in the shutdown condition within the following 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months IAW TS 3.2.A.3. Answer b is incorrect.

If SDM cannot be met while in REFUEL mode, then TS 3.2.A.5 requires that all control rods be fully inserted. Answer c is incorrect.

NRC SRO Exam 2006-1 Key Page 17 of 46

NRC Exam 2006-1 Senior Reactor Operator Key TS 3.2.B.4 allows only 6 inoperable, valved out of service control rods. In any u1 event, the startup cannot continue even if this verification was made. Answer d is incorrect.

214000 2.2.22 Knowledge of limiting conditions for operations and safety limits. (CFR: 43.2)

OC Learning Objective: 2621.828.0.001 1 (10451: Given Tech Specs, identify and explain associated actions for each section of Tech Specs relating to this system including personnel allocations and equipment operation.)

Cognitive Level: Comprehension or Analysis Question Type: New NRC SRO Exam 2006-1 Key Page 18 of 46

3.2 REACTIVITY CONTROL Applicability: Applies to core reactivity and the operating status of the

--J reactivity control systems for the reactor.

Obiective: To assure reactivity control capability of the reactor.

Soecification:

A. Core Reactivity

1. The SHUTDOWN MARGIN (SDM) under all operational conditions shall be equal to or greater than:

(a) 0.38% delta Wk, with the highest worth control rod analytically determined; or (b) 0.28% delta Wk, with the highest worth control rod determined by test.

7 2. If one or more control rods are determined to be inoperable as defined in Specification 3.2.B.4 while in the STARTUP MODE or the RUN MODE, then a determination of whether Specification 3.2 A. is met must be made within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . If a determination cannot be made within the specified time period, then assume Specification 3.2 A . l is not met.

3. If Specification 3.2.A.1 is not met while in the STARTUP Mode or the RUN MODE, meet Specification 3.2.A.1 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or be in the SHUTDOWN CONDITION within the following 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

4. If Specification 3.2.A.1 is not met while in the SHUTDOWN CONDITION, or the COLD SHUTDOWN CONDITION, then:

(a) Fully insert all insertable control rods within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , AND (b) Comply with the requirements of Specifications 3.2.C and 3.5.8.

5. If Specification 3.2.A.1 is not met while in the REFUEL MODE, then:

(a) Immediately suspend CORE ALTERATIONS except for fuel assembly removal, AND (b) Immediately initiate action to fully insert all insertable control rods in control cells containing one or more fuel assemblies, AND (c) Comply with the requirements of Specifications 3.2.C and 3.5.B.

OYSTERCREEK 3.2-1 Amendment No: 75, 113, 178

-J

NRC Exam 2006-1 Senior Reactor Operator Key

10. The plant is high on Range 9 of the Intermediate Range Monitors during a d'

startup.

Which of the following lists the on-duty shift requirements IAW Technical Specifications:

a. 1 Shift Manager 3 licensed Nuclear Plant Operators 2 licensed or non-licensed Nuclear Plant Operators 1 Shift Technical Advisor

b. 1 Unit Supervisor 3 licensed Nuclear Plant Operators 2 licensed or non-licensed Nuclear Plant Operators 1 Shift Technical Advisor

c. 1 Shift Manager 2 licensed Nuclear PJant Operators 3 licensed or non-licensed Nuclear Plant Operators

d. 1 Shift Manager 2 licensed Nuclear Plant Operators 3 licensed or non-licensed Nuclear Plant Operators 1 Shift Technical Advisor Answer: d HANDOUT: None - TS 6.0 NOT provided.

Justification: TS 6.2.2.2.a requires the following: 1 SM, 2 licensed Nuclear Plant Operators, 3 licensed or non-licensed Nuclear Plant Operators, 1 Shift Technical Advisor (STA is not required in shutdown or refuel with the reactor e 212" F, according to TS 6.2.2.2.h.). Answer d is correct. All other answers are incorrect.

Conduct of Operations 2.1.4 Knowledge of Shift Staffing requirements.

OC Learning Objective: 2621.850.0.0090 (01658: State requirements associated with given areas of Technical Specifications (Safety Limits, LSSS, etc.)

Cognitive Level: Comprehension or Analysis Question Type: Bank NRC SRO Exam 2006-1 Key Page 19 of 46

ADMINISTRATIVE CONTROLS 6.1 RESPONSIBILITY 6.1 .I The Vice President - Oyster Creek shall be responsible for overall facility operation.

Those responsibilities defeated to the Vice President as stated in the Oyster Creek Technical Specifications may also be fulfilled by the Plant Manager. The Vice President shall delegate in writing the succession to this responsibility during his and/or the Plant Manager absence.

I 6.2 ORGANIZATION 6.2.1 Corporate 6.2.1.1 An onsite and offsite organization shall be established for unit operation and corporate management. The onsite and offsite organization shall include the positions for activities affecting the safety of the nuclear power plant.

6.2.1.2 Lines of authority, responsibility and communication shall be established and defined from the highest management levels through intermediate levels to and including operating organization positions. These relationships shall be documented and updated as appropriate, in the form of organizational charts. These organizational charts will be documented in the Updated FSAR and updated in accordance with 10 CFR 50.71 e.

6.2.1.3 The Chief Nuclear Officer shall have corporate responsibility for overall plant nuclear safety and shall take measures needed to ensure acceptable performance of the staff in operating, maintaining, and providing technical support in the plant so that continued nuclear safety is assured.

6.2.2 FACILITY STAFF 6.2.2.1 The Vice President - Oyster Creek shall be responsible for over all unit safe operation and shall have control over those onsite activities necessary for safe operation and maintenance of the plant.

6.2.2.2 The facility organization shall meet the following:

a. Each on duty shift shall include at least the following shift staffing:

.. One (I) Shift Manager (see h below)

Two (2) licensed Nuclear Plant Operators

. Three (3) licensed or non-licensed Nuclear Plant Operators One (1) Shift Technical Adviser (see h. below)

Except for the Shift Manager, shift crew composition may be one less than the minimum requirements, for a period of time not to I exceed two hours, in order to accommodate unexpected absence of on-duty shift crew members. Immediate action must be taken to restore the shift crew OYSTER CREEK 6-1 Amendment No.: 54, 59, 65, 69, 102, 134, 194, 195, 203, 210, 213, 220

composition to within requirements given above. This provision does not permit any shift crew position to be unmanned upon shift change due to an incoming shift crew member being late or absent.

b. At all times when there is fuel in the vessel, at least one licensed senior reactor operator shall be on site and one licensed reactor operator should be at the controls.

C. At all times when there is fuel in the vessel, except when the reactor is in COLD SHUTDOWN or REFUEL modes, two licensed senior reactor operators and two licensed reactor operators shall be on site, with at least one licensed senior reactor operator in the control room and one licensed reactor operator at the controls.

d. At least two licensed reactor operators shall be in the control room during all reactor startups, shutdowns, and other periods involving planned control rod manipulations.

e. All CORE ALTERATIONS shall be directly supervised by either a licensed Senior Reactor Operator or Senior Reactor Operator Limited to Fuel Handling who has no other concurrent responsibilities during this operation.

f. An individual qualified in radiation protection measures shall be on site when fuel is in the reactor.

9. (deleted)

h. Each on duty shift shall include a Shift Technical Advisor except that the Shift Technical Advisors position need not be tilled if the reactor is in the refuel or shutdown mode and the reactor is less than 212°F. The Shift Technical Advisor position may be filled by an on-shift Senior Reactor Operator (dual-role SRO/STA) provided the individual meets the requirements of 6.3.3.

i. Administrative procedures shall be developed and implemented to limit the working hours of unit staff who perform safety related functions.

In the event that unforeseen problems require substantial amounts of overtime to be used or during extended periods of shutdown for refueling, major maintenance or major plant modifications, on a temporary basis, the following guidelines shall be followed:

a. An individual should not be permitted to work more than 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months straight, excluding shift turnover time.

b. An individual should not be permitted to work more than 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months in any 24-hour period, nor more than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months in any 48-hour period, nor more than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months in any seven-day period, all excluding shift turnover time.

1 ,

u' OYSTER CREEK 6-2 Amendment No.: 92, 102, 134, 161, 203, 220

NRC Exam 2006-1 Senior Reactor Operator Key

11. Which of the following proposed plant changes would require a

- 4 10CFR50.59 Evaluation and NRC approval prior to procedural implementation? (neglect any effects of the proposed changes on the Updated Safety Analysis Report)

(

a. Changing the Reactor Building Vent Radiation Monitors upscale trip setting to 20 mWhr

b. Changing the RPV heatup/cooldown rates to 16" F/10 minutes

c. Changing the requirement to use the Rod Worth Minimizer in the Low Power Mode until 15% power on a startup

d. Changing the Scram Discharge Volume Hi-Hi setpoint to 27 gallons Answer: a HANDOUT: TS Table 3.1 -1, 3.3, 3.2 Justification: IAW 1OCRF50.59(c)(l)l: A licensee may make changes in the facility, without obtaining a license amendment, as long as a tech spec change is not required. A 50.59 review would need to be performed for a change that would require a change in Tech Specs. (See LS-AA-104). A change in Tech Specs must first be approved by the NRC.

TS Table 3.1.1 .j requires the hi setpoint of RB vent radiation monitors be set at 5

. I 17 mR/hr (currently set at 9 mWhr (see RAP-1OF1f)). Changing this setpoint L,

above the TS value (to 20 mWhr) would first need a Tech Spec change, preceded by a 50.59 review and evaluation. Answer a is correct.

TS 3.3.c.l allows a 100" F/hr limit on heatup/cooldown rate. Startup and shutdown procedures limit this to 95" F/hr. Setting this limit to 96" F/hr (which equals 16" FA0 minites) is still less than the TS requirement and thus does not violate TS. Answer b is incorrect.

TS 3.2.8.2 requires the RWM be operable on a startup up tO 10% power (and this is reflected in procedure 409, Operation of the Rod Worth Minimizer).

Requiring the RWM to be operable up to 15% power on a startup does not effect Tech Specs. No NTC notification would be required. Answer c is incorrect.

TS Table 3.1.1 .a requires a scram signal from 5 29 gallons in the SDV, and is currently set at 26 gallons (se RAP-H1b). Setting this limit at 25 gallons is more conservative and does not violate TS. Answer d is incorrect.

Equipment Control 2.2.9 Knowledge of the process for determining if the proposed change /test or experiment increases the probability of occurrence or consequences of an accident during the change /test or experiment.

(CFR: 43.3)

Lj NRC SRO Exam 2006-1 Key Page 20 of 46

NRC Exam 2006-1 Senior Reactor Operator Key

.-' OC Learning Objective: 2621.830.0.0005 (02618: State what actions an operator and supervisor make to initiate a procedure change.)

Cognitive Level: Comprehension or Analysis Question Type: Bank NRC SRO Exam 2006-1 Key Page 21 of 46

TABLE 3.1.1 PROTECTIVE INSTRUMENTATION REQUIREMENTS Sheet 5 of 13 Reactor Modes Minimum Number of Minimum Number of in which Function OPERABLE or Instrument Channels Must Be OPERABLE OPERATING [tripped] Per OPERABLE Function Trip SettinR Shutdown Refuel Startup Run Trip Systems Trip Svstem Action Required*

1. Offqas Svstem Isolation

1. High Radiation In S 2000 mRemlhr X(S) X(S) X X l(ii) 2(ii) See note jj Offgas Line (e)

J. Reactor Buildinq Isolation and Standbv Gas Treatment Svstem Initiation Isolate Reactor

1. High Radiation I 100 mR1hr X(W) X(W) X X 1 1 Building and Reactor Building Initiate Standby Operator Floor Gas Treatment System or Manual

2. Reactor Building S 17 mWhr X(W) X(W) X X 1 1 Surveillance for Ventilation Exhaust not more than 24 Hours (Total for

3. High Drywell Pressure I 3.5 psig Nu) X(U) X X 1(k) 2(k) all instruments under J) in any

4. Low-Low-Reactor 2 72 above TOP of X X X X 1 2 30day period.

Water Level ACTIVE FUEL K. Rod Block

1. SRM Upscale 5 5x105cps 2 No control rod withdrawals

2. SRM Downscale 2 1OOcps(f) 2 permitted

3. IRM Downscale 251125 fullscale (9) X X 2 3 OYSTER CREEK 3.1-13 Amendment No.: 44,22,75,79,S?,? 72,?7? ,794,208 Change: 4

10 CFR 50.59 Changes, tests and experiments. Page 1 of 3 b4e-x I Site Map I E_Aa I Help I Glosm-y I Contact Us

.- U.S. Nuclear Regulatory Commission v

I Home 1 Who We Are Nuclear Nitdear Materials Radioactive Waste w Facility tnfo Finder Home > Electronic Readinq Room > Document Collections > NRC Requlations (10 CFR) > Part Index >

~~

Public Involvement 5 50.59 Changes, te!

experiments.

5 50.59 Changes, tests and experiments.

(a) Definitions for the purposes of this section:

(1) Change means a modification or addition to, or removal from, the facility or procedures that affects a desir method of performing or controlling the function, or an evaluation that demonstrates that intended functions v accomplished.

(2) Departure from a method of evaluation described in the FSAR (as updated) used in establishing the design the safety analyses means:

(i) Changing any of the elements of the method described in the FSAR (as updated) unless the results of the a conservative or essentially the same; or (ii) Changing from a method described in the FSAR to another method unless that method has been approved the intended application.

(3) Facility as described in the final safety analysis report (as updated) means:

--- (i) The structures, systems, and components (SSC) that are described in the final safety analysis report (FSAR updated),

(ii) The design and performance requirements for such SSCs described in the FSAR (as updated), and (iii) The evaluations or methods of evaluation included in the FSAR (as updated) for such SSCs which demonst their intended function(s) will be accomplished.

(4) Final Safety Analysis Report (as updated) means the Final Safety Analysis Report (or Final Hazards Summi submitted in accordance with Sec. 50.34, as amended and supplemented, and as updated per the requiremenl 50.71(e) or Sec. 50.71(f), as applicable.

(5) Procedures as described in the final safety analysis report (as updated) means those procedures that contE information described in the FSAR (as updated) such as how structures, systems, and components are operate controlled (including assumed operator actions and response times).

(6) Tests or experiments not described in the final safety analysis report (as updated) means any activity whei structure, system, or component is utilized or controlled in a manner which is either:

(i) Outside the reference bounds of the design bases as described in the final safety analysis report (as update (ii) Inconsistent with the analyses or descriptions in the final safety analysis report (as updated).

(b) Applicability. This section applies to each holder of a license authorizing operation of a production or utiliza including the holder of a license authorizing operation of a nuclear power reactor that has submitted the certifi iJ permanent cessation of operations required under Sec. 50.82(a)( 1) or a reactor licensee whose license has be' to allow possession of nuclear fuel but not operation of the facility.

http://www.nrc. gov/reading-nn/doc-collections/cfr/part05O/partO50-0059.html 8/2/2006

10 CFR 50.59 Changes, tests and experiments. Page 2 of 3 (c)( 1) A licensee may make changes in the facility as described in the final safety analysis report (as updated) changes in the procedures as described in the final safety analysis report (as updated), and conduct tests or e:

not described in the final safety analysis report (as updated) without obtaining a license amendment pursuant

- .d7 ,if:

only (i) A change to the technical specifications incorporated in the license is not required, and (ii) The change, test, or experiment does not meet any of the criteria in paragraph (c)(P) of this section.

(2) A licensee shall obtain a license amendment pursuant to Sec. 50.90 prior to implementing a proposed char experiment if the change, test, or experiment would:

(i) Result in more than a minimal increase in the frequency of occurrence of an accident previously evaluated i safety analysis report (as updated);

(ii) Result in more than a minimal increase in the likelihood of occurrence of a malfunction of a structure, systc component (SSC) important to safety previously evaluated in the final safety analysis report (as updated);

(iii) Result in more than a minimal increase in the consequences of an accident previously evaluated in the fin; analysis report (as updated);

(iv) Result in more than a minimal increase in the consequences of a malfunction of an SSC important to safet evaluated in the final safety analysis report (as updated);

(v) Create a possibility for an accident of a different type than any previously evaluated in the final safety anal (as updated);

(vi) Create a possibility for a malfunction of an SSC important to safety with a different result than any previoi in the final safety analysis report (as updated);

'4 (vii) Result in a design basis limit for a fission product barrier as described in the FSAR (as updated) being exc altered; or (viii) Result in a departure from a method of evaluation described in the FSAR (as updated) used in establishin bases or in the safety analyses.

(3) I n implementing this paragraph, the FSAR (as updated) is considered t o include FSAR changes resulting frc evaluations performed pursuant to this section and analyses performed pursuant to Sec. 50.90 since submittal update of the final safety analysis report pursuant to Sec. 50.71 of this part.

(4) The provisions in this section do not apply to changes to the facility or procedures when the applicable reg1 establish more specific criteria for accomplishing such changes.

(d)(l) The licensee shall maintain records of changes in the facility, of changes in procedures, and of tests anc made pursuant to paragraph (c) of this section. These records must include a written evaluation which provide for the determination that the change, test, or experiment does not require a license amendment pursuant to (2) of this section.

(2) The licensee shall submit, as specified in Sec. 50.4, a report containing a brief description of any changes, experiments, including a summary of the evaluation of each. A report must be submitted at intervals not to ex months.

(3) The records of changes in the facility must be maintained until the termination of a license issued pursuant or the termination of a license issued pursuant to 10 CFR part 54, whichever is later. Records of changes in prc records of tests and experiments must be maintained for a period of 5 years.

'.../'

http://www.nrc.gov/reading-rm/doc-collections/cfr/pa~O5O/part050-0059.html 8/2/2006

NRC Exam 2006-1 Senior Reactor Operator Key

12. The plant is at power with all systems normally aligned. An annunciator LJ came into alarm, in which the alarm response required an Operator to manipulate a manual valve (located at floor level, and requires no tools to manipulate) in a Locked High Radiation Area (LHRA). This area has a peak dose rate of 1050 mr/hr, and is routinely surveyed by Radiation Protection.

IAW RP-AA-460, Controls for High and Very High Radiation Areas, which of the following steps are required by the Operator (besides signing onto the appropriate RWP)?

1. Review the currently available survey data for the area

2. Receive a briefing from the RP Tech

3. Ensure that the RP Tech accompanies you into the LHRA

4. Verify the maximum dose rate with your electronic dosimetry

5. When leaving the area, notify RP to second check you that the access is closed and locked

a. 1, 2, and 3

b. 2, 4, and 5 C. 1,3, 4, and 5

d. 1,2, and 5

.~

--- Answer: d Justification: RP-AA-460, Controls for High and Very High Radiation Areas (section 4.8), the following are required: 1) review survey data (it does allow RP Tech to accompany the worker into the area, if there is no current survey data);

2) reviewkign RWP; 3) receive an RP brief; 4) When exiting, wait there and notify RP so that they can come and verify the gate/door is closed and locked.

Answer d is correct and all other answers are incorrect.

Verifying maximum dose rates is not a responsibility of the worker Therefore, items 1, 2 and 5 are required. Answer d is correct.

Radiation Control 2.3.1 0 Ability to perform procedures to reduce excessive levels of radiation and guard against personnel exposure. (CFR: 43.4)

OC Learning Objective:

Cognitive Level: Comprehension or Analysis Question Type: New

. I

.u-NRC SRO Exam 2006-1 Key Page 22 of 46

RP-AA-460 Revision 10 Page 9 of 20 d

4.7.6. When Attachment 2, LHRANHRA Access Log, is used to track ingress and egress of individuals for locations where locking a door would prevent free, unobstructed egress from an area, card reader data or access control programs may be used as the record of personnel entry/exit in lieu of completing the log in Section 2 of Attachment 2.

4.8. Required Actions for Responsible Personnel

- = 4.8.1. Individual Requesting Entry to Any HRNLHRANHRA NOTE: For certain entries to an HRAILHRA, such as for inspections or rounds, entry into the area with a Radiation Protection Technician may be appropriate in lieu of reviewing a current survey, if none exists.

1. REVIEW survey data for the applicable area.

2. REVIEW and SIGN the appropriate RWP.

3. For entries to an HRNLHRANHRA, RECEIVE a briefing from Radiation Protection (per step 4.8.2.1).

4. If work in the HRNLHRANHRA will require jocks, barricades, or physical barriers to be defeated or a radiological boundary must be modified to accommodate the work in the area, then REQUEST Radiation Protection to make the alteration.

5. When entering or exiting an HRA (4000 mrem/hr at 30 cm) and an Access Control Guard is not present, ENSURE the barricade is reset (e.g., ensure closure of the swing gate/ turnstile).

6. When exiting an LHRANHRA and an Access Control Guard is not present, ENSURE that the access is closed and securedAocked with a physical challenge of the access. Also, upon completion of work, NOTIFY Radiation Protection (if not present). Then WAIT outside the LHRANHRA exit.

Through a Documented Peer Check process with the Key Custodian/

Radiation Protection individual, ENSURE that the access is closed and securedllocked with a physical challenge of the access.

A. Where keys are required to lock doors when exiting, ENSURE that the access is closed and REMAIN outside the LHRANHRA exit until a Key Custodian/ Radiation Protection individual has verified that the access is closed and securedllocked with a physical challenge of the access.

Upon completion of work, PERFORM a Documented Peer Check that the access is secured/locked with a physical challenge of the access.

B. DOCUMENT access closure upon completion of work by completing the applicable portions of Attachment 1 or by using a computerized equivalent method.

NRC Exam 2006-1 Senior Reactor Operator Key

13. The reactor was at rated power when an event occurred. Present plant i/

conditions are as follows:

e Annunciator SCRAM CONTACTOR OPEN is in alarm e All red scram lights are ON e Annunciator ARI INITIATED is in alarm e RPV water level indicates 120" TAF and rising slowly e Drywell pressure is 2.2 psig and rising very slowly e Drywell temperature is 170" F and rising very slowly a Torus water temperature is 100" F and rising e All reactor Recirculation Pumps DRIVE MOTOR switches are green-flagged (switch semaphore indicates green) e Annunciators EMRV OPEN and SV/EMRV NOT CLOSED are in alarm Annunciator APRM DNSCL is NOT in alarm e Annunciator ROPS BYPASSED is in alarm Which of the following lists the next required operator action?

a. Initiate drywell sprays IAW EMG-3200-02, Primary Containment Control

b. Pull the open EMRV control fuses IAW ABN-40, Stuck Open EMRV L ' C. Perform scram reset and scram IAW EMG-3200-01B, RPV Control

-With ATWS

d. Vent the scram air header IAW EMG-3200-01B, RPV Control -

With ATWS Answer: c HANDOUT: EOPs Justification: The indications provided show that an electromatic relief valve (EMRV) is open (EMRV open and not closed alarms) and that a reactor scrammed occurred (scram contactor open alarm and scram lights on). It also shows that the reactor is not shutdown and that power is greater than 4% (APRM downscale alarm not in), and alternate rod insertion (ARI initiated alarm) has been initiated.

Answer a is incorrect because even though drywell sprays could be initiated now in the drywell temperature leg, temperature is far away from 281" F, and other actions are of higher priority. Answer a is incorrect.

NRC SRO Exam 2006-1 Key Page 23 of 46

NRC Exam 2006-1 Senior Reactor Operator Key Actions to close the EMRV should be performed in conjunction with EOP actions.

b-But pulling control fuses to close the EMRV is not an action in ABN-40. Answer b is incorrect.

The initial conditions show that reactor overfill protection (ROPS) is bypassed and that all reactor recirculation pumps have been manually tripped (green-flagged switches). The next action in RPV Control - With ATWS is to insert control rods given a hydraulic ATWS exists (since all red scram lights are on, then all scram valves have opened and the ATWS is not electric). A possible method to insert control rods is to reset the scram, allow the scram discharge volume time to drain, and to scram again. Answer c is correct.

Venting the scram air header (performed for an electric ATWS) will not help in inserting control rods. Answer d is incorrect.

Emergency Procedures/Plan 2.4.46 Ability to verify that the alarms are consistent with the plant conditions.

(CFR: 43.5)

OC Learning Objective: 2621-845.0.0005 (03060: During a walkthrough on the BPT or BWR simulator, demonstrate the ability to shutdown the reactor during a failure to scram situation in a timely manner IAW EMG-3200.016, Support Procedure 21 .)

Cognitive Level: Comprehension or Analysis Question Type: New NRC SRO Exam 2006-1 Key Page 24 of 46

P r o c e d u r e EMG-3200.01B S u p p o r t Proc-2 1 Rev. 14 Attachment N W P a g e 2 of 1 4.0 E L E C T R I C A L ATWS NOTE A l t e r n a t e m e t h o d s o f c o n t r o l r o d i n s e r t i o n for e l e c t r i c a l ATWS may b e p e r f o r m e d i n a n y o r d e r or c o n c u r r e n t l y a s a p p l i c a b l e .

~

1.1 Vent t h e Scram A i r Header 4.1.1 Close S c r a m A i r H e a d e r i s o l a t i o n v a l v e V-6-175 (RB 23 S E ) .

4.1.2 Open S c r a m A i r H e a d e r d r a i n v a l v e V-6-409 (RB 23 S E ) .

4.1.3 WHEN c o n t r o l r o d s are no l o n g e r moving i n ,

THEN 1. C l o s e S c r a m A i r H e a d e r d r a i n v a l v e V-6-409.

2. Open S c r a m A i r H e a d e r i s o l a t i o n v a l v e V-6-175.

4.2 D e - e n e r g i z e t h e Scram S o l e n o i d s 4.2.1 MSIVs a r e O P E N ,

THEN

- p l a c e RPS C h a n n e l I a n d I 1 S u b c h a n n e l T e s t Keylocks IA, IB, I I A and I I B i n t h e T r i p p o s i t i o n

( P a n e l s 6R/7R).

- t h e c o n t r o l r o d s are no l o n g e r moving i n ,

WHEN THEN

- c o n f i r m t h e RPS C h a n n e l I a n d I1 S u b c h a n n e l T e s t k e y l o c k s i n t h e NORMAL p o s i t i o n .

4.2.2 MSIVs a r e CLOSED, THEN

- p l a c e b o t h 1 0 0 amp Main RPS b r e a k e r s i n OFF (Panels 6R/IR).

WHEN t h e c o n t r o l r o d s a r e no l o n g e r moving i n ,

THEN c o n f i r m b o t h 1 0 0 amp Main RPS b r e a k e r s i n O N .

4.3 I n c r e a s e CRD C o o l i n g W a t e r D i f f e r e n t i a l P r e s s u r e 4.3.1 C o n f i r m a l l a v a i l a b l e C R D pumps a r e r u n n i n g .

4.3.2 C l o s e C h a r g i n g Header S u p p l y v a l v e V-15-52 (RB 23 SEI.

4.3.3 I n c r e a s e CRD c o o l i n g w a t e r d i f f e r e n t i a l p r e s s u r e by c l o s i n g CRD C o o l i n g W a t e r PCV NC40 ( P a n e l 4 F ) .

4.3.4 IF CRD B y p a s s v a l v e V-15-30 i s o p e n f o r RPV i n j e c t i o n ,

THEN c l o s e CRD B y p a s s v a l v e V-15-30 (RB 23 S E ) .

(20001B/S16) E14-2

Procedure EMG3200.01B Support Proc-21 Rev. 14 Attachment N Page 3 of 4.5.10 Monitor Reactor Building airborne radiation levels.

4.5.11 WHEN control rods are no longer moving in, THEN 1. Close V-15-74 (RB 23 SE) .

2. Open the following valves (RB 23 SE):

V-15-40 V-15-25 V-15-24 5.0 HYDRAULIC ATWS NOTE Alternate methods of control rod insertion for hydraulic ATWS may be performed in any order or concurrently as applicable.

5.1 Reset the Scram and Manually Scram the Reactor 5.1.1 Confirm all available CRD pumps are running.

5.1.2 Place the ARI Normal/Bypass switch in the BYPASS position (Rear of Panel 8R).

-\-

5.1.3 Depress the ARI Manual Reset pushbutton.

5.1.4 E RPS automatic scram signals are present (except SDV HI-HI level),

THEN perform the following unless already completed in Step 5.2.4:

1. Obtain four (4) bypass plugs from the EOP tool box.

2. Open the EOP BYPASS PLUGS panel in the rear of Panel 6R and, Insert a bypass plug in BP5 Insert a bypass plug in BP6

3. Open the EOP BYPASS PLUGS panel in the rear of Panel 7R, and, Insert a bypass plug into BP5 Insert a bypass plug into BP6 5.1.5 If necessary, place the SDV HI LVL BYPASS switch to BYPASS.

(20001B/S16 E14-4

Procedure EMG-3200.01B Support Proc-21 Rev. 14 Attachment N Page 5 of 2 5.1.6 Reset the scram by depressing the Scram Reset Buttons.

5.1.7 Confirm open the SDV Vent and Drain valves (Panel 4 F ) .

5.1.8 WHEN the S D V LEVEL HI-HI alarms (H-1-b and H-2-b) clear, THEN manually scram the reactor by depressing the scram buttons.

5.1.9 Repeat steps 5 . 1 . 6 through 5 . 1 . 8 as required to insert control rods.

5.2 Open Individual Scram Test Switches 5.2.1 Confirm all available CRD pumps are running.

5.2.2 Place the ARI Normal/Bypass switch in the BYPASS position (Rear of Panel 8R).

5.2.3 Depress the ARI Manual Reset pushbutton.

5.2.4 -

IF RPS automatic scram signals are present (except SDV HI-HI level).

THEN perform the following unless already completed in Step 5 . 1 . 4 :

1. Obtain four ( 4 ) bypass plugs from the EOP tool box.

2. Open the EOP BYPASS PLUGS panel in the rear of Panel 6R and, Insert a bypass plug into BP5 Insert a bypass plug into BP6

3. Open the EOP BYPASS PLUGS panel in the rear of Panel IR and, Insert a bypass plug into BP5 Insert a bypass plug into BP6 5.2.5 If necessary, place the SDV HI LVL BYPASS switch to BYPASS.

5.2.6 Reset the scram by depressing the Scram Reset Buttons.

5.2.7 Confirm open SDV Vent and Drain valves (Panel 4 F ) .

--- OVER (20001B/S16 ) E14-5

AmerGen, All $X<'bll C W l p d r OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-40 Title Revision No.

STUCK OPEN EMRV 2 STUCK OPEN EMRV 1.o APPLICABILITY This procedure provides direction for any EMRV that remains open when not required.

2.0 INDl CAT1ONS 2.1 Annunciators Engraving Location Setpoint I EMRVoPEN SV/EMRV NOT CLOSED B-3-g B-4-g valve open (pilot valve limit switch)

VMS alarm (acoustic monitor) 2.2 Plant parameters I Parameter Location I Change I I I

EMRV discharge temperature Panel 1F/2F I rises above 2OO0F I

Acoustic monitor Panel 1F/2F indicates EMRV I Torus water temperature Panel 1F/2F rising I Red VALVE OPEN light Panel 1F/2F iI Iuminated Green VALVE CLOSED Panel 1F/2F extinguished light 2.3 Other indications 1 Red VALVE OPEN indication light is illuminated if the solenoid is energized

2. Acoustic monitoring system indications 3.0

AmerGen, An Exe%Yi Eompdv OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-40 I

~.-' Title Revision No.

STUCK OPEN EMRV 2 3, EMRV discharge temperature indications

4. Lowering RPV pressure

5. Drop in generator load (MWe)

6. Rising Torus temperature

7. Indicated steam flow less than indicated feed flow

8. EMRV tailpipe temperature (RB 23' elevation on recorder) 3.0 OPERATOR ACTIONS If while executing this procedure, an entry condition for any EOP occurs, then EXECUTE this procedure concurrently with the appropriate EOP.

3.1 VERIFY the EMRV condition by observing the following:

Red VALVE OPEN indication light is illuminated if the solenoid is energized [ I Acoustic monitoring system indications [ I EMRV discharge temperature indications [ I

. Lowering RPV pressure [ I Drop in generator load (MWe) [ I Rising Torus temperature [ I

. Indicated steam flow less than indicated feed flow [ I

. EMRV tailpipe temperature (RB 23' elevation on recorder) [ ]

4.0

AmerGenx. OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-40 An fxeion Cornpdrrj ii Title Revision No.

STUCK OPEN EMRV 2 3.2 PERFORM the following to close the EMRV:

1. If a feedwater transient is in progress, then ALLOW the transient to stabilize prior to performing step 2.

from automatic to manual mode is a bumpless transfer and should have no effect on RPV level.

2. PLACE Feedwater Level Control in manual by depressing the MAN pushbutton on the MASTER FEEDWATER CONTROLLER and VERIFY the red manual LED is illuminated.

3. PLACE the AUTO DEPRESS VALVE switch in OFF for the open EMRV.

4. DETERMINE if the EMRV closed as indicated by the Acoustic Monitor and/or the valve solenoid light.

5. If the EMRV is still open, then CYCLE the respective AUTO DEPRESS VALVE switch from OFF to MAN to OFF.

6. If the EMRV is closed, then GO TO step 8.

If the EMRV is not closed, then REPEAT steps 5 and 6 another three to five times in an attempt to close the EMRV.

7. If the EMRV cannot be closed using the AUTO DEPRESS VALVE switch, then PLACE the EMRV NORMALIDISABLE keylock switch for the affected EMRV in DISABLE (rear of Panel 1F/2F.)

5.0

AmerGen, An ixeion Company OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-40 d Title Revision No.

STUCK OPEN EMRV 2 I

8. If the EMRV closes, then PERFORM the following:

A. RESET the MASTER ALARM units in Panel 15R to silence the acoustic monitor alarm. [ I B. PLOT EMRV downcomer temperature in accordance with Procedure 602.4.003, [ I Electromatic Relief Valve Operability Test.

C. REFER to Technical Specifications 4.5.F.5 and 4.5.L for surveillance requirements following [ I EMRV actuation.

9. PLACE Feedwater Level Control in the AUTO mode as directed by the Unit Supervisor (US) as follows:

A. SELECT and MONITOR the P display digital readout on the MASTER FEEDWATER LEVEL [ I CONTROLLER.

B. SELECT the S display on the MASTER FEEDWATER LEVEL CONTROLLER. [ I C. MATCH the S display digital readout to the P display digital readout on the MASTER [ I FEEDWATER LEVEL CONTROLLER.

D. When the S display and P display digital readouts are equal,

[ I then PLACE the MASTER FEEDWATER LEVEL CONTROLLER in AUTO.

3.3 If the EMRV cannot be closed, then PERFORM the following:

1. CONFIRM Feedwater Level Control in the AUTO mode. [ I

2. SCRAM the Reactor in accordance with ABN-1, Reactor Scram. [ I 6.0

OYSTER CREEK GENERATING Number A n fxcidri Company STATION PROCEDURE ABN-40 I

~-4 Title Revision No.

STUCK OPEN EMRV 2

3. If RPV cooldown rate is excessive,

[ I then CONSIDER shutting MSIVs.

4. BYPASS and DEFEAT the respective EMRV Acoustic Monitor by completing the following (Panel 15R):

A. PLACE HI-ALARM switch in DEFEAT. [ I B. PLACE LO-BIAS switch in DEFEAT. [ I C. RESET MASTER ALARM units. [ I

5. REFER to EPIP-OC-1010, Radiological Emergency Plan for [ ]

Oyster Creek, for EAL determination.

6. REFER to Procedure OP-AA-106-101, Significant Event Reporting. [ I

...J

4.0 REFERENCES

4. I ABN-I , Reactor Scram 4.2 EPIP-OC-1010, Radiological Emergency Plan for Oyster Creek 4.3 OP-AA-106-101, Significant Event Reporting 4.4 Procedure 602.4.003, Electromatic Relief Valve Operability Test 4.5 Technical Specifications 5.0 ATTACHMENTS - None 7.0

NRC Exam 2006-1 Senior Reactor Operator Key

14. The reactor is at 23% power and the turbine generator has just been ic/

placed on-line. The Reactor Operator is raising reactor power by withdrawing control rods.

Which one of the following is correct?

a. A turbine vibration of 15 mils (and trending up) requires an immediate reactor scram and turbine trip IAW TURBINE MECH -

VIBRATION HI annunciator response procedure

b. A turbine vibration of 15 mils (and trending up) requires an immediate turbine trip ONLY IAW TURBINE MECH - VIBRATION HI annunciator response procedure

c. A loss of both stator cooling water pumps requires an immediate reactor scram and turbine trip IAW ABN-11, Loss of Generator Stator Cooling

d. A loss of both stator cooling water pumps requires an immediate turbine trip ONLY IAW ABN-I 1, Loss of Generator Stator Cooling Answer: b Handouts: None Justification: IAW RAP-Q3b (vibration high), an immediate turbine trip is required if any turbine bearing reaches 12 mils or above (and continues to increase).

Since reactor power is less than 30%, a reactor scram is not required. Answer a is incorrect and answer b is correct.

IAW ABN-11, if a turbine runback occurs (as a result of the loss of stator cooling) or stator temperatures are rising AND reactor power is less than 30%, then generator MVARs should be manually reduced to zero, or as low as allowed by grid conditions. At 24% power, a runback is not expected anyway because power is so low. No scram nor turbine trip are required. Answers c and d are incorrect.

295005 G2.4.49 Main Turbine Generator Trip / Emergency Procedures /Plan:

Ability to perform without reference to procedures those actions that require immediate operation of system components and controls. (CFR: 43.5)

OC Learning Objective: 2621.828.0.0050. Obiective S:

Describe and interpret procedure sections and steps for plant emergency or off-normal conditions that involve this system including personnel allocation and equipment operation in accordance with applicable ABN, SDRP, EOP & EOP support procedures and EPIPs.

Cognitive Level: Comprehension or Analysis Question Type: Modified Bank

.v.

NRC SRO Exam 2006-1 Key Page 25 of 46

NRC Exam 2006-1 Senior Reactor Operator Key

References:

RAP-Q3b, ABN-IO NRC SRO Exam 2006-1 Key Page 26 of 46

TURBINE MECH VIBRATION

ONFIRMATORY ACTIONS:

UJTOMATIC ACTIONS:

JONE VlANUAL CORRECTIVE ACTIONS:

OBSERVE the following vibration limits:

SHAF-i (RPM)

TRIP TURBINE IF ANY BEARING VIBRATION EXCEEDS MILS FOR MINUTES TRIP TURBINE IMMED'IM I LLY IF ANY VIBRATION EXCEEDS:

I

and increasing with no signs of turning downward LlE Turbine speed is > 800 rpm, THEN COMMENCE timing the alarm condition. 1 MANUAL CORRECTIVE ACTIONS: (continued on Page 2 of 3)

Subject Procedure No.

Page 1 of 3 BOP RAP-Q3b Q-3-b Alarm Response Procedures Revision No: 3

Group Heading Q-3-b TURBINE MECH VIBRATION HI MANUAL CORRECTIVE ACTIONS: (continued from Page I of 3)

NOTE

1. During startup, the Turbine should be accelerated steadily and not to dwell at the critical speed range (900-1400 rpm) to avoid excessive vibration.

2. Turbine damageifahre may meet an EAL threshold, refer to Procedure EP-OC-1010, Radiological Emergency Plan for Oyster Creek if damage is experienced.

OK power is ~ 3 0 %and Turbine trip is required due to high vibration, 1 THEN PERFORM the following: 1

1. TRIP the Turbine.

2. REFER TO ABN-10, Turbine Trip.

PIE power is >30% and Turbine trip is required due to high vibration, 1 THEN PERFORM the following: 1

1. SCRAM the reactor. 1

2. REFER to ABN-1, Reactor Scram. 1

3. CONFIRM Turbine tripped.

4. REFER to ABN-IO, Turbine Trip.

MANUAL CORRECTIVE ACTIONS: (continued on Page 3 of 3)

Subject Page 2 of 3 BOP RAP-Q3b I Q-3-b Alarm Response Procedures Revision No: 3

'-' I Title Revision No.

LOSS OF GENERATOR STATOR COOLING 0 LOSS OF GENERATOR STATOR COOLING 1.O APPLICABILITY This procedure is applicable following a loss of generator stator cooling capability due to any of the following:

Stator Cooling Pump trip.

0 Loss of Stator Cooling flow.

0 Loss of TBCCW cooling capability 2.0 INDICATIONS 0 Standby Stator Cooling Water pump automatically starts at 94 psig pump discharge pressure.

Turbine runback to approximately 25% rated power (182 MWe) on low Stator Cooling Water flow below 230 gpm or high cooling water temperature of 89 OC at the stator outlet.

0 Turbine trip if generator output remains above 4800 amps for more than 3 minutes following receipt of a turbine runback signal.

2.0

Number herGm %W OYSTER CREEK GENERATING ABN-1 I A r %&mjt?ri::3 ~rwyyfarwpng STATION PROCEDURE I

4 Title Revision No.

LOSS OF GENERATOR STATOR COOLING 0 3.0 OPERATOR ACTIONS 3.1 If stator cooling pump discharge header pressure lowers to 94 psig, then CONFIRM automatic start of standby Stator Cooling Water Pump. [ I 3.2 If a turbine runback occurs or stator temperatures are rising and reactor power is above 30% (580 MWth),

then SCRAM the reactor and EXECUTE ABN-1. [ I 3.3 If a turbine runback occurs or stator temperatures are rising and reactor power is less than 30% (580 MWth),

then concurrently PERFORM the following:

1. REDUCE Main Generator MVARs to zero or as low as grid conditions permit. [ I

2. When generator load is below 25% (180 MWe, as indicated by actuation of the 25% LOAD TRIP NOT RESET, Q-8-a),

then RESET the 25% load trip. [ I 3.4 CONFIRM power operations in accordance with Procedure 202.I, Power Operations. [ I 3.5 DIRECT Reactor Engineering to evaluate a post-transient Powerplex case of Core Thermal Limits. [ I 3.6 If Stator Cooling flow has been lost and can m b e restored immediately, then PERFORM the actions listed in Attachment ABN-11-1 within the specified time limits. [ I

4.0 REFERENCES

- None 5.0 ATTACHMENTS - ABN-11-1, Operator Actions For Sustained Loss of Stator Cooling Flow.

.J 4.0

NRC Exam 2006-1 Senior Reactor Operator Key

15. The Control Room has been evacuated IAW ABN-30, Control Room Evacuation. The following conditions exist:

~W 0 The reactor is in a SHUTDOWN CONDITION 0 RPV pressure is 900 psig and lowering 0 The B Isolation Condenser is in service 0 The A Isolation Condenser and all EMRVs have been disabled IAW ABN-30 Which of the following actions must be met to comply with Technical Specifications?

1. Reduce RPV pressure to e 11 0 psig within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

2. Place the reactor in COLD SHUTDOWN within 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

a. 1 ONLY

b. 2 ONLY C. land2

d. Neither 1 o r 2 Answer: c Handouts: Tech Spec 3.4, 3.8

-- Justification: A, B and D are incorrect - both 1 and 2 must be met.

C is correct - both Tech Spec action statements must be met.. .with the EMRVs disabled (IAW Attachment ABN-30-8) the ADS function is also disabled. Tech Spec 3.4.8 (ADS) requires reactor pressure to be reduced to less than 110 psig within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months if ADS operability requirements are not met. Tech Spec 3.8.A requires both Isolation Condensers to be operable during power operations and whenever reactor coolant temperature is greater than 21 2 OF, except as specified in Tech Spec 3.8.C. Tech Spec 3.8.C states If one isolation condenser becomes inoperable durina the run mode the reactor may remain in operation for a period not to exceed 7 days. With the A IC disabled, Tech Spec 3.8.D requires the reactor to be placed in the cold shutdown condition. No time interval is specified, so the requirements of OP-OC-100 apply, which specify the 30-hour time limit.

NOTE: Procedure 307, P&L 3.2.4, and Tech Spec 3.8.A both state two Isolation Condenser loops shall be operable during power operation and whenever reactor coolant temperature is greater than 212 OF. There is plant history (OE) that provides the basis for having both ICs operable during a startup because Tech Spec 3.8 Bases specify that the 7-day out of service allowance when the system is required is limited to the RUN mode in order to require system availability, including redundancy, at startup. Although the given conditions apply to a shutdown and not a startup, the Tech Spec Bases clearly state the 7-day NRC SRO Exam 2006-1 Key Page 27 of 46

NRC Exam 2006-1 Senior Reactor Operator Key allowance only applies to the RUN mode. Therefore, for the conditions given

. d (not RUN mode), action #2 must also be met. Looking at this from another angle, Tech Spec 3.8 is clear on what to do in the RUN and STARTUP modes.

Since it is not as clear about the SHUTDOWN mode (other than its not the RUN mode), Tech Spec 3.0.A would apply, which also requires COLD SHUTDOWN within 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

295016 G2.2.22 Control Room Abandonment / Equipment Control: Knowledge of limiting conditions for operations and safety limits. (CFR: 43.2)

OC Learning Objective: 2621.828.0.0005, Obiective 0:

Given Technical Specifications, identify and explain associated actions for each section of the Technical Specifications relating to this system including personnel allocation and equipment operation.

2621.828.0.0023, Obiective I:

For Limiting Conditions of Operation (LCOs) related to the Isolation Condenser System, determine the impact on plant operations for given conditions using Technical Specifications.

Cognitive Level: Comprehension or Analysis Question Type: New

References:

ABN-30, 307, TS 3.4.B, TS 3.8, OP-OC-100

--i NRC SRO Exam 2006-1 Key Page 28 of 46

B. Automatic Depressurization System

1. Five electromatic relief valves, which provide the automatic depressurization and pressure relief functions, shall be operable when the reactor water temperature is greater than 212°F and pressurized above 110 psig, except as specified in 3.4.B.2 and during Reactor Vessel Pressure Testing consistent with Specifications 1.39 and 3.3.A.(i).

2. If at any time there are only four operable electromatic relief valves, the reactor may remain in operation for a period not to exceed 3 days provided the motor operated isolation and condensate makeup valves in both isolation condensers are verified daily to be operable.

-,> 3. If Specifications 3.4.B.1 and 3.4.B.2 are not met; reactor pressure shall be reduced to 110 psig or less, within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

4. The time delay set point for initiation after coincidence of low-low-low reactor water level and high drywell pressure shall be set not to exceed two minutes.

C. Containment Spray System and Emergency Service Water System NOTE: LCO 3.0.C.2 is not applicable to the Containment Spray System and Emergency Service Water System I. The containment spray system and the emergency service water system shall be operable at all times with irradiated fuel in the reactor vessel, except as specified in Specifications 3.4.C.3, 3.4.C.4,3.4.C.6 and 3.4.C.8.

2. The absorption chamber water volume shall not be less than 82,000 ft3 in order for the

.~.--- -

containment spray and emergency service water system to be considered operable.

3. If one emergency service water system loop becomes inoperable, its associated containment spray system loop shall be considered inoperable. If one containment spray system loop andor its associated emergency service water system loop becomes inoperable during the run mode, the reactor may remain in operation for a period not to exceed 7 days provided the remaining containment spray system loop and its associated emergency service water system loop each have no inoperable components and are verified daily to be operable.

4. If a pump in the containment spray system or emergency service water system becomes inoperable, the reactor may remain in operation for a period not to exceed 15 days provided the other similar pump is verified daily to be operable. A maximum of two pumps may be inoperable provided the two pumps are not in the same loop. If more than two pumps become inoperable, the limits of Specification 3.4.C.3 shall apply.

5. During the period when one diesel is inoperable, the containment spray loop and emergency service water system loop connected to the operable diesel shall have no inoperable components.

..--- I OYSTER CREEK 3.4-5 Amendment No.: 75, ! 5 3 , !5?, !?e, !99, W, 247

3.8 ISOLATION CONDENSER

-LJ Applicability: Applies to operating status of the isolation condenser Obiective: To assure heat removal capability under conditions of reactor vessel isolation from its normal heat sink.

Specification:

NOTE: LCO 3.0.C.2 is not applicable to the Isolation Condenser.

A. The two isolation condenser loops shall be operable during power operations and whenever the reactor coolant temperature is greater than 212°F except as specified in C, below or during reactor vessel pressure testing.

B. The shell side of each condenser shall contain a minimum water volume of 22, 730 gallons. If the minimum volume cannot be maintained or if a source of makeup water is not available to the condenser, the condenser shall be considered inoperable.

C. If one isolation condenser becomes inoperable during the run mode the reactor may remain in operation for a period not to exceed 7 days provided the motor operated isolation and condensate makeup valves in the operable isolation condenser are verified daily to be operable.

D. If Specification 3.8.A and 3.8.B are not met, or if an inoperable isolation condenser cannot be repaired within 7 days, the reactor shall be placed in the cold shutdown condition.

E. If an isolation condenser inlet (steam side) isolation valve (V-14-30, 31, 32 or 33) becomes or is made inoperable, in the open position during the run mode, the redundant inlet isolation valve shall be verified operable. If the inoperable valve is not returned to service within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months declare the affected isolation condenser inoperable, isolate it and comply with Specification 3.8.C.

. x-a F. If an AC motor-operated isolation condenser outlet (condensate return) isolation valve (V-14-36 or 37) becomes or is made inoperable in the open position in the run mode, return the valve to service within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or declare the affected isolation condenser inoperable, isolate it and comply with Specification 3.8.C.

Basis: The purpose of the isolation condenser is to depressurize the reactor and to remove reactor decay heat in the event that the turbine generator and main condenser is unavailable as a heat sink."'

Since the shell side of the isolation condensers operate at atmospheric pressure, they can accomplish their purpose when the reactor temperature is sufficiently above 212°F to provide for the heat transfer corresponding to reactor decay heat. The tube side of the isolation condensers form a closed loop with the reactor vessel and can operate without reducing the reactor coolant water inventory.

OYSTER CREEK 3.8-1 Amendment No.: 72, ?20, W ,241 d

0P-0c-100 Revision 5 Page 3 of 18

.4 4.2.3 When the plant is in an LCO, the operational condition shall not be changed outside the provisions of the LCO until a risk assessment is performed. This risk assessment must address inoperable equipment in the planned operational condition or other applicability specified condition and support the planned operational condition. Risk Management actions (if applicable) must be established. (Refer to Technical Specification 3.0.C)

Example: LCO 3.4.D.1- If a CRD pump fails during startup, repairs can be made well before 7 days of power operation is projected or will expire, and plant risk will remain Yellow. The startup could be conditional.

4.2.4 The following criteria shall be used for determining the time intervals in which the actions required by the Technical Specifications must be completed/performed:

TIME INTERVAL SPECIFIED CRITERIA Hourly or Daily The required actions must be performed Demonstrated Daily during each subsequent time period (Le., an hourly tour performed any time between 0000 and 0059 must again be performed prior to 0159, a daily sample must be taken by 2359 hours0.0273 days 0.655 hours 0.0039 weeks 8.975995e-4 months on the next day).

I Not-to-Exceed The required actions must be performed and Every 5 Hours completed within the specified time interval to Any 5 Day Period the exact minute (i.e., if an event occurs at Within X Days 0000 on X/I/XX and the corrective actions Within X Hours must be completed within 7 days, then the time interval will expire at 0000 on W8KX).

Technical Specification A continuous and controlled Reactor shutdown 3.0.A (COLD SHUTDOWN must be commenced within 60 minutes of the within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months ) Unit Supervisors determination that this technical specification applies.

the unit shall be placed in Initiation of a plant shutdown does NOT have to COLD SHUTDOWN within the be commenced within one hour. The minimum following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months initiation time when a plant shutdown should be commenced is derived by using the ACTION the Reactor shall be inOLD statement completion time and subtracting the SHUTDOWN within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months appropriate allotted plant maneuvering time. A minimum of four (4) hours (or longer, to meet environmental requirements) shall be allotted to maneuver from POWER OPERATION to SHUTDOWN CONDITION (or longer, to meet environmental requirements). A minimum of eight (8) hours shall be allotted to maneuver from the SHUTDOWN CONDITION to COLD SHUTDOWN.

the Reactor shall be placed in The Reactor shall be placed in a cold shutdown the cold shutdown condition condition in 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months . The minimum time of

---? (no time interval specified) initiation is as described above.

NRC Exam 2006-1 Senior Reactor Operator Key

16. An ATWS has occurred. All control rods have been inserted IAW Support u Procedure 21. The following plant conditions currently exist:

Reactor pressure is 900 psig Reactor water level is 10 inches Torus water level is 173 inches Torus water temperature is 160 O F What action is required for these conditions?

a. Reduce RPV pressure to prevent exceeding TLL

b. Reduce RPV pressure to prevent exceeding HCTL

c. Emergency Depressurize due to exceeding HCTL

d. Initiate Standby Liquid Control due to exceeding BllT Answer: c Handouts: EMG-3200.01A, EMG-3200.02 (Provide large figures for easier reading)

Justification: A is incorrect - this would be a viable answer if HCTL was not already exceeded.

---" B is incorrect - HCTL has already been exceeded.. .it's too late to lower pressure to "prevent exceeding HCTL."

C is correct - HCTL has been exceeded.. .Emergency Depressurization is required by EMG-3200.02, Primary Containment Control.

D is incorrect - all rods have been inserted.. .there is no requirement (or need) to initiate SLC relative to BIIT.

295026 EA2.01 Ability to determine and/or interpret the following as they apply to SUPPRESSION POOL HIGH WATER TEMPERATURE: Suppression pool water temperature (CFR: 43.5)

OC Learning Objective: 2621.828.0.0032, Obiective J:

Identify and interpret normal, abnormal and Emergency Operating Procedures for the Primary Containment System.

Cognitive Level: Comprehension or Analysis Question Type: Bank

References:

EMG-3200.01A, EMG-3200.02, EOP Users Guide

'c-'

NRC SRO Exam 2006-1 Key Page 29 of 46

EOP USERS GUIDE PRIMARY CONTAINMENT CONTROL TORUS TEMPERATURE

(*F)

I II I I

I I

TORUS TEMPERATUR E

(F I IEMERGENCY DEPRESSURIZATION IS REQUIRED CONCURRENTLY WlTH THIS PROCEDURE I

~.

Earlier steps in the Torus temperature control leg If it becomes apparent that these efforts will fail to L-- prescribed actions for: maintain the combination of Torus water temperature

. Reducing Torus water temperature (maximizing Torus cooling) and RPV pressure below the Heat Capacity Temperature Limit, an Emergency RPV Depressurization is initiated while the Torus can still safely accommodate the blow down. If the combination Eliminating unnecessary heat addition to the Torus of Torus water temperature RPV pressure can be (attempting to close any stuck open EMRVs maintained below the limit, efforts to control the closing any EMRVs not required for RPV pressure combination of Torus temperature and RPV pressure control or adequate core cooling) are continued.

0 Minimizing the energy transferred from the Reactor EMERGENCY DEPRESSURIZATION IS to the Torus (Reactor scram) REQUIRED is printed in bold, uppercase letters enclosed in a red box to emphasize the need to override Further, with entry to procedure RPV CONTROL - NO RPV pressure control actions carried out concurrently in ATWS, direction may have been given to depressurize the RPV CONTROL procedure. Conditional Statements the RPV to stay below the Heat Capacity Temperature will direct depressurization according to the applicable Limit (HCTL.) (Refer to Figure F of the Figures and EMERGENCY DEPRESSURIZATION procedure. The Limits section of this document for additional details of operator remains in the Primary Containment Control the HCTL.) procedure and performs it concurrently with the Emergency Depressurization procedure.

REVISION 7 2-11

EOP USER'S GUIDE EOP FIGURES AND LIMITS TORUS HIGH LEVEL 230 220 210 200 TORUS TEMPERATURE I90 TORUS 180 LEVEL 170

-144

-154 160

-164

-174 150

- 180 140 I 1 0 8 1 I

1 1 1 1 1 1 1 1 I

1 1 1 I I

I I I I I

I I 8 8 I

, ) I I I

I I I I I

I I I I

-188 0 100 200 300 400 500 600 700 800 d 0 1000 I 1 00 RPV PRESSURE (PSIG) I TORUS LOW LEVEL 240 230 220 210 200 TORUS TEMPERATURE I90 (OF) 180 170 TORUS LEVEL 160

-143 150 120

'I10 140 0 100 200 300 400 500 600 700 800 900 1000 1100 RPV PRESSURE (PSIG)

REVISION 7 13 - 18

NRC Exam 2006-1 Senior Reactor Operator Key

17. A turbine trip occurred while operating at rated power due to a loss of

\ --/ ,

turbine operating oil. Current plant conditions are as follows:

Reactor pressure is 1020 psig and rising slowly Reactor water level is 150 inches and rising slowly Aux flash tank pressure on Panel 7F indicates zero Which of the following should be used to control reactor pressure?

a. EMRVs ONLY

b. Isolation Condensers ONLY C. EMRVs and/or Isolation Condensers

d. Main Turbine Bypass Valves Answer: c Handouts: None Justification: A is incorrect. EMRVs can be used under the given conditions, but it is not the only system available. The main turbine bypass valves are not available (due to loss of condenser vacuum as indicated by aux flash tank pressure). With RPV level below 160 inches, the Isolation Condensers are also available, for stabilizing RPV pressure below 1045 psig as directed by ABN-1.

The other options given in ABN-1 (RWCU and IC tube side vents) are not practical for the given conditions.

B is incorrect. As stated above, the EMRVs are also available. There is nothing in the question stem that makes Isolation Condensers unavailable. An RPV water level above 160 would make the ICs unavailable.

C is correct since both the EMRVs and the ICs are available for pressure control and can be used.

D is incorrect - the main turbine bypass valves are not available without main condenser vacuum above 10 Hg (Vacuum Trip 2 trips the bypass valves at 10 Hg). Aux Flash Tank pressure at zero indicates main condenser vacuum is at zero.

295007 AA2.03 Ability to determine and/or interpret the following as they apply to HIGH REACTOR PRESSURE: reactor water level. (CFR: 43.5)

NRC SRO Exam 2006-1 Key Page 30 of 46

NRC Exam 2006-1 Senior Reactor Operator Key OC Learning Objective: 2621.828.0.0037. Obiective N:

Describe and interpret procedure sections and steps for plant emergency or off-normal conditions that involve this system including personnel allocation and equipment operation IAW applicable ABN, EOP & EOP support procedures and EPIPs.

Cognitive Level: Comprehension or Analysis Question Type: New

References:

ABN-1, 307 NRC SRO Exam 2006-1 Key Page 31 of 46

AmerGm OYSTER CREEK GENERATING Number An Ereh Compilny STATION PROCEDURE ABN-1 Title Revision No.

2 REACTOR SCRAM RWCU system in the recirculation mode. [ I RWCU system in the let down mode. [ I NOTE: Main Condenser must be available and ICs must not be isolated to utilize IC tube side vents for pressure control.

Isolation Condenser tube side vents.

~~

[ I NOTE: Resetting the scram will minimize the injection of cold water into the reactor bottom head from the CRD system and will relieve pressure from the control rod drives. (CM-1) 7.0

NRC Exam 2006-1 Senior Reactor Operator Key

18. Refueling is in progress when an accident occurs on the refuel floor. The following conditions exist five minutes later:

L../-*

Refueling has been suspended and the refuel floor has been evacuated ALL refuel floor radiation monitors indicate between 70 and 90 mWhr on Panel 2R Reactor Building ventilation exhaust radiation monitors indicate 3 mWhr on Panel 2R Reactor Building differential pressure is negative 0.25 inches WG Which of the following describes how the Reactor Building Ventilation System (RBVS) and Standby Gas Treatment System (SGTS) should be operated during this event.

a. RBVS is in service and should remain in service

b. SGTS is in service and should remain in service

c. RBVS is in service; SGTS should be placed in service

d. SGTS is in service; RBVS should be placed in service Answer: d Handouts: EMG-3200.11 Justification: Under the given conditions, the high radiation levels on the refuel floor have auto started SGTS and isolated normal RB ventilation (see RAP-10F4m).

A is incorrect - RBVS is tripped and isolated; SGTS is in service.

B is incorrect - SGTS is in service but the conditions for placing RBVS back in service are met, as directed by the Secondary Containment Control EOP.

C is incorrect - RBVS is tripped and isolated; SGTS is in service.

D is correct - RBVS isolated on Hi Refuel Floor radiation (> 50 mWhr w/2 minute time delay in either the spent fuel pool area or on the operating floor).

This also caused SGTS to initiate, maintaining RB negative differential pressure.

The Secondary Containment Control EOP directs placing the RBVS in service it has isolated or is shutdown, AND the drywell is not being vented through the RB supply fans (the drywell is open during refueling), AND RB ventilation exhaust radiation level is below 9 mWhr, RB pressure is above 0 inches WG and a ground level release is imminent or in progress. Since all of these conditions are met, RBVS should be placed back in service. This will require overriding interlocks (Hi Refuel Floor radiation initiation signals), resetting and NRC SRO Exam 2006-1 Key Page 32 of 46

NRC Exam 2006-1 Senior Reactor Operator Key restarting RB Ventilation as directed by Support Procedure 50, which also causes SGTS to shutdown.

295034 EA2.01 Ability to determine and/or interpret the following as they apply to SECONDARY CONTAINMENT VENTILATION HIGH RADIATION: Ventilation radiation levels (CFR: 43.5)

OC Learning Objective: 2621.828.0.0042. Obiective F:

Given a set of system indications or data, evaluate and interpret them to determine limits, trends and system status.

2621.828.0.0042, Obiective M:

Describe and interpret procedure sections and steps for plant emergency or off-normal conditions that involve this system including personnel allocation and equipment operations IAW applicable ABN, SDRP, EOP and EOP support procedures and EPIPs.

Cognitive Level: Comprehension or Analysis Question Type: New

References:

RAP-1OF1f, RAP-1OF3m, EMG-3200.11, EOP Users Guide NRC SRO Exam 2006-1 Key Page 33 of 46

Group Heading RADIATION MONITORS 10F-4-m CONFIRMATORY ACTIONS:

o VERIFY high radiation level at Panel 2R. [ I I

AUTOMATIC ACTIONS:

Local audible alarm. After a two minute time delay, the Reactor Building isolates and the standby gas treatment system initiates.

MANUAL CORRECTIVE ACTIONS:

CONFIRM high radiation condition. 1 O E confirmed, o THEN PERFORM the following:

ENTER EOP EMG-3200.11, Secondary Containment Control. 1 CONFIRM SGTS start. 1 MONITOR area radiation levels.

(Panel 2R) 1 NOTE This alarm indicates that a parameter has exceeded or has the potential to exceed an Emergency Action Level (EAL).

3 REFER to EP-OC-1010, Radiological Emergency Plan to determine EAL classification. 1 MANUAL CORRECTIVE ACTIONS: (continued on Page 2 of 2)

Subject Procedure No.

Page 1 of 2 NSSS RAP-I OF4m 10F-4-m

.--- l Alarm Response Procedures Revision No: 0

Group Heading RADIATION MONITORS 10F-4-m MANUAL CORRECTIVE ACTIONS: (continued from Page 1 of 21 o NOTIFY the Shift Manager. [ I a As directed, ANNOUNCE over the page system the evacuation requirements of the area. [ I CAUSES: SETPOINTS: ACTUATING DEVICES:

Radiation levels in excess of 50 mr/hr as 50 mr/hr R014B-9 Sensor measured at the equipment hatch on the Reactor Operating Floor.

Reference Drawings:

GU 3E-611-17-003 GE 706E835 Subject Procedure No.

Page 2 of 2 NSSS RAP-I OF4m 10F-4-m Alarm Response Procedures Revision No: 0

L-11 L NOISIA3tl

/2

NRC Exam 2006-1 Senior Reactor Operator Key

19. Given the following:

0 A plant startup is in progress 0 The reactor mode switch is in STARTUP 0 SRM 22 is bypassed due to a failed detector 0 IRMs 11-16 and 18 are indicating 10% on Range 8 0 IRM 17 is indicating 75% on Range 7 0 SRM 23 experiences an INOP condition due to a power supply failure Which statement below describes how this impacts the reactor startup?

1. A withdraw rod block

2. The reactor startup

a. (1) is generated (2) can continue because IRM 17 can be switched to Range 8

b. (1) is generated (2) CANNOT continue because one SRM is already bypassed

c. (1) is NOT generated (2) can continue because only two SRMs are required to be operable during a reactor startup

d. (1) is NOT generated (2) CANNOT continue because more than two SRMs are required to be operable during a reactor startup Answer: a Handouts: None Justification: A is correct - a rod block is generated due to the SRM 23 INOP condition and not ALL of the correlating IRMs (15, 16, 17 and 18) are on or above Range 8. Since IRM 17 is at the top of the 25-75% band, it can be switched to Range 8, as directed by Procedures 201 and 402.3. This will bypass the SRM 23 rod block, allowing control rod withdrawal to continue.

B is incorrect - the first statement is correct. However, while it is true that one SRM is already bypassed, switching IRM 17 to range 8 automatically bypasses all SRM rod block functions, which will allow control rod withdrawal to continue.

This is allowed (directed) by Procedures 201 and 402.3.

C is incorrect - the first statement is incorrect because a withdraw rod block IS

~--generated. The second statement is correct, although insignificant for the given conditions.

NRC SRO Exam 2006-1 Key Page 34 of 46

NRC Exam 2006-1 Senior Reactor Operator Key

-u D is incorrect - the first statement is incorrect because a withdraw rod block IS generated. The second statement is also incorrect in that Procedure 201 only requires two operable SRMs during a reactor startup (until all IRMs are on Range 8 or above).

21 5004 A2.02 Ability to (a) predict the impacts of the following on the SOURCE RANGE MONITOR (SRM) SYSTEM; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those abnormal conditions or operations: SRM inop condition (CFR: 43.5)

OC Learning Objective: 2621.828.0.0029, Obiective F:

Describe the interlock signals and setpoints for the affected system components and expected system response including power loss of failed components.

2621.828.0.0029, Obiective G:

Given a set of system indications or data, evaluate and interpret them to determine limits, trends and system status.

2621.828.0.0029, Obiective I:

Given normal operating procedures and documents for the system, describe or interpret the procedural steps. [Describe and interpret procedure sections or steps and documents, under normal operating conditions, that involve this system.] [200s, 300s, 400s, 8 0 0 ~ 1

.4 Cognitive Level: Comprehension or Analysis Question Type: New

References:

201, 401.4, 402.3, RAP-G4d, GE 237E912 NRC SRO Exam 2006-1 Key Page 35 of 46

her-_ A n Exebn Company 1 OYSTER CREEK GENERATING STATION PROCEDURE II Number 201 I I

.4 Title Revision No.

Plant Startup 39 6.19 VERIFY operability of the ROD WORTH MINIMIZER (RWM) as follows:

6.19.1 CONFIRM the RWM is not bypassed. -- I - I 6.19.2 PLACE "Rod Power" switch to ON. --- I I 6.19.3 SELECT Control Rod 30-51. -- I -

I 6.19.4 VERIFY a SELECT ERROR is received. -- I -

I 6.19.5 WITHDRAW Control Rod 30-51 to notch "02". --- I I 6.19.6 VERIFY the following:

0 ROD BLOCK alarm (H-7-a) is received -- I -

I 0 RWM indicated on Rod Block display -- I -

I 0 WITHDRAW BLOCK indicated on RWM C'

main display -- I -

I 6.19.7 SELECT Control Rod 30-03. --- f I 6.19.8 VERIFY the following are indicated on the RWM main display:

0 SELECT ERROR 0 INSERT BLOCK 0 WITHDRAW BLOCK 6.19.9 SELECT Control Rod 30-51. --- I f 6.19.I O INSERT Control Rod 30-51 to notch "00". --- I I 6.19.1I INITIAL for test complete. -- I -

I 76.20 COMMENCE recording log entries in the Reactor Operating Logs instead of the Reactor Shutdown Logs.

CONTINUE recording SRM levels per the Shutdown Log until no longer needed (IRM Range 8 or RUN mode). --- I f 22.0

An be&- Company I OYSTER CREEK GENERATING STATION PROCEDURE I Number 201 I

L l Title Revision No.

Plant Startup 39 Initial I Time I Date 6.35.3.1 OBTAIN temperature readings from Recorder IA02 every 30 minutes or as directed by the Unit Supervisor until heat-up is complete. -- I -

I 6.35.3.2 E either HEAD METAL-TO-HEAD FLANGE or VESSEL METAL-TO-VESSEL FLANGE AT approaches 180 F,O THEN immediately ADJUST heat-up rate to ensure the maximum AT limit of 200°F is not exceeded. -I I 6.36 RECORD in the Operations Control Room Log when i reactor coolant temperature reaches 200°F. --- I I

-. 6.37 E the SRMs are not fully withdrawn by the time all IRM RANGE SWITCHES are selected to Range 8, THEN fullv WITHDRAW the SRMs in accordance with Procedure 401.2.

6.38 Prior to exceeding a reactor coolant temperature of 284°F (approximately 38 psig), DIRECT the Chemistry Department to perform the following:

1. OBTAIN a sample via the Chemette Method to verify that the dissolved oxygen concentration in the reactor coolant is less than or equal to 300 ppb. --- I I

2. OBTAIN a reactor coolant sample to be analyzed for insoluble iron concentration.

31.O

her-," An I x e b Company I OYSTER CREEK GENERATING STATION PROCEDURE I Number 201 I

x u ' Title Revision No.

Plant Startut, 39 Initial I Time I Date 6.31 CAUTION Switching any IRM RANGE SWITCH upscale too early or too far will result in a downscale alarm and a rod block.

Switching upscale too late or inadvertently switching downscale will result in an IRM Hi-Hi Scram Trip.

WHEN IRMs come on scale, THEN PERFORM the following:

---3 6.31. I OPERATE the IRM RANGE SWITCHES in accordance with Procedure 402.2, IRM Operation During Startup, to maintain from approximately 25 percent - 75 percent (0 - 125 scale). --- I I 6.31.2 WHEN at least three IRMs in each Reactor Protection System are reading approximately 50 percent of scale on Range 1, THEN WITHDRAW the SRM detectors in accordance with Procedure 401.2, Nuclear Instrumentation SRM Channels Operation During Startup, maintaining the SRM count rate between I O 3 and io5CPS. -- I -

1 6.32 As each IRM indicates high in Range 6 (50-75% on 0-125% scale), PERFORM the following:

6.32.1 MONITOR and MAINTAIN Reactor power high in IRM Range 6 (approximately 50 - 75% on 0-125% scale). -I-I-6.32.2 STOP any further control rod withdrawal and LEVEL power. --- I I 29.0

Group Heading CONTROL RODSlDRlVES ROD CNTRL H-7-a ROD BLOCK

- __p_ -

SETPOINTS: ACTUATING DEVICES:

These trips are inputs to Rod Block: Relays:

RWM: Rod not withdrawn or inserted in 4K12 accordance with programmed pre- 21K20 condition. 21K21 21K22 APRM hop Recirc flow monitoring Iifference OR inoperative or flow comparator )etween Flow-ias: trip. :hannels

.IO% (16000 Ipm)

)rawer Mode

witch not in iperate.

nodule inplugged.

Recirc Flow Recirc Flow Equal to or 20% or FY-622-0042A Relay C)

Upscale Rod greater than 120% Rated Flow. 9.2 x io4 FY-622-0042B Relay C)

Block: ;PM IRM hop: Intermediate Range Monitor module inoperative and mode switch in STARTUP or REFUEL.

SRM hop: Source Range Monitor module inoperative and mode switch in Reference Drawings:

STARTUP or REFUEL (below IRM Range 8). GE 729E838 GU 3E-611-17-010

[Continued on Page 13 of 14)

Subject Procedure No. 1 Page 12 of 14 NSSS RAP-H7a H-7-a Alarm Response Procedures Revision No: 2 I

NRC Exam 2006-1 Senior Reactor Operator Key

20. The reactor is operating at rated power when the SV/EMRV OPEN

, annunciator aoes into alarm. Related indications are as follows:

0 Generator MW is slightly lower than at shift turnover 0 Drywell pressure is 1.2 psig and steady, which is the same as at shift turnover 0 Drywell temperature is 132 O F and steady, which is 2 O F higher than at shift turnover 0 Torus water temperature is 78 O F and steady, which is the same as at shift turnover The Acoustic Monitor for Safety Valve NR-28J is in the red Valve Open Region Tailpipe temperature for NR-28J is 245 O F ; all others are reading approximately 130 O F This indicates (1) . The correct action to take for this is to

-(2)-.

a. (1) a Safety Valve is open (2) enter ABN-1, Reactor Scram

b. (1) a Safety Valve is open (2) enter ABN-40, Stuck Open EMRV

c. (1) a Safety Valve is leaking (2) commence an immediate plant shutdown

d. (1) a Safety Valve is leaking (2) write an IR for Engineering to evaluate Answer: d Handouts: None Justification: A and B are incorrect - safety valve NR-28J is leaking. If it were open, tailpipe temperature would be higher than 275 O F and drywell pressure would be rising. Entering ABN-1, Reactor Scram, would be the correct action to take if this were the case; ABN-40, Stuck Open EMRV, does not contain any guidance for an open safety valve.

C is incorrect - safety valve NR-28J is leaking, but not enough to warrant an immediate plant shutdown.

D is correct - based on the given conditions, this is the appropriate action to take for the leaking safety valve.

NRC SRO Exam 2006-1 Key Page 36 of 46

NRC Exam 2006-1 Senior Reactor Operator Key 239002 A2.02 Ability to (a) predict the impacts of the following on the RELIEFBAFETY v

VALVES; and (b) based on those predictions, use procedures to correct, control,

. or mitigate the consequences of those abnormal conditions or operations: Leaky SRV (CFR: 43.5)

OC Learning Objective: 2621.828.0.0005, Obiective K.2:

Describe and interpret procedure sections and steps for plant emergency or off-normal conditions that involve this system including personnel allocation and equipment operation IAW applicable ABN, SDRP, EOP & EOP support procedures and EPIPs.

Cognitive Level: Comprehension or Analysis Question Type: Modified Bank

References:

RAP-BQg,ABN-40

\_-

-e-NRC SRO Exam 2006-1 Key Page 37 of 46

ADS SVlEMRV SVIEMRV NOT CLOSED

ONFIRMATORY ACTIONS:

NOTE Confirmation that a safety valve has lifted may be a rise in drywell pressure or rise in the thermocouple temperature located in the discharge of the suspect valve(s).

Indications of an open EMRV are rising Torus temperature, changing reactor pressure, and a rise in tailpipe temperature.

1 CHECK Reactor pressure.

(Panels 4F, 5F/6F, and IF/2F)

[ I 1 CHECK for auto-depressurization.

[ I I DETERMINE if a safety valve and/or relief valve has opened using the meters or Panel 1F/2F for indication in the valve Open position of the meter.

[ I AUTOMATIC ACTIONS:

4ONE Subject Procedure No.

Page 1 of 3 NSSS RAP-B4g B-4-g Alarm Response Procedures Revision No: 0 I I

NRC Exam 2006-1 Senior Reactor Operator Key

21. The reactor was operating at rated power when a loss of all off-site power occurred. The following conditions currently exist:

Lj All control rods are inserted to or beyond position 04 RPV water level is 105 inches and slowly lowering Reactor pressure is being controlled at 900-1000 psig Power was restored to Bus C two minutes ago Emergency Diesel Generator #2 failed to start 0 It is necessary to maximize CRD flow to restore and maintain RPV water level How can this be accomplished given the current plant conditions?

a. Control CRD flow using the in-service Flow Control Valve NC-30, IAW Support Procedure 3

b. Close charging header supply V-15-52, lineup and throttle CRD bypass flow at less than or equal to 150 gpm IAW Support Procedure 3

c. Cross-tie USS 1A2 to 1B2 and start a second CRD pump IAW ABN-36, Loss of Off-Site Power. Then control CRD flow using the in-service Flow Control Valve NC-30 IAW Support Procedure 3

d. Cross-tie USS 1A2 to 182 and start a second CRD pump IAW ABN-36, Loss of Off-Site Power. Then close charging header supply V-15-52, lineup and throttle CRD bypass flow as necessary to restore RPV water level IAW Support Procedure 3 Answer: b Handouts: None Justification: A is incorrect - the scram is not reset (since RPV level is 105 inches). Support Procedure 3 directs controlling CRD flow using the in-service Flow Control Valve NC-30, only if the scram is reset.

8 is correct - in cases where the scram cannot be reset, Support Procedure 3 directs closing V-15-52, then opening V-15-237 (CRD bypass isolation) and throttling V-15-20 (CRD bypass) so as not to exceed 150 gpm (for one or two pump operation). A CAUTION in SP 3 states Operating one CRD pump at greater than 150 gpm may result in a pump trip.

C and D are incorrect - USS 1A2 and 182 cannot be cross-tied when reactor temperature is above 212 OF, EXCEPT during station blackout conditions, as directed by ABN-37, Station Blackout.

NRC SRO Exam 2006-1 Key Page 38 of 46

NRC Exam 2006-1 Senior Reactor Operator Key 201001 A2.03

. I L--'

Ability to (a) predict the impacts of the following on the CONTROL ROD DRIVE HYDRAULIC SYSTEM; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those abnormal conditions or operations: Power supply failures (CFR: 43.5)

OC Learning Objective: 2621.828.0.001 1, Obiective 16:

Describe and interpret procedure sections and steps for plant emergency or off-normal conditions that involve this system including personnel allocation and equipment operation IAW applicable ABN, EOP & EOP support procedures and EPIPs.

Cognitive Level: Comprehension or Analysis Question Type: New

References:

ABN-36, Support Procedure 3 NRC SRO Exam 2006-1 Key Page39of 46

Procedure EMG-3200.01A Support Proc-3 Rev. 12 Attachment D 1 of 2 Page -

SUPPORT PROCEDURE 3 CRD SYSTEM OPERATION 1.0 E Directed to maintain RPV level with the CRD System by the Emergency Operating Procedures, 2.0 PREPARATION None 3.0 PROCEDURE NOTE There are three methods of injection using the CRD system:

1. Scram reset and controlling with the CRD Flow Control Valve (NC30).

2. Post scram injection (with the scram not reset) through the CRDs.

3. Post scram injection using bypass flow and controlling with t h e CRD Bypass Valve V-15-30.

.\--- 3.1 Confirm running all available CRD Pumps (Panel 4 F ) .

3.2 CAUTION Operating one CRD pump at greater than 150 g p m may result in a pump trip.

IF the scram has been reset, CRD bypass flow is not required (based on flow rate required),

THEN control CRD flow using the in-service Flow Control Valve NC-30.

OVER

( 3 2 0 0 0 1A/S6 ) E4-1

Procedure EMG-3200.01A Support Proc-3 Rev. 12 Attachment D 2

2 of -

Page -

7 3.3 CRD bypass flow is desired for RPV water level control, THEN complete the following, 1.Confirm the scram reset.

2.E the scram cannot be reset, THEN close CRD Charging Header Supply Valve V-15-52 (RB 23 SE).

3. Open CRD Bypass Isolation Valve, V-15-237 (RB 23 SE)

4. Monitor flow on Flow Gage FI-225-2 (RB 23 SE),

AND throttle open CRD Bypass Valve, V-15-30 (RB 23 SE), so as not to exceed 150 g p m flow for one or two pump operation.

3.4 2 RPV water level cannot be maintained below 160 in.,

THEN 1. Throttle closed CRD Bypass Valve, V-15-30 (RB 23 SE), if

-.---- open

2. Throttle closed CRD Flow Control Valve NC-30 3.5 E RPV water level reaches 170 in.,

THEN trip the operating CRD pumps.

1

( 3 2 0 0 0 1A/S6 ) E4-2

NRC Exam 2006-1 Senior Reactor Operator Key

22. Given the following:

0 An ATWS is in progress with the MSlVs closed 0 The conditions required by RPV Control -With ATWS for re-opening the MSlVs have been met 0 Differential pressure across the MSlVs is 280 psid Which one of the following describes the operating restrictions for opening the MSlVs under these conditions?

Shift Manager approval -(I)- required. Damage to downstream piping

-(2)- occur.

a. (1) IS (2) MAY

b. (1) IS NOT (2) MAY

c. (1) IS (2) WILL

d. (1) IS NOT (2) WILL Answer: b Handouts: None Justification: A is incorrect - SM approval is NOT required.

B is correct - Procedure 301.1 specifies the following restrictions for opening the MSIVs:

d/p I100 psid - no damage to piping; no approvals required 100 e d/p I160 psid - approaching limit where damage may occur; SM approval required 0 d/p 2 160 psid - repeated opening may damage piping; open IAW EOP's.

d/p 2 360 psig - single opening will damage piping; open IAW EOP's.

0 C is incorrect - SM approval is not required; damage to downstream piping MAY occur.

D is incorrect - damage to downstream piping MAY occur 239001 G2.1.32 Main and Reheat Steam System / Conduct of Operations: Ability

-- to explain and apply system limits and precautions. (CFR: 43.5)

NRC SRO Exam 2006-1 Key Page 40 of 46

NRC Exam 2006-1 Senior Reactor Operator Key L.-='

OC Learning Objective: 2621.828.0.0026, Obiective S:

Identify and interpret normal, abnormal, and emergency operating procedures for the various steam systems and explain the reasons for the applicable precautions and limitations.

Cognitive Level: Memory of Fundamental Question Type: New

References:

301.1, EMG-3200.01B Y

i NRC SRO Exam 2006-1 Key Page 41 of 46

hermu Ar txcion Company 1 OYSTER CREEK GENERATING STATION PROCEDURE Number 301.I

-4 Title Revision No.

Main Steam Supply System (Inside Drywell) 19 0 d p 5 100 psid No damage to piping.

Open as necessaryho approvals required.

0 100 psid <dp<l60 psid Approaching limit where damage may occur.

Open with Shift Manager (SM) approval 0 d p z 160 psid Repeated opening may damage piping.

Open IAW Emergency Operating Procedures (EOP's) 0 dp> 360 psid Single opening will damage piping.

Open IAW EOP's.

6.2.2 Prior to opening the outboard Main Steam Isolation Valves NS04A and NS04B (V-I-9 and V-I -10)' or the isolation bypass valve (V-1-1I O ) , the main steam header sections upstream of NS04A and NS04B shall be drained of all water in order to prevent water hammer in the steam lines.

6.2.3 While in startup and run modes and reactor pressure is greater than 600 psig, a Reactor Scram will occur with 2 10 percent Main Steam Isolation Valve closure from the full open position.

15.0

NRC Exam 2006-1 Senior Reactor Operator Key

23. A small-break LOCA occurred while at rated power. Current plant

\-.

conditions are as follows:

Reactor water level is 92 inches 0 Reactor pressure is 500 psig Drywell pressure is 13 psig 0 Drywell bulk temperature is 450 OF TR-IA55 on Panel 8R readings are as follows:

o Point 40 = 452 O F o Point 41 = 453 OF o Point 42 = 451 OF o Point 43 = 448 OF o Point 44 = 446 OF Which of the following RPV water level instruments can be used to determine RPV water level?

a. WR GEMAC ONLY

b. YARWAY A & 8 ONLY C. NR GEMAC A & B ONLY

d. NR GEMAC A & B YARWAY A & B ONLY Answer: b

,.v-Handouts: EMG-3200.02, Support Procedure 28 Justification: A is incorrect - at 451 O F and 92 inches, the WR GEMAC instrument is in the UNSAFE region of the graph in Support Procedure 28.

B is correct - at 448 OF (446 O F ) and 92 inches, both Yarway instruments are in the SAFE region of the graph in Support Procedure 28. None of the other instruments are in the SAFE region of their respective graph.

C is incorrect - at 452 OF (453 OF) and 92 inches, both NR instruments are in the UNSAFE region of the graph in Support Procedure 28.

D is incorrect - both NR instruments are in the UNSAFE region. Only the Yarway instruments are in the SAFE region.

G2.1.25 Conduct of Operations: Ability to obtain and interpret station reference materials such as graphs / monographs / and tables which contain performance data. (CFR: 43.5)

NRC SRO Exam 2006-1 Key Page 42 of 46

NRC Exam 2006-1 Senior Reactor Operator Key OC Learning Objective: 2621.828.0.0032, Obiective T:

Given a set of plant conditions, interpret Control Room and/or local Primary W'

Containment System indications and evaluate them in terms of limits and trends using available data.

Cognitive Level: Comprehensive or Analysis Question Type: New

References:

EMG-3200.02, Support procedure 28 NRC SRO Exam 2006-1 Key Page 43 of 46

Procedure EMG-3200.02 Support Proc. 28 Rev. 17 Attachment F Page 1 of 4 SUPPORT PROCEDURE 28 LEVEL INSTRUMENTATION AVAILABILITY 1.0 PREREQUISITES The evaluation of RPV Water Level Instruments has been directed by the Emergency Operating Procedures.

2.0 PREPARATION None 3.0 PROCEDURE An RPV water level instrument may be used to determine RPV water level only when all the following conditions are satisfied for that instrument 3.1 Record the temperatures of the following instrument reference leg vertical runs as read on recorder TR-IA55 on Panel 8R or the Plant Process Computer.

Level Instrument Temp Instrument No. Recorder Point Temperature NR GEMAC A (LT-1D13A) TE-130-450 40

-- NR GEMAC B (LT-1D13B) TE-130-451 41 WR GEMAC (LT-1A12) TE-130-452 42 YARWAY A (LT-RE05/19A) TE-130-453 43 YARWAY B (LT-RE05/19B) TE-130-454 44 OVER (320002/8) E6-1

Procedure EMG-3200.02 Support Proc. 28 Rev. 17 Attachment F Page 2 of 4 3.2 If reference leg temperatures are in the UNSAFE REGION of the curve, that instrument may not be used until an engineering evaluation of reference leg conditions has been performed.

Verify that the instrument reference leg temperatures are in the SAFE REGION of the RPV Saturation Temperature Curve.

RPV Saturabon Temperature 0 200 400 600 800 f000 RPV PRESSURE (poigJ (320002/8) E6-2

Procedure EMG-3200.02 Support Proc. 28 Rev. 17 Attachment F Page 3 of 4 3.3 -

NOTE Instruments may be used only when in the Safe Region o f the curve.

If the instrument goes in the Unsafe Region of the curve, it may not be used again until it returns to the Safe Region, at which time it is valid for level indication response.

its respective curve.

CEMAC NARROW RANGE 90 - I80 in.

106 104 102 100 98 96 94 92

.-t:

I 90 88 200 300 400 500 Reference Leg Temperature (F)

OVER (320002/8) E6-3

Procedure EMG-3200.02 Support Proc. 28 Rev. 17 Attachment F Page 2 of 5 Yarway 85 - 185 111.

105 - I - -

T---

I 1 1 i 554 I 200 300 400 500 Reference Leg Temperature (F)

GEMAC Wide Range

-1 W

170 1 Safe Region I

a 1 c1 ,50 (vu W $130 E .E E 110 E!- 90 5

E 70 50 50 150 250 350 450 550 Reference Leg Temperature (F)

(320002/8) E6-4

NRC Exam 2006-1 Senior Reactor Operator Key

24. Which of the following is NOT considered a refueling error, as specified in Procedure 205.0, Reactor Refueling?

L./

When loading fuel into the RPV, a (1) fuel assembly, discovered upon unlatching and lifting the grapple, and (2) nortWsouth movement of the bridge.

a. (1) mislocated (2) after

b. (1) mislocated (2) prior to

c. (1) misoriented (2) after

d. (1) misoriented (2) prior to Answer: d Handouts: None Justification: A and B are incorrect - mislocated fuel assembly is considered

-./

~,

a refueling error.

C is incorrect - a misoriented fuel assembly that is not discovered until after northkouth movement of the bridge is considered a refueling error.

D is correct - as stated in 205.0, if a misoriented fuel assembly is discovered upon unlatching and lifting the grapple, and prior to north/south movement of the bridge, then reorient the fuel assembly per the Fuel Move Sheet immediately without declaring a refueling error.

G2.2.31 Equipment Control: Knowledge of procedures and limitations involved in initial core loading. (CFR: 43.7)

OC Learning Objective: 2621.81 2.0.0003, Obiective K:

Describe, in general, refueling and fuel handling procedures to include precautions and limitations per Procedure 205 series.

Cognitive Level: Memory of Fundamental Question Type: New

References:

205.0

~-.,

NRC SRO Exam 2006-1 Key Page 44 of 46

AmerGen OYSTER CREEK GENERATING Number An t m o n Company STATION PROCEDURE 205.0 L./- Title Revision No.

Reactor Refueling 65 3.5 NOTE A refueling error is defined as any error which results in the actual mislocation

-or misorientation of a fuel assembly in the RPV. Correct orientation of a fuel cell gKJ a peripheral bundle is illustrated on Attachment 205.0-6.

-IF refuel error is discovered, THEN CEASE all fuel movement into out of the reactor vessel and CONTACT Shift Manager and Reactor Engineering.

3.6 -IF a misoriented fuel assembly is discovered upon unlatching and lifting the grapple, and prior to northkouth movement of the bridge, THEN REORIENT the fuel assembly per the Fuel Move Sheet immediately without declaring a refueling error.

3.7 CAUTION The movement of fuel g controls in the core (core alterations) is not allowed unless directly supervised by an SRO Licensed Operator Fuel Handling Director (FHD) assigned to refueling gKJ authorized by a Fuel Move Sheet g a Cell Component Move Sheet.

VERIFY final core configuration in accordance with Procedure NF-AA-330-1001.

3.8 -

IF Source Range counts increase by a factor of eight during fuel assembly

/ blade guide moves, THEN REFER to Procedure ABN-7 4.0 FULL CORE OFFLOAD 4.1 Prerequisites 4.1 .I The reactor mode switch is locked in the REFUEL position 6.0

NRC Exam 2006-1 Senior Reactor Operator Key

25. Given the following:

e The plant is operating at 25% power e A fire is reported and confirmed in the Reactor Water Cleanup Cage area e Several minutes later, the following parameters are noted:

e RPV pressure has lowered e MWe has lowered e Torus temperature is rising Which of the following is the correct action?

a. Initiate torus cooling while maintaining reactor power constant

b. Initiate torus cooling while reducing recirc. flow to minimum

c. Scram the reactor and execute ABN-1, Reactor Scram

d. Trip the turbine and execute ABN-10, Turbine Generator Trip Answer: c Handouts: ABN-29 (pages 22-44) Note: the main body of ABN-29 (pages 1-21) can be included with the RB 51 elevation section (pages 27-34) ONLY IF it is not available during the RO portion of the exam.

,d The information contained on page 17 provides the answer to RO question

48.

Justification: The indications provided show that an EMRV has opened (see ABN-40) during the fire event on RB 51 (the cleanup cage is located on RB 51).

IAW ABN-29, if there is a fire on RB 51 and spurious operation of an EMRV, then the action is to scram the reactor and to close the open EMRV. Answer c is correct.

Answer a and b are incorrect - it does not direct a scram, even though torus cooling may appropriate soon.

Answer d is incorrect - even though there is something that is reducing turbine generator load, the problem is not with the turbine generator. It also does not direct a reactor scram. Even if the turbine was tripped, reactor power is low enough that a scram would not be required because of the turbine trip.

G2.4.27 Emergency Procedures/Plan: Knowledge of fire in the plant procedure.

(CFR: 43.5)

NRC SRO Exam 2006-1 Key Page 45 of 46

NRC Exam 2006-1 Senior Reactor Operator Key OC Learning Objective: 2621.828.0.001 9, Obiective E:

Describe and interpret procedure sections and steps for plant emergency or off-

-u normal conditions that involve this system including personnel allocation and equipment operation in accordance with applicable ABN, SDRP, EOP and EOP support procedures, and EPIPs.

Cognitive Level: Comprehensive or Analysis Question Type: Bank

References:

ABN-29, ABN-40 NRC SRO Exam 2006-1 Key Page 46 of 46

OYSTER CREEK GENERATING Number AmerGenv An EX&Xl h l p d n y STATION PROCEDURE ABN-40 I

Title Revision No.

STUCK OPEN EMRV 2 STUCK OPEN EMRV 1.o APPLICABILITY This procedure provides direction for any EMRV that remains open when not required.

2.0 INDICATIONS 2.1 Annunciators Engraving Location Setpoint EMRV OPEN 1 1

B-3-g valve open (pilot valve limit switch)

SV/EMRV NOT CLOSED 6-4-g VMS alarm (acoustic monitor) a 2.2 Plant parameters Parameter I Location 1 Chanqe EMRV discharge Panel 1F/2F rises above 2OOOF temperature Acoustic monitor Panel 1F/2F indicates EMRV Torus water temperature 1 Panel 1F/2F 1 rising Red VALVE OPEN light 1 Panel 1F/2F 1 illuminated Green VALVE CLOSED Panel IF12F extinguished light 2.3 Other indications 1 Red VALVE OPEN indication light is illuminated if the solenoid is energized

2. Acoustic monitoring system indications 3.0

AmerGemAI? Ex&n Company OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-40 I

'.dTitle Revision No.

STUCK OPEN EMRV 2

3. EMRV discharge temperature indications

4. Lowering RPV pressure

5. Drop in generator load (MWe)

6. Rising Torus temperature

7. Indicated steam flow less than indicated feed flow

8. EMRV tailpipe temperature (RB 23' elevation on recorder) 3.0 OPERATOR ACTIONS If while executing this procedure, an entry condition for any EOP occurs, then EXECUTE this procedure concurrently with the appropriate EOP.

3.1 VERIFY the EMRV condition by observing the following:

Red VALVE OPEN indication light is illuminated if the solenoid is energized [ I

. Acoustic monitoring system indications [ I

. EMRV discharge temperature indications [ I

. Lowering RPV pressure [ I

. Drop in generator load (MWe) [ I

. Rising Torus temperature [ I

. Indicated steam flow less than indicated feed flow [ I

. EMRV tailpipe temperature (RB 23' elevation on recorder) [ ]

4.0

Attachment ABN-29-1 Procedure ABN-29 Equipment Availability Matrix for Fires Rev. 9 R.B. 119 ELEV. None NA NA NA (RB-FZ-I A)

References:

GU 3E-911-41-041 (Hot Shutdown Path #3 for RB-FZ-1A)

GU 3E-911-41-042 (Cold Shutdown Path # I for RB-FZ-1A)

Manual Action Required:

(1) -IF Instrument Air is lost, THEN V-2-90 in the Condensate Transfer Building should be closed promptly to prevent the CST from draining to the hotwell. Approximately 10.1 ft in the CST may be required for reactor vessel makeup during cooldown to cold shutdown. Makeup to the CST as necessary from Demineralized Water (procedure 320.1), High Purity (procedure 351 .Z), or the Fire Protection system (as last resort, close V-9-11, open V-9-9 and open V-11-247).

(

Attachment ABN-29-1 Procedure ABN-29 Equipment Availability Matrix for Fires Rev. 9

~~ ~

EQUIPMENT ALTERNATE REPAIR FIRE ZONE LOCATION OF ALTERNATE APPLICABLE POTENTIALLY AFFECTED CONTROLllNDlCATlON DOCUMENT CONTROUINDICATION PROCEDURE(S)

REFERENCE R.B. 95' ELEV. "A" ISOLATION CONDENSER (RB-FZ-1 B) Stm Vent Vlv (V-14-5) Local Manual RB 95' EL, East 307 NA Control Ckt Stm Vent Vlv (V-14-20) Local Manual RB 95' EL, East 307 NA Control CM Shell Makeup Valve Local Manual REI 95' EL, East 307 NA Power and Control Ckt (V-I 1-36)

"B" ISOLATION CONDENSER DC Steam Inlet Local Manual RB 75' EL, East 307 NA Vlv Ind Ckt (V-14-33)

Stm Vent Vlv Control Local Manual RB 95' EL, East 307 NA Ckt (V-I 4-1)

Stm Vent Vlv Control Local Manual RB 95' EL, East 307 NA Ckt (V-14-19)

Power and Control Ckt Local Manual RB 95' EL, East 307 NA Shell Makeup Valve (V-I 1-34)

References:

GU 3E-911-41-041 (Hot Shutdown Path #3 for RB-FZ-1 B)

GU 3E-91141-042 (Cold Shutdown Path # I for RB-FZ-1B)

Manual Action Required:

1) IF

- Instrument Air is lost, THEN V-2-90 in the Condensate Transfer Building should be closed promptly to prevent the CST from draining to the hotwell. Approximately 10.1 ft in the CST may be required for reactor vessel makeup during cooldown to cold shutdown. Makeup to the CST as necessary from Demineralized Water (procedure 320.1), High Purity (procedure 351.2), or the Fire Protection system (as last resort, close V-9-11, open V-9-9 and open V-I 1-247).

Attachment ABN-29-1 Procedure ABN-29 Equipment Availability Matrix for Fires Rev. 9 REPAIR EQUIPMENT ALTERNATE LOCATION OF ALTERNATE AP PLlCABLE FIRE ZONE DOCUMENT POTENTIALLY AFFECTED CONTROUINDICATION CONTROUINDICATION PROCEDURE(S)

REFERENCE R.B. 75' ELEV. CORE SPRAY SYS I1 (RB-FZ-1C) Parallel Vlvs. Power Local Manual RB 75' EL, South 308 NA and Control Ckts (V-20-21,41)

" A ISOLATION CONDENSER AC Stm Isolation Vlv Local Manual RB 75' EL, East 307 NA Power Ckt (V-14-30)

DC Strn Isolation Vlv Local Manual RB 75' EL, East 307 NA Pwr and Control Ckt (V-14-3 1)

DC Cond Return Valve Local Manual RB 75' EL, East 307 NA Pwr and Control Ckt (V-14-34) 10 P Steam Vent Vlv Control Local Manual RB 95' EL, East 307 NA 0 Ckt (V-I 4-5)

Steam Vent Vlv Control Local Manual RB 95' EL, East 307 NA Ckt (V-14-20)

Shell Makeup Vlv Power Local Manual RB 95' EL, East 307 NA and Control Ckt (V-I 1-36)

i Attachment ABN-29-1 Procedure ABN-29 Equipment Availability Matrix for Fires Rev. 9 REPAIR EQUIPMENT ALTERNATE LOCATION OF ALTERNATE APPLICABLE FIRE ZONE DOCUMENT POTENTIALLY AFFECTED CONTROUINDICATION CONTROUINDICATION PROCEDURE(S)

REFERENCE R.B. 75' ELEV. "B" ISOLATION CONDENSER (RB-FZ-1 C) AC Stm lsol Vlv Power Ckt 01-14-32) Local Manual RB 75' EL, East 307 NA (cont'd) DC Stm lsol Vlv Power, Ind and Control Ckt (V-14-33) Local Manual RB 75' EL, East 307 NA DC Cond Rtn Vlv Power, Ind and Control Ckt (V-14-35) Local Manual RB 75' EL, East 307 NA AC Cond Rtn Vlv Power, Ind and Control Ckt (V-14-37) None Drywell 307 NA Stm Vent Vlv lsol CM (V-14-1)

Stm Vent Vlv lsol Ckt (V-14-19) Local Manual RB 95' EL, East 307 NA Shell Makeup Vlv Power and Control CM (V-11-36) Local Manual RB 95' EL, East 307 NA REACTOR WATER CLEANUP Local Manual RB 75' EL, East 307 NA RWCU Inlet lsol Vlv Cont Ckt (V-16-1)

ELECTRICAL DISTR. SYS.

MCC DC-2 None Drywell 303 NA CONTAINMENT SYSTEM Torus Temperature Elements None NA 340.1 NA TI-664-438 TI-664-43A 1Fl2F NA NA

(:

Attachment ABN-29-1 Procedure ABN-29 Equipment Availability Matrix for Fires Rev. 9 R.B. 75' ELEV.

(RB-FZ-1 C)

(cont'd)

References:

GU 3E-91141-041 (Hot Shutdown Path #3 for RB-FZ-IC)

GU 3E-91141-042 (Cold Shutdown Path #I for RB-FZ-IC)

Manual Action Required:

1) -

IF Instrument Air is lost, THEN V-2-90 in the Condensate Transfer Building should be closed promptly to prevent the CST from draining to the hotwell. Approximately 10.1 ft in the CST may be required for reactor vessel makeup during cooldown to cold shutdown. Makeup to the CST as necessary from Demineralized Water (procedure 320.1), High Purity (procedure 351.2), or the Fire Protection system (as last resort, close V-9-11, open V-9-9 and open V-1 1-247).

2) Cable failures may cause DC-1 to trip.

IF

- DC-1 trips THEN Either manually control the SDC valves V-I 7-1, 2, 3, 55, 56 & 57 OR Open all load breakers on MCC DC-1 and re-close DC-B breaker #6 and then re-close MCC DC-1 breakers for SDC valves V-17-1, 2, 3, 55,56

& 57. Note that the remaining breakers on MCC DC-1 are not needed and should remain open to isolate the cable failures.

Attachment ABN-29-1 Procedure ABN-29 Equipment Availability Matrix for Fires Rev. 9 REPAIR EQUIPMENT ALTERNATE LOCATION OF ALTERNATE APPLICABLE DOCUMENT FIRE ZONE POTENTIALLY AFFECTED CONTROUINDICATION CONTROUINDICATION PROCEDURE@) REFERENCE R.B. 51' ELEV. (RB-FZ-1 D)

References:

GU 3E-91141-044 Hot Shutdown Path #5 - "B" Isolation Condenser, "B" CRD Pump, Condensate Transfer Pump, Fuel Zone Level Ind. Ll-622-1001 &

1002, Rx. Pressure Ind. PI-622-999 & 1000, Offsite Pwr available; ifspuriously opened EMRV, then Core Spray pumps NZOID & NZ03D, Containment Spray Pump 1 4 , ESW pump 1-4, Torus Level Indicator LI-IPIOB

& Containment Spray Suction Hdr Temperature TR-IP001.

GU 3E-91141-043 Cold Shutdown Path #3 - 2 EMRV's (with repairs), Core Spray Pumps, Containment Spray Pump, ESW pump, Fuel Zone Level Ind.

L1-622-1001 8 1002, Rx. Pressure Ind. PI-622-999 & 1000, Rx Wide Range Lvl Ind (with repairs), Torus Water Temperature Ind (with repairs) and Torus Level Indicator LI-IP1OB NOTE: This 'Cold Shutdown' Path utilizes 'Alternate Decay Heat Removal' per procedure 2000-OPS-3024.27, Section 4.4 to approach the Cold Shutdown condition (Core Spray, Containment Spray in Torus Cooling, and EMRV's). It may be necessary to perform repairs on affected equipment as identified in the list below.

Prompt Manual Actions:

NOTE: These steps can be performed concurrently and are listed in the order of priority but are dependent on actual plant symptoms.

1) NOTE: During a fire condition on the 51' elevation of the Reactor Building (RB-FZ-1 D), the possibility exists that hot shorts will develop in the EMRV cabling such that 125 VDC from an external source will be supplied to an EMRV, causing it to fail open. This spuriously opened EMRV may not be reclosable by any means. Therefore, the following actions are required:

CAUTION: The following action is required to preclude or terminate a spuriously opened EMRV. This action will disable the ADS, High Pressure and manual controls associated with the EMRV's. If the EOP's require the use of the EMRV's the disable switches can be returned to the normal position.

IF One or more EMRV's exhibit abnormal or spurious operation or there are insufficient indications available to determine the status of an EMRV.

THEN Ensure the reactor is scrammed in accordance with ABN-1 "Reactor Scram".

AND Place the disable switch on the rear of panel 1F/2F to the "DISABLE" position for those EMRV's affected. NOTE: "EMRV DISABLED" annunciator on Panel 1F/2F (B-6-g) will alarm.

Attachment ABN-29-1 Procedure ABN-29 Equipment Availability Matrix for Fires Rev. 9 REPAIR EQUIPMENT ALTERNATE LOCATION OF ALTERNATE APPLICABLE FIRE ZONE DOCUMENT POTENTIALLY AFFECTED CONTROUINDICATION CONTROUINDICATION REFERENCE

2) E

! An EMRV is failed open.

THEN Follow the Emergency Operating Procedures.

3) CAUTION 1) The Core Spray parallel injection valves may not automatically open when the valve permissive is satisfied and control from the control room may also be lost. If the valves cannot be controlled automaticallylremotely,then immediately dispatch an operator to manually open the valve to assure adequate core cooling. Note that there is 66 minutes to perform this manual action from the start of the event but the valve permissive may not be satisfied for approximately 33 minutes leaving only 33 minutes to perform this manual action.

2) SCBA may be required to perform the manual opening of V-20-21 due to the possibility of smoke rising through the open equipment hatch from Rx. Bldg. 51' elevation.

IF:

- V-20-21 can not be operated from the control room N

ITHEN Dispatch an operator with a radio to MCC 1A21 located in the 480V Room to place the breaker for V-20-21 to the "OFF" position. The operator should P then proceed directly to 75' elevation and standby to manually open V-20-21 upon direction from the Control Room.

0 NOTE 1: Torus cooling must be initiated within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to prevent losing NPSH requirements for the Core Spray System

4) NOTE: During a fire condition on the 51' elevation (RB-FZ-I D), the possibility exists that hot shorts will occur in the high flow logic circuitry of the "B" Isolation Condenser. This could cause a spurious isolation of valves V-14-32, V-14-33, V-14-35 and V-14-37.

-IF no other decay heat removal system is available, THEN override the isolation signal by placing the individual valve control switches to the position desired.

5) E

! Instrument Air is lost.

THEN V-2-90 in the Condensate Transfer Building should be closed promptly to prevent the CST from draining to the hotwell. Approximately 17.4 ft in the CST may be required for isolation condenser shell makeup during cooldown to cold shutdown. Makeup to the CST as necessary from Demineralized Water (procedure 320.1), High Purity (procedure 351.2), or the Fire Protection system (as last resort, close V-9-11, open V-9-9 and open V-I 1-247).

(

Attachment ABN-29-1 Procedure ABN-29 Equipment Availability Matrix for Fires Rev. 9 r---

FIRE ZONE EQUIPMENT POTENTIALLY AFFECTED ALTERNATE CONTROUlNDlCATlON LOCATION OF ALTERNATE CONTROUlNDlCATlON APPLICABLE PROCEDURE(S)

REPAIR DOCUMENT REFERENCE R.B. 51' ELEV. CORE SPRAY SYSTEM I (RB-FZ-1 D) Parallel Vlvs Power Local Manual RB 51' EL, NW 308 NA (cont'd) and Control Ckts (V-20-15,40)

Booster Pump Disch. Local Gage RB 51' EL, NW 308 NA Press. Ind (PT-RV41A) (PI-40C) and diff press. sw.

(DPS-RV40A&C) None NA NA NA Core Spray Booster Pumps (NZ03A, C)

CORE SPRAY SYSTEM I I Local Manual RB 75' EL, South 308 NA Parallel Vlvs Power and Control Ckts (V-20-21,41)

Pumps NZOI B & NZ03B NZOl D & NZ03D CR 308 NA N

co Containment Istr.

TE 40A TR lPOl Repair 2400-APR-0 Torus Temp Ind.

TI66443 A&B Suction Header Temp. for Panel I F Procedure 3228.02 Core & Cont. Spray, or perform repair procedure

(

Attachment ABN-29-1 Procedure ABN-29 Equipment AvaiI abiIity Matrix for Fires Rev. 9 LOCATION OF REPAIR EQUIPMENT ALTERNATE APPLICABLE FIRE ZONE ALTERNATE DOCUMENT POTENTIALLY AFFECTED CONTROUINDICATION PROCEDURE(S)

CONTROUINDICATION REFERENCE R.B. 51' ELEV. " A ISOLATION CONDENSER (RB-FZ-1 D) AC Stm lsol Vlv Power Ckt (V-1430) Local Manual RB 75' EL, East 307 NA (cont'd) DC Stm Is01Vlv Power and Control Ckt (V-I 4-3 1) Local Manual RB 75' EL, East 307 NA DC Cond Rtn Vlv Power and Control CM (V-14-34) Local Manual RB 75' EL, East 307 NA Shell Makeup Vlv Power and Control Ckt (V-I 1-36) Local Manual RB 95' EL, East 307 NA LT-IGOGA Ind. Circuit None NA 307 NA "B" Isolation Condenser Hi Flow Protection (IB05-B1 8, B2 and Override 1Fl2F 1811-81 8, 82) Isolation (Individual Valve 307 NA Signal Control Switch)

G, P ELECTROMATIC RELIEF VLVS 0 EMRV "A" Control CM. EMRV " A Disable Swt Rear 1F/2F 30 1 NA EMRV "B" Control Ckt. EMRV "B" Disable Swt Rear 1F12F 301 NA EMRV "C" Control Ckt. EMRV "C" Disable Swt Rear 1F/2F 301 NA EMRV "0" Control Ckt. EMRV "D" Disable Swt Rear 1Fl2F 30 1 NA Temporary Control and NA Repair Procedure 2400-APR-Indication for NR108D 341 1.01 2400-AP R-341 1.04

Attachment ABN-29-1 Procedure ABN-29 Equipment Availability Matrix for Fires Rev. 9 FIRE ZONE EQUIPMENT POTENTIALLY AFFECTED ALTERNATE CONTROUINDICATION I LOCATION OF ALTERNATE CONTROUINDICATION APPLICABLE PROCEDURE(S)

REPAIR DOCUMENT REFERENCE R.B. 51' ELEV. ELECTROMATIC RELIEF VLVS (RB-FZ-1 D) (cont'd)

(cont'd) EMRV " E Control Ckt. EMRV "E' Disable Swi Rear 1F12F 301 NA Temporary Control and NA Repair Procedure 2400-AP R-Indication for NRIOBE 341 1.01 2400-APR-3411.04 CONTAINMENT SYSTEM

?x Low-Low Wtr Lvl (REO2A) Inst. Circuit None NA NA NA Rx Low-Low Wtr Lvl (RE028) Inst.

Circuit None NA NA NA Rx Low-Low Wtr Lvl (REO2C) Inst.

Circuit None NA NA NA Rx Low-Low Wtr Lvl (RE02D) Inst.

Circuit None NA NA NA

(\

Attachment ABN-29-1 Procedure ABN-29 Equipment Availability Matrix for Fires Rev. 9 REPAIR EQUIPMENT ALTERNATE LOCATION OF ALTERNATE APPLICABLE FIRE ZONE DOCUMENT POTENTIALLY AFFECTED CONTROUlNDlCATlON CONTROUlNDlCATlON PROCEDURE(S)

REFERENCE R.B. 51' ELEV. SHUTDOWN COOLING SYSTEM (RB-FZ-1 D) "A" LOOPFlow (FI 17-1) None NA 305 NA (cont'd)

"6"LOOPFlow (FI 17-2) None NA 305 NA "C" LOOPFlow (FI 17-3) None NA 305 NA "A" FUEL ZONE LEVEL LI-IA94A "C" Fuel Zone Lvl. CR PNL 5FI6F 410 NA PI-622-849 (Ll-622-100 1) or (PI-622-999) RSP ("B" 480V 346 NA Swgr Rm)

"B" FUEL ZONE LEVEL LI-IA94B "D" Fuel Zone Lvl. CR PNL 5FI6F 410 NA Pl-622-850 (Ll-622-1002) or w RSP ("B" 480V 346 NA N, (PI-622-1 000) 0 Swgr Rrn)

RX LEVEUPRESSURE INSTR.

GEMAC Wide Range Level Install Local Gage RKOI (R.B. 75'EL, Repair Procedure 2400-APR-Ind. (LI-IA13) (Ll-626-1007) East) 3665.01 RBCCW SYSTEM Pump 1-1 None NA NA NA Pump 1-2 None NA NA NA SID Clg Hx Outlet Vlv Local Manual S/D Clg Room 305 NA Power and Control Ckt (V-5-106)

Attachment ABN-29-1 Procedure ABN-29 Equipment Availability Matrix for Fires Rev. 9 REPAIR EQUIPMENT ALTERNATE LOCATION OF ALTERNATE APPLICABLE FIRE ZONE DOCUMENT POTENTIALLY AFFECTED CONTROUINDICATION CONTROUINDICATION PROCEDURE(S)

REFERENCE R.B. 51' ELEV. CONT. SPRAY SYSTEM I (RB-FZ-1 D) Drywell Spray Isol. Local Manual R.B. 51' EL. East 310 NA (cont'd) Valve (V-21-11) Pwr.

and Control Ckt.

Cont Spray System Local Manual See Manual Actions Below NA NA DC Control Power CONT SPRAY SYSTEM I I Cont Spray System Local Manual See Manual Actions Below NA NA DC Control Power RX WTR CLEANUP SYSTEM Aux Pump Suction Is01 Local Manual R.B. 51' EL. South 303 NA Vlv. Pwr and Control 0

0 Ckt (V-I6-2) 0 Cleanup Inlet Is01 Local Manual R.B. 51' EL. South 303 NA Vlv. Pwr and Control Ckt (V-I 6-14)

High Press. Isol. High Press. lsol SW R.B. 75' EL. South 303 NA Switch (PS-215-1044) (PS-IJO4A)

(:;

Attachment ABN-29-1 Procedure ABN-29 Equipment Availability Matrix for Fires Rev. 9 REPAIR EQUIPMENT ALTERNATE LOCATION OF ALTERNATE APPLICABLE FIRE ZONE DOCUMENT POTENTIALLY AFFECTED CONTROUINDICATION CONTROUI N DI CATION REFERENCE R.B. 51' ELEV. (RB-FZ-1 D)

(cont'd)

Additional Manual Actions Required:

1. If an EMRV is stuck open, then Containment Spray System must be started within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to prevent loosing NPSH for the core spray and containment spray pumps:

a. Containment Spray System II Containment Spray Pump 1 4 and ESW Pump 1-4 are designated for use during hot shutdown with an EMRV stuck open.

System I may still be used if its components are operable and accessible. However, no emergency lighting is provided for System I .

b. Operation of the following valves can be performed locally for the Containment Spray System if necessary. However prior to manually operating the valve, open its supply breaker on MCC 1821B for System I I or on MCC 1A21 B for System I.

- D w e l l Spray Valve V-21-5 (SYSII) v-21-11 (Sys I)

Location: V-21-5 RB 23' East V-21-11 RB 51' East Required Position: Closed w - TORUS CLG Discharqe Valve V-21-13 (Sys II) v-21-17 (Sys I)

P Location: V-21-13 RB 23' South V-21-17 RB 23' North 0 Required Position: Open

c. Emergency lighting to operate the System I I TORUS CLG Discharge Valve, V-21-13, is located near the drywell wall across from the railroad airlock door. This assembly consists of a portable DC light attached to an emergency lighting battery by 40' of cable. If needed, this cable is unwound and the light is used to gain access to the valve and illuminate the valve for operation. Two operators will be required to operate this valve if emergency lighting is required.

2. It may be necessary to use the CRD bypass line due to the loss of instrument air by performing the following:

Open V-15-237 Throttle V-I 5-30 for desired flow on Fl-225-2 Close V-I 5-52

3. Recharge V-I 1-34 Accumulator per Procedure 307 as required (accumulator is sized for approximately 5 strokes).

("

Attachment ABN-29-1 Procedure ABN-29 Equipment Availability Matrix 13rFires Rev. 9 REPAIR EQUIPMENT ALTERNATE LOCATION OF ALTERNATE APPLICABLE DOCUMENT FIRE ZONE POTENTIALLY AFFECTED CONTROUINDICATION CONTROUINDICATION REFERENCE

References:

GU 3E-91141-040 Hot Shutdown Path #I -"B" Isolation Condenser, "8"CRD Pump, Condensate Transfer Pump, Fuel Zone Level Ind. LI-IA94B, Rx.

Pressure Ind. P1-622-850, Offsite Pwr available GU 3E-911-41-043 Cold Shutdown Path #3 - 2 EMRVs (with repairs), Core Spray Pumps, Containment Spray Pump (with repairs), ESW pump, Fuel Zone Level Ind. LI-IA94B, Rx. Pressure Ind. PI-622-850, Rx Wide Range Lvl Ind LI-IA13, Torus Water Temperature Ind (with repairs) and Torus Level Indicator LI-IPIOB NOTE: This 'Cold Shutdown' Path utilizes 'Alternate Decay Heat Removal' per procedure 2000-OPS-3024.27, Section 4.4 to approach the Cold Shutdown condition (Core Spray, Containment Spray in Torus Cooling, and EMRV's). It may be necessary to perform repairs on affected equipment as identified in the list below.

Prompt Manual Actions:

NOTE: These steps can be performed concurrently and are listed in the order of priority but are dependent on actual plant symptoms.

1) During a fire condition on the 23' elevation of the Reactor Building (RB-FZ-1 E), the possibility exists that hot shorts will develop in the EMRV cabling such that 125 VDC from an external source will be supplied to an EMRV, causing it to fail open. This spuriously opened EMRV will be reclosable using the normal EMRV control switch on 1F12F.

CAUTION: The following action is required to preclude or terminate a spuriously opened EMRV. This action will disable the ADS, High Pressure and manual controls associated with the EMRV's. If the EOP's require the use of the EMRV's, the disable switches can be returned to the normal position.

IF

- One or more EMRV's exhibit abnormal or spurious operation, OR There are insufficient indications available to determine the status of an EMRV.

THEN Ensure the reactor is scrammed in accordance with ABN-1 "Reactor Scram",

AND Place the disable switch on the rear of panel 1F/2F to the "DISABLE position for those EMRV's affected.

Attachment ABN-29-1 Procedure ABN-29 Equipment Availability Matrix for Fires Rev. 9 FIRE ZONE R.B. 23 ELEV.- RB-FZ-1E (Contd)

Prompt Manual Actions Icontdl:

2) NOTE: The Reactor Recirculation pump control circuits are located in this fire zone and they have to be tripped to utilize the Fuel Zone Level Indicators.

IF The Reactor Recirculation Pumps wont trip from the control room, THEN trip and locked out (69 switch) locally at their respective switchgear provided that these pumps are not required

3) E Instrument Air is lost, THEN V-2-90 in the Condensate Transfer Building should be closed promptly to prevent the CST from draining to the hotwell. Approximately 17.4 ft in the CST may be required for isolation condenser shell makeup during cooldown to cold shutdown. Makeup to the CST as necessary from Demineralized Water (procedure 320.1), High Purity (procedure 351.2), or the Fire Protection system (as last resort, close V-9-11, open V-9-9 and open V-l l-247).

(:~ (

Attachment ABN-29-1 Procedure ABN-29 Equipment Availability Matrix for Fires Rev. 9 REPAIR EQUIPMENT ALTERNATE LOCATION OF ALTERNATE APPLICABLE FIRE ZONE DOCUMENT POTENTIALLY AFFECTED CONTROUINDICATION CONTROUINDICATION 'ROCEDURE(S)

REFERENCE R.B. 23' ELEV. CRD HYDRAULIC SYSTEM (RB-FZ-1 E) CRD Flow to Rx Local Gage RB 51' EL, SE 302.1 NA (cont'd) Indication (FI-RD36) (Fl-225-998)

CORE SPRAY SYSTEM I Booster PumD "C" Booster Pump " A C.R. Panel 1F12F 308 NA (NZ03C) (NZ03A)

" A Pump Suct Vlv Local Manual RB -19' EL, NW 308 NA (V-20-3)

"C" Pump Suct Vlv Local Manual RB -19' EL, NW 308 NA (V-20-32)

Parallel Vlv (V-20-40) Local Manual RB 51' EL, NW 308 NA Booster Pmp Diff Press Sw (DPS-RV40A) PI-RV43A 1F12F 308 NA CORE SPRAY SYSTEM I I Booster Pumps "B", "D" None NA 308 NA Power Ckts (NZ03B,D)

Core Spray Pump Local Manual RB -1 9' EL, SW 308 NA Suction Vlvs Power and Control Ckts (V-20-4,33)

Parallel Vlvs Power Local Manual RB 75' EL, South 308 NA and Ckts 0/-20-21,41)

Booster Pump Disch. Local Gage RB 23' EL, South 308 NA Press Ind. (PI-RV43B) (PI-RV40B) and Diff Press Sw (DPS-RV40B & D)

"A' ISOLATION CONDENSER AC Stm lsol Vlv Power Local Manual RB 75' EL, East 307 NA and Control Ckt (V-14-30)

Attachment ABN-29-1 Procedure ABN-29 Equipment Availability Matrix for Fires Rev. 9 REPAIR EQUIPMENT ALTERNATE LOCATION OF ALTERNATE APPLICABLE DOCUMENT FIRE ZONE POTENTIALLY AFFECTED CONTROUlNDlCATlON CONTROUlNDlCATlON 'ROCEDURE(S) REFERENCE R.B. 23' ELEV. "A"ISOLATION CONDENSER (cont'd)

DC Stm Is01Vlv Power Local Manual RB 75' EL, East 307 NA

& Control Ckt (V-14-31)

None NA 307 NA AC Cond Rtn. Vlv Power

& Control CM (V-14-36)

Local Manual RB 75' EL. East 307 NA DC Cond Rtn. Vlv Power

& Control CM 01-14-34)

"B" ISOLATION CONDENSER None Drywell 307 NA AC Cond. Rtr Is01 Vlv Power CM (V-14-37)

Local Manual RB 75' EL, East 307 NA DC Steam Line Vlv Control

& Ind (V-14-33)

Local Manual RB 75' EL, East 307 NA DC Cond. Vlv Control &

Ind (V-14-35)

ELECTROMATIC RELIEF VALVES NA EMRV " A Disable Swt Rear CR PNL 1F/2F 301 EMRV " A Control Ckt EMRV " B Disable Swt Rear CR PNL 1F/2F 301 NA EMRV " B Control Ckt EMRV "C"Disable Swt Rear CR PNL 1F12F 301 NA EMRV "C"Control CM EMRV "D" Disable Swt Rear CR PNL 1F/2F 301 NA EMRV "D" Control Ckt Temporary Control & NA Repair 2400-APR-Indication for NR108D Procedures 3411.01 2400-AP R-3411.03 2400-APR-3411.04

Attachment ABN-29-1 Procedure ABN-29 Equipment Availability Matrix for Fires Rev. 9 REPAIR EQUIPMENT LOCATION OF ALTERNATE APPLICABLE DOCUMENT POTENTIALLY AFFECTED PROCEDURE(S) REFERENCE R.B. 23' ELEV. ELECTROMATIC RELIEF (RB-FZ-1 E) VALVES (cont'd) NA EMRV "E" Disable Swt Rear CR Pnl 1F/2F 30 1 (cont'd) EMRV " E Control Ckt Temporary Control & I NA Repair 2400-APR-Indication for NR108E Procedures 3411.02 2400-APR-341 1.01 2400-APR-3411.04

(1 Attachment ABN-29-1 Procedure ABN-29 Equi p ment AvaiIabiIity Matrix for Fires Rev. 9 REPAIR EQUIPMENT ALTERNATE LOCATION OF ALTERNATE APPLICABLE FIRE ZONE DOCUMENT POTENTIALLY AFFECTED CONTROUINDICATION CONTROUINDICATION >ROCEDURE(S)

REFERENCE R.B. 23' ELEV. SHUTDOWN COOLING SYS.

(RB-FZ-1 E) "A' SDC Pump Pwr and LSP-1A2 "A" 480V Swg. Room 305,346 NA (cont'd) Control Ckt "B" SDC Pump Pwr and RSP "B"480V Swg. Room 305,346 NA Control Ckt "C" SDC Pump Pwr and None NA 305 NA Control C M

" A Loop Suct Vlv Pwr Local Manual SDC Room 305 NA

& Control Ckt (V-17-1)

"B' Loop Suct Vlv Pwr Local Manual SDC Room 305 NA

& Control Ckt (V-I 7-2)

"C" Loop Suct Vlv Local Manual SDC Room 305 NA

& Control CM (V-17-3)

"A" Loop Disch Vlv Pwr Local Manual SDC Room 305 NA

& Control Ckt (V-17-55)

"B" Loop Disch Vlv Pwr Local Manual SDC Room 305 NA P

& Control Ckt (V-I 7-56)

P Local Manual SDC Room 305 NA 0 "C" Loop Disch Vlv Pwr

& Control Ckt (V-17-57)

Attachment ABN-29-1 Procedure ABN-29 Equipment Availability Matrix for Fires Rev. 9 REPAIR EQUIPMENT ALTERNATE LOCATION OF ALTERNATE APPLICABLE FIRE ZONE DOCUMENT POTENTIALLY AFFECTED CONTROUlNDlCATlON CONTROL/lNDlCATlON 'ROCEDURE(S)

REFERENCE R.B. 23' ELEV SHUTDOWN COOLING SYS.

(RE-FZ-1 E) (cont'd)

(cont'd) SDC Sys Outlet lsol Vlv LSP-1AB2 RB 23' EL., NE 305,346 NA Pwr & Control CM (v-I7-54)

SDC Sys Inlet lsol Vlv LSP-1AB2 RB 23' EL., NE 305,346 NA Pwr & Control CM (V-I7-19)

Loop Disch Press Ind Local Gages SDC Room 305 NA (PI-RVO9 A, B, C) (PIT-RVO6, A, B,C)

Rx LEVEUPRESS INSTR.

Fuel Zone Lvl "C", "D" Fuel Zone Lvl " A , C.R. Pnl5Fl6F 410 NA (L1822-1001, 1002) "Bit (LI-IA-94A, B)

Fuel Zone Press "C", Fuel Zone Press " A C.R. Pnl5Fl6F 410 NA "D" (Pl-622-999, 1000) "B" (P1-622-849,850)

CONTAINMENT INSTR.

Torus Temp Ind. TE-644-30B or Control Room Panel 19R Repair 2400-APR-(TI66443 A & B) TE-664-33B SSI Tl-664-428 Procedure 3228.02 RBCCW SYSTEM 1-1 RBCCW Pump Pwr Ckt None NA 309.2 NA 1-2 RBCCW Pump Pwr CM None NA 309.2 NA

\

Attachment ABN-29-1 Procedure ABN-29 Equipment Availability Matrix for Fires Rev. 9 REPAIR EQUIPMENT ALTERNATE LOCATION OF ALTERNATE APPLICABLE FIRE ZONE DOCUMENT POTENTIALLY AFFECTED CONTROUINDICATION CONTROUINDICATION 'ROCEDURE(S)

REFERENCE R.B. 23' ELEV. RBCCW SYSTEM (RB-FZ-1E) (Cont'd)

(cont'd) RBCCW from DW Is01Vlv Local Manual RB 23' EL., East 309.2 NA (v-5-167) Pwr & Control Ckt SDC heat Exchangers Local Manual SDC Room 305 NA Outlet Vlv. (v-5-106)

Power & Control Ckt CONTAINMENT SPRAY SYS.

Cont Spray Pump 1-1 None NA 310 NA (51-A)

Cont Spray Pump 1-2 None NA 310 NA (51-B)

Cont Spray Pump 1-3 Repair Pwr Feeder " B 480V Swgr Room 310 2400-APR-(51-C) Use Local Control At 3214.01 P USS 1B2 h) 0 Cont Spray Pump 1-4 Repair Pwr Feeder "B" 480V Swgr Room 310 2400-AP R-(51-D) Use Local Control At 3214.01 USS 182 51A Pump Suct Vlv Local Manual RB-19' EL., NE 310 NA (v-2 1-9) 51B Pump Suct Vlv Local Manual RB-I9 EL., NE 310 NA (v-2 1-7) 51C Pump Suct Vlv Local Manual RB-19' EL., NE 310 NA (v-21-1) 51D Pump Suct Vlv Local Manual RB-19' EL., NE 310 NA (v-2 1-3)

Sys I DW Spray Is01Vlv Local Manual RB-19' EL., NE 310 NA (v-21-11)

Sys I Torus CLG Discharge Vlv Local Manual RB-23' EL., N 310 NA (v-2 1-1 7)

Attachment ABN-29-1 Procedure ABN-29 Equipment Availability Matrix for Fires Rev. 9 EQUIPMENT ALTERNATE LOCATION OF ALTERNATE FIRE ZONE POTENTIALLY AFFECTED CONTROUINDICATION CONTROUlNDlCATlON R.B. 23 ELEV. CONTAINMENT SPRAY SYS.

(RE-FZ-1 E) (Contd)

(contd) Sys II DW Spray Is01 Local Manual RB-23 EL., SE NA Vlv (v-2 1-5)

Sys II TORUS CLG DischargeVlv Local Manual RB-23 EL., South NA (v-2 1-1 3)

Sys I, Sys II Flow Ind None NA NA (FT-IP03 A, B)

EMERG SERV WTR. SYS.

ESW Disch Vlv., Sys I Local Manual RB 23 EL., North NA (v-3-88)

ESW Disch Vlv., Sys II Local Manual RB 23 EL., South NA (V-3-87)

ELECTRICAL DISTRIBUTION P

w 0

MCC 1A21A MCC 1A21B None None NA NA 338 338 NA NA MCC 1B21A None NA 338 NA MCC 18218 None NA 338 NA MCC 1AB2 None NA 339 NA MCC DC-1 None NA 340.1 NA RECIRC SYSTEM Recirc Pump Disch Vlv LSP-1AB2 RB 23 EL., NE 301,305,346 NA NG03E (v-37-54) Power And Control CM REACTOR CLEANUP SYSTEM Inlet lsol Vlv (V-16-1) RWCU Aux Relay Pnl. N B Battery Room 303 NA (ER-215-087)

i;' (\ (

Attachment ABN-29-1 Procedure ABN-29 Equipment Availability Matrix for Fires Rev. 9 REPAIR EQUIPMENT ALTERNATE LOCATION OF ALTERNATE APPLICABLE FIRE ZONE DOCUMENT POTENTIALLY AFFECTED CONTROUINDICATION CONTROUINDICATION PROCEDURE(S)

REFERENCE R.B. 23' ELEV. MSIV's (RB-FZ-1 E) Inner MSlV (North) Outer MSlV (North) C.R. Pnl11F 30 1 NA (cont'd) (NS03A) (NS04A)

Inner MSlV (South) Outer MSlV (South) C.R. Pnl11F 30 1 NA (NS03B) (NS04B)

I I I I Manual Action Required:

(1) CRD Bypass Valves V-15-30 and V-15-237 can be manually opened and V-15-52 closed after the Fire is extinguished if RPV Makeup is required using the CRD pumps. Note that Fl-225-998 can be used for flow indication.

(2) Recharge V-11-34 Accumulator per Procedure 307 as required (accumulator is sized for approximately 5 strokes).

(3) !E V-20-41 has to be manually opened, P

THEN It will be necessary to de-energize MCC 1AB2 by opening VMCC 182, Unit CO1 and VMCC 1A2, Unit BO2 to prevent future spurious operations P of the valve.

0 (4) !E V-204, V-21-1 (or V-21-3) and V-21-13 have to be manually opened and V-21-5 has to be manually closed, THEN It will be necessary to de-energize MCC 1B21A & 1821B by opening supply breakers BO1 and DO1 at MCC 1821 to prevent future spurious operations of the valves.

NRC Exam 2006-1 Reactor Operator Exam Key

~.-' 1. The plant was at 65% power, following a short forced outage, and restoration of rated power is underway. A malfunction occurred in the master recirculation controller which caused recirculation flow and reactor power to lower. The Reactor Operator has taken all recirculation speed controllers to MANUAL and the flow/power reduction has ceased. The following conditions exist:

0 Reactor power is 45% and steady Reactor recirculation flow is 6 x 1O4 GPM Which of the following actions are required?

a. Manually scram the reactor

b. Raise reactor recirculation flow or insert control rods C. Lower recirculation flow or insert control rods

d. Raise recirculation flow or withdraw control rods Answer: b HANDOUT: OC POWER OPERATION CURVE (from 202.1)

Justification: The master controller malfunction has placed the plant in the

-- Exclusion Zone of the Power Operation Curve. IAW 202.1, Power Operation, the Exclusion Zone is a region where reactor operation is not allowed due to stability concerns. If the zone is entered inadvertently, then exit the zone by using rods or flow (the same wording is also used in 301.2, Reactor Recirculation System).

ABN-2, Recirculation System Failures, provides more detailed instruction if the exclusion zone is entered and how to exit the zone: exit the exclusion zone by raising pump speed and/or inserting the CRAM array (control rods). Therefore, answer b is correct.

Answer a is incorrect since scram is not the appropriate action. Answers c and d are also incorrect responses.

295001 AK1.04 Knowledge of the operational implications of the following concepts as they apply to PARTIAL OR COMPLETE LOSS OF FORCED CORE FLOW CIRCULATION :

?Limiting cycle oscillation (CFR: 41.8 to 41 .lo)

OC Learning Objective: 2621.828.0.0040 (00226: Identify and interpret procedures for plant emergency/off-normal situations which involve the Recirc.

System, including personnel and equipment allocations.)

NRC RO Exam 2006-1 Key Page 1 of 129

Number AmerGen_ OYSTER CREEK GENERATING STATION PROCEDURE AP txcb?Company 202.1 Title Revision No.

Power 0peration 98 3.9 The Exclusion Zone is a region where reactor operation is not allowed due to stability concerns. Entry into the Exclusion Zone is confirmed by flow being less than 6.72 x I O 4 GPM and reactor power is greater than 25%. (Refer to Procedure 202.1, Power Operation, Attachment 202.1-2).

(CM-1) 3.9.1 Intentional entry into the Exclusion Zone is not permitted.

-IF the Exclusion Zone is entered inadvertently, THEN EXIT immediately using rods or flow.

3.10 The Buffer Zone is a region where heightened awareness is required due to proximity to trip setpoints and the exclusion zone. Entry into the Buffer Zone is confirmed by flow being less than 8.5 x I O 4 GPM. (Refer to Procedure 202.1, Power Operation, Attachment 202.1-2). Entry into the buffer zone is p J permitted without Shift Manager approval and recirc.

flow shall not be reduced below 7.0 X I O 4 GPM.(CM-1)

-IF the Buffer Zone on the Power Operation Curve is entered, THEN VERIFY the Exclusion Zone is not entered.

AND MAINTAIN a heightened awareness of Plant Parameters.

3.11 LIMIT Feedwater temperature as follows.

3.11.1 E Feedwater temperature decreases to less than 215 deg. F at rated power.

THEN PLACE feedwater heaters in service to restore feedwater temperature above 215 deg F.

OR REDUCE reactor power to less than 25% of rated power.

3.12 PERFORM control rod movements in a deliberate, carefully controlled manner while constantly monitoring nuclear instrumentation and redundant indications of reactor power level and neutron flux. (SOER 96-02) 3.13 During transient conditions, peer checking of control rod movement is not required.

3.13.1 WHEN plant conditions permit, THEN VERIFY control rod positions.

..v 1- 3.14 PEER CHECK all non-transient control rod movements when the unit is in STARTUP or RUN Mode 11.0

Procedure 202. I Rev. 98 ATTACHMENT 202.1-2 Oyster Creek Power Operations Curve 0 I 2 3 4 5 6 7 8 t 8.5 9 10 11 12 13 14 15 16 17 t18 17.7 Recirculation Flow (x I O 4 GPM)

NRC Exam 2006-1 Reactor Operator Exam Key Cognitive Level: Comprehension or Analysis L..J Question Type: Bank NRC RO Exam 2006-1 Key Page 2 of 129

NRC Exam 2006-1 Reactor Operator Exam Key f

2. The plant was at rated power with all systems normally aligned, when the following annunciator came into alarm:

VITAL POWER DC PWR LOST - BUS A/B UV With the affected DC Bus at 0 volts, and in accordance with the applicable RAP, the Unit Supervisor has declared the following valves INOPERABLE:

0 V-16-2, Inlet Isolation Valve to Cleanup Auxiliary Pump V-16-14, Cleanup System Inlet Isolation Valve 0 V-14-31, Steam Inlet Valve to AEmergency Condenser 0 V-14-34, Emergency Condenser NE01A Condensate Return Valve Which of the following automatic actions should have occurred as a result of this event?

a. 125 VDC DC-D transfers to 125 VDC DC A

b. 125 VDC DC-1 transfers to 125 VDC DC C C. 125 VDC DC-E transfers to 125 VDC DC B

d. 125 VDC DC-2 transfers to 125 VDC DC A

~.--J answer: a Justification: The given annunciator, along with the inoperable valves are enough to determine that 125 VDC Bus B is the effected DC bus. When voltage is lost to the bus, 125 VDC DC-D will automatically transfer from 125 VDC Bus B to 125 VDC Bus A. Answer a is correct.

125 VDC DC-1, also normally supplied by Bus B, also transfers to Bus A, not Bus C. Answer b is incorrect.

125 VDC DC-E is normally powered from 125 VDC Bus A and is unaffected by the event. DC-E would transfer to Bus B on a loss of volts to Bus A. Answer c is incorrect.

125 VDC DC-2, powered from 125 VDC Bus C is unaffected by the event.

Answer d is incorrect.

References:

RAP-9XF1d, revision 2; BR 3000, Electrical Power System Key One Line Diagram, revision 8; ABN-54, DC Bus B and PaneVMCC Failures, revision 1.

NRC RO Exam 2006-1 Key Page 3 of 129

NRC Exam 2006-1 Reactor Operator Exam Key L/

295004 AK1.02 Knowledge of the operational implications of the following concepts as they apply to PARTIAL OR COMPLETE LOSS OF D.C. POWER : Redundant D.C. power supplies: Plant-Specific (CFR: 41.8 to 41.1 0)

OC Learning Objective: 2621.828.0.0012 (01121: State potential consequences on plant operation, plant equipment and environment due to failure of DC Electrical System.)

Cognitive Level: Comprehensive or Analysis Question Type: Bank NRC RO Exam 2006-1 Key Page 4 of 129

Group Heading VITAL POWER DC PWR LOST 9XF-1-d BUS A/B uv REFLASH CONFIRMATORY ACTIONS:

o MONITOR 125 VDC Bus A and B to determine which Bus has degraded voltage. [ I o CHECK Reflash Panel ER-43 (above SAR Panel), reflash Unit AR123 to determine which Bus is affected. [ I LED #I Bus B less than 115 VDC 0 LED #2 Bus A less than 115 VDC 0 LED #3 Bus B less than 127.8 VDC on 9F Digital Voltmeter AUTOMATIC ACTIONS:

DC Panel DC-1, DC-D and DC-E will transfer to alternate power sources when preferred power sources are lost.

MANUAL CORRECTIVE ACTIONS:

NOTE This alarm indicates that a parameter has exceeded or has the potential to exceed an Emergency Action Level (EAL).

I REFER to EP-OC-1010, Radiological Emergency Plan for Oyster Creek Generating Station to determine EAL classification. [ I O F the in-service Charger has failed, THEN PLACE the backup Charger in-service IAW Procedure 340.1, 125 VDC Distribution Systems A & B. [ I MANUAL CORRECTIVE ACTIONS: (continued on Page 2 of 3)

Subject Procedure No.

ELECTRICAL RAP-9XF1d Page 1 of 3 9XF-1-d Alarm Response Procedures

AmerGm OYSTER CREEK GENERATING Number An txclon C o n p q STATION PROCEDURE J ABN-54 Title Revision No.

DC BUS B AND PANELlMCC FAILURES 1 CAUTION If a loss of DC B occurs with a loss of DC A and the main generator trips, I then evacuation of the Turbine Operating Floor will be required due to loss of hydrogen seal oil and bearing oil pressure.

3.0 OPERATOR ACTIONS If while executing this procedure, any entry condition for any EOP occurs, then EXECUTE this procedure concurrently with the appropriate EOP.

3.1 If power panel DC-D is lost, then PERFORM the following:

3.1 VERIFY the following automatic actions:

0 Isolation Condenser A isolates 0 CRD Pump B trips, if running 0 Rod Out Block only if Mode Switch pJ in RUN IRMs <Range 8 0 IC B Vent Valves close 0 Containment Spray System 2 valves auto reposition to Torus Cooling mode (if in Drywell Spray mode), pumps stay running 0 Breaker controls powered from Remote Shutdown Panel return to normal (if in use)

3. I.2 If Auto Transfer Switch DC-D has not shifted to the alternate supply, then manually SHIFT transfer switch to DC Distribution Center A.

5.0

I

-1

\

I c UJ I-,

I

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.J 1

If I

U I I

I I

3 I

I nl I i

- I

, i

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1 I

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Actrvities/Notes LJ0a-e:

1 -

a Located in Lhc: A/B Battery Room. ESOP, EBOY, 460V USS Control Power, P C Panel E d b. Coniiuis dnd I~iclication- Local voliiig~iriclication, RSP invcrtw, KWCIJ vol tdge, current, and alarms at panel W9F.

Isolation Valves, CIP-3

9. Distribution Center C (DC-C): inxrter, DC Pand D, MCC DC-I.

a. All of the DC circuit breakers are located in a single REajor Loads:

metal-clad cabinet within the 4160 VAC Swilchgear MCC DC-2, SI30 Xfmr room. monitoring, 4160V/460V switchgear control power,

b. Local voltage indication, voltage and current indication EDG-1 switchgear control at panel 8F/9F. power, DC Panel F

10. Power Panels DC-D, DC-E, DC-F Major Loads:

DC-D: RX Recirc MG set field breaker, RDP, Core Spray I & 11, DC-E: Control Room annunciator, AM, DPRS, TTP, Turbine Control DC-F: ADS, RYS, Recirc pump trip breaker, Core Spray I & IT

a. Panels D and F are safety-related and equipped with LO R undervoltage relays which alarm in the control room to DC-D and DC-F supply power to indicate a loss of power to the panel. safety-related loads and control logic circuits.

b. Panel E is non-safety related. It supplies power to Panel DC-D from DC-B (norm) turbine controls and auxiliaries and to Control Room Panel DC-E from DC-A (norm) alarm annunciator panels.

c. Panels D and E are energized from either distribution center A or B through an auto transfer switch.

d. Locations: LO-K

1) Panel D - A/B Battery Room Panel E . Lower Cable Spreading Room Panel F - 480V SWGR Room

.C e ntent/SkiI Is ActivitiedNotes 1 1. 125 VDC MCC DC-1 and DC-2 Major Loads:

DC-1; SDC inlet/outlet d valves, A is0 condenser, Main Steam drain DC-2: B Is0 Condenser

a. Locations LO-R DC RB ~1.236 SE corner DC RB e1.753 E side

b. They provide power and control functions for the DC MOVs.

c. DC powered valves assure minimum safety-system availability in the event of an AC power loss.

d. MCC DC-1 is normally energized from 125V DC-B, backup power is via Auto Bus Transfer Switch from 125V DC-A. MCC DC-2 is energized from 125V DC-C.

12. 24 VDC Panels A and B Major Loads:

Neutron monitoring, SGTS d

Logic, off-gas ISOL logic.,

a. Located in the lower cable spreading room. LO-R Figure 5

b. Panels equipped with 3 bus bars, +24V, -24V, and neutral.

1) All breakers are 2 pole and connect to the positive and negative buses only.

2) One lead of the electrical load is connected directly to the ncutral bus.

13. Auto tlaiisfeer Switches (ATS); LO-B

a. Increase system reliability by providing two possible power sources to the following panels:

POWER CEXTER NORMAL ALTERNATE PP DC-D DC-B . DC.4 C J PP DC-E DC-A PC-I3

4 t ContentEkiiis Act i vit i es/Not es

~-

MCC DC-1 DC-B DC-A

b. Auiliary contacts in the ATS aciuate an alarm in the Mi 3 ATS's imve a power conu-01 worn to notify thz opel-aior h a t a transfer- has transfer a h - m (3XF) occurred.

c. Transfer test switches have been provided but made inoperable to prevent inadvertent transfer.

d. Two types:

1) Power seeking and normal seeking. Both switch to A power seeking ATS will not alternate source on loss of normal source power. On auto swap to normal source if on subsequent return of normal power, power seelung alternate source and normal will stay on alternate source until manually switched source is restored. Must depress back. "reset" to manually switch back to normal.

2) Normal seeking will auto return to normal source when power is restored.

e. ATS DC-1 is normal seeking.

f. ATS DC-D and DC-E are power seeking.

g. All ATS's have alternate power available lights.

' X J 14, "Kirk" Key Interlocks: LO-K

a. The A/Bbattery charger MG set DC output breakers and the static charger output breakers are interlocked to prevent parallel operation of the static charger with an MG set.

b. A key interlock also prevents DC buses A and B from being energized from the static charger at the same time.

C. The interlocks are comprised of six mechanical "Kirk" Removing the key from the lock key devices. The interlocks are operated with removable mechanism locks the circuit keys. breaker in the OPEN position.

d. The removable keys are placed into the interlock that corresponds to the breaker for the equipment that i s being used to energizc the DC bus.

e. The keys are controlled by the Shift Manager.

E. Instrumentation: LO-I

- I . 'l'he remote instrumentation associated with the 12SV DC systems is lucatecl on Control Room pancI SF/BF.

I480 VAG MCC 1821 I I I

I)

UTI r----- 1 I

L--

Con,tknt/S kills

- Activities/Notes MCC DC-1 DC-B DC-A

b. Auuiiiary coiiidits in thc A1 S actuate an alainl in the All 3 ATSs have a power control roo111to notify the opLixioi- that a t i a n s h has transfer alarm (9XF) occurred.

c. Transfer test switches have been provided but made inoperable to prevent inadvertent transfer.

d . Two types:

1 Power seelung and normal seelung. Both switch to A power seeking ATS will not alternate source on loss of normal source power. On auto swap to normal source if on subsequent return of normal power, power seeking alternate source and normal will stay on alternate source until manually switched source is restored. Must depress back. reset to manually switch back to normal.

2) Normal seeking will auto return to normal source

. when power is restored.

e. ATS DC-1 is normal seeking.

f. ATS DC-D and DC-E are power seeking.

g. All ATSs have alternate power available lights.

d

14. Kirk Key Interlocks: LO-K

a. The A B battery charger MG set DC output breakers and the static charger output bi-eakers are interlocked to prevent parallel operation of the static charger with an MG set.

b. A key interlock also prevents DC buses A and B from being energized from the static charger at the same time.

c. The interlocks are comprised of six mechanical Kirk Removing the key from the lock key devices. The interlocks are operated with removable mechanism locks the circuit keys. breaker in the OPEN position.

d. The removable keys are placed into the interlock that corresponds to the breaker for the equipment that is bcing used to energize thc;: DC bus.

e. The keys are controlled by the Shift Manager.

E. Tiist rumen t at ion : LO-I I I IIC remote instnimentation assoLiatccI with the 125V DC d

sybteins is located on Cunlt.01 ROOIU panel 8F/9F.

NRC Exam 2006-1 Reactor Operator Exam Key

3. The plant was at rated power when the following annunciators came into L.l alarm over a short period of time:

TURBINE VAC/SEALS - COND VAC LO 25 INCHES MAIN STEAM - COND VAC LO/TURB TRIP I and I I TURBINE VAC/SEALS - COND VAC TRIP 1 22 INCHES TURBINE VAC/SEALS - COND VAC TRIP 2 10 INCHES The following conditions currently exist:

RP.V water level lowered to 130 and has recovered to 170, and is stable All control rods indicate full-in Which of the following systems will be used for RPV pressure control?

a. Turbine Bypass Valves

b. Isolation Condenser Vents C. EMRVs

d. Isolation Condensers answer: c W

Justification: The turbine bypass valves are not available due to the loss of condenser vacuum (RAP-QIc). Answer a is incorrect.

Isolation Condenser vents are unavailable since condenser vacuum is lost (Support Procedure 15 of EMG-3200.01A requires the condenser to be intact).

Answer b is incorrect.

EMRVs are allowed IAW Support Procedure 12 of EMG-3200-01A. Answer c is correct. (There is no indication that torus water is too low that would preclude their use.)

The use of Isolation Condensers is prohibited due to RPV water level of 170.

Both EMG-3200.01A and ABN-I require RPV water level less than 160. Answer d is incorrect.

295005 AK2.07 Knowledge of the interrelations between MAIN TURBINE GENERATOR TRIP and the following: Reactor Pressure Control (CFR: 41.7)

NRC RO Exam 2006-1 Key Page 5 of 129

NRC Exam 2006-1 Reactor Operator Exam Key OC Learning Objective: 2621.845.0.0004 (03012: Utilize appropriate EOP

'4 Support Procedures to determine various parameters required to support operation under the SBEOPs.)

Cognitive Level: Comprehension or Analysis Question Type: New NRC RO Exam 2006-1 Key Page 6 of 129

roup Heading TURBINE VAC/SEALS Q-I -C COND VAC TRIP 2 10 INCHES SONFIRMATORY ACTIONS

1E on low vacuum caused by equipment failure, THEN VERIFY the following

condenser vacuum below I O " hg [ I BPVs closed (position lights on 7F and 13R, and Selsyn on 7F) [ I I E Main Trip Solenoid #2 manually tripped, THEN VERIFY BPVs closed (position lights on Panels 7F and 13R, and Selsyn on 7F). [ I NUTOMATIC ACTIONS:

2loses or prevents opening of Turbine Bypass valves.

MANUAL CORRECTIVE ACTIONS:

P E vacuum can be restored, AND a plant cooldown is in progress, AND the US desires to cooldown to Main Condenser, THEN RESTORE condenser vacuum. [ I OTHERWISE SELECT an alternate RPV pressure control method. [ I Subject Page 1 of 2 BOP RAP-Q1c I Q-1-c Alarm Response Procedures Revision No: 0

Procedure EMG-3200.01A Support Proc-12 Rev. 12 Attachment M Page 2 of 1 SUPPORT PROCEDURE 12 ALTERNATE PRESSURE CONTROL SYSTEMS EMRVs 1.0 PREREQUISITES RPV pressure control using the EMRVs has been directed by the Emergency Operating Procedures.

2.0 PREPARATION None 3.0 PROCEDURE 3.1 Verify that Torus water level is above 90 in.

=-xi 3.2 Place the selected EMRV control switch in the MAN position (Panel 1F/2F) .

3.3 Control reactor pressure in the specified band by opening the EMRVs in the following sequence:

NR10 8A NR108D NR108B NR108C NR108E 3.4 Monitor Torus water temperature.

=---

(320001A/S15) E13-1

P r o c e d u r e EMG-3200.01A S u p p o r t Proc-15 Rev. 1 2 Attachment P Page 1. of 2 SUPPORT PROCEDURE 15 ALTERNATE PRESSURE CONTROL SYSTEMS I C TUBE SIDE VENTS 1.0 PREREQUISITES RPV p r e s s u r e c o n t r o l u s i n g t h e I s o l a t i o n C o n d e n s e r T u b e S i d e V e n t s h a s b e e n d i r e c t e d b y t h e Emergency O p e r a t i n g P r o c e d u r e s .

2.0 PREPARATION Perform t h e following i n p r e p a r a t i o n f o r using t h e I C Tube Side Vents f o r RPV p r e s s u r e c o n t r o l .

2.1 Verify t h e following:

1. I s o l a t i o n C o n d e n s e r s a r e n o t r e q u i r e d t o be i s o l a t e d .

2. Main C o n d e n s e r i s i n t a c t .

3. O f f s i t e r a d i o a c t i v i t y release rate i s e x p e c t e d t o remain below t h e r e l e a s e r a t e w h i c h r e q u i r e s a n U n u s u a l E v e n t .

2.2 Open t h e EOP BYPASS PLUGS p a n e l i n s i d e o f P a n e l 10XF.

2 . 2 . 1 R e m o v e t h e b y p a s s p l u g f r o m p o s i t i o n BP2 a n d i n s e r t i t i n t o p o s i t i o n BP1.

2 . 2 . 2 R e m o v e t h e b y p a s s p l u g from p o s i t i o n BP4 a n d i n s e r t i t i n t o p o s i t i o n BP3.

OVER

( 3 2 0 0 OlA/S18 ) E16-1

Title AmerGen-I OYSTER CREEK GENERATING Number STATION PROCEDURE ABN-I Revision No.

2 REACTOR SCRAM RWCU system in the recirculation mode RWCU system in the let down mode.

NOTE: Main Condenser must be available and ICs must not be isolated to utilize IC tube side vents for pressure control.

Isolation Condenser tube side vents.

NOTE: Resetting the scram will minimize the injection of cold water into the reactor bottom head from the CRD system and will relieve pressure from the control rod drives. (CM-I) 7.0

NRC Exam 2006-1 Reactor Operator Exam Key

4. The reactor was at rated power when the Shift Manager declared the Lj' control room NOT habitable due to a toxic substance, and that a control room evacuation is required.

Prior to leaving the control room, the following actions were taken:

0 The reactor was scrammed and isolated 0 The turbine was tripped 0 Isolation Condenser B was placed into service.

While at the Remote Shutdown Panel, you have recorded the following RPV pressures:

Time (hhmm) RPV Pressure (Dsiq) 1100 1000 1110 895 Which of the following is correct regarding the RPV cooldown rate?

The RPV cooldown rate is...........

.-_--- ., a. less than that allowed by procedure 203, Plant Shutdown, and less than that allowed by Technical Specifications

b. greater than that allowed by procedure 203, Plant Shutdown, and less than that allowed by Technical Specifications

c. greater than that allowed by procedure 203, Plant Shutdown, and equal to that allowed by Technical Specifications

d. greater than that allowed by procedure 203, Plant Shutdown, and greater than that allowed by Technical Specifications answer: a HANDOUT: ATTACHMENT ABN-30-4 Justification: Procedure 203, Plant Shutdown (step 6.66) requires that normal cooldown rate be limited to < 15'/10 minute interval = 90' F/hour. TS 3.3.C.1 limits the cooldown rate to 100' F/hour.

From Attachment ABN 30-4, 1000 psig = 546.22" F, and 895 psig = 533.29" F (must interpolate). This gives a temperature change of 12.93" in a 10 minute period (which equals 77.58" F/hour). This cooldown rate is less than procedure NRC RO Exam 2006-1 Key Page 7 of 129

NRC Exam 2006-1 Reactor Operator Exam Key 203, and less that TS 3.3.C.1. Answer a is correct. All other answers are d

incorrect.

295016 AA2.06 Ability to determine and/or interpret the following as they apply to CONTROL ROOM ABANDONMENT : Cooldown Rate (CFR: 41.1 0)

OC Learning Objective: 2621.828.0.0064 (10445: Given a set of system indications or data, evaluate and interpret them to determine limits, trends and system status.)

Cognitive Level: Comprehensive or Analysis Question Type: New NRC RO Exam 2006-1 Key Page 8 of 129

AtnerGemAn Exelon Company OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-30 I

Title Revision No.

u CONTROL ROOM EVACUATION 5 ATTACHMENT ABN-30-4 SATURATION CONDITIONS PSlG O F PSlG O F PSlG OF PSlG OF 0 212 55 302.92 110 344.33 235 400.95 4 225.24 56 303.88 ill 344.94 240 402.70 5 227.96 57 304.83 112 345.54 245 404.42 6 230.57 58 305.76 113 346.13 250 406.1 1 7 233.07 59 306.68 114 346.73 255 407.78 8 235.49 60 307.60 115 347.32 260 409.43 9 237.82 61 308.50 116 347.90 265 41 1.05 10 240.07 62 309.40 117 348.48 270 412.65 11 242.25 63 310.29 118 349.06 275 414.23 12 244.36 64 31 1.I6 119 349.64 280 415.79 13 246.41 65 312.03 120 350.21 285 417.33 14 248.40 66 312.89 121 350.78 295 420.35 15 250.33 67 313.74 122 351.35 305 423.29 16 252.22 68 314.59 123 351.91 315 426.16 17 254.05 69 315.42 124 352.47 325 428.97 18 255.84 70 316.25 125 353.02 335 431.72 19 257.58 71 317.07 126 353.57 345 434.40 20 259.28 72 317.88 127 354.12 355 437.03 21 260.95 73 318.68 128 354.67 365 439.60 22 262.57 74 319.48 129 355.21 375 442.12 23 264.16 75 320.27 130 355.76 385 444.59 24 265.72 76 321.06 131 356.29 395 447.01 25 267.25 77 321.83 132 356.83 405 449.39 26 268.74 78 322.60 133 357.36 415 451.73 J 27 270.21 79 323.36 134 357.89 425 454.02 28 271.64 80 324.1 2 135 358.42 435 456.28 29 273.05 81 324.87 137 359.46 445 458.50 30 274.44 82 325.61 139 360.49 455 460.68 31 275.80 83 326.35 141 361.52 465 462.82 32 277.13 84 327.08 143 362.53 475 464.93 33 278.45 85 327.81 145 363.53 485 467.01 34 279.74 86 328.53 147 364.53 505 471.07 35 281.01 87 329.25 149 365.51 525 475.01 36 282.26 88 329.96 151 366.48 545 478.58 37 283.49 89 330.66 153 367.45 565 482.58 38 284.70 90 331.36 155 368.41 585 486.21 39 285.90 91 332.05 157 369.35 605 489.21 40 287.07 92 332.74 159 370.29 625 493.21 41 288.23 93 333.42 161 371.22 645 496.58 42 289.37 94 334.10 163 372.14 665 499.88 43 290.50 95 334.77 165 373.06 685 506.25 44 291.61 96 335.44 167 373.96 705 506.25 45 292.71 97 336. I1 169 374.86 725 509.34 46 293.79 98 336.77 171 375.75 745 512.36 47 294.85 99 337.42 173 376.64 765 515.33 48 295.90 100 338.07 175 377.51 785 518.23 49 296.94 101 338.72 177 378.38 805 521.08 50 297.97 102 339.36 179 379.24 825 523.88 51 298.99 103 339.99 181 380.10 845 526.63 52 299.99 104 340.62 183 380.95 865 529.33 53 300.98 105 341.25 185 381.79 885 531.98 54 301.96 106 341.88 190 383.86 905 534.59 107 342.50 195 385.90 925 537.16 108 343.1 1 200 387.89 945 539.68 109 343.72 205 389.86 965 542.17

-d 210 391.79 985 544.61 393.68 1000 546.22 395.54 1025 548.38 All pressures in PSlG are rounded to the 397.37 1035 550.57 nearest whole number.

AmerGen,.

An Ixdm Company I OYSTER CREEK GENERATING STATION PROCEDURE I Number 203

,J Title Plant Shutdown I Revision No.

30 Initial I Date I Time 6.66 WHEN all control rods are inserted to 00, AND it has been determined that there is no necessity to limit reactor cooldown for operational purposes, to facilitate drywell inspection or due to low decay heat conditions (as determined by Reactor Engineering),

THEN COMMENCE a cooldown rate 5 15°F in each I O -

minute interval by limiting the rate of reactor pressure decay. i I 6.67 During the cooldown, MAINTAIN a uniform rate of change in temperature.

6.67.1 ADJUST the EPR/MPR setpoint or use the Bypass Valve Opening Jack to control the cooldown. I I 6.67.2 E the Bypass Valve Opening Jack is being used to control cooldown, THEN MAINTAIN the MPR setpoint close to Reactor Pressure to serve as a backup pressure regulator. I I 6.67.3 PLOT the cooldown rate at ten-minute intervals. I I 6.67.3.1 Reactor Pressure is > 25 psig, THEN DETERMINE the cooldown rate by converting Reactor Pressure to its corresponding saturation temperature using Attachment 203-2 and plot cooldown rate on Attachment 203-4. -I-I-36.0

3.3 REACTOR COOLANT

'v' Applicability: Applies to the operating status of the reactor coolant system.

Obiective: To assure the structure integrity of the reactor coolant system.

Specification: A. Pressure Temperature Relationships (i) Reactor Vessel PressureTests - the minimum reactor vessel temperature at a given pressure shall be in excess of that indicated by the curve A in Figures 3.3.1,3.3.2and 3.3.3for reactor operations to 22,27 and 32 effective full power years, respectively.The maximum temperature for ReactorVessel Pressure Testing is 250°F.

(ii) Heatup and Cooldown Operations: Reactor noncritical - the minimum reactor vessel temperature for heatup and cooldown operations at a given pressure when the reactor is not critical shall be in excess of that indicated by the curve B in Figures 3.3.1,3.3.2and 3.3.3for reactor operations up to 22,27 and 32 effective full power years, respectively.

(iii) Power operations -- the minimum reactor vessel temperature for power operations at a given pressure shall be in excess of that indicated by the curve C in Figures 3.3.1,3.3.2and 3.3.3for reactor operations up to 22,27 and 32 effective full power years respectively.

Note: Curves A, B and C in Figures 3.3.1,3.3.2and 3.3.3apply when the closure head is on the reactor vessel and studs are fully tensioned.

(iv) Appropriate new pressure temperature limits must be generated when the reactor system has reached thirty-two (32)effective full power years of reactor operation.

B. Reactor Vessel Closure Head Boltdown: The reactor vessel closure head studs may be elongated .020"(1/3design preload) with no restrictions on reactor vessel temperature as long as the reactor vessel is at atmospheric pressure. Full tensioning of the studs is not permitted unless the temperature of the reactor vessel flange and closure head flange is in excess of 85°F.

C. Thermal Transients

1. The average rate of reactor coolant temperature change during normal heatup and cooldown shall not exceed 100°F in any one hour period.

2. The pump in an idle recirculation loop shall not be started unless the temperature of the coolant within the idle recirculation loop is within 50°F of the reactor coolant temperature.

OYSTER CREEK 3.3-1 Amendment No: 42,120,151,188

NRC Exam 2006-1 Reactor Operator Exam Key

5. The reactor is at rated power.

Which of the following would require an entry into Technical Specifications if instrument air were lost to the listed systedcomponent?

a. Feedwater Control System

b. Scram Discharge Volume

c. Reactor Recirculation System

d. Shutdown Cooling System Answer: b HANDOUT: TS 4.2 Justification: IAW ABN-35, a loss of air to the feedwater flow control system, the flow control valves will lockup, and may be manually controlled locally. There is no TS for these valves. Answer a is incorrect.

A loss of air to the scram discharge volume results in the ventldrain valves failing closed. TS 4.2.G requires that the SDV ventldrain valves verified open at least once per 31 days. Answer b is correct.

A loss of air to the reactor recirculation system results in the lockup of the fluid couplers, and can be manually controlled locally. A loss of air to the shutdown system results in the minimum flow valves failing open. There are no TS associated with recirculation pumps in manual control nor with an shutdown cooling loop. Answers c and d are incorrect.

295019 2.1.33 Ability to recognize indications for system operating parameters which are entry-level conditions for technical specifications. (Partial or complete loss of instrument air) (CFR: 43.2 / 43.3) (CFR 41.7 - this is my tie to RO CFR)

OC Learning Objective: 2621.850.0.0090 (01661 : Using the Tech Specs, determine if the LCO requirements are/are not being met and determine the appropriate plant/operator response and state the basis for response.)

Cognitive Level: Comprehensive or Analysis Question Type: New NRC RO Exam 2006-1 Key Page 9 of 129

E. Surveillance of the standby liquid control system shall be as follows:

1. Pump operability Once13 months

2. Boron concentration Once/month determination

3. Functionaltest Once every 24 months

4. Solution volume and Once/day temperature check

5. Solution Boron-IO Once every 24 months. Enrich-Enrichment ment analyses shall be received no later than 30 days after sampling.

If not received within 30 days, notify NRC (within 7 days) of plans to obtain test results.

F. At specific power operation conditions, the actual control rod configuration will be compared with the expected configuration based upon appropriately corrected past data. This comparison shall be made every equivalent full power month. The initial rod inventory measurement performed with equilibrium conditions are established after a refueling or major core alteration will be used as base data for reactivity monitoring during subsequent power operationthroughout the fuel cycle.

G. The scram discharge volume drain and vent valves shall be verified open at least once per 31 days, except in shutdown mode*, and shall be cycled at least one complete cycle of full travel at least quarterly.

H. All withdrawn control rods shall be determined OPERABLE by demonstrating the scram discharge volume drain and vent valves OPERABLE. This will be done at least once per refueling cycle by placing the mode switch in shutdown and by verifying that:

a. The drain and vent valves close within 30 seconds after receipt of a signal for control rods to scram, and

b. The scram signal can be reset and the drain and vent valves open when the scram discharge volume trip is bypassed.

These valves may be closed intermittently for testing under administrative control.

Corrected: 12/24/84 OYSTER CREEK 4.2-2 Amendment No.: 64, 74, 75,124,141,159, 172, 178 Change: 25 I

I 1 1I

.(

- I OYSTER CREEK GENERATING Number

~

AmerGenw AnExdollcompany STATION PROCEDURE 305 Title Revision No.

u Shutdown Cooling System Operation 90 4.2.3 Due to Yarway level indication inaccuracies at lower reactor temperatures and pressures, GEMAC Narrow Range instrumentation should be used as the primary indication of Reactor water level.

4.2.4 RBCCW System flow reduction will alleviate excessive vibration or noise at the RBCCW Heat Exchangers.

4.2.5 If an automatic isolation occurs, do not attempt to restart the SDC System until available indications have been checked and found to be normal.

4.2.6 The maximum allowed RBCCW flow through a SDC Heat Exchanger is 1500 gpm.

4.2.7 Always attempt to maintain equal RBCCW flow through any operating SDC Heat Exchangers by keeping the shell side differential pressures as close as possible.

4.2.8 Maximum SDC System flow (tubeside) through a heat exchanger is 3400 gpm (assuming 10% of tubes are plugged).

4.2.9 In the case of system degradation due to a fire or a control room evacuation, steps that are absolutely necessary for system operation may be omitted.

4.2.10 To ensure full closure of MOVs V-17-55, V-17-56 and V-17-57, the control switch must be held in CLOSE for approximately 3 seconds after the red OPEN light (Panel I 1F) extinguishes. This action is necessary since these valves do not have a seal-in circuit in the close direction.

4.2.1 1 To prevent SDC System flow from short-cycling the core, the E Recirc Loop Discharge Valve must be CLOSED the E Recirc Pump running.

4.2.12 If the Cleanup System is in service, the B Recirc Loop should not be the selected loop in those instances where one loop is required to be fully open.

4.2.13 Section 4.3 of this procedure is written to startup the SDC System in order to cooldown the Reactor. If system startup is to be done after cooldown, as when maintaining a temperature band during outages, those steps applicable only to startup for a cooldown may be omitted at the discretion of the Operations Supervisor.

20.0

h e l An ExelonCompany I OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-3 I

Title d

Revision No.

0 LOSS OF SHUTDOWN COOLING 1.O APPLICABILITY This procedure is applicable following an inadvertent Loss of Shutdown Cooling inability to establish Shutdown Cooling when required.

2.0 INDICATIONS 2.1 Annunciators Engravinq Location PUMP A C-2-d TRIP PUMP B C-3-d TRIP PUMP C C-4-d TRIP (RBCCW) c-3-c PUMP 1-1 TRIP (RBCCW) c-4-c I PUMP 1-2 I TRIP CCW/SD CLGlFUEL POOL TEMP C-8-c HIGH SVC WATER PUMP TRIP K-I -f I I 2.2 Plant Parameters 2.2.1 Rising Recirculation Loop Inlet Temperatures (3F) coincident with rising temperatures in other RBCCW cooled components.

2.2.2 ESW System I pump trip (52A or 52B) if ESW is aligned to supply Service Water.

2.2.3 RPV level below the requirements for Shutdown Cooling flow for Shutdown Cooling Condition 2 or Condition 3 (refer to Procedure 305, Precaution and

' Limitation 4.2).

3 .O

Ameroen* OYSTER CREEK GENERATING Number ABN-3 An Exeh Company STATION PROCEDURE Title Revision No.

Ll LOSS OF SHUTDOWN COOLING 0 2.2.4 Valid or inadvertent Shutdown Cooling System isolation evidenced by V-I 7-19 and V-I 7-54 position indication on Panel 11F being closed and annunciator C-7-d, ISOL VALVES OPEN, in a cleared state when Shutdown Cooling is required.

3.0 OPERATOR ACTIONS If while executing this procedure an entry condition for any EOP occurs, then EXECUTE this procedure concurrently with the appropriate EOP.

3.1 a total loss of Shutdown Cooling occurs and an uncontrolled temperature rise causes RPV coolant temperature to approach or exceed 212OF, THEN REFER to the Emergency Plan [ I 3.2 DETERMINE cause for loss of Shutdown Cooling. [ I 3.2.1 -

IF an inadvertent isolation caused the loss of Shutdown Cooling and the inadvertent isolation is no longer present, THEN RESTORE Shutdown Cooling in accordance with Procedure 305. [ I 3.2.2 -

IF Shutdown Cooling isolation has occurred due to a failed Recirculation loop thermocouple, THEN PERFORM the following:

3.2.2.1. BYPASS the temperature interlock in accordance with Procedure 305 Section 9. [ I 3.2.2.2. RESTORE Shutdown Cooling in accordance with Procedure 305. [ I 3.2.3 -

IF Shutdown Cooling System isolation signal has occurred and cannot be bypassed, THEN PERFORM the following:

3.2.3.1. RE-ESTABLISH conditions required to place Shutdown Cooling in service. [ I 4.0

Title AmerGenl An Exekmtompany 1 OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-3 e Revision No.

LOSS OF SHUTDOWN COOLING 0 3.2.3.2. RESTORE Shutdown Cooling in accordance with Procedure 305. [ I 3.2.4 -

IF Shutdown Cooling System heat removal rate is insufficient, THEN PERFORM the following:

3.2.4.1 CONFIRM RPV level and Shutdown cooling flow meet the requirements of the Shutdown Cooling System operating Condition 1, 2 or 3 (Refer to Procedure 305, Precaution and Limitation 4.2). [ I 3.2.4.2 CONFIRM Shutdown Cooling System is aligned per Procedure 305. [ I 3.2.5 -

IF Shutdown Cooling System has tripped due to a loss of power from Unit Substation 1A2(1B2),

THEN PERFORM the following:

3.2.5.1 RESTORE power in accordance with ABN-45(48). [ I 3.2.5.2 RESTORE Shutdown Cooling in accordance with Procedure 305.

3.2.6 IF RBCCW flow to Shutdown Cooling Heat Exchangers is lost RBCCW heat removal capacity is reduced, THEN REFER to ABN-I9 RBCCW Failure. [ I 3.2.7 IF Service Water flow to RBCCW Heat Exchangers is lost, THEN REFER to ABN-18 Service Water Failure Response. [ ]

5.0

. 1 T

AmerGeny Number 3 ,

OYSTER CREEK GENERATING ABN-3 An Exam Company STATION PROCEDURE Title W

Revision No.

LOSS OF SHUTDOWN COOLING 0 3.2.8 -

IF Shutdown Cooling is lost cannot be established when required, THEN PERFORM the following:

NOTE Use the time-to-boil when determining alternate cooling method.

3.2.8.1 OBTAIN the time-to-boil from the Outage Command Center. [ I 3.2.8.2 REFER to Table ABN-3-1, Alternate Cooling Methods. [ I 3.2.8.3 MONITOR RPV temperature and pressure for approach to 212OF. [ I Y'

3.2.8.4 INITIATE actions to restore primary and secondary containment to the extent possible. [ I 6.0

- - NRC Exam 2006-1 Reactor Operator Exam Key

-.-.-J

6. While at the controls during a fuel shuffle, you are notified that an irradiated fuel bundle was dropped while being moved over the core, Which of the following would be an expected radiation monitoring response from this event?

a. 119 elevation radiation monitor C10 will indicate elevated radiation levels, and when tripped high, will initiate the Standby Gas Treatment System (after a time delay)

b. 119 elevation radiation monitor C5 will indicate elevated radiation levels, and when tripped high, will isolate the DW venvpurge valves (after a time delay)

C. 119 elevation radiation monitor C9 will indicate elevated radiation levels, and when tripped high, will initiate the Standby Gas Treatment System (after a time delay)

d. 119 elevation radiation monitor B9 will indicate elevated radiation levels, and when tripped high, will isolate the DW venvpurge valves (after a time delay)

Answer: c 4

Justification: All the listed radiation monitors measure radiation levels on the refuel floor (119). Only rad monitors C9 and B9, when tripped high, will initiate SGT after a short time delay. Rad monitors C5 and C10 initiate no protective actions. The containment high range radiation monitors (CHRRM), when tripped high, will isolate DWKorus vent and purge valves. Answer c is correct. All other answers are incorrect. (see RAP-1OF1m, -1 OF2m, -1OF3m, -1OF4m, and -

1OF4k.)

295023 AA1.04 Ability to operate and/or monitor the following as they apply to REFUELING ACCIDENTS : Radiation Monitoring Equipment (CFR: 41.7)

OC Learning Objective: 2621.828.0.033A (00819: State any automatic actions initiated by the ARM System. State which monitors provide these actions and the setpoints.)

Cognitive Level: Comprehensive or Analysis Question Type: Modified NRC RO Exam 2006-1 Key Page 10 of 129

Group Heading RADIATION MONITORS 10F-3-m CONFIRMATORY ACTIONS:

P VERIFY high radiation level.

(Panel 2R)

AUTOMATIC ACTIONS:

Local audible alarm. After a two (2) minute time delay, the Reactor Building isolates and the standby gas treatment system initiates.

MANUAL CORRECTIVE ACTIONS:

o CONFIRM high radiation condition.

o E confirmed, o THEN PERFORM the following:

0 CONFIRM SGTS start.

ENTER EOP EMG-3200.11, Secondar] Containment Control.

P MONITOR area radiation levels.

(Panel 2R)

NOTE This alarm indicates that a parameter has exceeded or has the potential to exceed an Emergency Action Level (EAL).

P REFER to EP-OC-1010, Radiological Emergency Plan to determine EAL classification.

MANUAL CORRECTIVE ACTIONS: (continued on Page 2 of 2)

Subject Procedure No.

Page 1 of 2 NSSS RAP-I OF3m IOF-3-m Alarm Response Procedures Revision No: 0

Group Heading RADIATION MONITORS AREA 10F-I-m 119 FT ELEV CONFIRMATORY ACTIONS:

a VERIFY the high radiation level.

(Panel 2R) [ I MJTOMATIC ACTIONS:

4udible alarm.

VlANUAL CORRECTIVE ACTIONS:

v' 1 CONFIRM high radiation condition.

1E confirmed, 1 THEN ENTER EOP EMG-3200.11, Secondary Containment Control.

NOTE This alarm indicates that a parameter has exceeded or has the potential to exceed an Emergency Action Level (EAL).

I REFER to EP-OC-1010, Radiological Emergency Plan to determine EAL classification.

IANUAL CORRECTIVE ACTIONS: (continued on Page 2 of 2) ubject Procedure No.

Page 1 of 2 NSSS RAP-I OF1m IOF-I - m Alarm Response Procedures Revision No: 1

1 Group Heading RADIATION MONITORS AREA 10F-2-m 119 FT ELEV I

ONFIRMATORY ACTIONS:

I VERIFY high radiation level.

(Panel 2R) [ I WTOMATIC ACTIONS:

.oca1 audible alarm.

JlANUAL CORRECTIVE ACTIONS:

3 CONFIRM high radiation condition. [ I I K confirmed, 3 THEN ENTER EOP EMG-3200.1I, Secondary Containment Control. [ I 2 MONITOR area radiation levels.

(Panel 2R) [ I NOTE This alarm indicates that a parameter has exceeded or has the potential to exceed an Emergency Action Level (EAL).

o REFER to EP-OC-1010, Radiological Emergency Plan to determine EAL classification. [ I MANUAL CORRECTIVE ACTIONS: (continued on Page 2 of 2)

Subject Procedure No.

Page 1 of 2 NSSS RAP-I OF2m I 10F-2-m I Alarm Response I I Procedures I Revision No: I I

I I

I

' ContentKkills o m + +.

lOF-2-r-11, "North Wall C10" I

ctivities/Notes 10F-3-m, "C9 HI Vent Trip" lOF-4-m, "Bc) HI Vent Trip" C- 1-g, "CAPGRMS Rad fir' C-2-g, "CAPGRMS Trouble" C-4-g, "TorusiDW Vent and Purge 31Rad Isolation" P-5-f, "1-5 (Sump) Rad HiLevel Hi/ Trouble I. Automatic Actions (Interlocks)

1. B-9 and C-9 monitor 119' RB primarily during fuel movement across the operating floor.

a. If setpoint of 50 m / h r occurs, will isolate, after a 2 T.S. I 1 0 0 mrhr minute time delay the RB Ventilation inlet and outlet Q. Why 2 minute delay?

valves isolate, trip operating exhaust fan and initiate A. Prevent inadvertent trip Standby Gas Treatment System. Audible horns on 119' from momentary refueling will also initiate. equipment shine.

\d b. Logic: one out of two taken once.

2. Containment High Range I/II located inside the Drywell LO R,S provide an assessment for post accident conditions.

a. If setpoint of 45 Whr is exceeded will result in an T.S. 574.6 R/hr isolation signal to DW Vent and Purge Valves (V-27-1,-

2,-3,-4) and Torus Vent Valves (V-28-17 & IS).

b. Isolation signal is processed if RP S Panel is lost or de-energized if TorusDW Vent and Purge VLVS Hi Rad Bypass Channel switch is not in BYPASS (11F).

c. Logic: one out of two taken once.

d. At 30 R/hr operators are expected to closc Torus 2" vent Alert alarm @ 30 R h r bypassV-38-47 (1 IF), and DW 2" vent bypass valves V-23-21 and -22 (12XR) in accordance with RAP.

3. TI3 1-5 Sump Rad Monitor Ratcmcter primarily monitors a LO R?s poterltial Irqiwl relea3e path to the e r l v i v m - m t if manually Q . W h t other controls are liiied up to dischdrge to the 30" hedder. Sump indy become a there to prevent a release?

source of radioactive eftliient in the evctit nt cpillage or 4. Chemistry sample required 4 oveiflow L'lo~no t i m sumps. prior to discharge.

NRC Exam 2006-1 Reactor Operator Exam Key

.ei

7. The reactor was at rated power when an RPV over-pressure event occurred. One electromatic relief valve (EMRV) opened momentarily as designed.

While the EMRV was oDen, which of the following is correct? (select one from each part) e Control Room panel EMRV position indicating lights are a(n) .

1 (directhdirect) indication of EMRV position; e EMRV tailpiece temperature indication is a(n) 2 (directhdirect) indication of EMRV position.

a. (1) direct (2) direct

b. (1) indirect (2) direct C. (1) direct (2) indirect

d. (1) indirect (2) indirect Answer: b Justification: The control room panel EMRV position indicating lights show the position of the EMRV pilot valve position - not the EMRV. This is an indirect indication of the actual EMRV position. The EMRV tailpiece temperature indicators indicate temperature in the EMRV tailpiece. Only when the EMRV is open, will there be elevated temperatures in the tailpiece. This provides direct indication of the EMRV position. (See RAP-B3g, -B4g, ABN-40) 295025 EK1.03 Knowledge of the operational implications of the following concepts as they apply to HIGH REACTOR PRESSURE : Safetyhelief valve tailpipe temperature/pressure relationships (CFR: 41.8 to 41 .lo)

OC Learning Objective: 2621.828.0.0026 (00538: Describe Control Room and/or local steam system indications.)

Cognitive Level: Comprehensive or Analysis Question Type: New b-NRC RO Exam 2006-1 Key Page 11 of 129

AmerGen An Explln Company OYSTER CREEK GENERATING STATION PROCEDURE Number I

301.1 Title Revision No.

d Main Steam Supply System (Inside Drywell) 19 9.3.7 MONITOR electromatic relief valve tailpipe temperature to detect any evidence of seat leakage (On the "ISOL CONDENSER/EMRV DISCH TEMPERATURES" recorder or digital indicator on Control Room Panel 1F/2F). E l 9.4 Manual Operation of the Electromatic Relief Valves NOTE The electromatic relief valves provide over-pressure relief at a Reactor pressure of 1065/1085 psig.

NOTE Electromatic relief valve operation as part of the Automatic Depressurization System is included as part of Procedure 308, "Emergency Core Cooling System".

9.4.1 PLACE selected ADS/EMRV control switch in MAN.

9.4.2 VERIFY red Valve Open indicator Lit.

9.4.3 VERIFY green Valve Closed indicator extinguishes.

9.4.4 VERIFY annunciator B-4-g, SV/EMRV NOT CLOSED and B-3-g, EMRV OPEN are actuated/illuminated.

1 9.4.5 VERIFY EMRV Acoustic Monitor Indicators are in the red Valve Open Position.

4 21 .o

ADS SVIEMRV EMRV OPEN MANUAL CORRECTIVE ACTIONS: (continued from Page 1 of 2)

O K an EMRV has failed, THEN REFER to Technical Specification 3.4.B and Procedure 413, Operation of the Safety VaIve/EMRV Acoustic Monitoring System. [ I NOTE This alarm indicates that a parameter has exceeded or has the potential to exceed an Emergency Action Level (EAL).

REFER to EP-OC-1010, Radiological Emergency Plan to determine EAL classification. [ I CAUSES: SETPOlNTS: ACTUATING DEVICES:

Valve open EMRV Pilot Solenoid Valve NOTE limit switch (UNI-SW2)

Valves are automatically opened on high reactor pressure (I 065 or 1085 psig) or auto-depressurization signal.

Reference Drawinqs:

GU 3E-611-17-004 Sh. 1 One or more EMRVs open. GE 729E182 BR 2002 Subject Procedure No.

NSSS RAP-B3g B-3-g Alarm Response Procedures Revision No: 1

ADS SVlEMRV SV/EMRV NOT CLOSED CAUSES: SETPOlNTS: ACTUATING DEVICES:

NOTE Valve not closed Valve monitoring system master alarm Units # I and Relief valves automatically open on #2 Panel 15R high reactor pressure (1065 or 1085 psig) or auto-depressurization signal; safety valves begin opening at 1212 psig.

~

Reference Drawinqs:

One or more safety or relief valves not GU 3E-611-17-004 Sh. 1 closed. BR 2002 BX I106078 Subject Procedure No. I NSSS RAP-BIQg 1 Page30f3 B-4-g Alarm Response Procedures Revision No: 0

AmerGm OYSTER CREEK GENERATING I Number A n freki Campany 1

STATION PROCEDURE I ABN-40

'u'Title Revision No.

STUCK OPEN EMRV 2 STUCK OPEN EMRV 1.o APPLICABILITY This procedure provides direction for any EMRV that remains open when not required.

2.0 INDICATIONS 2.1 Annunciators Engraving Location Setpoint I

I EMRVOPEN 1 B-3-g valve open (pilot valve limit switch)

SV/EMRV NOT CLOSED B-4-g VMS alarm (acoustic monitor) 2.2 Plant parameters Parameter Location Change EMRV discharge Panel 1F/2F rises above ZOOOF temperature Acoustic monitor Panel IF/ZF indicates EMRV open Torus water temperature Panel lF/ZF rising Red VALVE OPEN light Panel 1FQF iIluminated Green VALVE CLOSED Panel 1F/2F extinguished light 2.3 Other indications 1 Red VALVE OPEN indication light is illuminated if the solenoid is energized

2. Acoustic monitoring system indications 3.0

- AmerGen, - OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-40 An EXebn COYlIpdT iJ Title Revision No.

STUCK OPEN EMRV 2

3. EMRV discharge temperature indications

4. Lowering RPV pressure

5. Drop in generator load (MWe)

6. Rising Torus temperature

7. Indicated steam flow less than indicated feed flow

8. EMRV tailpipe temperature (RB 23' elevation on recorder) 3.0 OPERATOR ACTIONS If while executing this procedure, an entry condition for any EOP occurs, then EXECUTE this procedure concurrently with the appropriate EOP.

3.1 VERIFY the EMRV condition by observing the following:

Red VALVE OPEN indication light is illuminated if the solenoid is energized [ I

. Acoustic monitoring system indications [ I

. EMRV discharge temperature indications [ I

. Lowering RPV pressure [ I

. Drop in generator load (MWe) [ I

. Rising Torus temperature [ I

. Indicated steam flow less than indicated feed flow [ I

. EMRV tailpipe temperature (RB 23' elevation on recorder) [ ]

4.0

NRC Exam 2006-1 Reactor Operator Exam Key

' 3 . d 8. In accordance with the Primary Containment Control EOP, EMG-3200.02, before bulk drywell temperature reaches 281 O F, drywell sprays are lined-up and initiated.

Which of the following lists why containment sprays are initiated before the bulk drywell temperature reaches 281 O F?

Spraying the drywell will ensure that the.. ..

a. environmental qualification temperature of the EMRV solenoids is not exceeded

b. environmental qualification temperature of the dryweIVtorus vent and purge valve solenoids is not exceeded

c. drywell design temperature of 281 O F at a design internal drywell pressure of 48 psig is not exceeded

d. drywell design temperature of 281 O F at a design internal drywell pressure of 35 psig is not exceeded Answer: d Justification: A drywell temperature of 281 O F is the drywell design temperature at 35 psig (see USAR 6.2.1.3.5 and 3.8.2.3.b.2 and EOP Users Guide, 2000-BAS-u*.

3200.02). As stated on page 2-24, the EQ temperature of safety related equipment is only slightly above this temperature. The drywell design is 292" F at 44 psig and 281 O F at 35 psig. Answer d is correct. All other answers are incorrect.

295028 EK3.03 Knowledge of the reasons for the following responses as they apply to HIGH DRYWELL TEMPERATURE : Drywell Spray Operation (CFR: 41.5 / 45.6)

OC Learning Objective: 2621.845.0.0007 (03000: Using procedure EMG-3200.02, evaluate the technical bases foe each step in the procedure and apply this evaluation to determine correct courses of action under emergency conditions.)

Cognitive Level: Memory or Fundamental Question Type: Bank NRC RO Exam 2006-1 Key Page 12 of 129

EOP USERS GUIDE PRIMARY CONTAINMENTCONTROL

/ BEFORE I

/ BULK DRYWELL TEMPERATURE REACHES 281°F 1

ENTER EMG-3200.01A, RPV CONTROL-NO ATWS, AT AND PERFORM IT CONCURRENTLY WITH THIS PROCEDURE f

If an increasing Drywell temperature cannot be Although a high Drywell temperature condition will terminated before equipment operability limits or most likely be accompanied by a high Drywell pressure structural design limits of the Primary Containment are scram (3.0 psig is the scram condition and entry reached, Drywell sprays are initiated to effect the condition of RPV CONTROL - NO ATWS), the required Drywell temperature reduction. The specified explicit instruction to scram the Reactor adequately

.\--

, value of 28 1°F is the Drywell design temperature. (The addresses all scenarios where this may not be the case.

environmental qualifications of safety related Entry to RPV CONTROL - NO ATWS also allows the equipment is only slightly above this value.) operator to reduce Reactor pressure via normal means should Drywell sprays prove unsuccessful in The direction to enter RPV CONTROL - NO ATWS terminating the Drywell temperature increase. A ensures a Reactor scram is initiated before the reduction in Reactor pressure lowers the saturation Recirculation pumps are tripped in subsequent steps. temperature in the Reactor and reduces the rate at which heat is transferred from the Reactor to the Drywell.

u REVISION 7 2 - 24

Oyster Creek Nuclear Generating Station FSAR Update 6.2.1.3.4 Calculation Procedure The system of equations representing the pressure suppression system must be solved simultaneously by analog or digital methods. A digital computer program was used to arrive at a solution.

6.2.1.3.5. Results The peak drywell pressure calculated during the blowdown phase was 33 psig at 275°F. The torus peak pressure was 20 psig at 150°F. The curves are shown in Figure 6.2-3. The preceding discussion applies to the first 60 second portion of the curves.

The peak drywell pressure of 33 psig is lower than the 37 psig pressure interpolated from the test

+10 data, primarily because the reactor pressure in Oyster Creek is 1020 psig rather than 1250 psig which was used in the tests. The drywell is designed for a 44 psig internal pressure coincident with a 292°F temperature and a 35 psig at 28 1 OF. The torus is designed for a 35 psig internal pressure and a coincident 150°F temperature. Therefore it is concluded that the design conditions for the containment are well within that calculated for the Design Basis Accident.

6.2.1.3.6 Operational Considerations The OCNGS primary containment design considers loads and load combinations corresponding to normal operating temperatures up to 150°F at close to atmospheric pressure (Subsection 3.8.2.3.b.l). During normal operations, the calculated bulk drywell temperature is usually near or a few degrees above 135°F. However, the accident scenario presented in Subsection 6.2.1.3.3 assumes an initial drywell bulk temperature of 150°F at the time of the break.

A series of analyses was performed to determine primary containment response to the design basis LOCA from various initial drywell temperatures (Reference 12). The resulting peak temperatures and pressures are nearly identical irrespective of the initial drywell temperature.

6.2.1.4 Long Term Response AAer Blowdown 6.2.1.4.1 Events Following Blowdown Decay heat is removed from the core by the core spray water and transported to the drywell, where the core spray water and containment spray water mix and flow down the vents to the suppression pool. The Containment Spray heat exchangers remove heat from the pool. Only one of two loops was assumed to be operating for this evaluation. The heat transfer for the Containment Spray heat exchangers is a function of the inlet temperatures as given in Table 6.2-1 5 . Also, the flow from one of the two Core Spray Loops was used in the calculations.

6.2-15 Update 10 04/97

NRC Exam 2006-1 Reactor Operator Exam Key

.d

9. The reactor was at rated power with all systems normally aligned, when the following annunciators came into alarm:

REACTOR LEVEL - RX LVL LO I 0 REACTOR LEVEL - RX LVL LO II Which of the following states (1) where feedwater control will control RPV water level in AUTO (prior to any Operator actions), and (2) the procedurally required manual operator actions to control RPV water level?

a. (1) The Feedwater Control System will control RPV water level at the pre-scram level setpoint (2) Trip two feedwater pumps when RPV water level begins to rise

b. (1) The Feedwater Control System will control RPV water level at the post-scram level setdown level setpoint (2) Trip two feedwater pumps when RPV water level begins to rise

c. (1) The Feedwater Control System will control RPV water level at the post-scram level setdown level setpoint (2) Trip two feedwater pumps when RPV water level reaches 140

d. (1) The Feedwater Control System will control RPV water level at the pre-scram level setpoint (2) Trip two feedwater pumps when RPV water level reaches 140 Answer: b Justification: RAP-H5e and -H6e (RX LVL LO) require if a scram occurs, to verify actuation of the post scram level setdown and to perform followup actions of ABN-1.

Following a scram and lowering RPV water level, feedwater level control will attempt to control RPV water level at the reactor level setdown setpoint (142)

(when feedwater level control is left in AUTO). ABN-1, Reactor Scram, requires that when RPV water level begins to rise, to trip two feedwater pumps. When RPV water level reaches 140, to place the main feed regulating valves in manual and close. Answer b has both correct components and is correct. All other answers provide the incorrect setpoint after the scram or the incorrect operator actions. (See also MDD-OC-625-B.)

295031 (Reactor Low Water Level) 2.4.31 Knowledge of annunciators alarms and indications / and use of the response instructions.

NRC RO Exam 2006-1 Key Page 13 of 129

NRC Exam 2006-1 Reactor Operator Exam Key

' i d OC Learning Objective: 2621.828.0.001 8 (10446: Identify and explain system operating controls/indications under all plant operating conditions.)

Cognitive Level: Comprehensive or Analysis Question Type: Modified NRC RO Exam 2006-1 Key Page 14 of 129

hn fxem Cmp~ny STATION PROCEDURE ABN-1 Title 4 Revision No.

2 REACTOR SCRAM 3.8 CONFIRM the following:

0 Main Turbine Tripped r 0 GDI Open c 0 GCI Open r Field breaker Open c 3.9 If off-site power is not available to both startup transformer, then EXIT this procedure and enter ABN-36, Loss of Off-site Power. r

4. When directed by the Unit Supervisor, PLACE the LFRV in automatic. [ I 5.0

~-

04/19/06 10:40:14 MDD-OC-625-BDTVXI Rev. 3 Page 16 of 62 defined in GPUN MDD-OC-6258 DIV I (Reference 1.2.1.20) and as described i n GPUN Vendor Document VM-OC-0238 (Reference 1.2.1.2).

I The DFCS passes the lower o f the demand signals

- the normal demand or the flow limit flow demand. When a representative value of feedwater flow in any one feedwater train A, B, or C exceeds the runout flow setpoint, the DCC automatically selects the output of the flow limit PI block for the MFRV in the affected train. The representative value of flow is the measured flow in the affected feed train unless the flow transmitter is bad. If the flow transmitter is bad, the DCC selects a calculated line flow if the feed train is in service. If the affected feed train ie out of service, the flow feedback is set to zero. The DCC calculates the backup line flow signal based on reactor pressure and valve position.

The purpose of the runout protection is to prevent feed water pump overload trip and protect t h e condensate demineralizers from excess flow. MFRV position continues to be determined by feedwater flow control (without respect to reactor water level) until the measured feedwater channel flow decreases to a

, point below the flow limit logic setpoint at which point MFRV position reverts to level control.

DCC logic provides separate flow limit setpoints for each of the three feedwater lines.

Detailed descriptions of the Runout Protection Logic can be found in Ref. 1.2.1.6, 37, and 38.

Existing Panel SF/6F located Feedwater flow limits initiation indicating lights are replaced with amber push-to-lighte status lights driven directly by the DFCS in accordance with human factors requirements.

In addition, when any feed train enters flow control mode the trouble alarm is activated.

P o e t Scram Level Control (Reactor Level Setdown) 1.3.1.9 The DFCS includes a post scram level control (PSLC} scheme for MFRV control. Wctional I requirements are as defined in GPUN MDD-OC-625A (Ref. 1.2.1.3) , and as described in GPUN Vendor Manual VM-OC-0238 (Reference 1,2.1.2) have been revised per MDD-OC-625B DIV I (Reference 1.2.1.20).

005/008

04/19/06 10:40:14 MDD-OC-625-BDIVfI Rev. 3 P a g e 17 of 62 The PSLC operative scheme is actuated by the DFCS upon receipt of a reactor SCRAM Signal from existing control relay 3K10X located in I

panel 6XR validated with a sensed level decrease (as given by the post-scram void collapse) and is designed to work even with the local instrument link down.

The PSLC anticipates SCRAM related reactor vessel transients and automatically reduces the master level controller setpoint to a predetermined value to reduce flow demand in order to prevent a high water level transient condition that would normally occur following a SCRAM.

The PSLC can be operated during either single element or three element control mode of operation.

PSLC features include:

0 automatic setpoint change upon scram O MF'RV demand freeze during first part of post scram response 0 gains automatically adjueted for best level response (derivative action phased out) 0 control released to operator after demand unfrozen above allowed to recur after acrarn signal has cleared SCRAM signal backlighted existing pushbutton ID0035. located on Control Panel 4F, is removed since automatic reset does not require a manual pushbutton.

Annunciator alarm window "Reactor Level Setdown Initiatedn located on Control Board 4F is deleted since positive indication of setpoint change is provided on MLC (ID00661 " S " display.

Also, PSLC is activated on every validated scram. 1 PSLC logic is described in greater detail in Reference 1.2.1.6, 37. 38 and 46.

MFRV tockup 1.3.1.10 The DFCS includes MFRV lockup. This feature's functional requirement is the same as the original feature's functional requirement as described in GPUN Vendor Manual VM-060238 (Reference 1.2.1.2).

MFRV lockup occurs on loss of all 120 VAC power, loss of air to the MFRV positioner, or loss of signal to the I/P transducer for the MFRV. The lose of signal to the MFRV I/P is detected within the DFCS. Positive annunciation is provided by pressure switches

NRC Exam 2006-1 Reactor Operator Exam Key

10. The plant was at rated when power when an event occurred resulting in

d an airborne radiological release outside of the plant structures. The current conditions exist:

All control rods indicate full-in A radiological release is in-progress The outside air temperature is 50" F and the control room air temperature is 74" F Which of the following lists how and why the control room HVAC system should be aligned?

a. System A must be run in the PURGE Mode, to remove contaminated air from the Control Room, utilizing the fan &

b. System B must be run in the PURGE Mode, to remove contaminated air from the Control Room, utilizing the fan&o

c. System A must be run in the PART RECIRC Mode to maintain a positive pressure in the Control Room

d. System B must be run in the FULL RECIRC Mode to minimize the use of outside air into the Control Room Answer: c

.d' Justification: There are no automatic actions of the control room ventilation system from any high radiation signal.

Procedure 331 .l, Control Room and Old Cable Spreading Room Heating, Ventilation and Air Conditioning System, describes the partial recirculation mode:

this mode of operation is provided to minimize contamination infiltration into the control room by maintaining a positive pressure in the control room using partial outside air.

Section 6.1.1 of 331 .l, provides guidance for a radiological release with offsite power available. With offsite power available, System B or System A should be run in PART RECIRC mode. Only when there is a loss of offsite power, shall the System be run with the fan only (to limit EDG loading). Answer c is correct.

Running System A in the PURGE mode is incorrect. Purge mode is used to remove smoke, fumes, or other undesirable odors from the control room. Also, running the systems with fans only is required only when combined with a loss of off-site power to reduce EDG loading. Answer a is incorrect.

NRC RO Exam 2006-1 Key Page 15 of 129

NRC Exam 2006-1 Reactor Operator Exam Key Running System B in the PURGE mode is incorrect. Purge mode is used to

..-' remove smoke, fumes, or other undesirable odors from the control room. Answer b is incorrect.

Running System A in the FULL RECIRC Mode is incorrect. Full Recirc mode is used to minimize the intrusion of toxic gases into the control room. Answer d is incorrect.

295038 EK3.03 Knowledge of the reasons for the following responses as they apply to HIGH OFF-SITE RELEASE RATE: Control Room Ventilation Isolation (CFR: 41 5 )

OC Learning Objective: 2621.828.0.0054 (02324: Explain the basis, with use of the procedures, for the four different modes of control room ventilation damper alignment and the effects of the damper alignment modes on control room habitability.)

Cognitive Level: Comprehensive or Analysis Question Type: Modified NRC RO Exam 2006-1 Key Page 16 of 129

AmerGen+ OYSTER CREEK GENERATING STATION PROCEDURE Number 331.I An Ex?bn rcmpny 4

Title Revision No.

Control Room and Old Cable Spreading Room Heating, 19 Ventilation and Air Conditioning System 6.0 EMERGENCY OPERATION NOTE Conditions that require emergency operations that are described in this section are as follows:

Radiological release with offsite power available (Section 6.1.1) 0 Radiological release with offsite power not available.

(Section 6.1.2).

0 Fire anywhere in the plant.

(Section 6.2) 0 Chlorine gas/toxic gas release.

(Section 6.3) 0 Loss of both HVAC units.

(Section 6.4) 0 Security Event (Section 6.5)

Loss of Offsite Power with no radiological release due to seismic event without a LOCA.

(Section 6.6).

6.1 During a Radiological Release 6.1. I Offsite Power Available 6.1,I .I PLACE system in partial recirculation mode by placing mode switch for System B (Panel 9XR) or for System A (Panel 11R) in PAR REC.

6.1.I .2 MINIMIZE traffic through Control Room doors (i.e., keep doors closed as much as possible).

14.0

NRC Exam 2006-1 Reactor Operator Exam Key 4

. 11. The reactor was at rated power when the following annunciator came into alarm:

TURBINE VAC/SEALS - COND VAC LO 25 INCHES The reactor operator lowered recirculation flow as directed by the associated RAP. Condenser vacuum has recovered to 25.8 and is steady. The Unit Supervisor directs you to restore RPV pressure to the pre-event valve by adjusting the electronic pressure regulator (EPR), in accordance with 202.1, Power Operations.

Which of the following lists the required action and its effect?

Take the EPR RELAY POSITION switch to 1 which will cause turbine control valves to 2

a. (1) LOWER (?Yo) (2) close further

b. (1) LOWER (7%) (2) open further

c. (1) RAISE (I%) (2) open further

d. (1) RAISE (1%) (2) close further Answer: d Justification: As power is reduced, the EPR relay position also goes down (proportional to turbine load). To raise RPV pressure back up, the turbine control valves must close down some. Lowering the EPR relay position even further will do this (Raise (JYo)). As the TCV close down some, RPV pressure will rise.

Therefore, the EPR relay position must be taken to the RAISE position, which will cause turbine control valves to close further, causing RPV pressure to rise.

Answer d is correct. All other answers either manipulate the switch in the incorrect direction or the plant effect is incorrect. (See also procedure 315.4.)

RAP-Q3c directs a power reduction to maintain vacuum > 25.

295002 AA1.06 Ability to operate and/or monitor the following as they apply to LOSS OF MAIN CONDENSER VACUUM : Reactodturbine pressure regulating system (CFR:

41 -7)

OC Learning Objective: 2621.828.0.0051 (10446: Identify and explain system operating controls/indications under all plant operating conditions.)

-L---+

NRC RO Exam 2006-1 Key Page 17 of 129

NRC Exam 2006-1 Reactor Operator Exam Key 4.* Cognitive Level: Comprehensive or Analysis Question Type: Modified NRC RO Exam 2006-1 Key Page 18 of 129

OYSTER CREEK GENERATING Number AmerGenu An k l w Company STATION PROCEDURE 315.4 I

-d Title Revision No.

Transferring Pressure Regulators 2 1.0 PURPOSE To provide detailed instructions on transferring Main Turbine Pressure Regulators.

Operations included in this procedure are as follows:

Section Operation 3.0 Transferring From EPR to MPR 4.0 Transferring From MPR to EPR after Startup or Extended Operation

2.0 REFERENCES

2.1 Procedure 201, Plant Startup 2.2 Drawings 0 BR 3022, Turbine Generator Control Elementary Diagram 0 BR 3023, Turbine Generator Control Elementary Diagram 2.3 Steam Turbine and Generator Vendor Manual VM-OC-0233 Vol I and I I e

3.0 TRANSFERRING FROM EPR TO MPR 3.1 Prerequisites 3.1.1 The MPR relay position indicator is approximately 8-10% below EPR setting or as directed by the Operations Supervisor (not to exceed 12.5%). (1 psi = 2.5%) (Panel 7F). [ I 3.2 Precautions and Limitation 3.2.1 Do not drive the MPR setpoint excessively beyond actual reactor pressure, as reactor pressure and level transients may result.

3.3 Procedure 3.3.1 LOWER slowly the MPR setpoint by placing the MPR Control Switch in the Lower "?%" position for approximately one second periods until the MPR relay position indicator moves in the direction to reach the EPR setting. [ I 3.0

AmerGen-An Exr'or, Comlrany OYSTER CREEK GENERATING STATION PROCEDURE Number 315.4 I

. , Revision No.

/.- Title Transferring Pressure Regulators 2 3.3.2 CAUTION Driving MPR setpoint excessively beyond actual reactor pressure may result in reactor and level transients. Failure of the MPR to respond at the selected setpoint may be caused by incorrect setpoint calibration or improper rate adjustment.

-IF abnormal operation of the MPR is observed, THEN TRANSFER control to the EPR in accordance with step 3.3.4. [ I 3.3.3 NOTE The EPR relay position will continue to lower slowly with the MPR in control. For the weekly test, it should not be necessary to operate EPR control switch at all.

-IF it is desirable to remain on the MPR, THEN ADJUST EPR control switch so the EPR pressure setpoint at 6-7 psig higher than the pressure at which it had been operating. [ I 3.3.4 MPR control was only for the weekly test, and it is desirable to return to EPR control, THEN COMPLETE the following:

3.3.4.1 NOTE EPR relay position indication will start to rise after raising the MPR setpoint.

RAISE the MPR setpoint by placing the MPR Control Switch in the Raise "&%" position for approximately one second periods. [ I 4.0

NRC Exam 2006-1 Reactor Operator Exam Key d 12. The plant was at rated power with all systems normally aligned, when the following annunciators came into alarm:

TORUS/DRYWELL - DW SUMP HI LEAWPWR FAIL TORUWDRYWELL - DW PRESS HI/LO Drywell pressure indicates 1.4 psig, and the PWR FAIL has been ruled out as a cause.

Which of the following would NOT be used to determine the drywell unidentified leak rate?

a. Directly, by reading the Unidentified Drywell Leakage recorder (ULRM-1) on Panel 3F

b. Calculate, given the drywell sump flow integrator readings and times of the readings

c. Calculate, given the time between the drywell sump low and high level alarms

d. Estimate, given the drywell equipment drain tank leak rate and condenser hotwell makeup rate answer: d 4

Justification: The given question stem identifies an increased DW pressure from an increase in DW unidentified leakage.

Procedure 312.9, Primary Containment Control, provides directions on how to calculate the DW unidentified leak rate: take the difference between the DW sump integrator readings and divide by the elapsed time of the readings (this is the method used for the daily surveillance). There also exists an unidentified DW leakage recorder on Panel 3F. If these are not functional, procedure 351 .l, The Chemical Waste/Floor Drain Operating Procedure, provides a method to calculate DW unidentified leakage: measure the time between the low and high sump level alarms, and divide into the sump volume between these two alarms.

Answers a, b, and c are all acceptable methods. Answers a, b, and c are incorrect.

Answer d is a mix of identified leak rates and possible sources of unidentified leak rates. Answer d is correct. (Refer to drawings 147474, RAP-C3h, and procedures 351 -1, 351.2, and 312.9).

295010 AA2.01 Ability to determine and/or interpret the following as they apply to HIGH DRYWELL PRESSURE : Leak Rates (CFR: 41.1 0)

NRC RO Exam 2006-1 Key Page 19 of 129

NRC Exam 2006-1 Reactor Operator Exam Key OC Learning Objective: 2621.828.0.0032 (00418: Given control panel indications, interpret the cause of Primary Containment System alarms, alone and in combination, as applicable.

Cognitive Level: Comprehensive or Analysis Question Type: New NRC RO Exam 2006-1 Key Page 20 of 129

procedure EFTS 3 3 " O . 0 2 Support Proc. 1 Rev. 17 At cachment B Page 1 of 3 1

SYSTEM OPERATING DETAILS rimary Any of the fsllowing conditions e x i s t :

>nta ir,in ent RPIJ water level i?to r below 86 in. 2nd not bypassed.

solation Drywell piessure at or above 3.0 psig and not bypassed.

Confirm closed the following valves that are not required to be open by the Emergency Operating Procedures:

System Valve NO.

DW Vent/Purge V-27-1 (Panel 11F)

It V-27-2 I,

V-27-3 11 V-27-4 Torus Vent V-28-17 (Panel 11F)

,I v-2 8-18 Torus 2" Vent Bypass V-28-47 (Panel 11F)

DWEDT v-22-1 (Panel 11F) 11 v-22-2 DW Floor Sump v-22-28 (Panel 11F) 11 V-22-29 Torus/Rx Bldg. V-26-16 (Panel 11F)

Vacuum Breakers V-26-18 II TIP Valves Common Ind. (Panel 11F)

DW 2" Vent Bypass V-23-21 (Panel 12XR)

If V-23-22 N* Purge V-23-13 (Panel 12XR)

V-23-14 V-2 3-15 11 If V-23-16 N? Makeup v-23-17 (Panel 12XR)

V-23-18 v-33-14 V-2 3 - 7 0 I,

An Exeen Compdny I OYSTER CREEK GENERATING STATION PROCEDURE 1 DCC FILE #:20.1812.0010 Number 3,2.9

-4 Title Revision No.

Primary Containment Control 37 9.0 LEAK RATE CALCULATIONS 9.1 Prerequisites None 9.2 Precautions and Limitations None 9.3 Unidentified Leak Rate 9.3.1 OBTAIN drywell sump flow integrator readings at approximate four-hour intervals and RECORD the reading on the Technical Specification Log Sheet (681.4.004). 1 1 9.3.2 CALCULATE the four-hour average Drywell sump leak rate by taking the difference, in gallons, between the current and

. previous readings, and divide by the elapsed time between readings in minutes. [ I 9.3.3 E the Drywell sump flow integrator becomes inoperable, THEN PERFORM the following:

1. REFER to Technical Specification 3.3.0. [ I

2. CALCULATE the unidentified leak rate in accordance with Procedure 351.I. [ I 9.3.4 SUBTRACT the current days highest Torus water level reading from the lowest reading of the previous day as recorded on the Technical Specification Log Sheet (681.4.004). [ I 36.0

OYSTER CREEK GENERATING Number AmerGen An Exeon Company STATION PROCEDURE 351.I U

Title Revision No.

The Chemical Waste/Floor Drain System Operating 104 Procedure

[ I

-c-12.4.1 E the 1-8 sump flow integrator is inoperable, THEN SUBMIT a Work Request for repair. [ I 12.4.2 USE the Unidentified Drywell Leakage Recorder on Panel 3F to determine Drywell unidentified leakrate. [ I 12.4.3 E the Panel 3F Drywell unidentified leakage recorder is @

operable, THEN PERFORM the following steps:

1. PLACE the control switch for the 1-8 sump pumps located on Panel RB-IC in New Radwaste to MANUAL. [ I

2. PUMP the Drywell sump until the low level alarm is received.

0 RECORD the time on Attachment 351.I-4, Unidentified Leak Rate Calculation. [ I

3. PLACE the control switch to AUTO. [ I

4. CLOSE the following valves using the control switches on Panel 11F.

V-22-28 [ I V-22-29 [ I 138.0

her-.,

An Lxrlon Cnmpdny OYSTER CREEK GENERATING STATION PROCEDURE Number 351 .I

. . d l Title Revision No The Chemical Waste/Floor Drain System Operating 104 Procedure

5. CONFIRM closed indication for V-22-28. [ I

6. CONFIRM closed indication for V-22-29. [ I

7. RECORD the time the high level alarm is received on Attachment 351 .I-4, Unidentified Leak Rate Calculation. [ J

8. DETERMINE the unidentified leak rate using Attachment 351.1-4, Unidentified Leak Rate Calculation. [ I

9. OPEN the following valves using the control switches on Panel 1 1 F. [ I V-22-28 [ I V-22-29 [ I 139.0

NRC Exam 2006-1 Reactor Operator Exam Key

13. The plant was at rated power when the Secondary Containment Control

'i/

EOP, EMG-3200.11, was entered due to high area temperatures (not due to a fire).

Which of the following area leak detection system annunciators will result in automatic isolation of the affected system?

a. Cleanup System area leak detection: CLEANUP SYSTEM - RWCU HELB annunciators

b. Shutdown Cooling System area leak detection: SD HX CLG - SD HX PUMP RM TEMP HI annunciators

c. Isolation Condenser System area leak detection: ISOL COND -

COND AREA TEMP HI annunciators

d. Trunion Room area leak detection: MAIN STEAM - TRUNION RM TEMP HI annunciators Answer: a Justification: Cleanup system leaks will be annunciated by D l d and D2d (RWCU HELB at 160" F) and by D8d (CU ROOM TEMP HI). The HELB annunciators, when alarmed simultaneously, will isolate the cleanup system at 160" F area temperature. The other cleanup alarm does no auto action. Answer a is correct.

Shutdown cooling system leaks will be annunciated by C8d (SD HX PUMP RM

-4 TEMP HI) but provide no automatic actions. Answer b is incorrect.

Isolation condenser leaks will be annunciated by C8b (COND AREA TEMP HI) but provide no automatic actions. Answer c is incorrect.

Trunion room leaks will be annunciated by J8a (TRUNION RM TEMP HI) but provide no automatic actions. Answer d is incorrect. Main steam leaks into the steam tunnel (trunion room) are annunciated by J3a and J4a (FLOW HI/MN STM LINE AREA TEMP HI-HI 1 and II) but answer d is asking specifically for trunion room leak detection.

295032 EK1.03 Knowledge of the operational implications of the following concepts as they apply to HIGH SECONDARY CONTAINMENT AREA TEMPERATURE: Secondary containment leakage detection (CFR: 41.8 to 41.1 0)

OC Learning Objective: 2621.828.0.0039 (10449: State the function of system alarms, alone and in combination, as applicable in accordance with the system RAPS.)

NRC RO Exam 2006-1 Key Page 21 of 129

NRC Exam 2006-1 Reactor Operator Exam Key Cognitive Level: Memory of Fundamental Question Type: New NRC RO Exam 2006-1 Key Page 22 of 129

roup Heading CLEANUP SYSTEM D-I-d CONFIRMATORY ACTIONS

3 CHECK temperature indicator for affected areas and components.

(Panel IOR) 2 CHECK Annunciator D-8-d, CU ROOM TEMP HI. [ I AUTOMATIC ACTIONS:

Isolation of:

V-16-1 CU Inlet Isolation Valve From Reactor Vessel V-16-2, Inlet Isolation Valve To Cleanup Auxiliary Pump V-16-14, Clean-up Inlet Isolation Valve V-I 6-61 Regenerative Ht Exhanger Outlet To Reactor Vessel and Trip of pumps.

Annunciator D-2-d, RWCU HELB II is received concurrently.

MANUAL CORRECTIVE ACTIONS:

NOTE This alarm indicates that a parameter has exceeded or has the potential to exceed an Emergency Action Level (EAL).

REFER to EP-OC-1010, Radiological Emergency Plan for Oyster Creek Generating Station to determine EAL classification. [ I MANUAL CORRECTIVE ACTIONS: (continued on Page 2 of 3)

Subject Procedure No.

Page 1 of 3 NSSS RAP-Dl d D - I -d Alarm Response Procedures Revision No: 2

Group Heading SHUT DN CLG C-8-d CONFIRMATORY ACTIONS:

o CHECK local alarm indicator for affected area or component(s).

(Panel 10R) conditions permit.

o THEN CHECK Shutdown Cooling Heat Exchanger and pump rooms for steam leaks.

AUTOMATIC ACTIONS:

NONE MANUAL CORRECTIVE ACTIONS:

MONITOR Reactor water level.

NOTE This alarm indicates that a parameter has exceeded or has the potential to exceed an Emergency Action Level (EAL).

Q REFER to EP-OC-1010, Radiological Emergency Plan for Oyster Creek Generating Station to determine EAL classification.

ENTER EMG-3200.11, Secondary Containment Control.

MANUAL CORRECTIVE ACTIONS: (continued on Page 2 of 2)

Subject Page 1 of 2 NSSS RAP-C8d C-8-d Alarm Response Procedures Revision No: 1

Group Heading ISOL COND C-8-b CONFIRMATORY ACTIONS:

a CHECK for system isolation.

(Panel 1F/2F) o CHECK local alarm indicator for affected area.

(Panel IOR) o CHECK radiation levels of isolation condenser area.

(Panel 1R/2R)

AUTOMATIC ACTIONS:

NONE MANUAL CORRECTIVE ACTIONS:

P ENTER EMG-3200.11, Secondary Containment Control. [ I NOTE This alarm indicates that a parameter has exceeded or has the potential to exceed an Emergency Action Level (EAL).

o REFER to EP-OC-1010, Radiological Emergency Plan for Oyster Creek Generating Station to determine EAL classification. [ I MANUAL CORRECTIVE ACTIONS: (continued on Pane 2 of 3):

Subject Procedure No.

Page 1 of 3 NSSS RAP-C8b C-8-b Alarm Response Procedures Revision No: 1

roup Heading J-8-a MAIN STEAM

ONFIRMATORY ACTIONS:

3 VERIFY individual readouts of tunnel temperature on Panel 1OR. [ I UJTOMATIC ACTIONS:

4ONE MANUAL CORRECTIVE ACTIONS:

2 ENTER Procedure EMG-3200.11, Secondary Containment Control.

NOTE This alarm indicates that a parameter has exceeded or has the potential to exceed an Emergency Action Level (EAL).

2 REFER to EP-OC-1010, Radiological Emergency Plan for Oyster Creek Generating Station to determine EAL classification. [ I 3 a reactor scram and/or MSlV closure occurs, THEN REFER to Procedure ABN-1, Reactor Scram. [ I Subject 1 Procedure No.

BOP I RAP-J8a I

Page 1 of 2 J-8-a Alarm Response Procedures Revision No: 1

NRC Exam 2006-1 Reactor Operator Exam Key

14. The plant is at rated power with all systems normally aligned. You have W just received a phone call from a Non-licensed Operator in the plant. While investigating the Reactor Building Sump 1-7 high level alarm, he states that due to an apparent fault in the RB sump 1-7 control circuitry, neither sump pump will start.

Which of the following actions is required?

a. Manually isolate the inputs from RB Sump 1-6 into RB Sump 1-7

b. Check that RB Sump 1-6 inputs into RB Sump 1-7 have automatically isolated

c. Manually isolate Drywell Floor Drain Sump inputs into RB Sump 1-7

d. Check that the Drywell Floor Drain Sump inputs into RB Slwlr, 1-7--

have automatically isolated Answer: b Justification: With the RB Sump 1-7 high ala Secondary Containment EOP is entered (Eh into the sump should be isolated (except for suppression - of which, neither currently apF RB Sump 1-7, and sump 1-7 automatically is (which was given). According to the applicabl automatic valve closure of inputs from Sump 4

correct.

Since sump 1-6 output automatically isolated, isolate are required. Answer a is incorrect.

The drywell floor drain sump discharges to thE collection tanks (the same place where RB su discharge check valve). Therefore, there shou 7 from the drywell floor drains. Answers c and 147434, sheet 3, rev. 58) 295036 EK 1.02 Knowledge of the operational implications of th to SECONDARY CONTAINMENT HIGH SUMF Electrical ground/ circuit malfunction (CFR: 41 .i OC Learning Objective: 2621.828.0.0015 (1414: Describe the operation of the pumps and level instrumentation associated with Reactor Building Sumps 1-6 and 107 including automatic isolations.)

NRC RO Exam 2006-1 Key Page 23 of 129

NRC Exam 2006-1 Reactor Operator Exam Key Cognitive Level: Comprehensive or Analysis LJ Question Type: New NRC RO Exam 2006-1 Key Page 24 of 129

NRW ANNUNCIATORS 1-7 SUMP REACTOR BLDG FLR DRAIN SUMP HIGH LEVEL CONFIRMATORY ACTIONS:

CHECK for pump operation, automatic valve closure and valve alignment. [ I o REDUCE sump level as required manually if necessary [ I the 1-7 sump level cannot be restored and maintained below the setpoint, THEN at Shift Manager direction isolate systems discharging into the area, except systems required to shutdown the Reactor, assure adequate core cooling, or suppress a fire. [ I o ENTER Procedure EMG-3200.1I, Secondary Containment Control. [ I AUTOMATIC ACTIONS:

Sump pump starts and V-24-35, V-24-36, V-24-37 and V-24-38 close.

MANUAL CORRECTIVE ACTIONS:

None Subject NRW I Procedure No.

RAP-RBI C( 1-7) 1 Page 1 o f 2 RBlC(1-7)

Alarm Response Procedures Revision No: 0 I I

I I -

I 7-I I

N i

I - !

I P-

+

i d

NRC Exam 2006-1 Reactor Operator Exam Key

15. The plant was at rated power with all systems normally aligned. The

'4 following annunciators came into alarm:

ISOL COND - COND AREA TEMP HI RADIATION MONITORS AREA - AREA MON HI ISOL COND - COND A FLOW HI POSSIBLE RUPTURE The Operator verifies the isolation condenser area rad monitor is above the high setpoint (Panel 2R) and area temperature has risen (Panel 1OR).

Which of the following lists the expected Isolation Condenser A lineup in this condition? (assume no operator actions)

a. The steam supply valves, condensate return valves and vent valves indicate OPEN

b. The steam supply valves, condensate return valves and vent valves indicate CLOSED

c. The steam supply valves and the condensate return valves indicate OPEN, and the vent valves indicate CLOSED

d. The steam supply valves and the condensate return valves indicate CLOSED and the vent valves indicate OPEN answer: d

,d Justification: All three annunciators point to a rupture in Isolation Condenser A, in the vicinity of the IC (rad levels and temperatures: Rap-C8b, RAP-lOF1k). These first annunciators have no automatic actions associated with them. The third annunciator (RAP-C3a), will isolate the steam and condensate return valves for the associated IC A from high Dp (high flow) (See also drawing 3029, sheet 2).

The IC vent valves are unaffected by the isolation signal to the steam and condensate return valves. The vent valves, which are normally open while at power (auto close on system initiation), remain open following the isolation signal. The only answer which lists steam and condensate return valves closed and vent valves open, is answer d. Answer d is correct. All other answers are incorrect, since they provide the incorrect valve lineup. (The associated RAP does require the operator to close the vent valves, but no operator action is assumed in the question.)

207000 K4.01 Knowledge of ISOLATION (EMERGENCY) CONDENSER design feature(s) and/or interlocks which provide for the following: Isolation of the system in the event of a line break (CFR: 41.7)

NRC RO Exam 2006-1 Key Page 25 of 129

NRC Exam 2006-1 Reactor Operator Exam Key

-Ll OC Learning Objective: 2621.828.0.0023 (02030: Describe the Isolation Condenser design features and/or interlocks (including signals and setpoints) which provide for the following: 1) automatic system initiation; 2) automatic system isolation.)

Cognitive Level: Comprehensive or Analysis Question Type: New NRC RO Exam 2006-1 Key Page 26 of 129

Group Heading ISOL COND C-3-a COND A I FLOW HI POSSIBLE RUPTURE CONFIRMATORY ACTIONS:

a VERIFY Closed System A Isolation Valves.

Check for indication of pipe break:

o Annunciator C-8-b, COND AREA TEMP HI alarmed.

a Rise in area temperatures.

(Panel ?OR)

P CHECK level changes.

(Panel 2F) o CHECK shell temperature rise on TR IG02.

(Panel 2F)

Check for indication of tube leak:

CHECK level changes.

(Panel 2F) a CHECK shell temperature rise on TR IG02.

(Panel 2F)

Subject Procedure No.

Page 1 of 4 NSSS RAP-C3a C-3-a Alarm Response Procedures Revision No: 1

ISOL COND COND A FLOW HI POSSIBLE RUPTURE WTOMATIC ACTIONS:

loses Isolation Condenser System A Valves.

0 V-14-30, Steam Inlet Valve to ' A Emergency Condenser 0 V-14-31, Steam Inlet Valve to 'AEmergency Condenser 0 V-14-34, Emergency Condenser NEOlA Condensate Return Valve 0 V-14-36, Isolation Valve Emergency Condenser NEOlA AANUAL CORRECTIVE ACTIONS:

NOTE This alarm indicates that a parameter has exceeded or has the potential to exceed an Emergency Action Level (EAL).

I REFER to EP-OC-1010, Radiological Emergency Plan for Oyster Creek Generating Station to determine EAL classification.

AANUAL CORRECTIVE ACTIONS: (continued on Pane 3 of 41

u bject Procedure No.

Page 2 of 4 NSSS RAP-C3a C-3-a Alarm Response Procedures Revision No: 1

ISOL COND COND A FLOW HI POSSIBLE RUPTURE

~

MANUAL CORRECTIVE ACTIONS: (continued from Page 2 of 41

IE pipe break tube leak is verified, THEN PERFORM the following

0 EVACUATE Reactor Building.

PLACE V-14-30, V-14-31, V-14-34, V-14-36 A Is0 Cond Isolation Valves Control Switches to CLOSE.

0 PLACE V-14-5 and V-14-20, Emergency Condenser NEOIA High Point Vent Valves Control Switches to CLOSE.

IE no pipe break tube leak is indicated, THEN RETURN A I S 0 COND to Service as follows

0 OPEN V-14-30 and V-14-31.

(Panel 1F/2F)

OPEN V-14-34.

(Panel 1F/2F)

OPEN V-14-36.

(Panel 1F/2F 0 RESET the Isolation Condenser isolation signal using the Isolation Condenser Reset pushbutton.

(Panel 4F) 0 PLACE all Isolation Condenser A valve control switches to AUTO.

Subject Procedure No.

Page 3 of 4 NSSS RAP-C3a C-3-a Alarm Response Procedures Revision No: 1

NRC Exam 2006-1 Reactor Operator Exam Key

16. The plant is at rated power. Core Spray Main Pump NZOl C is running for W a normal operability surveillance test (610.4.021, Core Spray System 1 Pump Operability and Quarterly In-Service Test).

If a 10 GPM leak developed at the union of the Core Spray Main Pump NZOl C casing and the pump casing vent valve V-20-66, what impacts would this have on the system or the plant?

a. Room flooding would be annunciated in the Control Room

b. Torus water level would remain unaffected

c. Primary Containment integrity would be affected

d. Satisfying the ADS logic is prevented due to low pressure Answer: c Justification: The vent line from the pump casing is a 1/2 line (see drawing 885D781, procedure 308). Manual valve V-20-70 is normally closed, and opened for system fill and vent. With the valve open, water would be discharged from the valve, whether the pump was running or not. There are no water level alarms in the four corner rooms, and thus no Control Room annunciation (see EOP Users Guide). Answer a is incorrect.

As already stated, water will be discharged through the open vent valve. This water will come from the core spray suction - the torus. Thus, the open valve will cause torus water level to lower (see drawing 885D781). Answer b is incorrect.

Since this manual valve directly communicates with the primary containment, leaving the valve open would negatively impact primary containment integrity.

Answer c is correct.

The ADS logic requires core spray booster delta-P (25-47 psid), not core spray main pump pressure. On a core spray start (10-10 or high DW pressure), the main core spray pumps and booster pumps start (See GE 729E182, sheet 1). The backup pumps (of which NZOlC is one) do not start. Thus ADS can be satisfied with the main pumps operating as designed. Answer d is incorrect.

209001 K5.05 Knowledge of the operational implications of the following concepts as they apply to LOW PRESSURE CORE SPRAY SYSTEM : System Venting (CFR: 41.5)

OC Learning Objective: 2621.828.0.0010 (209-10445: Given a set of system indications or data, evaluate and interpret them to determine limits, trends and system status.)

Cognitive Level: Comprehensive or Analysis NRC RO Exam 2006-1 Key Page 27 of 129

NRC Exam 2006-1 Reactor Operator Exam Key Question Type: New NRC RO Exam 2006-1 Key Page 28 of 129

.J Title AmerGen_

An Excion Company OYSTER CREEK GENERATING STATION PROCEDURE 11 N~mber Ren v;i 308 No.

Emergency Core Cooling System Operation ~

ATTACHMENT 308-1 (continued)

Valve Checkoff List for Core Spray System SYSTEM I Valve TY Pe Control initials Number Oper Function Location Position ChecWerify V-20-3 MO Pump NZOIA Suct. from Torus IF 0 I

.A V-20-32 MO Pump NZOI C Suct. from Torus IF 0 I

/

v-20-12 MO System 1 Discharge 1Ff2F 0 I v-20-15 MO Sys. 1 Parallel Isolation Valve IFl2F C I V-20-40 MO Sys. 1 Parallel Isolation Valve 1Fl2F C /

V-20-17 M Sys. 1 Shutoff Inside Drywell DW LO

V-20-87 M Sys. 1 High Point Inner Vent Valve DW C

U V-20-96 M Sys. 1 High Point Outer Vent Valve DW C

Checked By: I I Signature /Date /Time Verified By: I I Signature /Date /Time Reviewed and Approved By: I I Signature /Date /Time

Documentation provided on Drywell Valve Lineup (Attachment 233-9) of Drywell Access and Control Procedure 233.

El-7

AmerGen, OYSTER CREEK GENERATlNG Number An Ixclon Company STATION PROCEDURE 308

-d Title Revision No.

Emergency Core Cooling System Operation 76 ATTACHMENT 308-1 Valve Checkoff List for Core Spray System SYSTEM I Valve TY Pe Control Initials Number Oper Function Location Position ChecWerifv v-20-1 M Core Spray Sys. Sup. from Cond. Stg. Tk. RB NW-19 LC I V-20-171 M Core Spray Sys. Sup. from CST Drain Vlv. RB NW-19 LC I V-20-5 M Pump NZOIA Suct. from Cond. Stg. Tank RB NW-19 LC I V-20-34 M Pump NZOIC Suct. from Cond. Stg. Tank RB NW-19 LC I V-20-28 M Pass System Return to Torus (Cap downstream locked in place) RB NW-19 0 I V-20-46 M Pump NZOIA Suct. from Torus Drain RB NW-19 LC I V-20-165 M Instrument PI-25A Root Valve RB NW-19 0 1 V-20-1086 M Instrument PI-25A Isolation Valve RB NW-19 C I V-20-48 M Pump NZOIA Seal Water Line Vent RB NW-19 C V-20-64 M Pump NZOIA Casing Vent RB NW-19 C

.--. I V-20-6 M Pump NZOIA Casing Drain RB NW-19 C V-20-72 M Pump NZOIA Disch. Check Bypass &

Fill Pump NZ04A Suction RB NW-19 LO v-20-100 M Disch Fill Pump NZ04A to NZOIA Disch.

Piping RB NW-19 0 V-20-259 M Pump NZ04A Cooling Line Vent RB NW-19 C V-20-264 M Discharge NZO4A Pump PI-212-9 Isolation RB NW-19 C V-20-166 M Instrument PI-25C Root Valve RB NW-19 0 V-20-1085 M Instrument PI-25C Isolation Valve RB NW-19 C

~ - 5 V-20-66 M Pump NZOIC Casing Vent RB NW-19 C J V-20-36 M Pump NZOI C Casing Drain RB NW-19 C I Checked By: I I Signature /Date Rime Verified By: I I Signature /Date /Time El-I

"'.,A, NRC Exam 2006-1 Reactor Operator Exam Key

17. The reactor was at rated power with all systems normally aligned. An

.d event occurred that caused the Reactor Operator to manually scram the plant. Reactor power was 22% following the scram. The following conditions exist:

Reactor pressure is 1004 psig Standby Liquid Control System 1 was initiated.

Which of the following shows the expected indications for SLC System 1?

PUMP ON Light SQUIBS Light Pump Discharge Pressure (psig)

a. ON ON 1085

b. ON OFF 1085 C. OFF ON 985

d. ON OFF 985 Answer: a 4

Justification: There is no automatic initiation of the SLC System. In a normal

-u standby configuration, both the PUMPS ON and SQUIBS lights are OFF (pumps are off and squib valves are energized). When a system is manually initiated, both lights go ON (see procedure 304, and EMG-3200.018, Support Procedure 22). SLC discharge pressure should be some valve greater than RPV pressure.

Answer a is correct.

No other answer has this correct combination and are therefore incorrect.

21 1000 A3.02 Ability to monitor automatic operations of the STANDBY LIQUID CONTROL SYSTEM including: Explosive valves indicating lights: (CFR: 41.7)

OC Learning Objective: 2621.828.0.0046 (10446: Identify and explain system operating controls/indications under all plant operating conditions.)

Cognitive Level: Memory or Fundamental Question Type: Modified NRC RO Exam 2006-1 Key Page 29 of 129

Procedure E M G 3 2 0 0 . 0 1 B Support Proc-22 Rev. 14 Attachment 0 Page 1 of 1 SUPPORT PROCEDURE 22 INITIATING THE LIQUID POISON SYSTEM 1.0 PREREQUISITES Initiation of Standby Liquid Control System has been directed by the Emergency Operating Procedures.

2.0 PREPARATIONS None 3.0 PROCEDURE tI 1 CAUTION Due to pressure fluctuations, Fuel Zone Level Indicator Channels "A" and "C" will not provide accurate indication of RPV water level if a Standby Liquid Control Pump is injecting into the RPV and should not be used.

L! I]

3.1 Place the STANDBY LIQUID CONTROL keylock in the FIRE SYS 1 or FIRE SYS 2 position.

3.2 Verify the following:

1. PUMP ON light for selected system illuminated (Panel 4F).

2. SQUIBS light for selected system illuminated (Panel 4F).

3. PUMP DISCH PRESS greater than Rx pressure (Panel 4F).

4. FLOW ON Alarm annunciates (G-1-b).

5. SQUIB VALVE OPEN Alarm annunciates (G-2-b).

3.3 IF the above expected indications do NOT occur, THEN 1. Place the STANDBY LIQUID CONTROL Keylock in the opposite position to use the other system

2. Verify proper operation using step 3.2

.'-/

i

( 2 0 0 01B/S17) E15-1

NRC Exam 2006-1 Reactor Operator Exam Key

18. A plant start-up is underway. The following plant conditions exist:

'ij Reactor power is on Range 8 of the Intermediate Range Monitors (1 RM)

IRM 11 is in BYPASS due to erratic detector output Control rods are being withdrawn to raise reactor power The following annunciator came into alarm, followed by the listed automatic system initiation:

VITAL POWER DC PWR LOST - 24 VDC PP-A PWR LOST Standby Gas Treatment System automatically initiated Which of the following lists the effects on the IRM System from this event?

a. IRMs 1 1-14 meters indicate downscale on Panel 5R, and a rodblock and '/2 scram exists

b. IRMs 11-14 meters indicate downscale on Panel 4F, and a rodblock&o exists

c. IRMs 11-14 meters indicate upscale on Panel 5R, and a rodblock and M scram exists

d. Only IRMs 12-14 meters indicate upscale on Panel 4F and a rodblock and '/2 scram exists

-W' Answer: a Justification: The indications in the stem are those of a loss of 24 VDC Panel A (RAP-9XF7d). Power is lost to 11, 12 SRMs and to 11-14 IRMs, and to the SGT trip relays (which causes SGT to auto start). The IRM trip auxiliary relays (and the IRM drawers on Panel 5R) (see drawings 706E812, sheet 9, 3 and 237E566, sheet 1) are powered from 24 VDC. The trip auxiliary relays are normally energized. When power is lost, all trips are instituted (upscale rodblock, upscale scram, inop. and rodblocks). The effected IRM drawers also show downscale on the meter from loss of power. Therefore, answer a is correct: the IRM meter shows downscale, and a rodblock and Y2 scram exist. All other answers either provide incorrect meter indication or wrong trips.

295003 K6.05 Knowledge of the effect that a loss or malfunction of the following will have on the INTERMEDIATE RANGE MONITOR (IRM) SYSTEM : Trip Units (CFR: 41.7)

OC Learning Objective: 2621.828.0.0029 (10444: Describe the interlock signals and setpoints for the affected system components and expected response including power loss or failed components.)

NRC RO Exam 2006-1 Key Page 30 of 129

NRC Exam 2006-1 Reactor Operator Exam Key Cognitive Level: Comprehensive or Analysis Question Type: New NRC RO Exam 2006-1 Key Page 31 of 129

VITAL POWER DC PWR LOST 9XF-7-d 24 VDC PP-A PWR LOST CONFIRMATORY ACTIONS:

o VERIFY the following loss of power alarms and indications:

Loss of Power Alarms:

Engraving Location IRM HI-HI/INOP I1 G-2-e SRM HMNOP G-4-d Loss of Power Indications:

Indication Location IRMs 15 through 18 fail downscale 4F Half scram from neutron monitors 4F (if mode switch is in startup or refuel)

Rod Block (if mode switch is in startup or refuel) 4F AUTOMATIC ACTIONS:

The following actions will occur when power is lost to 24 VDC PP-A:

Half scram from neutron monitoring.

(IRM's 11 through 14 if Mode Switch is in STARTUP or REFUEL)

Rod Block.

(if Mode Switch is in STARTUP or REFUEL)

Subject Procedure No.

ELECTRICAL RAP-9XF7d Page 1 of 2 9XF-7-d Alarm Response Procedures Revision No: 0 I I

VITAL POWER DC PWR LOST 9XF-8-d 24 VDC PP-B PWR LOST q__c -

CONFIRMATORY ACTIONS:

P VERIFY the following loss of power alarms and indications:

Loss of Power Alarms:

Engravinq Location IRM HI-HVINOP II G-2-e SRM HVINOP G-4-d Loss of Power Indications:

Indication Location IRMs 15 through 18 fail downscale 4F Half scram from neutron monitors. 4F (if Mode Switch is in STARTUP or REFUEL)

Rod Block (if Mode Switch is in STARTUP or REFUEL) 4F Subject Procedure No.

ELECTRICAL RAP-9XF8d Page 1 of 2 9XF-8-d Alarm Response Procedures Revision No: 0 I I

roup Heading VITAL POWER DC PWR LOST 9XF-8-d 24 VDC PP-B LUTOMATICACTIONS

NOTE The following action will occur when power is lost to 24VDC PP-B:

Half scram from neutron monitoring (IRM's 15 through 18 if Mode Switch is in STARTUP or REFUEL)

Rod Block (if Mode Switch is in STARTUP or REFUEL)

IONE llANUAL CORRECTIVE ACTIONS:

I REFER to Tech Spec 3.7. [ I I ENERGIZE 24 VDC Power Panel B in accordance with Procedure 340.2, 24 VDC Distribution System. [ I

AUSES: SETPOlNTS: ACTUATING DEVICES:

.oss of power to 2 24V DC Power None Relay K1 and K2

'anel "B" Reference Drawings:

BR 3028 Sh. 2 GU 3E-611-17-022

-736-11-002

ubject Procedure No.

ELECTRICAL 1 RAP-9XF8d I

Page 2 of 2 9XF-8-d Alarm Response Revision No: 0 Procedures

-- _I-5 I 4 I 3 I

.L I I J

J-+

I

NRC Exam 2006-1 Reactor Operator Exam Key

19. A plant startup is underway. The following plant conditions exist:

SRM 22 has failed and is in BYPASS 0 The 8'h control rod has just been fully withdrawn An event occurs which results in the loss of instrument power to SRM drawer 24.

Which of the following lists the neutron monitoring indications from this event?

a. SRM recorder (Panel 4F) has lost power

b. Channel 24 period meter (Panel 4F) indicates infinity

c. SRM 24 meter (Panel 5R) indicates upscale

d. Channel 24 period meter (Panel 5 R ) indicates downscale answer: d Justification: 24 VDC powers the SRM drawer, including the trip relays. A loss of instrument power results in the downscale indication of the SRM meters and period meters, both on Panel 5 R and 4F. Therefore, answer d is correct. (see drawings 706E812, sheets 4,47, procedure 401 . l )

b -- .

The SRM recorder power comes from 120 VAC CIP Div 1 (see drawings 706E812, sheets 3 and 4). Therefore, the SRM recorder is still powered. Answer a is incorrect.

Answers b and c are incorrect since both fail downscale.

215004 K6.05 Knowledge of the effect that a loss or malfunction of the following will have on the SOURCE RANGE MONITOR (SRM) SYSTEM : Trip units (CFR: 41.7)

OC Learning Objective: 2621.828.0.0029 (10444: Describe the interlock signals and setpoints for the affected system components and expected response including power loss or failed components.)

Cognitive Level: Memory or Fundamental Question Type: New

-\--

NRC RO Exam 2006-1 Key Page 32 of 129

u' Title AmerGen.,

An ExelonIBrit sh Energy Company I OYSTER CREEK GENERATING STATION PROCEDURE Number 401 .I Revision No.

Energizing SRM Channels for Operation 11 ATTACHMENT 401.I-1 VERIFICATION AND ELECTRICAL LINE-UP LIST ITEM POWER LOCATI 0N BREAKER SUPPLY POSIT10N Pwr Supply Reg, 24V DC Pnl "AI Lower Cable C Trip Aux Relays, Brkr 6 Spreading Room Pnl3R Neut Mon -I-Pnl 5R Neut Mon 24V DC Pnl "B" Lower Cable C Brkr 2 Spreading Room -I-Bypass Relays, Protection Panel Lower Cable C Trip Aux Relays, No. IBrkr 7 Spreading Room Pnl3R -I-Pnl5R Protection Panel Lower Cable C No. 2 Brkr 9 Spreading Room -I-d Transformer VMCC 1A2 via Lower Cable SW-733-169 PS-1 SW-733-169 Spreading Room ON OR VMCC 182 via SW-733-170 -I-5.7.1 Initial line-up performed by:

I I Signature Date Time I I Signature Date Time 5.8 Independent Verification performed by:

I I Signature Date Time 5.10 OS Review:

I I Signature Date Time El-2

8 7 8 I

I 1 H' x1 1252 1 83 2

INDICATOR PML 4F (REF 22) 7261 LlNE APRM TRIP AUX f NDICAT0 R LPRM QUAD 2 PNL 4F PWF? RANGE MON (REF 23)

RJOSB

{REF 18) 41 I 17kl I IhlC 7

.FJ

NRC Exam 2006-1 Reactor Operator Exam Key

20. The reactor is at rated power. Below are the currently bypassed Local Power Range Monitors (LPRMs) into Average Power Range Monitors L-(APRMs):

APRM 1 APRM 5 APRM 6 28-33A 44-33D 04-338 28-496 36-41B 20-49D 36-41A Which of the following LPRM inputs to APRMs:

(1) CANNOT be bypassed (and maintain APRMs OPERABLE), as allowed by procedure 403, LPRM-APRM System Operations, and (2) the effect if bypassed?

a. (1)44-33A (2) Too many LPRM inputs bypassed resulting in an automatic YZ scram

b. (1)36-410 (2) Too many LPRM inputs bypassed in one radial location resulting in an automatic /2 scram C. (1)28-49D (2) Too many LPRM inputs bypassed resulting in an automatic /2 scram

d. (1)20-498 (2) Too many LPRM inputs bypassed in one radial location resulting in an automatic rodblock Answer: a HANDOUT: Attachment 202.1 -1, Daily APRM Status Check Justification: Procedure 403 has 2 precautions: 5.2.2.2 (and 5.3.2.3) says Each APRM requires at least 5 LPRM signals. Inadvertently bypassing a qfhLPRM signal will initiate an INOP trip. 5.3.2.4 says Failure of, or bypassing, two chambers from one radial location in any one APRM shall make that APRM channel inoperable.

Answer a bypasses the 4h LPRM from APRM 1 and this APRM will become inoperable, and an automatic YZ scram occurs. (APRM 1 and 5 are located in the same core quadrant. APRM 1 has a and c LPRM inputs. Even though the given table does not show any LPRMs into APRM 1 from 44-33, it can be seen that v

NRC RO Exam 2006-1 Key Page 33 of 129

NRC Exam 2006-1 Reactor Operator Exam Key LPRM 44-33D inputs into APRM 5. Therefore,LPRM 44-33A must input into

'-4 APRM 1 .) Answer a is correct.

Answer b bypasses a second LPRM in the same radial location in APRM 15, which makes APRM 5 inoperable. There is no automatic function from this bypass. Answer b is incorrect.

Answer c bypasses a 3rdLPRM in APRM 5 and is allowed. No automatic function occurs from this bypass. Answer c is incorrect.

Answer d bypasses a second LPRM in the same radial location for APRM 6, which makes APRM 6 inoperable. There is no automatic action from this bypass.

Answer d is incorrect.

215005 2.1.32 Ability to explain and apply system limits and precautions: APRM/LPRM (CFR:

41.10)

OC Learning Objective: 2621.828.0.0029 (10444: Describe the interlock signals and setpoints for the affected system components and expected response including power loss or failed components.)

Cognitive Level: Comprehensive or Analysis

'4 Question Type: Modified NRC RO Exam 2006-1 Key Page 34 of 129

Amer-_

Ar CxemCo?lpaw I OYSTER CREEK GENERATING STATION PROCEDURE umber 202.1 Title I Revision No.

Power Operation 98 DAILY APRM STATUS CHECK NOTE: MARK FAILED OR INOP LPRMS WITH AN "X" Complete work sheet per 202.1-4 instructions Section 1: Perform nightly 403-3 Verified correct (initial) 403-4 Verified correct (initial)

Section 2: Perform on the first Sunday of each month.

0 Place an X in the box next to the LPRM's that are Bypassed 0 Place the number of un-bypassed inputs in last row. Perform drawer count per 403. Verify number of inputs correct and bypassed LPRM inputs are correct. (initial)

E l-1

AmerGen-An Extion Company 1 OYSTER CREEK GENERATING STATION PROCEDURE 1 Number 403 I

'v.' Title Revision No.

LPRM-APRM System Operations 11 5.1.3.21 PERFORM the following:

1. SIGN off Attachment 403-1. [ I

2. FORWARD Attachment 403-1 to OS for review and signature. [ I 5.2 LPRM-APRM SYSTEM OPERATION DURING STARTUP AND POWER 0PERAT1ON 5.2.1 Prerequisites 5.2.1.1 Reactor Mode Switch in STARTUP or RUN. [ I 5.2.2 Precautions And Limitations 5.2.2.1 APRM level adjustment is required in accordance with Procedure 202.1.

5.2.2.2 Each APRM requires at lea?; 5 LPRM signals.

Inadvertently bypassing a 4 LPRM signal will initiate an INOP trip. With the reactor mode switch in REFUEL, a single APRM will initiate a reactor scram if the non-coincidencejumpers have been removed.

5.2.2.3 Failure to bypass an APRM channel while change FCTR display number may result in a half-scram.

5.2.3 Procedure 5.2.3.1 PERFORM the following as power level is raised and approaches the APRM range.

(IRM range IO) [ I

1. OBSERVE APRM level as displayed on 0-150%

APRM scale of dual scale. [ I

2. CONFIRM the recorders are coming onscale. [ I 5.2.3.2 SELECT IRM-APRM 0-150% APRM scale recorder by pressing the right or left arrow key when Reactor is placed in RUN mode. [ I 11.0

AmerGenu OYSTER CREEK GENERATING Number A n lxelcrn Cornpa? STATION PROCEDURE 403 L4 Title Revision No.

LPRM-APRM System Operations 11 5.2.3.3 REFER to Bypass Section 5.3 for rod blocks initiated by LPRM DOWNSCALE trips requiring bypass.

1 NOTE The APRM ALARM LEVEL recorder functions on Panel 4F may be used to compute the difference between an APRM channel indicated power and the channel alarm (rod block) set point.

PRESS the appropriate pushbutton (CH 1 to 4 RECORD or CH 5 TO 8 RECORD) for a recorder indication of the differential percent power.

5.2.3.4 PERFORM Attachment 403-7 daily to verify proper FCTR operation.

5.2.3.5 CONFIRM Attachments 403-3 and 403-4 are up-to-date.

5.3 BYPASS OPERATIONS OF THE LPRM-APRM SYSTEM 5.3.1 Prerequisites Refer to Tech Spec Section 3.1 prior to bypass operations.

5.3.2 Precautions And Limitations 5.3.2.1 When LPRM detectors or APRMs are bypassed or inoperable the core MCPR may be raised.

5.3.2.2 For the pairs of LPRM strings designated in Section 5.4, Attachment 403-2, the allowed combinations of bypassed detectors are limited. No more than 3 of the 4 detectors located in the A and B level, or in the C and D level may be bypassed.

5.3.2.3 A maximum of three LPRM inputs may be bypassed for each APRM channel. Bypassing a fourth input will result in an INOP scram trip in that RPS system. Check all channel inputs for bypass conditions prior to bypassing additional channels.

5.3.2.4 Failure of, or bypassing, two chambers from one radial core location in any one APRM shall make that APRM channel inoperable.

12.0

1.

I REACTOR NEUTRON MONITORING SYSTEM TRIPS REACTOR REF2 PRESS REF 1

_til

AmerGen. OYSTER CREEK GENERATING Number rn[xcmco.np~ STATION PROCEDURE 202.1 Title Revision No.

Power Operation 98 ATTACHMENT 202.1-1 DAILY APRM STATUS CHECK NOTE: MARK FAILED OR INOP LPRMS WITH AN X Complete work sheet per 202.1-4 instructions Section 1: Perform nightly A I21

/ \

/

]FHF[

20 A la) os A 14) 403-3 Verified correct (initial) 403-4 Verified correct (initial)

Section 2: Perform on the first Sunday of each month.

Place an X in the box next to the LPRMs that are Bypassed Place the number of un-bypassed inputs in last row. Perform drawer count per 403. Verify number of inputs correct and bypassedLPRM inputs are correct. (initial)

STeT 0

El-1

NRC Exam 2006-1 Reactor Operator Exam Key

21. With the reactor at power, which of the following would prevent the ability LJ to determine reactor coolant system leak rate?

a. Containment High Range Radiation Monitor indicates 1x l O5 CPM

b. Containment Airborne Particulate and Gaseous Radiation Monitoring System indicates 45WHr

c. Drywell pressure at or above 2.0 psig

d. Reactor water level at or below 86 TAF Answer: d Justification: Reactor coolant system leak rate into the containment is measured by how much water is pumped out of the primary containment over time. With the drywell equipment and floor sump isolation valves closed, the reactor coolant system leak rate cannot be determined. Anything that causes an isolation of these valves would prevent the ability to determine reactor coolant system leak rate.

RAP-C1g, CAPGRAMS Radiation High, has no automatic actions. Answer a is incorrect.

RAP-1OF4k, Hi Range Rad. Monitor Abnorm., will close the torus/DW vent and purge valves at the high setpoint (not the DW floor and equipment drain valves).

Answer b is incorrect.

.u Support procedure 1 of RPV Control - No ATWS (EMG-3200-01A) and RAP-C4h, shows that the drywell equipment and floor drain IVs isolate on a primary containment isolation signal (RPV water level at or below 86 TAF, or drywell pressure at or above 3.0 psig). Answer c is incorrect.

Answer d is correct since the drain valves close at or below 8 6 TAF (see Support procedure 1).

223002 K1.14 Knowledge of the physical connections and/or cause-effect relationships between PRIMARY CONTAINMENT ISOLATION SYSTEM/NUCLEAR STEAM SUPPLY SHUT-OFF and the following: Containment drainage system (CFR: 41.2 to 41.9)

OC Learning Objective: 2621.828.0.0037 (02456: Describe RPS isolation logic trip signals and functions, including the following: 1) purpose/design basis; 2) setpoints; 3) conditions that allow bypassing isolation signals; 4) how bypassing isolation signals is accomplished.)

NRC RO Exam 2006-1 Key Page 35 of 129

NRC Exam 2006-1 Reactor Operator Exam Key Cognitive Level: Memory or Fundamental Question Type: New NRC RO Exam 2006-1 Key Page 36 of 129

Procedure EMG-3200.01A Support Proc-1 Rev. 12 Attachment B Page 2 of 2 SYSTEM OPERATING DETAILS

?rimary Any of the following conditions exist:

on tainment E RPV water level at or below 8 6 i n . and not bypassed.

[solation Drywell pressure at or above 3.0 p s i g and not bypassed.

Confirm closed the following valves that are not required to be open by the Emergency Operating Procedures:

System Valve No.

DW Vent/Purge v-27-1 (Panel 11F) v-27-2 1 V-27-3 I, 1

V-27-4 Torus Vent V-28-17 (Panel 11F)

V-28-18 11 Torus 2" Vent Bypass V-28-47 (Panel 11F)

DWEDT v-22-1 (Panel 11F) v-22-2 ,I DW Floor Sump V-22-28 (Panel 11F)

V-22-29 Torus/Rx Bldg. V-26-16 (Panel llF) r Vacuum Breakers V-26-18 TIP Valves Common Ind. (Panel 11F)

DW 2" Vent Bypass V-2 3-21 (Panel 12XR)

V-23-22 11 NZ Purge V-23-13 (Panel 12XR)

V-23-14 11 V-23-15 ,I V-23-16 1 N2 Makeup V-2 3- 1 7 (Panel 12XR)

V-23-18 I, V-23-19 11 V-23-20 I, 320001A/S4) E2-3

NRC Exam 2006-1 Reactor Operator Exam Key

22. Which of the following would result in reactor water level being controlled in single-element control?

a. The loss of a steam flow signal to the digital control computers while at rated power

b. The loss of a feed flow signal to the digital control computers while at rated power

c. The loss of both digital control computers while at rated power

d. Following a scram from rated power while controlling with the low flow regulating valve in MANUAL Answer: c Justification: FW level control uses a steam flow signal from each of the two steam lines. When a steam flow input is lost, the system will double the good remaining steam flow input and will continue to use 3-element control. Answer a is incorrect.

The FW level control system uses feedwater flow from each of two feedwater lines. When one FW flow input is lost, the system will calculate the feed flow based upon valve position, number of running pumps and reactor pressure. The system will continue to use 3-element control. Answer b is incorrect.

When a single digital control computer is lost, the system will continue in 3-element control with the operable digital control computer. When both computers are lost, control is transferred to the Moore controllers, which will control in single-element control. Answer c is correct. (see RAP-J1c)

Following a scram, if water level was being controlled by the LFRV in AUTO, then single-element control would be in control. But, with the controller in MANUAL, level control is set by the manual-remote opening of the low flow regulating valve. Answer d is incorrect. (See MDD-OC-625-B, FW and Recirc Control Systems Upgrade Modification) 259002 K4.09 Knowledge of REACTOR WATER LEVEL CONTROL SYSTEM design feature(s) and/or interlocks which provide for the following: Single element control (reactor water level provides the only input) (CFR: 41.7)

OC Learning Objective: 2621.828.0.0018 (10444: Describe the interlock signals and setpoints for the affected system components and expected response including power loss or failed components.)

NRC RO Exam 2006-1 Key Page 37 of 129

NRC Exam 2006-1 Reactor Operator Exam Key Cognitive Level: Memory or Fundamental

Question Type: New NRC RO Exam 2006-1 Key Page 38 of 129

FCSlRFCS DUAL COMPUTER FAILURE AUTOMATIC ACTIONS:

NOTE During the control transfer, a transient should be expected.

Control functions are transferred to the Moore Stations.

The following automatic control system functions are disabled:

Post Scram Level Control (Level Setpoint setdown may or may not occur) 0 Feedwater Pump Runout Control including associated lights 0 3 Element level control 0 MFRV lockup on loss of electrical control signal (loss of air still functional) 0 Recirc scoop lockup on loss of electrical control signal (loss of air still functional) 0 RWM Low power interlock (input to RWM would indicate Reactor power was above the LPSP and LPAP whenever both DCC-X AND DCC-Y are OFFLINE) 0 Steam flow mismatch alarm (J-7-a) 0 Block valve trouble alarms (J-6-d and J-6-9 0 Dual Link Failure alarm J-2-c MANUAL CORRECTIVE ACTIONS:

P MONITOR plant parameters (e.g., reactor level, total feedwater flow, recirc pump speed, etc.) until conditions stabilize. [ I P MAINTAIN steady state conditions unless otherwise required by abnormal plant conditions or Technical Specifications. [ I MANUAL CORRECTIVE ACTIONS (continued on Page 3 of 3)

Subject Procedure No.

Page 2 of 3 BOP RAP-JIC J-I-c Alarm Response Procedures Revision No: 0

04/19/06 10:40:14 MDD-OC-625-BDIVII Rev. 3 Page 46 of 62 Shutdowq The shutdown procedure is similar tothe existing system; individual t

loops are removed from service by placing the controller in "manual", decreasing flow to a minimum, shutting the pump diixharge valve, and stopping the pump.

Specific details f o r operation of the DRFCS during varioue plant operating modes are included in Reference 1.2.1.8.

4.0 CASUALTY EVENTS AND RECOVERY PROCEDURE&

A failure modes and effects analysis (FMEA) was not performed since the vendor (AECL) has performed a similar analysis. However, the following failure analysis is provided.

4.1 Common Mode Bailurea (Dual Computet P a i l u e o )

4.1.1 Software FailuxQ In theory, a software defect could adveraely affect both DCC control channels since identical software is used or each channel. The control software being used is PROTROL control block language developed by AECL. The operating system and each control block has been verified and validated by AECL with the intent of meeting the IEBB software standards. In addition, after the control blocks are configured into a working control program, the control program is subjected to a thorough deeign review and then tested with an AECL developed plant computer model of Oyster Creek. Then, the control program is tested again by a different computer model, the basic principles simulator, developed by an independent organization. Again, the control program is tested using the Oyster Creek replica simulator.

Finally, t h e control program structure ie tested on the real plant. The verification/ validation program i s similar to that described in EPRI NP-5524 (Ref. 1.2.2.2).

Because of the extensive verification and validation being performed on the PROTROL software, a software fault that results in dual DCC failure is not likely.

Even if a common fault occurred, the DCS is designed t o detect the fault, trip the watchdogs, and transfer control to the smart M/A stations which will continue in automatic single element level control (for DFCS) and automatic speed control (for DRFCS) if they are in automatic mode. With both DCC'a down, "hard" manual control is available by switching the smart M/A statione to manual.

The transfer of control logic is performed using electromechanical relays. This approach provides diversity from the DCCs when viewed from a software or hardware .

viewpoint. The smart M/A stations use software that is completely different from the software in the DCCS (hardware is different as well).

00 5 / 008

NRC Exam 2006-1 Reactor Operator Exam Key

23. The plant is at rated power with all systems normally aligned. The L..l following switch position is noted:

STANDBY GAS SELECT is in position SYS 2 An event occurs which automatically initiates the Standby Gas Treatment System.

Five minutes after the initiation, which of the following is the correct fanhalve configuration if the lead system developed/maintained a low flow signal?

System 2 Orifice Svstem 1 Fan Svstem 2 Fan Valve V-28-28

a. ON ON OPEN

b. ON OFF CLOSED C. OFF ON CLOSED

d. ON OFF OPEN Answer: a

-e Justification: On an automatic system initiation, both SGT fans start. If the lead fan develops adequate flow within the first 2-3 minutes, the lag fan will shutdown and the associated inlet/outlet valves close. If the lead fan does not develop adequate flow, the lag fan continues and the lead fan continues to run, but with the lead system inletloutlet valves closed. The system orifice valves are normally closed (with the systems is standby) and stays closed when the lead system starts with proper flow. If the lead running system sees low flow, then besides whats already been said, the lead system orifice valve also opens (and inleVoutlet valves close and the redundant system assumes the SGT function).

Therefore, 5 minutes after an auto initiation, system 2 fan (which was selected as lead) will be running with the loop inlet/outlet valves closed and loop orifice valve open. System 1 fan is also running performing the SGT function. Answer a is correct. (See also procedure 330)

All other answers are incorrect due to incorrect status of fanhalve. (See RAP-L5b) .

261000 A3.01 Ability to monitor automatic operations of the STANDBY GAS TREATMENT SYSTEM including: System Flow (CFR: 41.7 )

NRC RO Exam 2006-1 Key Page 39 of 129

NRC Exam 2006-1 Reactor Operator Exam Key OC Learning Objective: 2621.828.0.0042 (10445: Given a set of system i/

indications or data, evaluate and interpret them to determine limits, trends, and system status.)

Cognitive Level: Comprehensive or Analysis Question Type: Modified NRC RO Exam 2006-1 Key Page 40 of 129

H&V RX BLDG SGTS TRAIN A FLOW LO ATTACHMENT 1 SGTS DAMPER LINEUPS MODE Damper Standby Operating Trip sys 1 I sys2 sys 1 I sys2 SGTS CROSSTIE V-28-48 Open I Closed I Closed I Open I Open STANDBY GAS 1 INLET V-28-23 Closed Open Closed Closed Open STANDBY GAS 1 OUTLET V-28-26 Closed Open Closed Closed Open STANDBY GAS 1 ORIFICE INLET V-28-24 Closed Closed Open Open Closed STANDBY GAS 2 INLET V-28-27 Closed I Closed I Open 1 Open I Closed STANDBY GAS 2 OUTLET V-28-30 Closed I Closed 1 Open 1 Open 1 Closed STANDBY GAS 2 ORIFICE INLET V-28-28 Closed 1 Open I Closed I Closed 1 Open Subject Procedure No.

Page 3 of 3 BOP RAP-L5b L-5-b Alarm Response Procedures Revision No: 0

AmerGen_

An Fxcion Cornpaoy OYSTER CREEK GENERATING STATION PROCEDURE Number 330 L/ Title Revision No.

Standby Gas Treatment System I 43 5.3.4 SGTS I1 is selected as the preferential system, AND SGTS I1 develops a low flow condition (alarm L-5-b),

THEN VERIFY the following occur (Panel 1IR):

0 Exhaust Fan EF-1-8 ................................. starts [ ]

0 System I inlet valve V-28-23 .................... opens [ ]

0 System I outlet valve V-28-26 ..................opens [ ]

0 System I orifice valve V-28-24 ................ closes [ ]

0 System I1 inlet valve V-28-27.................. closes [ ]

0 System I1 outlet valve V-28-30 ............... closes [ ]

System I1 orifice valve V-28-28................ opens [ ]

0 SGTS Crosstie valve V-28-48..................opens [ ]

5.3.4.1 STOP Exhaust Fan EF-1-9 by placing control switch to OFF (Panel 11R). [ I 24.0

NRC Exam 2006-1 Reactor Operator Exam Key

24. The plant was at 50% power when a small LOCA into the primary containment occurred. Following the scram, all offsite power was lost and both emergency diesels could not be started. The following conditions exist:

RPV water level is 113 TAF and lowering very slowly 0 Drywell pressure is 5.1 psig and rising slowly 0 RPV pressure is 820 psig and lowering slowly 0 All control rods are fully inserted ABN-37, Station Blackout, has been entered o 4160 VAC Bus D has been powered from the combustion turbine, and critical loads have been restored in accordance with ABN-37-7 o the SBO Transformer load is currently 2.4 MWe Which of the following is the required action to restore RPV water level?

a. Lower RPV pressure as required and lineup and inject condensate transfer to core spray

b. Lower RPV pressure as required and lineup and inject fire water to core spray

c. Lineup and inject with condensate/feedwater

d. Lineup and inject with the maximum flow using both CRD pumps Answer: c HANDOUTS: ABN-37-7 and EMG-3200.01A Justification: With the given conditions, only feedwater and CRD can inject into the RPV at 820 psig. There is ample room on the SBO transformer (8 MWe maximum allowable and currently at 2.4) to start one condensate pump and one feedwater pump (0.81 1 MWe for the CP, and 3.141 MWe for the FWP = 3.952 additional MWe for 1 condensate/feed pump; so 8 - 2.4 = 5.6 MWe room on the SBO transformer). Therefore, injecting now with feedwater is the quickest method to inject into the RPV. Allowing RPV pressure to lower so that low pressure systems can inject (fire water, condensate transfer) increases the amount of time that RPV water level is lowering. Answer c is correct.

To inject with condensate transfer or fire water, core spray system 1 or core spray system 2 must be unavailable. With the given conditions of power to Bus D, components on core spray system 1 and core spray system 2 are available.

Therefore, conditions have not been met to inject with either condensate transfer of fire water. Answers a and b are incorrect.

NRC RO Exam 2006-1 Key Page 41 of 129

NRC Exam 2006-1 Reactor Operator Exam Key Even though CRD can also inject, maximizing CRD flow with both CRD pumps is

..4'not possible since CRD pump A is not powered from the SBO. (Se ABN-37, EMG-3200-01A) 262001 (A.C. Electrical Distribution) 2.4.6 Knowledge symptom based EOP mitigation strategies.

(CFR: 41.10)

Cognitive Level: Comprehensive or Analysis Question Type: New NRC RO Exam 2006-1 Key Page 42 of 129

AmerGem OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-37 An Exelon Company I

d Title Revision No.

STATION BLACKOUT 3 Attachment ABN-37-7 Maximum allowable S60 transformer load is limited to 8 MWe.

1.o MONITOR SBO transformer load at the SBO Panel or by maintaining contact with the CT Operator and MAINTAIN SBO transformer load less than 8 MWe. [ I NOTE: 1. The maximum load added from all possible equipment in this step is 2.1 MWe.

2. If the first pump in each system below is being started, and time permits, consider starting the pump with its discharge valve closed, in order to limit starting current and system perturbations.

L, 2.0 RESTART loads in the following order, unless dictated otherwise by the EOPs or plant conditions, and if power is available (through other attachments):

System Panel Load CRD pump(s) IAW 302.1, Control Rod Drive 4F 200 Kwe each System Service Water pump(s) IAW 322, Service 5F/6F 204 Kwe each Water System TBCCW pump(s) IAW 309.1, Turbine 13R 181 Kwe each Building Closed Cooling Water System Air compressor(s) IAW 334, Instrument and 5F/6F 144 Kwe each Service Air System RBCCW pump(s) IAW 309.2, Reactor 13R 159 Kwe each Building Closed Cooling Water System Drywell Cooling fans IAW 312.9, Primary 11R 25 Kwe each Containment Control 25.0

AmerGeSr, OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-37 An ExelonCompany I

ij Title Revision No.

STATION BLACKOUT 3 Attachment ABN-37-7 Restartinq Critical Loads (continued)

System Panel Load Condensate Transfer pump(s) IAW 316.1, 5F/6F 41 Kwe each Condensate Transfer System [ I A Battery Charger IAW 340.1, 125 VDC 8F/9F 65 Kwe Distribution Systems A& B [ I B Battery Charger IAW 340.1, 125 VDC 8F/9F 65 Kwe Distribution Systems A& B [ I End of Attachment ABN-37-7 26.0

AmerGenw An Ixektr C o m p q OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-37 L.--j Title Revision No.

STATION BLACKOUT 3 Attachment ABN-37-8 Condensate and Feedwater Pump Start 1.o CONFIRM the following support systems are in service:

Control air [ I Service Water or Circulating Water [ I TBCCW [ I 2.0 If condensate makeup valves were closed in Attachment ABN-37-5, then CONFIRM OPEN the following valves:

V-2-90, CST Isolation valve [ I V-2-54, Makeup IsolationValve to A Condenser [ I V-2-55, Makeup Isolation Valve to B Condenser [ I V-2-56, Makeup Isolation Valve to C Condenser [ I V-2-230, Feedwater Pump Minimum Flow isolation valve [ I V-2-231, Feedwater Pump Minimum Flow isolation valve [ I V-2-232, Feedwater Pump Minimum Flow isolation valve [ I 3.0 CONFIRM CLOSED all feedwater regulating valves and low flow valves. [ I 4.0 SELECT a feedwater string to control feedwater flow rate (if a feedwater pump is required, select either B or C feed string.) [ I 5.0 RESET the Reactor Feed Pump Aux Oil Pump thermal overload for the selected feed string at MCC 1A I 3 or MCC 1B13. [ I 6.0 START Condensate Pump B or C (811 Kwe) [ I 27.0

AmerGen.,

An twbr cmywty OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-37 4

Title Revision No.

STATION BLACKOUT 3 Attachment ABN-37-8 (continued)

Condensate and Feedwater Pump Start 7.0 If a Reactor Feed Pump is required, then PERFORM the following:

1. CONFIRM SBO Transformer load is less than 5 MWe. Strip loads as needed. r

2. START the selected Reactor Feed Pump (3141 Kwe). r 8.0 When feedwater pump suction pressure is stable, then CONTROL feedwater flow as directed. r End of Attachment ABN-37-8 28.0

NRC Exam 2006-1 Reactor Operator Exam Key

25. The plant was at rated power with all systems normally aligned. An event occurred which resulted in a loss of 125 VDC Bus C.

-4 Which of the following components has lost DC power?

1. Station Blackout Transformer Remote Monitoring Panel

2. 4160V Switchgear 1A and 1B

3. Turbine Generator Excitation Switchgear

4. Remote Shutdown Panel Inverter

5. Emergency Diesel Generator 1 Switchgear

a. 1 and 2

b. 2, 3, and 4 C. 3 and 5

d. 1 and 5 Answer: d Justification: The following components receive DC power from that listed:

1. Station Blackout Transformer Remote Monitoring Panel - DC C (correct)

2. 41 60V Switchgear 1A and 1B - 1A from DC C and 1B from DC B (incorrect)

3. Turbine Generator Excitation Switchgear - DC A (incorrect) 4 4. Remote Shutdown Panel Inverter - DC B (incorrect)

5. Emergency Diesel Generator 1 Switchgear - DC C (correct)

Therefore, only answer a has choices of 1 and 5. Answer a is correct and all other answers are incorrect. (See ABN-54, ABN-55, drawing BR 3028 and D-3033).

263000 K2.01 Knowledge of electrical power supplies to the following: Major DC Loads (CFR: 41.7)

OC Learning Objective: 2621.828.0.0012 (01106: Draw a one-line diagram of the 125 VDC Distribution System including: major busses (A, B and C battery systems), battery charging power supplies, major breakers, automatic bus transfer switches, manual bus transfer switches, and major loads for each DC panel.)

Cognitive Level: Memory or Fundamental Question Type: Bank NRC RO Exam 2006-1 Key Page 43 of 129

NRC Exam 2006-1 Reactor Operator Exam Key

,4 26. The plant is at rated power with all systems normally aligned. The Operator is preparing to manually start and synchronize EDGl for Peaking Operations, IAW 341, Emergency Diesel Generator Operation. The Operator has placed the EDG-1 MODE SELECTOR SWITCH in the IDLE position, when breaker 1C spuriously opened.

Which of the following lists how EDGl will respond?

EDGl will start and .......

a. idle at 400 RPM for 90 seconds then accelerate to 900 RPM, but will NOT load onto the bus

b. idle at 400 RPM for 90 seconds then accelerate to 900 RPM, and will load onto the bus C. accelerate from 0 to 900 RPM and will load onto the bus

d. idle at 400 RPM, and will NOT accelerate to 900 RPM answer: d Justification: With a loss of voltage to Bus l C , EDGl would normally fast start (immediate start and speed-up to 900 RPM) and load onto the bus. Taking the EDG-1 MODE SELECTOR SWITCH out of the AUTO position to IDLE will result in an automatic start and idle at 400 RPM, until something changes (ie,. The u EDG is shutdown, EDG-1 MODE SELECTOR SWITCH taken back to AUTO).

Therefore, in IDLE, the EDG will start, idle at 400 RPM, and it will not load onto the de-energized Bus C. (See procedure 341) As noted in RAP-T5b (EDGl Not in Auto), unless DG-1 is in auto mode, there cannot be an automatic fast start.

Answer d is correct.

All other answers are incorrect.

264000 A4.03 Ability to manually operate and/or monitor in the control room: Transfer of emergency control between manual and automatic (CFR: 41.7)

OC Learning Objective: 2621.828.0.0013 (264-10446: identify and explain system operating controls/indications under all plant operating conditions.)

Cognitive Level: Memory or Fundamental Question Type: New NRC RO Exam 2006-1 Key Page 44 of 129

Title Revision No.

4 Emergency Diesel Generator Operation 75

3. NOTIFY the System Operator that Bank 5 regulators are in Manual.

4. RECORD in Control Room Log that Bank 5 regulators are in Manual.

7.3.1.2 NOTE All controls are located in the Diesel Generator Switchgear unless otherwise noted.

PLACE EDG-1 MODE SELECTOR SWITCH in the IDLE position.

[ I 7.3.1.3 START EDG-1 by placing the STOP/START SWITCH in the START position.

I 1 7.3.1.4 NOTE After the engine has idled for 90 seconds (90 seconds from initial start), engine speed will increase to 900 RPM.

PLACE EDG-I MODE SELECTOR SWITCH in the RUN position

[ I 7.3.1.5 PLACE EDG-1 MODE SELECTOR SWITCH in the EXC position.

[ I 7.3.1.6 COMPARE EDG-1 output voltage with line voltage using the KILOVOLT METER selecting any GEN or BUS position on the VOLTAGE/FREQUENCY SELECTOR SWITCH. 1 7.3.1.7 NOTE EDG output voltage should be slightly higher than line voltage so that the machine will have lagging VARS when it is parallel with the system.

ADJUST EDG-1 output voltage to be slightly higher than line voltage using the VOLTAGE CONTROL SWITCH.

1 32.0

ContentlS kills ActivitiedNotes 4

2) not running) has occurred and only one diesel is available, MAINTAIN diesel load less than 1000 If a loss of power without LOCA i/ KW to allow for up to 1800 KW LOCA loads if a (i.e. Core Spray is LOCA subsequently occurs.

4. Design Criteria

a. Each EDG shall be capable of auto starting and attaining rated speed and terminal voltage within 15 seconds following the initiation of a start signal.

b. A frequency deviation of no more than 3 Hz on sudden application or removal of rated load.

c. EDGs shall operate independent of each other and supply separate, redundant 4160 VAC buses.

d. Any of the below operating conditions shall initiate a fast start of the associated EDG. The EDG shall accelerate to the rated speed and attain the rated voltage. ON achieving rated frequency and voltage, the EDG breaker shall auto close to reenergize the affected bus and initiate sequential loading of the EDG to supply safe shutdown loads.

1) A LOOP or loss of normal power to bus 1C or 1D.

2 ) LOOP concurrent with a LOCA.

3) LOOP with 1 EDG inop (single failure) concurrent with a LOCA.

e. On receipt of an auto START and IDLE signal, the EDG shall auto start, and idle at 400 rpm. (Idling at 400 rpm is provided to allow for the engine to warm up, venting of the EDG cooling system and achieving acceptable engine oil pressure in preparation for a potential LOOP.)

f. On receipt of a manual START signal, the EDG shall start and idle at 400 rpm for 90 seconds and then accelerate to 900 rpm. This will allow for engine warmup, venting of the EDG cooling system and achieving acceptable engine oil pressure prior to achieving rated speed.

g. On receipt of a FAST START signal, the EDGs will auto start and accelerate to 900 rpm. The FAST START signals bypass the following engine protections, but NOT overspeed:

k:\training\admin\word\262 1\82800013.doc Page 3 of 47

' Content/Skills ActivitiedNotes b) The strip heaters and fans are normally automatically operated by temperature switches.

4

2) CPM BKR provides AC power to the Circulating Oil Pump; and AC Turbocharger Oil Pump motors through two normally closed switches.

a) Switch SW-SLOM provides power to the AC Turbocharger Oil Pump motor.

b) Switch SW-CPM provides power to the Circulating Oil Pump motor.

3) Control switch DC MAN STR provides DC power to the DC Turbocharger Oil Pump motor and control circuits.

4) Control switch SW-FT provides AC power to the motors and control circuits for the EDG day tank Fuel Oil Transfer pumps.

5) There currently are no circuit isolation devices for Fuses will be installed for the AC power to the Immersion Heaters and Battery Battery Charger power supply Chargers. and a breaker will be installed in the Immersion Heater power supply per ECRs 01-00991 &

00992 sometime in 2006.

9. Engine Starting System and Control Logic LO B, I The EDGs are normally maintained in a stancdy con4 ition. Ref. 7(8), Sh. 3 The EDG control logic is configured to cause the engine to start automatically and assume emergency busloads at any time during ,power operation. The engine will also automatically start and run at idle speed under certain conditions. The EDGs can also be started and controlled manually.

a. EDG Start Sequences LO J Instructor must walk through The Diesel Engine has two start sequences based upon logic prints GE 233R0173, Sh.

the initiating signal that is present. The normal start 1A and support prints GE sequence occurs if the EDG is given a NORMAL- 124B2708 sh. 4,223R0173, sh.20, START signal from the MCR. A FAST-START signal and GE 2373901, Sh. 1 & 2 for produces a start sequence that causes the EDG to start RO and SRO license candidates.

and load as quickly as possible to provide emergency This may be done as an exercise.

power to the plant busses.

k:\training\admin\word\262 1\82800013,doc Page 20 of 47

' ContentEkills ActivitiedNotes

1) Normal Start sequence:

Starter motors (2 high-torque DC motors PPT Slide 60-62 connected in series) are connected to EDG DC battery Solenoid operated starter motor pinion gears engage main engine bull gear to turn engine crankshaft. If pinion gear fails to engage after three attempts, an SEQ Fault shuts down the engine.

During normal start sequence, resistors are used Q: What is a hydraulic lock?

to reduce voltage to starting motors, resulting in a slow cranking of the engine or "creeping crank". A: A hydraulic lock occurs when a This slow cranking on the first engine revolution cylinder is flooded with a non-minimizes chance of engine damage if a cylinder compressible fluid such as cooling is hydraulically locked. This condition results in water or lube oil.

engine shutdown and lockout.

If engine does not start after 15 seconds of Q: How many revolutions of the cranking, an SEQ Fault shuts down the engine. engine are required for ignition?

Following engine ignition, the engine accelerates A: Less than one. Ignition of only to idle speed and remains at idle speed for 90 one cylinder will start the engine.

W seconds. The engine then accelerates to full speed.

The generator field is flashed, the governor and voltage regulator establish synchronous conditions with the emergency bus and the EDG output breaker is automatically closed.

2) Fast Start sequence:

a) Starter motors are connected to EDG DC battery.

b) Solenoid operated starter motor pinion gears engage main engine bull gear to turn engine crankshaft. If pinion gear fails to engage after three attempts, an SEQ Fault shuts down the engine.

c) During fast start sequence, the slow cranking of the engine or "creeping crank" described above is bypassed so as to start the engine as quickly as possible.

d) If the engine does not start after 15 seconds of cranking, an SEQ Fault shuts down the engine.

Page 21 of 47

' Content/Skills ActivitiedNotes e) Following ignition, the engine accelerates to full speed in about 15 seconds.

f) The generator field is flashed, the governor and Interim Summary:

voltage regulator establish 4160 VAC, 60 Hz In this section we have discussed EDG output power. EDG output breaker is the function and operation of the automatically closed to energize the emergency EDG electrical auxiliary systems bus. and the basics of the engine starting system. In the next section will discuss EDG start signals and EDG loading sequences.

b. EDG Start Signals LO B, I Ref.7(8), Sh. 3

1) Idle-Start Signals PPT Slide 63 The EDGs will automatically start after a 10-second time delay and accelerate to 400 rpm upon receipt of any of the following signals:

a) RPV Lo-Lo Water Level (86" TAF) b) Drywell High Pressure (3.0 psig) c) Engine Low Lube-Oil Temperature (LOTS set at 85 OF) - Lube oil is warmed by engine heat The EDG will continue running at idle speed until the start signal has been reset or a manual stop has been initiated. Following a 15-minute time delay the engine will shutdown.

2) Fast-Start Signals PPT Slide 64 The EDGs will automatically start and accelerate to 900 WM, and assume emergency busloads in 15-20 seconds upon receipt of any of the following signals:

a) Loss of Power:

Voltage < 65% for 3 seconds on bus 1C (1D) and no bus fault present b) Grid Under-voltage:

Voltage e 92% for 10 seconds on bus 1C (1D) and no bus fault present W c) Emergency Start pushbutton on MCR panel 8F/9F k:\training\adrnin\word\2621\82800013.doc Page 22 of 47

Content/S kilIs ActivitiedNotes d) Note: use of the Emergency Start pushbutton bypasses 1C (1D) bus fault interlocks "d

e) LSP-DG2 Alternate Emergency Start switch (#2 PPT Slide 65 EDG only)

Note: use of the Alternate Emergency Start switch bypasses 1C (1D) bus-tie breaker and bus fault interlocks f) On receipt of a fast-start signal, all engine fault relays are given an automatic reset signal for 10-seconds.

g) The following engine fault signals are bypassed on receipt of a fast-start signal:

Low lube oil pressure Positive crankcase pressure Low cooling water pressure High cooling water temperature h) If a deadline condition on bus 1C (1D) occurs the W

EDG will immediately start or if running at idle speed, it will accelerate to full speed and assume emergency busloads in 15 seconds.

i) If a fast-start signal is present, the EDG cannot be shutdown at the local control station.

c. EDG Automatic Loading Sequences LO K The automatic starting of selected loads following EDG PPT Slides 66-68 fast-start is determined by whether a LOCA condition exists and if an EDG fails to start. Q: Why is load sequencing important?

See Attachment I1 for load sequences A: Load sequencing is important

d. Manual Operation because it prevents overloading The EDGs can be manually operated from either the the EDG when many large loads MCR or locally at the EDG switchgear cubicle. Normal are started simultaneously (as manual operation is from MCR panel 8F/9F. during LOCA).

k:\training\admin\word\262 1\82800013.doc Page 23 of 47

' Content/S kills Activities/Notes Operation of the emergency diesel generators in parallel LO P W with an unstable grid can compromise the ability of the Discuss operation of EDG in diesel generator to function as an emergency power parallel with unstable power grid source due to voltage surge. These surges can cause damage to circuitry, thereby affecting diesel generator operability.

1) Normal Start switch at panel 8F/9F PPT Slides 69-71 a) When the Normal Start switch is placed in the Ops Fundamentals:

RUN position, the EDG will start and accelerate # 1 & #2 EDG control switches are to idle speed (400 RPM) and remain at idle speed grouped close together on Panel for 90 seconds. It then accelerates to full speed 8F/9F. Use self and peer checks to (900 RPM), automatically synchronizes the ensure operation of the correct generator to the 1C (1D) emergency bus and switch for the correct unit.

assumes rated peak load (2750 KW) b) When the Normal Start switch is placed in the STOP position, the EDG automatically unloads to 500 KW, and the EDG output breaker trips automatically. The engine decelerates to idle speed, continues to run for 15 minutes and then shuts down.

2) Manual Operation at the EDG Switchgear Cubicle a) When starting the EDG at the local control station, the Mode Selector Switch (MS) is used to control EDG start, acceleration, and generator field excitation. Synchronization and loading is also performed manually using local controls.

b) Local shutdown is performed by placing the local Start/Stop switch in the STOP position.

c) The local S t d S t o p switch is bypassed by a Fast- Q: Why is the local S t d S t o p Start signal. If a fast start signal is present, switch bypassed by a fast-start placing the local switch in STOP will have no signal?

effect.

A: Assures the EDG will not be

3) Auto-Resynch stopped if needed for emergency power when local testing is in Following restoration of normal power, the progress.

emergency busloads can be shifted from the EDG to the Off-Site power supply by use of the Auto-Resynch pushbutton on MCR panel 8F/9F. Pushing the Auto-Resynch pushbutton produces the following:

k:\training\admin\word\2621\82800013.doc Page 24 of 47

ContentEkills ActivitiedNotes

4) Engine Fault (EN) - Initiates immediate output breaker trip and engine shutdown on any of the d following conditions:

a) Low engine lube oil pressure (bypassed on fast-start signal) b) Positive crankcase pressure (bypassed on fast-start signal) c) Low cooling water pressure. (bypassed on fast-start signal) d) Engine over-speed

10. Controls, Indications, and Alarms LO H Proper operation of the EDGs requires some knowledge and understanding of the controls, interlocks, protective relays, and a l m s associated with the equipment. The following is a brief overview.

a. Local Controls PPT Slides 75-77 Local controls for EDG operation are located in the W

EDG switchgear cubicles inside the EDG buildings

1) Mode Selector Switch ( M S ) - 5 positions, normal Q: When are the EDG local position is AUTO controls used?

a) STOP - shuts-down engine immediately A: Operator training, surveillance tests, and maintenance activities b) IDLE - engine starts and accelerates to idle speed when given local or remote start signal c) RUN - engine accelerates from idle sped to full speed d) EXCITE - energizes generator field flashing circuit and voltage regulator e) AUTO - lines-up EDG control logic for automatic operation

2) Start/Stop Switch a) START - will start EDG if MS switch is in AUTO or IDLE k:\training\admin\word\262 1\82800013.doc Page 26 of 47

roup Heading 4160V STATION POWER EDG 1 T-5-b EDG 1 NOT IN AUTO

ONFIRMATORY ACTIONS:

I CHECK Manual selector switch in automatic. [ I I CHECK AR de-energized.

I CHECK Control Switches OFF Normal. [ I UTOMATIC ACTIONS:

NOTE Unless DG-1 is in auto mode, there cannot be an automatic fast start. CS2 does not affect the fast start capability.

JONE AANUAL CORRECTIVE ACTIONS:

NOTE Refer to Section 3.7 of Technical Specifications for instructions on continued plant operation with an inoperable Diesel Generator.

o INVESTIGATE cause for any out-of-position switch(es).

.. Diesel Generator Cabinet: Manual selector switch, CSI, CS3, CS5 & CS7 Diesel Generator Switchgear: CS2 & CS4

[ I

[ I AANUAL CORRECTIVE ACTIONS: (continued on Page 2 of 21 hbject ELECTRICAL RAP-TSb Page 1 of 2 T-5-b Alarm Response Procedures Revision No: 0

NRC Exam 2006-1 Reactor Operator Exam Key

27. The plant is at rated power with all systems normally aligned.

If a total loss of offsite power, were to occur, which of the following Reactor Building Closed Cooling Water valves would still have electrical power to operate?

0 V-5-147 CCW Inlet Isolation Valve 0 V-5-166 RBCCW Outlet Isolation Valve 0 V-5-167 RBCCW Outlet Isolation Valve

a. V-5-147 and V-5-166 only

b. V-5-147 and V-5-167 only

c. V-5-166 and V-5-167 only

d. V-5-147, V-5-166 and V-5-167 Answer: d Justification: The valves are powered from the following busses:

V-5-147 MCC 1821A V-5-166 MCC 1B21B V-5-167 MCC 1A21 Ll During a loss of offsite power, busses C and D (which will be re-powered from EDGl and EDG2 respectively) load shed. Busses 1A2 and 1B2 always get power. These busses power 1821A, B and 1A21. Therefore, all three RBCCW isolation valves have power. Answer d is correct. The other answers are incorrect since they do not list all valves that have electrical AC power. (see 309.2) (The valve noun names provided above are named as in the procedure.)

400000 K2.02 Knowledge of electrical power supplies to the following: CCW Valves (CFR: 41.7)

OC Learning Objective: 2621.828.0.0016 (262-10444: Describe the interlock signals and setpoints for the effected system components and expected system response including power loss or failed components) 2621.828.0.0035 (07261:

State the location and explain how to manipulate all controls normally operated for the RBCCW System.)

Cognitive Level: Memory or Fundamental Question Type: Bank NRC RO Exam 2006-1 Key Page 45 of 129

AmerGem OYSTER CREEK GENERATING Number An Eukm Company STATION PROCEDURE 309.2 Title Revision No.

Reactor Building Closed Cooling Water System 69 ATTACHMENT 309.2-2 RBCCW ELECTRICAL CHECK OFF LIST POWER BREAKER INITIALS SUPPLY LOCATION POSITION PERFORMI*IV RBCCW Pump 1-1 MCC USIA2 460 V. Swgear C Room Bypass Switch Normal RBCCW Pump 1-2 MCC US1B2 460 V. Swgear C Room Bypass Switch Normal V-5-147 MCC 1B21A Rx Bldg. 25 C I V-5-148 MCC 1B21A Rx Bldg. 25 C V-5-166 MCC 1B21B Rx Bldg. 25 C V-5-167 MCC 1A21 Rx Bldg. 25 C - I-V-5-106 MCC 1B21A Rx Bldg. 25 C -I-REMARKS:

Completed By:

Signature Date Time Verified By:

Signature Date Time Reviewed and Approved By:

os Date Time

~.---/

IndependentVerification (IV)

E2-1

3.7 AUXILIARY ELECTRICAL POWER Applicability: Applies to the OPERATING status of the auxiliary electrical power supply.

Obiective: To assure the OPERABILITY of the auxiliary electrical power supply.

Specification:

NOTE: LCO 3.0.C.2 is not applicable to Auxiliary Electrical Power.

A. The reactor shall not be made critical unless all of the following requirements are satisfied:

1. The following buses or panels energized.

a. 4160 volt buses I C and 1D in the Turbine Building Switchgear Room.

b. 460 volt buses:

USS 1A2, USS 1B2, MCC 1A21, MCC 1B21, Vital MCC 1A2, and Vital MCC IB2 in the Reactor Building 480 V Switchgear Room.

USS 1A3 and USS l B 3 in the Intake Structure.

MCC IAZIA, MCC 1A21B, MCC lB21A, MCC IBZIB, and Vital MCC 1AB2 on Reactor Building Elevation 23 6.

MCC 1A24 and 1B24 in the Boiler House.

c. 208/120 volt panels CIP-3, IP-4, IP-4A, IP-4B, IP-4C and VACP-1 in the Reactor Building Switchgear Room.

d. 120 volt protection panels PSP-1 and PSP-2 in the Lower Cable Spreading Room.

e. 125 VDC Distribution Centers DC-B and DC-C.

125 VDC Power Panels DC-D and DC-F.

125 VDC MCCs DC-1 and DC-2

f. 24 volt DC power panels DC-A and DC-B in the Lower Cable Spreading Room.

2. One 230 KV line (N-line or 0-line) is fully operational and switch gear and both I startup transformers are energized to carry power to the station 4160 volt AC buses and carry power to or away from the plant.

3. An additional source of power consisting of one of the following is in service connected to feed the appropriate plant 4160 V bus or buses:

a. A 230 KV S-line fully operational.

b. A 34.5 KV line fully operational.

OYSTER CREEK 3.7-1 Amendment No.: 4-4,55,8Q,?19;

NRC Exam 2006-1 Reactor Operator Exam Key

28. Which of the following could be indicative of a Reactor Manual Control 2

System control rod movement timer malfunction?

a. The green INSERT light ON for 3.5 seconds during a control rod single notch ROD IN

b. The red WITHDRAW light ON for 3 seconds during a control rod ROD OUT NOTCH

c. The amber SETTLE light ON for 5 seconds following a control rod single notch ROD IN evolution

d. The green INSERT light ON for 1 second during a control rod ROD OUT NOTCH Answer: b Justification: For a single notch-in, the green insert light should be on for 3.5 seconds (See ABN-6, Control Rod Drive System). Answer a is incorrect.

For a rod notch-out, the red withdraw light should be on for 1.5 seconds. The given answer is twice as long. Answer b is correct.

The amber settle light should be on for 5 seconds following the insert or withdraw evolution. Answer c is incorrect.

The green light is on for 1 second during a control rod out notch. Answer d is incorrect.

201002 A3.04 Ability to monitor automatic operations of the REACTOR MANUAL CONTROL SYSTEM including: Rod movement sequence timer malfunction alarm (CFR: 41.7)

OC Learning Objective: 2621.828.0.036 (00726: Given a mode and direction for control rod movement, describe response of the timer, response of the CRD System, system indications and operation of controls.

Cognitive Level: Memory or Fundamental Question Type: New NRC RO Exam 2006-1 Key Page 46 of 129

her- OYSTER CREEK GENERATING Number AI; &'Cbti Cbll'l.(kmy STATION PROCEDURE

'U' ABN-6 Title Revision Control Rod Drive System 2 LIGHT NOTCH IN I NOTCH OUT CONTINUOUS WITHDRAWAL CONTINUOUS INSERT Green INSERT ON for 3.5 sec.

1 ON for 7 sec. ON for Isec.

ON until switch is released.

I

[ I Immediately Wlin 2 sec. of after positioning positioning the ROD Red ROD CONTROL NIA NIA Withdraw CONTROL switch, ON until switch, ON for switch is 1.5 sec.

released.

~~~

Wlin 3 sec Immediately Immediately Wlin 3 sec of of after releasing after releasing releasing the releasing Amber ROD the ROD the ROD Settle the ROD CONTROL CONTROL CONTROL [ I CONTROL switch, ON for 5 switch, ON for switch, ON for 5 switch, ON sec.

5 sec. sec.

for 5 sec.

7. If all attempts to withdraw the rods are unsuccessful, then REFER to Procedure 235, Determination and Correction of Control Rod Drive System Problems. [ I 17.0

NRC Exam 2006-1 Reactor Operator Exam Key

29. Which of the following would require that a Technical Specification action

.--' statement be applied?

a. While at power, a recirculation pump was started in an idle loop whose loop temperature was 40" F less than reactor coolant temperature

b. While at power (5-lOOp), a single recirculation pump tripped, and the loop was placed in an IDLE condition in accordance with procedure

c. During a startup, while on Range 10 of the Intermediate Range Monitors, a malfunction in the Master Recirc Speed Controller lowered recirculation flow to 38x1O6 Ib/hr

d. While at power, an event occurred which required that a single recirculationscoop tube be placed into local manual control in accordance with procedure Answer: c HANDOUT: TECH SPECS 3.3 Justification: IAW TS 3.3.C2, an idle recirculation pump shall not be started unless the loop temperature is within 50" F of the reactor coolant temperature.

Since this answer gave 40" F, the operation is allowed by TS and no TS entry is required. Answer a is incorrect.

IAW TS 3.3.F, a single idle recirculation loop is allowed with no further actions.

Since there is no TS entry required, answer b is incorrect.

IAW TS 3.3.H.2, the minimum required recirculation flow rate while on IRM Range 10 is 39.65~1 O6 Ib/hr. Since flow was below this minimum, a TS action would be required. Answer c is correct (this is also stated in procedure 301.2, Reactor Recirculation System).

Placing a recirculation MG set scoop tube in local manual control is not mentioned in TS, and therefore requires no TS entry. Answer d is incorrect.

202002 2.1.33 (Recirculation Flow Control)

Ability to recognize indications for system operating parameters which are entry-level conditions for technical specifications. (CFR 41.10 / 43.2 / 43.3)

OC Learning Objective: 2621.850.0.0090 (016581: Identify whether or not a Tech Spec or License Limit has been exceeded.)

Cognitive Level: Comprehensive or Analysis NRC RO Exam 2006-1 Key Page 47 of 129

NRC Exam 2006-1 Reactor Operator Exam Key Question Type: Modified NRC RO Exam 2006-1 Key Page 48 of 129

\

4

. L E.

o Reactor Coolant Ouality w

P$ ':

,4+-

.1.

1. The reactor coolant quality during power operation with steaming rates to the turbine-condenser of less than 100,000 pounds per hour shall be limited to:

conductivity 2 us/cm[s=mhos at 25°C (77"FI chloride ion 0.1 ppm

2. When the conductivity and chloride concentration limits given in 3.3.E. 1 are exceeded, an orderly shutdown shall be initiated immediately, and the reactor coolant temperature shall be reduced to less than 212°F within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

3. The reactor coolant quality during power operation with steaming rates to the turbine-condenser of greater than or equal to 100,000 pounds per hour shall be limited to:

conductivity 10uS/cm [S=mhos at 25°C (77"F)I chloride ion 0.5 ppm

4. When the maximum conductivity or chloride concentration limits given in 3.3.E.3 are exceeded, an orderly shutdown shall be initiated immediately, and the reactor coolant temperature shall be reduced to less than 212°F within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

5. During power operation with steaming rates on the turbine-condenser of greater than or equal to 100,000 pounds per hour, the time limit above 1.0 uS/cm at 25°C (77°F) and 0.2 ppm chloride shall not exceed 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months for any single incident.

4

6. When the time limits for 3.3.E.5 are exceeded, an orderly shutdown shall be initiated within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

F. Recirculation Loop Operability

1. During POWER OPERATION, all five recirculation loops shall be OPERATING except as specified in Specification 3.3.F.2.

2. POWER OPERATION with a maximum of two IDLE RECIRCULATION LOOPS or one IDLE RECIRCULATIONLOOP and one ISOLATED RECIRCULATIONLOOP is permitted. The reactor shall not operate with two ISOLATED RECIRCULATION LOOPS.

a. With one ISOLATED LOOP the following conditions shall be met:

1. The AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR) as a function of average planar exposure, at any axial location shall not exceed 98% of the limits specified in 3.10.A. The action to bring the core to 98% of the AF'HLGR limits shall be completed prior to isolating the recirculation loop.

4 OYSTERCREEK 3.3-3 Corrected Letter dated 8/7/2000 Amendment No: 42,93,135, 140,212

\ ?

il

, e

. 3 ?-#-.-

i-

2. The circuit breaker of the recirculation pump motor generator

.~ . . ~

set associated with an ISOLATED RECIRCULATION LOOP __L.--.--

shall be open and defeated from operation.

3. An ISOLATED RECIRCULATION LOOP shall not be returned to service unless the reactor is in the COLD SHUTDOWN condition.

b. When there are two inoperable recirculation loops (either two IDLE RECIRCULATION LOOPS or one IDLE RECIRCULATION LOOP and one ISOLATED RECIRCULATION LOOP) the reactor core thermal power shall not exceed 90% of rated power.

3. If Specifications 3.3.F.1and 3.3.F.2are not met, an orderly shutdown shall be initiated immediately until all operable control rods are fully inserted and the reactor is in either the REFUEL MODE or SHUTDOWN CONDITION within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

4. With reactor coolant temperature greater than 212°F and irradiated fuel in the reactor vessel, at least one recircuIation loop discharge valve and its associated suction valve shall be in the full open position.

5. If Specification 3.3.F.4is not met, immediately open one recirculation loop discharge valve and its associated suction valve.

6. With reactor coolant temperature less than 212°F and irradiated he1 in the E reactor vessel, at least one recirculation loop discharge valve and its associated u suction valve shall be in the full open position unless the reactor vessel is flooded to a level above 185 inches TAF or unless the steam separator and dryer are removed.

L./

OYSTER CREEK 3.3-3a Corrected Letter dated 8/7/2000 Amendment No: 135, 140,212

G. Primarv Coolant System Pressure Isolation Valves Applicabil itv:

Operational conditions - Startup and Run Modes; applies to the operational status of the primary coolant system pressure isolation valves.

Obiective:

To increase the reliability of primary coolant system pressure isolation valves thereby reducing the potential of an inter-system loss of coolant accident.

Specification:

1. During reactor power operating conditions, the integrity of all pressure isolation valves listed in Table 3.3.1 shall be demonstrated. Valve leakage shall not exceed the amounts indicated.

2. If Specification 1 cannot be met, an orderly shutdown shall be initiated and the reactor shall be in the cold shutdown condition within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

H. Renuired Minimum Recirculation Flow Rate for Operation in IRM Ranize 10

1. During STARTUP mode operation, a minimum recirculation flow rate is required before operating in IRM range 10 to ensure that technical specification transient MCPR limits for operation are not exceeded. This minimum flow rate

'.j is no longer required once the reactor is in the RUN mode.

2. 39.65 x 1 O6 lbhr is the minimum recirculation flow rate necessary for operation in IRh4 range 10 at this time. This flow rate leaves sufficient margin between the minimum flow required by the RWE analysis performed and the minimum flow used while operating in IRM range 10.

NRC Order Dated April 20, 1981 OYSTER CREEK 3.3-4 Corrected Letter dated 8/7/2000 Amendment No: 15,42,7 1 , 2 12

NRC Exam 2006-1 Reactor Operator Exam Key

30. Which of the following power losses would cause the Rod Worth Minimizer

.4 to be INOPERABLE due to the loss of control rod position information?

a. Protection System Panel A

b. Instrument Panel 4A C. Continuous Instrument Panel CIP-3

d. VACP-1 Answer: c Justification: Of the listed power supplies, only continuous instrument panel 3 provides electrical power to the control rod position indications. All other listed power supplies do not provide this power. Answer c is correct. (See ABN-58, GU 3C-733-11-005) 214000 K1.01 Knowledge of the physical connections and/or cause/effect relationships between ROD POSITION INFORMATION SYSTEM and the following: RWM: Plant-Specific (CFR: 41.2 to 41 -9)

OC Learning Objective: 2621.828.0.0041 (10444: Describe the interlock signals and setpoints for the effected system components and expected system response including power loss of failed components.)

i/

Cognitive Level: Memory or Fundamental Question Type: New NRC RO Exam 2006-1 Key Page 49 of 129

AmerGen-An Exc1o.i Company I OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-58 LJ Title Revision No.

Instrument Power Failures 1 ATTACHMENT ABN-58-1 (continued)

Continuous Instrument Panel (CIP)-3 Breaker Cable Number Desiqnation Load Designation 1 11-308 Panel 8R, Power Supply for DCS (Primary power)*

Temporary FW & CRD Return Nozzle Instr.,

ARI Hi Pressure Logic (1.3 KVA)

Note: DCS Control will transfer from DCC-X to DCC-Y 11-401 Relay Cubicle RY22-a (.2 KVA)

Spare 11-402 Relay Cubicle RY22-B (.2 KVA)11-235 Rod Worth Minimizer NC 140 (3.2 KVA)11-403 Relay Cubicle RY22-C (.2KVA)

Spare 11-404 Relay Cubicle RY22-D (.2 KVA)11-180 4F Neutron Monitor Recorders, Digitals, 6.3 V LTG SDlV B Train Valve IND (.I5 KVA) b' 10 11-49 Turb. Elec. Hyd. Press. Reg. (.26 KVA) 11 11-405 Relay Cubicle RY22-E 12 11-165 Panel 2R Vent & Eff. RAD MON, SGTS Timer 18TM-1 (.2 KVA) 13 11-191 Panel I 1F NS03A & B, NS04A & B Logic, V-6-395 Logic (.793 KVA) 14 11-200 Area RAD Monitor Recorders ROO6 A & B (.I 7 KVA) 15 11-540 ER2 Rod Pos Ind Relay (2.0 KVA) 16 11-285 IOF Process Rad Mon Recorders, Off Gas isolation logic &

Solenoid Power (.15 KVA) 17 11-675 Spare (6XR) 18 Spare 19 11-182 3F Recorders and Digitals, C/U System Flow and Pressure Controllers, CRT atop 3F 20 11-334 Panel 5F Feed Reg Valve Position Indicator, Flange Leak Detection Valves, Condenser Valve Local Permissive Logic, Fuel Zone C & D "ON" lites 21 Spare 22 Spare 23 Spare 24 Spare REF: DWG. GU-3C-733-11-005

..-' DWG. BR 3159 E1-3

n ~ c I

NRC Exam 2006-1 Reactor Operator Exam Key

31. The plant is at 2% power during a startup, with drywell inerting in-l.J progress. Drywell oxygen concentration is currently 9% and lowering slowly.

If a spurious high drywell pressure signal initiated Standby Gas Treatment system, which of the following is correct?

a. Drywell pressure will rise due to the nitrogen addition but venting at a slower rate through Standby Gas Treatment

b. Drywell pressure will lower due to nitrogen addition isolation and venting through Standby Gas Treatment system C. The drywell oxygen indicator shows a stable valid indication due to the isolation of nitrogen and DW vent and purge valves

d. The drywell oxygen indicator no longer shows a valid indication due to the isolation of the drywell oxygen sampling system Answer: d With a high drywell pressure isolation signal, nitrogen into the drywell is isolated (V-23-14, -14), and the drywell atmosphere to RB HVAC isolate (V-27-1, -2). On the same isolation signal, the drywell oxygen sample primary containment isolation valves also close. Therefore, nitrogen inleVoutlets of the primary containment are isolated, and the oxygen sampling system is also isolated.

u Answer d is correct.

Answer a is incorrect since nitrogen addition is isolated. Answer b is incorrect since drywell venting is isolated. Answer c is incorrect since the oxygen reading is not valid since the oxygen sampling system is isolated. (see BR2011, 13432.19-1, M0012, 3E-666-21-1000, USAR Table 6.2-12; 312.9) 223001 A1.06 Ability to predict and/or monitor changes in parameters associated with operating the PRIMARY CONTAINMENT SYSTEM AND AUXILIARIES controls including:

Oxygen Concentration CFR: 41 5 )

OC Learning Objective: 2621.828.0.0032 (00394: Given auto isolation signals, list or identify causes, system responses, and affected primary containment system components.)

Cognitive Level: Comprehensive or Analysis Question Type: New NRC RO Exam 2006-1 Key Page 50 of 129

Procedure 312.9 Rev. 37 DCC File No. 20.1812.0010 ATTACHMENT 312.9-3 PRIMARY CONTAINMENT ISOLATION VALVES (CM-1)

Section 4.3 SYSTEM VALVE NO. NOTES DW Vent V-27-1 173 V-27-2 1,3 DW Purge V-27-3 V-27-4 Torus Vent V-28-17 V-28-18 DW 2" Vent Bypass V-23-2 I 1 V-23-22 1 Torus 2" Vent Bypass V-28-47 1 N2 Purge V-23-13 V-23-14 V-23-15 V-23-16

.d N2 Makeup V-23-17 V-23-18 V-23-19 V-23-20 DWEDT v-22-1 1 v-22-2 1 DW Sump V-22-28 1 V-22-29 1

- DW 0 2 Sample Valves V-38-9 V-38-10 V-38-16 V-38-17

--, Torus 0 2 Sample Valves V-38-22 V-38-23 E3-1

Procedure 312.9 Rev. 37 DCC File No. 20.1812.0010 ATTACHMENT 312.9-3 (continued)

PRIMARY CONTAINMENT ISOLATION VALVES Section 4.3 NOTES

1. Automatically isolates on high Drywell pressure low low Reactor water level.

2. Automatically isolates on high Drywell pressure ytJi low low Reactor water level or triple low water level.

3. Automatically isolates on primary containment high radiation.

4. -

No valve position indication available. Place control switch on Panel IOF to CLOSE and confirm no flow at local Panel, RB-23.

5. Valves will automatically open as needed to provide vacuum relief.

6. Indication on 4R and I 1F.

7. Automatically isolates on high main steam line flow, high trunion room temperature, low-low Reactor water level or low Reactor Pressure Vessel pressure.

E3-3

NRC Exam 2006-1 Reactor Operator Exam Key

32. The plant is starting-up following a refuel outage. The startup is continuing

.- with no noted problems, in accordance with procedure 201, Plant Startup.

The current conditions exist:

RPV pressure is 150 psig Turbine warming is in-progress The very next step is to open the turbine control valves and turbine stop valve #2 The Mechanical Pressure Regulator is set at 250 psig Turbine Bypass Valves are CLOSED Which of the following lists the method to open turbine control valves and turbine stop valve #2 for turbine warming?

Open the turbine control valves by using (1) and open turbine stop valve #2 by usinq (2) .

a. (1) the BYPASS VALVE OPENING JACK switch (2) the LOAD LIMIT CONTROL switch

b. (1) the MPR Control Switch (2) the SPEED LOAD CHANGER switch 4 c. (1) the BYPASS VALVE OPENING JACK switch (2) the MAIN STOP VALVE NO. 2 INTERNAL BYPASS switch

d. (1) the LOAD LIMIT CONTROL switch (2) the MAIN STOP VALVE NO. 2 INTERNAL BYPASS switch Answer: c Justification: IAW 315.1, Turbine Generator Startup, given that the turbine bypass valves are closed, and the , placing the BYPASS VALVE OPENING JACK in RAISE will open the turbine control valves. Then the stop valve is opened to admit steam by placing the MAIN STOP VALVE NO. 2 INTERNAL BYPASS in RAISE position. If the turbine bypass valves were open, then the placing the load limit control switch to raise would open the turbine control valves; and stop valve number 2 bypass would open the stop valves. Answer c is correct.

245000 K5.02 Knowledge of the operational implications of the following concepts as they apply to MAIN TURBINE GENERATOR AND AUXILIARY SYSTEMS : Turbine operation and limitations (CFR: 41.5)

-u NRC RO Exam 2006-1 Key Page 51 of 129

NRC Exam 2006-1 Reactor Operator Exam Key

j OC Learning Objective: 2621.828.0.0050 (10446: Identify and explain system operating controldindications under plant operating conditions.)

Cognitive Level: Memory or Fundamental Question Type: Modified NRC RO Exam 2006-1 Key Page 52 of 129

AmerCenx OYSTER CREEK GENERATING Number An txclon Company STATION PROCEDURE 315.1 I

J Title Revision No.

Turbine Generator Startup 59 3.3.12 NOTE This condition is indicative of a normal plant startup where a plant heatup is in progress and the MPR setpoint is being maintained approximately 100 psig above Reactor pressure.

-IF the MPR is being maintained approximately 100 psi above Reactor pressure, AND Turbine Bypass Valves are not open, THEN PERFORM the following:

1 3.3.12.1 OPEN the load limit to the Turbine pre-warming

'v' mark on the load limit position indicator by placing the switch at Panel 8F in the RAISE position. [ I 3.3.12.2 Control Valves will start operating at about 5-10%

Bypass Valve Jack stroke.

Verv slowlv OPEN the Bypass Valve Opening Jack using the Bypass Valve Opening Jack control switch in the RAISE position at Panel 7F until one of the following occurs:

0 Movement is noticed on the Bypass Valve Valve No. 1 Position Selsyn indicator, [ I Red Bypass Valve Position light for # I Bypass Valve iIluminates. [ I

-v' 10.0

AmerGenl OYSTER CREEK GENERATING Number Ar txc:onCompany STATION PROCEDURE 315.1 4

Title Revision No.

Turbine Generator Startup 59 3.3.12.3 CLOSE the Bypass Valve Opening Jack using the Bypass Valve Opening Jack control switch in the LOWER position until one of the following occurs:

0 Red light extinguishes. [ I 0 Selsyn returns to 0% on the stroke indicator. [ I 3.3.1 2.4 VERIFY the Control Valves are open 30-40%

as indicated on the Turbine Valves Position Recorder at Panel 14R. [ I 3.3.12.5 E control valves are open more than 40%,

THEN PERFORM the following:

a. Fully CLOSE the Bypass Valve Opening Jack. [ I

b. Slightly LOWER the load limit setpoint as indicated on the load limit position indicator by placing the Load Limit Control Switch at Panel 8F in the LOWER position. [ I

c. PERFORM Steps 3.3.12.2 through 3.3.12.4. E l 3.3.12.6 E Control Valves are open less than 30%,

THEN PERFORM the following:

a. RAISE slightly the load limit setpoint as indicated on the load limit position indicator at Panel 8F. [ I

b. PERFORM Steps 3.3.12.2 through 3.3.12.4. [ I 11.0

AmerGenl OYSTER CREEK GENERATING Number An Ew'm Cornpany STATION PROCEDURE 315.1

.4 Title Revision No.

Turbine Generator Startup 59 3.3.13 COMMENCE warming the Steam Chest and High Pressure Turbine as follows:

3.3.13.1 NOTE The designed Lift Pumps are being stopped to minimize the potential for the Turbine rolling off the Turning Gear during warmup.

STOP individual Lift Pumps in the following sequence as directed by the Operations Supervisor:

1. Pumps 3-5 (Motor No. 2, MCC IA12, B03) [ I

2. Pumps 1-6 (Motor No. 3, MCC lB12, D05) [ I

3. Pumps 2-4 (Motor No. 1, MCC 1A12, B02) [ I 3.3.1 3.2 NOTE If Turbine shell warming is started at an elevated Reactor pressure, small changes with Stop Valve No. 2 bypass position will have large effects on shell warming and possibly roll the Turbine off the Turning Gear.

CAUTION Exceeding 100 psig extraction stm to 1st Stage Reheater Pressure Indicator at Panel 7F, during shell warming may cause a Reactor scram due to Stop Valves being closed at greater than 30 percent power.

Throttle OPEN the No. 2 Stop Valve Internal Bypass using the Main Stop Valve No. 2 Internal Bypass control switch in the RAISE direction in order to slowly raise the pressure in the high pressure Turbine shell to about 60 to 90 psig as read on Extraction Stm To IS' Stage Reheater Pressure indication at Panel 7F. [ I 12.0

NRC Exam 2006-1 Reactor Operator Exam Key

33. The plant is at rated power with all systems normally aligned and no u equipment out of service. You have just received a report that fire detector R5D9 (Reactor Building 51 North, Zone 1) failed its surveillance test to detect and alarm a fire. The SRO has declared this fire detector inoperable. (There are no alarms locked-in from this inoperable fire detector).

Your initial investigation shows that there are 8 fire detectors on RB 51 North, Zone 1, and 9 fire detectors on RB 51 North, Zone 2.

Which of the following states how this inoperable fire detector effects the ability of the fire protection system to detect fires in RB 51 North and to actuate Deluge System #5?

a. The fire protection system can still detect fires and actuate the fire protection system for mitigation; no compensatory measures are required

b. The fire protection system can still detect fires but CANNOT actuate the fire protection system for mitigation; no compensatory measures are required

c. The fire protection system CANNOT detect fires nor actuate the fire protection system for mitigation; an hourly fire watch patrol must be established

. I

d. The fire protection system CANNOT detect fires nor actuate the fire V

protection system for mitigation; a continuous fire watch must be established Answer: a HANDOUT: PROCEDURE 333 (Plant Fire Protection System, Attachment 333-15) AND PROCEDURE 101.2 (OYSTER CREEK SITE FIRE PROTECTION PROGRAM, Attachment 101.2-3)

Justification: IAW procedure 645.6.031 (Attachment 645.6.031 -2), there are 8 fire detectors in 51 RB North Zone 1 (which includes the given inoperable detector).

As stated in the stem, there are no other inoperable detectors. Therefore, all other fire detectors in Zone 1, and all those in Zone 2 of 51 RB North will alarm at the fire panels when activated. Each fire detector is independent of the others to activate the alarms on the panels.

IAW procedure 333 (Attachment 333-15) actuation of Deluge System 5 (for 51 RB North) requires only 1 detector from 51 RB North Zone 1 to actuate, and 1 detector from 51 RB North Zone 2 to actuate. Therefore, one inoperable detector will still allow the fire protection system to detect and mitigate a fire in 51 RB North.

NRC RO Exam 2006-1 Key Page 53 of 129

NRC Exam 2006-1 Reactor Operator Exam Key i

i Procedure 101.2 tells us that 6 detectors are required for RB 51' North Zone 1, and 7 detectors are required for RB 51 North Zone 7. With the number of operable fire detectors less than required, a fire watch patrol must be established. Therefore, fire detection in RB 51' North is still operable and functional, and no compensatory actions are required. Answer a is correct.

Since the system is still able to mitigate a fire, answer b is incorrect. Since the system is still able to detect and mitigate a fire in the area, no compensatory measures are required. Answers c and d are incorrect.

286000 K3.01 Knowledge of the effect that a loss or malfunction of the FIRE PROTECTION SYSTEM will have on following: The ability to detect fires (CFR: 41.7)

OC Learning Objective: 2621.828.0.001 9 (286-10445: Given a set of system indications or data, evaluate and interpret them to determine limits, trends, and system status.)

Cognitive Level: Comprehensive or Analysis Question Type: New NRC RO Exam 2006-1 Key Page 54 of 129

DCC FILE: 20.2707.0008 OYSTER CREEK GENERATING I STATION PROCEDURE 645.6.031

..- - ~

Title Fire Detection System Alarm Circuitry Test for Reactor ATTACHMENT 645.6.031-2 Ionization and Photoelectric Detector Alarm Circuitrv Test Data Deluge System #5 & #6 - Rx. Blds. 51 Step 6.5.3.2 LFAP #I FAMP A Detector Alarm Alarm Alarm POC ZH-30 CP-31 ZA-3 1 CP-30 (Red LED) (Red Light)

Illuminated Location Initial Initial Initial Initial R5D9 R5D10 R5D11 51 Elev.

Zone North1 I-FR5D12 R5D13 R5D15 R5D - Br Tool Room E2-I

An lxebn Company 1

I OYSTER CREEK GENERATING STATION PROCEDURE I umber 333

%u Title Revision No.

Plant Fire Protection System 83 ATTACHMENT 333-15 (conti nued)

EQUIPMENT ACTUATED BY FIRE PANELS FIRE PANEL REFERENCE INIT1AT1NG AFFECTED EQUIPMENT NUMBER DRAWING EVENT LFAP # I (Reactor AP PE-521 Sh. 1 1) Actuate one 1) Actuate Deluge System #5 Building) JC 19635 Sh. 2 detector from Rx Bldg 51 North side Zone 1 AND

2) Actuate one detector from Rx Bldg 51 North side Zone 2 OR

3) Actuate manual pull station LFAP # I (Reactor AP PE-521 Sh. 1 1) Actuate one 1) Actuate Deluge System #6 Building) JC 19635 Sh. 2 detector from Rx Bldg 51 South side Zone 1 AND

2) Actuate one detector from Rx Bldg 51 South side Zone 2 OR

3) Actuate manual pull station E l 5-2

AmerGenY I OYSTER CREEK GENERATING STATION PROCEDURE Number 101.2 I

.v' Title Revision No.

Oyster Creek Site Fire Protection Program 54 ATTACHMENT 101.2-3

( continued )

TABLE 1 FIRE DETECTION INSTRUMENTATION Fire Required Area/ Zone Location Detection Zone # of Detectors RB-FZ-1A Rx. Bldg. 119' elev. Sprinkler Sys. #10 1 (WFS)

RB-FZ-1B 'I 95' I1 NA 24*

RB - FZ- 1C I' 75' 'I NA 22*

I' 75' I' Sprinkler Sys. #11 1 (WFS)

RB - FZ- 1D 'I 51' " RKOl/RKO2 2 I1 51' 'I 1 - North 6 + y I' 51' I' 2 - North 7 +

'I 51' I' 1 - South 6 +

I' 51' 'I 2 - South 6 +

RB - FZ- 1G " 38'/51' I' Shutdown Pump Rm. 7 RB-FZ-1E 'I 23' 'I 1 - North 7 +

'I 23' 'I 2 - North 6 +

'I 23' I' 1 - South 6 +

'I 23' I' 2 - South 6 +

RB-FZ-1F I' -19' It NA 4 (1 per corner room) b-- TB - FA-3A 4160 Swgr. Rm. Vaul t I1 C I1 1 TB- FA-3B 'I Vault I1 D I1 1 TB- FZ-11C 11 Gen. Area 5+

TB- FA-26 11 llC1l Battery Rm. 1 OB-FZ-4 Cable Spread Rm. 4A-Zone 1 3 +

1' 4A-Zone 2 3 +

'I 4B-Zone 3 4 +

'1 4B-Zone 4 5 +

OB-FZ-5 Control Room Gen. Area 6 11 A-Zone 1 3 +

'I A-Zone 2 3 +

I1 B-Zone 1 7*+

II B-Zone 2 7*+

11 C-Zone 1 1 +

11 C-Zone 2 1 +

11 Duct 1 OB - FZ- 6A 480 Swgr.** Rm. Zone 3 7 +

I' Zone 4 6 +

E3-16

NRC Exam 2006-1 Reactor Operator Exam Key

34. The plant is at rated power with all systems normally aligned and no equipment out of service.

Which of the following Emergency Operating Procedures has an entry condition that is available through the plant process computer and is not read on the control room panels?

a. EMG-3200.01A1RPV Control - NO ATWS

b. EMG-3200-01B, RPV Control -With ATWS

c. EMG-3200.02, Primary Containment Control

d. EMG-3200.11, Secondary Containment Control Answer: c Justification: Indications RPV water level, RPV pressure, drywell pressure, and reactor power (entry conditions into RPV Control - No ATWS, and RPV Control -

With ATWS) can be found on the control room panels. Answers a and b are incorrect.

Indications for torus water temperature, drywell pressure, torus water level, and primary containment hydrogen concentration (entries for Primary Containment Control) can be found on control room panels. Bulk drywell temperature (also an (

entry into Primary Containment Control) is available only on the plant process computer (SPDS - Containment Conditions screen). (When the PPC is not operable, DWT can be calculated from plant indications, but the question stem states that no equipment is 00s.)

Indications of the Alert emergency classification for radioactivity release are found from control room panel indications, and from other data sources, including procedures. Indications of an isolation condenser tube leak are found from control room panel indications and alarms. Answer d is incorrect.

2.1.19 Ability to use plant computer to obtain and evaluate parametric information on system or component status. (CFR: 41.1 0)

OC Learning Objective: 2621.863.0.0007 (02233: Discuss the relevance of information shown on the PPC SPDS displays to the implementation of the SBEOPs. )

Cognitive Level: Memory or Fundamental Question Type: New NRC RO Exam 2006-1 Key Page 55 of 129

NRC Exam 2006-1 Reactor Operator Exam Key

35. The plant is starting-up after a 5-day forced outage. The following i

conditions exist:

0 The MODE Switch is in STARTUP, with control rod withdrawals in-progress 0 IRMs 11, 12, 15,16, 18 read 72-74 on Range 1 0 IRMs 13,14, and 17 read 9 - 10 on Range 2 A malfunction in the IRM drive circuitry caused IRM 13 to withdraw to the full-out position.

Which of the following states the effect on the plant and the required Operator actions to continue withdrawing control rods?

a. There are panel annunciators ONLY; withdrawing control rods may continue without any other control panel manipulations

b. There are panel annunciators and a rodblock from IRM downscale ONLY; bypassing the IRM is required to continue withdrawing control rods C. There are panel annunciators and a rodblock from IRM downscale AND IRM detector position; bypassing the IRM is required to continue withdrawing control rods

. I

'W' d. There are panel annunciators, a rodblock and a '/2 scram; bypassing the IRM and resetting the '/2 scram is required to continue withdrawing control rods Answer: c Justification: The following I RM parameters provide roblocks only (no scram input): IRM downscale (in REFUAL and STARTUP; bypassed in Range 1 or in RUN), detector not fully inserted (bypassed in RUN), and IRM high (bypassed in RUN). When the IRM comes off the full-in position, a rodblock is instituted (plus panel annunciators). It is expected that the IRM will also go downscale as it drives to the fully withdrawn position (downscale also gives a rodblock except in Range 1). There are no '/2 scrams from these conditions. Therefore, to continue to move control rods, IRM 13 (which is instituting a rodblock both from downscale and IRM position) must be bypassed. Answer c is correct.

Answer a is incorrect since it does not list rodblocks. Answer b is incorrect since it does not list all rodblocks. Answer d is incorrect since no '/2 scram occurs. (See RAP-H7a, 237E912 and 796E212).

2.2.2 Ability to manipulate the console controls as required to operate the facility between shutdown and designated power levels. (CFR: 45.2)

NRC RO Exam 2006-1 Key Page 56 of 129

NRC Exam 2006-1 Reactor Operator Exam Key 215003 K3.02 il Knowledge of the effect that a loss or malfunction of the INTERMEDIATE RANGE MONITOR (IRM) SYSTEM will have on following: Reactor manual Control (CFR: 41.7 / 45.4)

OC Learning Objective: 2621.828.0.0029 (10449: State the function and interpretation of system alarms, alone and in combination, in accordance with system RAPS.)

Cognitive Level: Comprehensive or Analysis Question Type: New NRC RO Exam 2006-1 Key Page 57 of 129

CONTROL RODSlDRlVES R ROD BLOCK CAUSES: SETPOINTS: ACTUATING DEVICES:

I RM/APRM: IRM level greater than 106/125 scale with APRM level less than 2% and mode switch in STARTUP or REFUEL.

APRM APRM level less than 2/150 Downscale: scale with mode switch in RUN.

IRM IRM level less than 51125 Downscale: scale except in Range 1.

SRM High: SRM level greater than 1 x I O 5 and mode switch in STARTUP or REFUEL (below IRM Range 8).

Timer Failure of timer switch during Malfunction: rod out sequence.

APRM High: APRM level greater than (.9 x w + 60.1 with a Maximum Value of 115%

I RM IRM detector not full in with Detector mode switch in STARTUP or Position: REFUEL.

(Continued on Page 14 of 14)

Subject Procedure No. I Page 13 of 14 NSSS RAP-H7a H-7-a Alarm Response - 1 Procedures I Revision No: 2 I

NRC Exam 2006-1 Reactor Operator Exam Key

36. The plant is shutdown for a refuel outage. A fuel shuffle is in-progress.

Even though continuous communication is maintained between the Refuel Senior Reactor Operator and the Control Room Licensed Operator during core alterations, which of the following, as stated by procedure 205.0, Reactor Refueling, lists when a communication must be made between the Control Room Licensed Operator and the Refueling Senior Reactor Operator?

a. When a blade guide is vertically aligned and is being lowered into the core

b. When a new fuel bundle is vertically aligned and is being lowered into the core

c. When an irradiated fuel bundle is vertically aligned and is being lowered into the spent fuel racks

d. When a control rod is vertically aligned and is being lowered into the core Answer: b Justification: IAW procedure 205.0, (section 7.3.1) Reactor Refueling, a communication between the Refuel SRO and the CRO is required at the commencement and completion of each move, and whenever a bundle enters or exits the core. None of the answers provided are the commencement or

completion of a step. Answer b does meet the procedural requirement in that a bundle is entering the core. Answer b is correct.

Procedure 205.0 does not require a communication regarding the blade guide into the core. Answer a is incorrect.

Procedure 205.0 does not require a communication regarding the fuel placement into the fuel pool racks. Answer c is incorrect.

Procedure 205.29, Control Rod Blade Removal and Replacement, does not require a communication as the blade enters the core. Answer d is incorrect.

2.2.28 Knowledge of new and spent fuel movement procedures. (CFR: 43.7 )

OC Learning Objective: 2621.81 2.0.0003 (00323: State the responsibilities of the following personnel during refueling operations IAW procedure 205.0: 1) Reactor Engineer; 2) Shift Manager; 3) Control Room Licensed Operator; 4) Bridge Operator; 5) Fuel Move Checker; 6) Fuel Handling Director.)

NRC RO Exam 2006-1 Key Page 58 of 129

NRC Exam 2006-1 Reactor Operator Exam Key W

Cognitive Level: Memory of Fundamental Question Type: New NRC RO Exam 2006-1 Key Page 59 of 129

AmerGen, OYSTER CREEK GENERATING Number A r Cxekn Company STATION PROCEDURE 205.0 Ll Title Revision No.

Reactor Refueling 65 7.3 Control Room Licensed Operator (CRO) is responsible for:

NOTE A core alteration is the addition, removal, relocation a other manual movement of fuel controls in the reactor core. Movement of control rods with the control rod drive hydraulic system is not considered a core alteration 7.3.1 Maintaining communication with the Fuel Handling Director (FHD), an SRO licensed operator on the refueling bridge while core alterations are in progress. The following communications are required between the CRO and the Refueling SRO:

7.3.I .1 Commencement and completion of each move 7.3.1.2 Whenever a bundle enters exits the core 7.3.2 Monitor communications between the Control Room and the bridge SRO to detect possible imminent errors 7.3.3 Record SRM reading and the time each move is completed u

7.3.4 Continuously monitoring, during core alterations, all SRM channels for indication of approach to inadvertent criticality.

7.3.5 Notifying the bridge and the Shift Manager immediately if any operable SRM has a sustained count rate of less than Icps.

7.3.6 Notifying the bridge anytime that the refueling interlock rod block fails to activate when the bridge is known to be over the reactor cavity.

7.3.7 Ensuring all pertinent information regarding refueling activities, including refueling interruptions, problems refuel bridge discrepancies, is properly documented in the Control Room Log.

34.0

NRC Exam 2006-1 Reactor Operator Exam Key

37. The plant is at rated power with all systems normally aligned, with the

.-4 following exception:

0 The Reactor Water Cleanup System has been removed from service to support system repair (electrical)

The outside containment motor operated isolation valve is to be used as a clearance boundary. IAW OP-MA-109-101, Clearance and Tagging, this is allowed as long as the following conditions are met:

1. The valve control station is tagged

2. The electrical energy source is removed

3. The valves handwheel is tagged Given that the valve is located in a high radiation area, which of the following states who can waive the 3rdrequirement above, due to A U R A considerations?

a. The Unit Supervisor

b. The Radiation Protection Technician

c. The Cleanup System Engineer

d. The Clearance Writer (Reactor Operator)

Answer: a L-.

Justification: OP-MA-109-101, Clearance and Tagging, states that the above requirement shall only be waived by the clearance approver (who is a first line supervisor or above) or Shift Management when radiological or hazardous conditions exist. The same procedure defined clearance approver as an individual trained and qualified to approve clearances; a clearance approver should be a currently or previously licensed SRO. OP-OC-100, Oyster Creek Conduct of Operations provides the following for Shift Management: normally consists of an SRO licensed Shift Manager, an SRO licensed Unit Supervisor, and an SRO licensed Field Supervisor. Therefore, answer a is correct. All other answers are incorrect.

The RP Tech is not a licensed SRO. Answer b is incorrect.

The Cleanup System Engineer is not a licensed SRO. Answer c is incorrect.

The clearance writer is usually a RO licensed individual. Answer d is incorrect.

2.3.2 Knowledge of facility ALARA program. (CFR: 41.12)

NRC RO Exam 2006-1 Key Page 60 of 129

NRC Exam 2006-1 Reactor Operator Exam Key

1 OC Learning Objective: RWT (Objective 22: Describe the Station ALARA Program).

Cognitive Level: Memory or Fundamental Question Type: New NRC RO Exam 2006-1 Key Page 61 of 129

OP-MA-109-101 Revision 4 I Page 25 of 135

2. If a vent path is not available, then breaking a flange connection, fitting, gauge line, or opening a pressure regulator petcock valve, etc. is acceptable to accommodate a vent path.

All appropriate FME prevention steps shall be taken.

3. If a vent path cannot be established, then the clearance shall be designated as an Exceptional Clearance.

4. A fail-as-is POV may be used as an isolation point if all of the following conditions are met:

A. The valve control station(s) shall be tagged.

B. The valve should be visually checked closed.

C. The valve shall be tagged and forcibly held closed with an installed gag or blocking device unless the valve mechanically locks in position without pneumatic supply.

D. The air supply valve shall be tagged closed.

E. If the above requirements cannot be met, then the POV may still be used as an isolation point provided it is designated as an Exceptional Clearance.

-.d.

5.3.5. Motor Operated Valve Rules

1. A motor operated valve may be used as a clearance isolation point provided all the following conditions are met:

A. The valve control station(s) shall be tagged.

B. The electrical energy source shall de-energized and tagged.

C. The valves hand wheel should be tagged.

1. This requirement shall only be waived by the Clearance Approver (who is a first line supervisor or above) or Shift Management when radiological or hazardous conditions exist.

2. If the requirement is waived, then a precaution shall be added to the comments section of the clearance indicating that the requirement was waived.

5.3.6. Venting and Draining 1, Each vent and drain opened under the clearance and not used for personnel protection should be tagged with an information tag.

NRC Exam 2006-1 Reactor Operator Exam Key

38. The plant was at rated power with all systems normally aligned, when a loss of 125 VDC DC-E occurred, and cannot be restored.

0 The applicable ABN has been entered Which of the following states why available Non-Licensed Operators are directed to perform plant tours?

a. All fire protection mitigation systems have been disabled

b. Power has been lost to all control room annunciators

c. Automatic trip ability for feedwater pumps, condensate pumps and main turbine has been lost

d. Power is lost to all area radiation monitors and most process radiation monitors Answer: b Justification: The loss of DC-E results in the loss of all control room annunciators.

ABN-53 requires that plant operators tour plant areas where the annunciators are lost (plant wide). Answer b is correct.

The ability of the fire protection system to mitigate fires is not effected, but fire annunciation is lost in the control room. Answer a is incorrect.

DC power for feedwater and condensate pumps (on 4160 Bus A and 4160 Bus B) are powered from DC Bus B and Bus C. Answer c is incorrect.

Radiation monitors are power by various AC power supplies (mostly vital AC).

ARMS are powered by Continuous Instrument Panel-3 (CIP-3) (reference procedure 407.1) Answer d is incorrect.

2.4.32 Knowledge of operator response to loss of all annunciators. (CFR: 41.1 0)

OC Learning Objective: 2621.828.0.001 2 (10450: Describe and interpret procedure sections and steps for plant emergency or off-normal conditions that involve this system including personnel allocation and equipment operation IAW applicable ABN, SDRP, EOP & EOP Support Procedures and EPIPs.)

Cognitive Level: Comprehensive or Analysis Question Type: New NRC RO Exam 2006-1 Key Page 62 of 129

Number AmerGen.- OYSTER CREEK GENERATING An I x c b C m y p n y STATION PROCEDURE ABN-53

.4 Title Revision No.

DC BUS A AND PANEL FAILURES 1 3.0 OPERATOR ACTIONS If while executing this procedure, any entry condition for any EOP occurs, then EXECUTE this procedure concurrently with the appropriate EOP.

3.1 If power panel DC-E is lost, then PERFORM the following:

CAUTION A loss of panel DC-E will cause all Reactor Feed Pump Minimum Flow Valves to fail open and a total loss of Control Room Annunciators.

NOTE If power is lost to 125 VDC Power Panel E, a turbine or generator trip will not cause an automatic scram. If a turbine or generator trip occurs, the reactor must therefore be scrammed manually.

3.1. I PERFORM a rapid power reduction in accordance with Procedure 202.1 to stabilize RPV level 155 - 165. [ I

3. I.2 If SCRAM occurs, then REFER to ABN-1, Reactor Scram. [ I 3.1.3 VERIFY standby TBCCW Pump starts unless DC-B power is unavailable. [ I 3.1.4 If Auto Transfer Switch DC-E has not shifted to the alternate supply, then manually SHIFT transfer switch to DC Distribution Center A. [ I 5.0

Number AmerGen, OYSTER CREEK GENERATING AT; Fxclon b r n p n y STATION PROCEDURE ABN-53

..4 Title Revision No.

DC BUS A AND PANEL FAILURES 1 NOTE Attachment ABN-53-2 lists DC-E Equipment Loads.

3.1.5 If power cannot be restored to 125 VDC Power Panel DC-E, then PERFORM the following:

3.1.5.1 CONFIRM that CRD pump A is running. [ I 3.1.5.2 Closely MONITOR plant parameters. [ I 3.1.5.3 DISPATCH Operators to appropriate areas of plant to monitor equipment affected due to lost

'.d.' annunciators. [ I 3.1.5.4 REFER to Emergency Plan for loss of annunciators. [ I 3.1.5.5 CONTACT Work Week Manager to initiate Panel E repairs. [ I 3.1.5.6 If a Turbine trip condition occurs, then DISPATCH an operator to trip turbine at the Front Standard. [ I 3.15 . 7 If a Turbine trip condition has occurred and no operator is available to trip Turbine at Front Standard or RPV cooldown is excessive, then PERFORM the following:

1. CONFIRM Reactor Scram and REFER to ABN-1, Reactor Scram. [ I

2. CLOSE MSIVs. [ I 3.1.5.8 MONITOR Firewater header pressure. [ I 6.0

An Wontompany STATION PROCEDURE ABN-53

/--

d Title Revision No.

DC BUS A AND PANEL FAILURES 1 ATTACHMENT ABN-53-2 EQUIPMENT AFFECTED BY A LOSS OF POWER PANEL E Annunciator Panel 3F Annunciator Panel IM175 Annunciator Panel 7F Feedwater runout protection panel and Alternate Rod Injection System Panel 12R (relay system)

Panel 13R Dilution Plant d

LIR 1-1 Fire Alarm Panel Panel 4F Panel 5F/6F Panel 7F Panel 8F/9F Panel 9XF Panel 4R (TIP System)

Sequence of Alarms Recorder (Panel ER-46)

ROPS relay logic (Panel 14XR)

Digital Protection Relay System A and B (Panel 1IXR)

" W' 11.0

NRC Exam 2006-1 Reactor Operator Exam Key

39. The reactor was operating at rated power when a loss of all offsite power L

occurred. Plant conditions are as follows:

Reactor water level dropped to 82 inches and is currently 110 inches and rising slowly Reactor pressure dropped to 890 psig and is currently 950 psig and rising slowly 0 Both EDG output breakers have been closed for two minutes Restoration of power to plant buses IAW ABN-36-3, Plant Electrical Distribution Restoration, has NOT yet commenced.

Which one of the following statements is true for these conditions?

a. Drywell temperature is rising because there are no drywell recirc fans running

b. Instrument air pressure is lowering because there are no air compressors running

c. Reactor Building AP is zero because no reactor building ventilation fans are running

d. Service water temperatures are rising because there are no service water pumps running

--.-./

Answer: b Handouts: None Justification: A is incorrect - since there is no LOCA signal (Hi DW pressure AND Lo-Lo RPV level), drywell recirc fans 1, 3 and 5 auto-started 2.5 seconds after power was restored to buses 1C and 1D (and USS 1A2 and 1B2). Although RPV level dropped below the Lo-Lo level setpoint (86 inches), a concurrent high drywell pressure must be received to prevent drywell recirc fans from starting when 1C/1 D bus power is restored.

B is correct - on loss of all offsite power, all (4) 41 60V buses de-energize. The UV logic for the 1C and 1 D buses trips the load breakers on buses 1C and 1D as well as the feeder breakers to USS 1A1 and 1B1, which power Turbine Building loads. The feeder breakers for USSs 1A2/1B2 and 1A3/1 B3 remain closed since UV trip devices on individual loads provide load shedding for these USSs.

When power is restored to buses 1C and 1D by their respective EDGs, USSs 1A1 and 1B1 remain de-energized and USSs 1A2/1B2 and 1A3/1B3 automatically re-energize. Certain loads powered from these USSs are automatically sequenced on at various time intervals to prevent overloading the EDGs, including CRD pumps, RBCCW pumps and Service Water pumps. The service and instrument air compressors are powered from USS 1Al/1 B1 and NRC RO Exam 2006-1 Key Page 63 of 129

NRC Exam 2006-1 Reactor Operator Exam Key therefore require manual restoration. This is directed by ABN-36 following

.- restoration of power to USS 1A l / 1 B1 IAW Attachment ABN-36-3.

C is incorrect - reactor building ventilation fans tripped on the loss of offsite power, but the Standby Gas Treatment System started due to the Lo-Lo RPV level signal (SGTS does not require a concurrent high drywell pressure),

restoring the Reactor Building negative AP.

D is incorrect - service water pumps automatically restart two minutes after power is restored to buses 1C and 1D with no LOCA signal present. A LOCA signal (preventing restart) requires Lo-Lo RPV level AND Hi DW pressure.

295003 AK1.02 Knowledge of the operational implications of the following concepts as they apply to PARTIAL OR COMPLETE LOSS OF A.C. POWER: Load Shedding (CFR 41.5)

OC Learning Objective:

2621.828.0.0016, Obiective E:

Describe the interlocks signals and setpoints for the affected system components and expected system response including power loss or failed components.

2621.828.0.0016, Obiective M:

Given a set of system indications or data, evaluate and interpret them to determine limits, trends and system status.

2621.828.0.0016, Obiective 0:

L-Describe and interpret procedure sections and steps for plant emergency or off-normal conditions that involve this system including personnel allocation and equipment operation IAW applicable ABN, EOP & EOP support procedures and EPIPs.

Cognitive Level: Comprehension or Analysis Question Type: New

References:

338, ABN-36, GE 223R0173, sh. 1A NRC RO Exam 2006-1 Key Page 64 of 129

AmerGenl OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-36 An txcbnE;Knpany L./

Title Revision No.

LOSS OF OFF-SITE POWER 3 Attachment AB N-36-2 (continued)

Powering In-Plant Buses via the SBO Transformer

1. I 1 If it is desired to energize bus 1D from the Forked River CT, and bus 1D is not being powered from EDG #2, then PERFORM the following:

1. PLACE the control switches for the following equipment in the PULL-TO-LOCK position.

Core Spray Main Pump NZOIB [ I Core Spray Main Pump NZOIC [ I

2. VERIFY bus 1D is de-energized. [ I

3. PLACE synchronizing key for Breaker I D to ON. [ I

4. PLACE and HOLD Breaker I D control switch in the CLOSE position for approximately 6 seconds. [ I NOTE: Any AC-powered valves that received an isolation signal wil stroke to the closed position when power is restored.

5. VERIFY voltage and frequency on the following buses are within normal limits:

0 4160 VAC bus 1D [ I 0 480 VAC USS lB2 [ I 0 480 VAC USS 1B3 [ I 13.0

AmerGen-An Eue'vn Company 1 OYSTER CREEK GENERATING STATION PROCEDURE 1 Number 334 I

-e' Title Revision No.

Instrument and Service Air System 93 ATTACHMENT 334-4 ELECTRICAL CHECK-0FF LIST POWER BREAKER ITEM SUPPLY LOCATI0N POSITION PERFORMNERI FY

---? # I Air Compressor US1A I TB Basement Closed I 7 #2 Air Compressor US1B1 TB Basement Closed I Air Compressor Dryer A+B MCClA13 TB Basement Open I Air Compressor Dryer C+D MCClA I 3 TB Basement Open I

__3 #3 Air Compressor US1B1 TB Basement Closed I

3 Air Compressor SP-1B

.L--I Control Power BKR #4 TB Basement Closed I

3 Air Compressor SP-1B Space Heater BKR #6 TB Basement Closed I E4-1

NRC Exam 2006-1 Reactor Operator Exam Key

40. Given the following:

Reactor power is 28% with a power ascension in progress The main generator is loaded to 175 MW and 50 MVAR Stator cooling water pump 1A is tagged out for maintenance A ground fault on DC Bus A causes it to de-energize The electrical fault on DC-A causes a trip of breaker 181M I

\

Which statement below describes the effect of this event on main \

generator voltage regulation? \

Generator terminal voltage

a. must be maintained manually

b. will be maintained automatically

c. will rise since there is a loss of automatic and manual voltage control

d. will lower since there is a loss of automatic and manual voltage control Answer: c Handouts: None Justification: A and B are incorrect - a loss of DC-A, which powers the main generator excitation equipment, results in a loss of both automatic and manual voltage control. The CAUTION for Step 3.2 of ABN-53 states, in part, Loss of Main Generator voltage control will result from a loss of power to DC Distribution Center A. In addition, a NOTE for Step 3.3 of ABN-12 states, in part, Loss of DC control power to the excitation switchgear will result in a loss of generator voltage control.

C is correct - a trip of 1B1M causes a loss of USS 1B1, which results in a loss of the only available stator cooling water pump. When stator flow drops below 230 gpm, a generator runback occurs. This causes an automatic load reduction on the generator. Since reactor power is below 30%, the crew will not scram the reactor (ABN-11 directs a reactor scram if a generator runback occurs when reactor power is above 30%). If below 30% power, ABN-11 directs reducing MVARs to zero. Since there is a loss of both automatic and manual voltage control, the operator will be unable to reduce generator voltage/MVARs and as generator (real) load is reduced during the runback, generator terminal voltage will increase.

D is incorrect - a loss of stator cooling results in a generator runback. As the generator unloads with no method of controlling voltage, generator terminal voltage will increase.

NRC RO Exam 2006-1 Key Page 65 of 129

NRC Exam 2006-1 Reactor Operator Exam Key 295004 G2.1.28 Partial or Complete Loss of D.C. Power / Conduct of Operations: Knowledge of the purpose and function of major system components and controls. (CFR 41.5, 41.7)

OC Learning Objective:

2621.828.0.0025. Obiective A:

Describe and interpret procedure sections and steps for plant emergency or off-normal conditions that involve this system including personnel allocation and equipment operation IAW applicable ABN, EOP & EOP support procedures and EPlPs 2621.828.0.0025, Obiective G:

Given a set of system indications or data, evaluate and interpret them to determine limits, trends and system status.

2621.828.0.0025, Obiective H:

Identify and explain system operating controls/indications under all plant operating conditions.

Cognitive Level: Comprehension or Analysis u

Question Type: New

References:

ABN-11, ABN-12, ABN-53 NRC RO Exam 2006-1 Key Page 66 of 129

Number

'Y OYSTER CREEK GENERATING ABN-1I h~:~&nmrio& Eiiey,Coix~rrp STATION PROCEDURE I

Title Revision No.

LOSS OF GENERATOR STATOR COOLING 0 3.0 OPERATOR ACTIONS 3.1 If stator cooling pump discharge header pressure lowers to 94 psig, then CONFIRM automatic start of standby Stator Cooling Water pump. [ I 3.2 If a turbine runback occurs or stator temperatures are rising and reactor power is above 30% (580 MWth),

then SCRAM the reactor and EXECUTE ABN-1. [ I 3.3 If a turbine runback occurs or stator temperatures are rising and reactor power is less than 30% (580 MWth),

then concurrently PERFORM the following:

1. REDUCE Main Generator MVARs to zero or as low as grid conditions permit. [ I

2. When generator load is below 25% (180 MWe, as indicated by actuation of the 25% LOAD TRIP NOT RESET, Q-8-a),

then RESET the 25% load trip. [ I 3.4 CONFIRM power operations in accordance with Procedure 202.1, Power Operations. [ I 3.5 DIRECT Reactor Engineering to evaluate a post-transient Powerplex case of Core Thermal Limits. [ I 3.6 If Stator Cooling flow has been lost and can m b e restored immediately, then PERFORM the actions listed in Attachment ABN-11-1 within the specified time limits. [ I

4.0 REFERENCES

- None 5.0 ATTACHMENTS - ABN-11-1, Operator Actions For Sustained Loss of Stator Cooling Flow.

4.0

Number Amereen, OYSTER CREEK GENERATING STATION PROCEDURE An ExelonlBntish Energy Company ABN-12

.v Title Revision No.

GENERATOR EXCITATION EQUIPMENT MALFUNCTION 0 2.2 Plant Parameters Parameter 1 Location 1 Change Main Generator KILOVOLTS I 8F/9F 1 various Main Generator MEGAVARS I 8F/9F I various EXCITER AMPS I 8F/9F I various 2.3 Other Indications

1. AMPLIDYNE CONTROL 43CS switch green OFF lamp lit.

2. MW, MVAR, and AMPS indications fluctuate widely for 230 KV lines N-1028, 0-1029 and transformer Bank 1 (Panels 12F-1 and 12F-2).

3. Loss of indicating lights for AMPLIDYNE CONTROL, GENERATOR FIELD BREAKER and REGULATOR SELECTOR switches.

4. Loss of manual voltage control.

5. Any of the following may indicate a generator malfunction:

Over-excitation or high field current.

Exciter fire louvers closed in exciter housing.

Exciter air filters blocked or plugged.

Hydrogen pressure, purity or cooling system trouble.

Faults or partial grounds of generator excitation equipment.

3.0

AmerGem OYSTER CREEK GENERATING Number STATION PROCEDURE ABN-53

.--' ~~

Title Revision No.

DC BUS A AND PANEL FAILURES 1 2.2 Parameter Location Chanqe I BUS AVOLTS I 8F/9F I downscale 1 BlkA AMPS I 8F/9F I downscale ICHARGERAAMPS I 8F/9F I downscale I 2.3 Other Indications

1. Loss of power to Generator Excitation switchgear transfers voltage regulator to the manual rheostat. No voltage

'u' adjustment capability exists.

2. Loss of indication to breakers powered from 480 VAC USS IB I and the Generator Excitation switchgear.

CAUTION If a loss of DC-A occurs with a loss of DC-B and the main generator trips, then evacuation of the Turbine Operating Floor will be required due to loss of hydrogen seal oil and bearing oil pressure.

4.0

NRC Exam 2006-1 Reactor Operator Exam Key

41. Initial plant conditions are as follows:

0 A plant startup is in progress with reactor power at 12%

0 The mode switch is in STARTUP 0 Recirculation flow is 11 E4 gpm 0 Reactor pressure is 1000 psig A turbine bypass valve malfunction causes:

0 A spike in reactor pressure to 1043 psig 0 A spike in reactor power to 40%

What is the status of the reactor?

a. At power

b. Scrammed due to high reactor pressure

c. Scrammed due to high IRM neutron flux

d. Scrammed due to high APRM neutron flux Answer: c Handouts: Nome

'--- Justification: A is incorrect - the reactor scrammed due to high IRM neutron flux.

B is incorrect - from RAP-Hlf, the high reactor pressure scram setpoint is 1045 psig.

C is correct - based on the conditions given (STARTUP, at 12% power), the reactor is operating on IRM Range 10. The scram setpoint for IRM Range 10 is 38.4% (LSSS), which was exceeded.

D is incorrect - the APRM Hi-Hi scram setpoint with recirc flow at 11 E4 gpm would be greater than 60%.

295006 AK2.06 Knowledge of the interrelations between SCRAM and the following: Reactor power (CFR 41 5 , 41.6)

OC Learning Objective:

2621.828.0.0037, Obiective C:

Describe all RPS scram logic trip signals, including the following:

1. Purpose / Design Basis

2. Setpoints

3. Conditions that allow bypassing scram signals

4. How bypassing scram signals is accomplished NRC RO Exam 2006-1 Key Page 67 of 129

NRC Exam 2006-1 Reactor Operator Exam Key Cognitive Level: Comprehension or Analysis 4

Question Type: Modified Bank

References:

201, RAP-H1f, Tech Spec 2.3

-\--

NRC RO Exam 2006-1 Key Page 68 of 129

2.3 LIMITING SAFETY SYSTEM SETTINGS Applicabilitv: Applies to trip settings on automatic protective devices related to variables on which safety limits have been placed.

Obiective: To provide automatic corrective action to prevent the safety limits from being exceeded.

Specification: Limiting safety system settings shall be as follows:

FUNCTION LIMITING SAFETY SYSTEM SETTINGS A. Neutron Flux, Scram A.l APRM When the reactor mode switch is in the Run position, the APRM flux scram setting shall be the minimum of:

For W 20.0 x1061b/hr:

FRP S 5 [(0.90 x W + 65.11 MFLPD ; or The applicable stability protection settings, as defined in the COLR, I with a maximum setpoint of 120.0% for core flow equal to 61 x I O 6 Ib/hr and greater, where:

S= setting in percent of rated power W= recirculation flow (Ib/hr)

FRP = fraction of rated thermal power is the ratio of core thermal power to rated thermal power MFLPD = maximum fraction of limiting power density where the limiting power density for each bundle is the design linear heat generation rate for that bundle.

The ratio of FRP/MFLPD shall be set equal to 1.O unless the actual operating value is less than 1.O in which case the actual operating value will be used.

This adjustment may be accomplished by increasing the APRM gain and thus reducing the flow reference APRM High Flux Scram Curve by the reciprocal of the APRM gain change.

A.2 IRM 538.4 percent of rated neutron flux A.3 APRM Downscale 2 2% Rated Thermal Power coincident with IRM Upscale (high-high) or Inoperative OYSTERCREEK 2.3-1 Amendment No.: 71 75, !! !, 2%, 235, 248

roup Heading REACTOR PRESS H-I -f AANUAL CORRECTIVE ACTIONS: (continued from Page 1 of 2)

I E full scram condition occurs, THEN REFER to ABN-1, Reactor Scram.

NOTE This alarm indicates that a parameter has exceeded or has the potential to exceed an Emergency Action Level (EAL).

I REFER to EP-OC-1010, Radiological Emergency Plan to determine EAL classification.

AUSES: SETPOINTS: ACTUATING DEVICES:

iigh reactor pressure trip to Reactor Protection 1045 psig PT-RE03A

ystem Channel I. PT-RE03C Reference Drawings

GE237E566 Sh. 1 GU 3E-611-17-010 hbject Procedure No.

Page 2 of 2 RAP-H1f I H-I-f Alarm Response Procedures Revision No: 0

NRC Exam 2006-1 Reactor Operator Exam Key

42. Given the following:

ii The reactor is operating at rated power on a hot summer day 0 RBCCW & TBCCW heat exchangers are being cooled by Service Water 0 RBCCW pump 1-1 and heat exchanger 1-1 are in service 0 RBCCW heat exchanger 1-2 is tagged out due to a tube leak 0 RBCCW temperatures have been trending upward The crew has entered ABN-19, RBCCW Failure Response Which one of the following actions can be utilized to reduce RBCCW system temperatures?

a. Place RBCCW pump 1-2 in service along with pump 1-1

b. Increase Reactor Water Cleanup regenerative heat exchanger flow

c. Lineup the A & B Fuel Pool Cooling heat exchangers to be cooled by TBCCW

d. Lineup the TBCCW heat exchangers to be cooled by the Circulating Water System Answer: d Handouts: None b

Justification: A is incorrect - in order to prevent flow-induced vibration (due to excessive flow) in the RBCCW heat exchangers, Procedure 309.2 requires two RBCCW heat exchangers to be in service prior to placing a second RBCCW pump in service.

B is incorrect -this cant be done without increasing RWCU system flow rate, which would increase the heat load on the RBCCW system.

C is incorrect - the A & B FPC heat exchangers cannot be aligned to be cooled by TBCCW; only the augmented (C) FPC heat exchanger can.

D is correct - ABN-19 directs this action Operating with 2 RBCCW pumps in service requires 2 heat exchangers to be in se rvice.

295018 AA1.01 Ability to operate and/or monitor the following as they apply to PARTIAL OR COMPLETE LOSS OF COMPONENT COOLING WATER: Backup systems (CFR 41.4, 41 .lo)

NRC RO Exam 2006-1 Key Page 69 of 129

NRC Exam 2006-1 Reactor Operator Exam Key

.-' OC Learning Objective: 2621.828.0.0035, Obiective P:

Describe and interpret procedure sections and steps for plant emergency and off-normal conditions that involve this system including personnel allocation and equipment operation in accordance with plant procedures.

Cognitive Level: Comprehension or Analysis Question Type: New

References:

ABN-19, 309.2, 31 1. I , BR 2006 NRC RO Exam 2006-1 Key Page 70 of 129

AmerGeny An txe10n canprny OYSTER CREEK GENERATING Number STATION PROCEDURE ABN-I 9 I

'v' Title Revision No.

RBCCW FAILURE RESPONSE 3

2. STOP all operating recirculation pumps [ I

3. CONFIRM that the recirculation pump suction and discharge valves for at least one recirculation loop are OPEN. [ I

4. MONITOR the systems and components cooled by RBCCW in accordance with section 3.6 of this procedure. [ I 3.3 If RPV temperature is less than 212 OF and any of the following conditions occur:

All RBCCW flow is lost, [ I e

Any RBCCW Drywell Isolation Valve has closed and can not be re-opened (V-5-147, -166, -167), [ I e

CCW FLOW LO alarms for more than one recirculation Pump, [ I A major, unisolable RBCCW system leak occurs, [ I then, MONITOR RBCCW system loads in accordance with section 3.6 of this procedure. [ I 3.4 If RBCCW cooling capability is reduced, then MONITOR RBCCW system loads (Attachment ABN-I 9-1) and PERFORM concurrently steps 3.5 and 3.6. [ I 3.5 If RBCCW temperatures are rising, then PERFORM the following actions until RBCCW return temperature is stabilized below 135°F: [ I

1. REDUCE Cleanup System flow rate. [ I

2. RAISE Service Water System flow through the RBCCW heat exchangers. [ I

3. RAISE RBCCW flow through the RBCCW heat exchangers. [ I 7.0

mmss A:i Exelon Corrpariy 1 OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-19 I ,

' -% Title Revision No.

RBCCW FAILURE RESPONSE 3

4. If the Circulating Water System is available and the TBCCW heat exchangers are being cooled by Service Water, then TRANSFER the TBCCW heat exchangers to Circulating Water in accordance with Procedure 322, Service Water System. [ I

5. REDUCE recirculation flow to minimum. [ I

6. REDUCE RBCCW flow to the Shutdown Cooling System in accordance with Procedure 309.2, RBCCW System. [ I

7. SHUTDOWN and ISOLATE the Reactor Water Cleanup System in accordance with section 3.6 of this procedure. [ I 3.6 If the temperature/conditions in any of the following systems/components reaches the specified limits below, then PERFORM the indicated actions:

Recirculation Pumps

1. If any of the following temperature limits are exceeded:

0 RCP motor bearing (TR-IA55, Panel 8R) 185°F [ J 0 RCP motor winding (TR-IA70, Panel 8R) 230°F [ ]

0 RCP Upper Seal (#2) (TR-IA71, Panel 3F) 160°F [ ]

0 RCP Lower Seal (#I) (TR-IA71, Panel 3F) 180°F [ J then ENTER ABN-2 and TRIP the affected pump(s). [ I CleanuD Svstem

2. If either of the following temperature limits is exceeded:

NRHX outlet (D-8-).............................. ..140°F [ J Aux pump cooling water outlet................130°F [ ]

8.0

NRC Exam 2006-1 Reactor Operator Exam Key

43. Given the following:

L 0 The reactor is SHUTDOWN and a cooldown is in progress 0 Reactor pressure is 15 psig; reactor water level is 160 inches 0 Reactor recirculation system status is as follows:

o Loops A and C are ISOLATED o Loops B and D are IDLE o Pump E is in service 0 Shutdown cooling pumps Aand B are in service The auxiliary reactor water cleanup pump is in service Bus 1A de-energizes due to an electrical fault The crew places shutdown cooling pump C in service What action should be taken regarding the reactor recirculation system?

a. OPEN the B pump discharge valve then CLOSE the E pump discharge valve

b. CLOSE the Epump discharge valve, then OPEN the B pump discharge valve

c. OPEN the D pump discharge valve then CLOSE the E pump discharge valve

d. CLOSE the E pump discharge valve, then OPEN the D pump discharge valve

.-d Answer: c Handouts: None Justification: A is incorrect - P&L 4.2.1 2 in Procedure 305, Shutdown Cooling System Operation, states If the Cleanup System is in service, the B Recirc loop should not be the selected loop in those instances where one loop is required to be fully open. NOTE: the auxiliary reactor water cleanup pump is powered from MCC 1821 (Bus 1B) and therefore remains in service on loss of Bus 1A.

B is incorrect - for the reason stated above for choice A. In addition, and more importantly, closing the E pump discharge valve would violate Tech Spec 3.3.F.4, which states With reactor coolant temperature greater than 21 2 OF and irradiated fuel in the reactor vessel, at least one recirculation loop discharge valve and its associated suction valve shall be in the open position.

C is correct - a loss of Bus 1A causes a trip of recirc pump E. P&L 4.2.1 1 in Procedure 305 states: To prevent SDC System flow from short-cycling the core, the E Recirc Loop Discharge Valve must be CLOSED the E Recirc Pump running. This statement requires the operator to close the E recirc pump discharge valve due to the pump trip. However, Tech Spec 3.3.F.4 requires at

.-, least one recirc loop suction and associated discharge valve to be open. To NRC RO Exam 2006-1 Key Page 71 of 129

NRC Exam 2006-1 Reactor Operator Exam Key meet both of these requirements, the correct action to take would be to open the

.L--

. D pump discharge valve, then close the E pump discharge valve.

D is incorrect - this violates Tech Spec 3.3.F.4.. .see explanation for choice B above.

295021 AA1.05 Ability to operate and/or monitor the following as they apply to LOSS OF SHUTDOWN COOLING: Reactor recirculation (CFR 41.1 0)

OC Learning Objective:

2621.828.0.0038, Obiective J:

Given normal operating procedure and documents for the system, describe or interpret the procedural steps.

2621.828.0.0038, Obiective M:

Given Technical Specifications, identify and explain associated actions for each section of the Technical Specifications relating to this system including personnel allocation and equipment operation.

Cognitive Level: Comprehension or Analysis Question Type: New

'W'

References:

ABN-2, ABN-3, 301.2, Tech Spec 3.3.F.4 NRC RO Exam 2006-1 Key Page 72 of 129

AmerGen, OYSTER CREEK GENERATING Number nn fmon Cowpany STATION PROCEDURE 301.2

.w Title Reactor Recirculation System I Revision No.

46 DCC# 20.1704.0010 ATTACHMENT 301.2-3 (continued)

RECIRCULATIONPUMP ELECTRICAL LINEUP 4160V SWITCHGEAR ROOM Power Breaker Initials Component Supply Number Position Checwerifv RCP A M-G Motor NGOIA 4 160V-1A Racked Up - I -

Charged -I-69 Permissive - I -

SW. Closed -I-RCP C M-G Motor NGOIC 4 160V-1A Racked Up - I -

Charged -I-69 Permissive SW. Closed -I-

., -P

d. RCP E M-G Motor NGOIE 4160V-1A Racked Up -I-Charged - I -

69 Permissive SW. Closed -I-RCP B M-G Motor NGOIB 416OV-1B Racked Up -I-Charged -I-69 Permissive SW. Closed -I-RCP D M-G Motor NGOID 4160V-1B Racked Up -I-Charged -I-69 Permissive SW. Closed -I-RCP Drive Motor DC Cont. 125 VDC 8 C -I-Pwr. Bus 1A Panel C Checked By: Date: Time:

Verified By: Date: Time:

Approved By: Date: Time:

os E3-3

id- Title AmerGenx An Excm Company I OYSTER CREEK GENERATING STATION PROCEDURE 1 Number 305 Revision No.

Shutdown Cooling System Operation 90 4.2.3 Due to Yarway level indication inaccuracies at lower reactor temperatures and pressures, GEMAC Narrow Range instrumentation should be used as the primary indication of Reactor water level.

4.2.4 RBCCW System flow reduction will alleviate excessive vibration or noise at the RBCCW Heat Exchangers.

4.2.5 If an automatic isolation occurs, do goJ attempt to restart the SDC System until available indications have been checked and found to be normal.

4.2.6 The maximum allowed RBCCW flow through a SDC Heat Exchanger is 1500 gpm.

4.2.7 Always attempt to maintain equal RBCCW flow through any operating SDC Heat Exchangers by keeping the shell side differential pressures as close as possible.

4.2.8 Maximum SDC System flow (tubeside) through a heat exchanger is 3400 gpm (assuming 10% of tubes are plugged).

4.2.9 In the case of system degradation due to a fire or a control room evacuation, steps that are not absolutely necessary for system operation may be omitted.

4.2.I O To ensure full closure of MOVs V-17-55, V-17-56 and V-17-57, the control switch must be held in CLOSE for approximately 3 seconds after the red OPEN light (Panel 11F) extinguishes. This action is necessary since these valves do have a seal-in circuit in the close direction.

4.2.1I To prevent SDC System flow from short-cycling the core, the E Recirc Loop Discharge Valve must be CLOSED the E Recirc Pump running.

4.2.12 If the Cleanup System is in service, the B Recirc Loop should not be the selected loop in those instances where one loop is required to be fully open.

4.2.13 Section 4.3 of this procedure is written to startup the SDC System in order to cooldown the Reactor. If system startup is to be done after cooldown, as when maintaining a temperature band during outages, those steps applicable only to startup for a cooldown may be omitted at the discretion of the Operations Supervisor.

20.0

2. The circuit breaker of the recirculation pump motor generator set associated with an ISOLATED RECIRCULATION,LOOP shall be open and defeated from operation.

3. An ISOLATED RECIRCULATION LOOP shall not be returned to service unless the reactor is in the COLD SHUTDOWN condition.

b. When there are two inoperable recirculation loops (either two IDLE RECIRCULATION LOOPS or one IDLE RECIRCULATION LOOP and one ISOLATED RECIRCULATION LOOP) the reactor core thermal power shall not exceed 90% of rated power.

3. If Specifications 3.3.F.1 and 3.3.F.2 are not met, an orderly shutdown shall be initiated immediately until all operable control rods are fully inserted and the reactor is in either the REFUEL MODE or SHUTDOWN CONDITION within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

4. With reactor coolant temperature greater than 2 12°F and irradiated fuel in the reactor vessel, at least one recirculation loop discharge valve and its associated suction valve shall be in the full open position.

5. If Specification 3.3.F.4 is not met, immediately open one recirculation loop discharge valve and its associated suction valve.

6. With reactor coolant temperature less than 212°F and irradiated fuel in the reactor vessel, at least one recirculation loop discharge valve and its associated suction valve shall be in the full open position unless the reactor vessel is flooded to a level above 185 inches TAF or unless the steam separator and dryer are removed.

OYSTER CREEK 3.3-3a Corrected Letter dated 8/7/2000 Amendment No: 135, 140,2 12

NRC Exam 2006-1 Reactor Operator Exam Key

44. The reactor was manually scrammed from rated power due to a loss of coolant accident (LOCA). Current plant conditions are as follows:

-u Reactor water level is 140 inches and steady 0 Reactor pressure is 650 psig and lowering 0 Drywell pressure is 26 psig and rising 0 Drywell temperature is 225 O F and rising 0 Torus pressure is 25 psig and rising Torus water level is 150 inches and steady Torus water temperature is 165 O F and rising A RED Priority 1 Alarm is displayed on the SPDS Containment Cond /

Post Trip screen.

This alarm is due to

a. exceeding PSP

b. exceeding HCTL

c. drywell pressure above 12 psig

d. drywell temperature above 200 OF Answer: a

.4 Handouts: EMG-3200.02, or, providing the LARGE figures of the graphs would be preferred Justification: A is correct - at 150 inches torus water level, the value of torus pressure that exceeds PSP is 24.6 psig. With drywell pressure at 26 psig, this is the only one of the given parameters that could cause a RED Priority 1 alarm.

B is incorrect - exceeding HCTL does generate a RED Priority 1 alarm, but HCTL has not been exceeded.. .torus water temperature is below the value that would exceed the curve for 650 psig reactor pressure.

C is incorrect - this generates a YELLOW Priority 2 alarm.

D is incorrect - this generates a YELLOW Priority 2 alarm.

295024 EK2.16 Knowledge of the interrelations between HIGH DRYWELL PRESSURE and the following: SPDE/ERIS/CRIDS (CFR 41.7, 41.1 0)

OC Learning Objective:

2621.863.0.0007, Obiective 0:

Discuss the relevance of information shown on the PPC SPDS displays to the implementation of SBEOPs.

-d NRC RO Exam 2006-1 Key Page 73 of 129

NRC Exam 2006-1 Reactor Operator Exam Key Cognitive Level: Comprehension or Analysis Question Type: New

References:

EMG-3200.02,OC-PPC-SRS-0001 NRC RO Exam 2006-1 Key Page 74 of 129

NRC Exam 2006-1 Reactor Operator Exam Key

45. The reactor was operating at rated power when a loss of all offsite power L

occurred. The transient resulted in EMRV actuation and one EMRV stuck open. Current plant conditions are as follows:

Reactor water level is 80 inches and lowering slowly Reactor pressure is 350 psig and lowering slowly Torus water temperature is 145 O F EDG-1 is loaded to 1400 KW 0 EDG-2 is loaded to 1800 KW Which Containment Spray pumps, and associated ESW pumps, should be placed in the torus cooling mode?

a. Two Containment Spray pumps and two ESW pumps in System 1

b. Two Containment Spray pumps and two ESW pumps in System 2

c. One Containment Spray pump and one ESW pump in either System 1 O R 2

d. Two Containment Spray pumps and two ESW pumps in both System 1 AND 2 Answer: a Handouts: Attachments 341-5 and 341-6

.w Justification: A is correct - based on the given conditions, the Primary Containment Control EOP directs placing both Containment Spray Systems in the Torus Cooling mode. EDG-1 has sufficient capacity to carry two containment spray pumps and two ESW pumps, while EDG-2 does not. In addition, since 2 Core Spray pumps are running (due to Lo-Lo level) and getting ready to inject when RPV pressure drops below -31 0 psig, securing Core Spray to run 4 Containment Spray pumps is not an option. Therefore, since only one Containment Spray System can be placed in service, System 1 is the correct choice.

B is incorrect - a CAUTION in Support Procedure 25 states: Diesel Generator overload will result if a Containment Spray Pump and ESW pump are started with a Diesel Generator load of greater than 2150 KW. Since EDG-2 is already loaded to 1800 KW, and a containment spray/ESW pump combination will add -

580 KW (as shown in Attachment 341-6), EDG-2 does not have sufficient capacity to carry System 2 (C and D) containment spray pumps and System 2 (C and D) ESW pumps ...it can only carry 1 containment spray pump and 1 ESW pump.

C is incorrect - according to the Primary Containment Control EOP, if torus water temperature cannot be maintained below 95 O F , two containment spray systems 4

NRC RO Exam 2006-1 Key Page 75 of 129

NRC Exam 2006-1 Reactor Operator Exam Key (4 pumps) should be operated in torus cooling, if available. Current plant

.~-- I conditions prevent operating all four containment spray pumps, however two pumps can and should be placed in torus cooling.

D is incorrect - in addition to the EDG load restrictions mentioned above, there is a CAUTION in Support Procedure 25 that states: NPSH problems will develop on all operating pumps if more than 4 Containment Spray/Core Spray Main pumps are operated at the same time. With RPV level at 80 inches, Core Spray Systems 1 and 2 (2 main pumps and 2 booster pumps) would be operating, but not injecting (core spray will begin to inject when RPV pressure is -31 0 psig).

Since 2 core spray pumps are running, and are needed to restore RPV level when RPV pressure drops below 310 psig, only 2 containment spray pumps can be placed in service.

295026 EAl.01 Ability to operate and/or monitor the following as they apply to SUPPRESSION POOL HIGH WATER TEMPERATURE: Suppression pool cooling (CFR 41 -10)

OC Learning Objective:

2621.828.0.0009, Obiective L:

Given normal operating procedures and documents for the system, describe or interpret the procedural steps.

Cognitive Level: Comprehension or Analysis

. 4 Question Type: New

References:

EMG-3200.02, Support Procedure 25, 341 NRC RO Exam 2006-1 Key Page 76 of 129

\-

L v

An Exelon Company STATION PROCEDURE 341 I

Title Revision No.

e Emergency Diesel Generator Operation 75 ATTACHMENT 341-6 EDG 2 ENGINEERED SAFEGUARD LOADS AND OTHER CRITICAL LOADS

-- INDICATES ENGINEERED SAFEGUARD LOAD 0 INDICATES PRIORITY PUMP FOR SAFETY SYSTEM INDICATES ALTERNATE PUMP FOR SAFETY SYSTEM A INDICATES VALVE COULD RENDER SYSTEM INOPERABLE SYSTEM BUS EQUIPMENT CORE ID 0 CORE SPRAY MAIN PUMP NZOIB (474KW) SYS 2

-- SPRAY ID CORE SPRAY MAIN PUMP NZOIC (474KW) SYS I SYSTEM 1B2 0 CORE SPRAY BOOSTER PUMP NZ03B (247KW) SYS 2 PUMPS 182 CORE SPRAY BOOSTER PUMP NZ03C (247KW) SYS 1 -AUTO STARTS ONLY IF BOTH NZ03A AND NZ03B NOT RUNNING NOTE: MANUAL START ONLY. START PREVENTED FOR 200 SECONDS AFTER EDG BREAKER CLOSURE.

CONT. 1B2 O CONTAINMENT SPRAY PUMP 51C (239KW) SYS 2

--SPRAY 1B2 O CONTAINMENT SPRAY PUMP 51D (239KW) SYS 2 SYSTEM 2D O ESW PUMP 52C (333KW) SYS 2 PUMPS 2D O ESW PUMP 52D (333KW) SYS 2 LIQUID POISON 1B21 LIQUID POISON PUMP NP02-B AND SQUIB VALVE NP05-B (25KW)

SYSTEM O (PUMP)

STANDBY NOTE: PRIORITY SGTS DEPENDS ON SYSTEM SELECTED ON PANEL 11R -

--GAS ALL ASSOCIATED VALVES ARE AIR OPERATED.

TREATMENT SYSTEM 1B24 O EF-1-9 (SGTS 11) (13KW)

FANS CRD SYSTEM 1B2 O CRD SYS. PUMP NC08B (200KW)

PUMP SERVICE WATER SYS. IB3 O SERVICE WATER PUMP 1-2 (204KW)

PUMP RBCCW SYS. 1B2 O RBCCW PUMP 1-2 (159KW)

PUMP

--CONTROL ROOM HVAC 1B3 O SUPPLY FAN, FN-826-008B (14KW)

SYSTEM FAN POST ACCIDENT INSTRUMENT 1B2 O PAIPP-2, PDP-733-058 (1.8KW)

POWER PANEL (PAIPP)

E6-I

- 1 Anteroenl OYSTER CREEK GENERATING STATION PROCEDURE Number AnExdonmpany 341

~

Title Revision No.

0 Emergency Diesel Generator Operation 75 ATTACHMENT 341-6 (Continued)

EDG 2 ENGINEERED SAFEGUARD LOADS AND OTHER CRITICAL LOADS

-- INDICATES ENGINEERED SAFEGUARD LOAD 0 INDICATES PRIORITY PUMP FOR SAFETY SYSTEM 0 INDICATES ALTERNATE PUMP FOR SAFETY SYSTEM A INDICATESVALVE COULD RENDER SYSTEM INOPERABLE SYSTEM BUS EQUIPMENT

-- CORE 1AB2 O V-20-41 SYSTEM 2 DISCHARGE VALVE SPRAY (A IF V-20-21 IS OOS/IA21)

SYSTEM 1B21A O V-20-40 SYSTEM 1 DISCHARGE VALVE CRIT1CAL (A IF V-20-15 IS OOS/IA2)

VALVES 1B21A A V-20-4 NZOl B (SYS 2) PUMP SUCTION VALVE FROM TORUS 0 1B21A A V-20-32 NZOlC (SYS 1) PUMP SUCTION VALVE FROM TORUS 0 1B21A A V-20-18 SYSTEM 2 DISCHARGE VALVE 1B21A V-20-26 SYSTEM 2 RECIR. TEST VALVE TO TORUS

-- CONT. 1B21B A V-21-1 PUMP 51C SUCTION SPRAY 1B21B A V-21-3 PUMP 51D SUCTION SYSTEM 1B21B A V-21-5 DW SPRAY DISCHARGE CR[TICAL 1B21B V-21-13 TORUS CLG DISCHARGE VALVES 1821B A V-21-15 TORUS SPRAY 5% DISCHARGE "B" BATTERY MUST BE IN SERVICE TO CONSIDER EDG 2 OPERABLE.

E6-2

-iTitle I

OYSTER CREEK Revision No.

W PRIMARY CONTAINMENT CONTROL 17 ATTACHMENT A Attachment A to EMG-3200.02, Primary Containment Control, is the Primary Containment Control EOP Flowchart, EMG-3200.02 Rev. 5.

(320002/3) El-1

'. . Procedure EMG-3200.02 Support Proc. 25 Rev. 17 Attachment C Page 1 of 2 u SUPPORT PROCEDURE 25 INITIATION OF THE CONTAINMENT SPRAY SYSTEM IN THE TORUS COOLING MODE 1.0 PREREQUISITES Initiation of the Containment Spray System in the Torus Cooling Mode has been directed by the Emergency Operating Procedures.

2.0 PREPARATION None 3.0 PROCEDURE CAUTION Containment Spray suction strainer plugging may occur due to debris in the Primary Containment and result in a loss of Containment Spray System Flow.

3.1 CAUTION Diesel Generator overload will result if a Containment Spray Pump and ESW pump are started with a Diesel Generator load of greater than 2150 KW.

IF Bus IC or 1D are being supplied by an Emergency Diesel Generator, THEN verify that adequate load margin is available so as NOT to exceed EDG load limit when starting Containment Spray and ESW Pumps.

3.2 CAUT ION NPSH problems will develop on all operating pumps if more than 4 Containment Spray/Core Spray Main pumps are operated at the same time.

-IF 4 Containment Spray/Core Spray Main pumps are in operation,

-THEN do -not start additional Containment Spray pumps until Core Spray Main pumps can be secured.

'd OVER (320002/5) E3-1

Procedure EMG-3200.02 Support Proc. 25 Rev. 17 Attachment C Page 2 of 2 3.3 Start a Containment Spray Pump as follows:

L/

3.3.1 Select the Containment Spray System to be used by confirming either SYSTEM 1 MODE SELECT or SYSTEM 2 MODE SELECT switch in TORUS CLG position (Panel 1F/2F).

3.3.2 Select a Containment Spray Pump to be started.

3.3.3 Place and hold the System Pump Start Permissive Keylock for the selected pump in the appropriate position (Panel 1F/2F).

3.3.4 Start the selected Containment Spray Pump using its control switch (Panel 1F/2F).

3.4 Start an associated ESW Pump using its control switch (Panel 1F/2F).

3.5 CAUTION Operation of Containment Spray pumps with flow above the NPSH or vortex limits may result in equipment damage. When operating beyond any flow limits, periodic evaluations should be made to verify that continued operation beyond these limits is still required.

Monitor system parameters for expected performance.

3.6 Start additional Containment Spray and ESW Pumps as directed by the LOS in accordance with Steps 3.1 thru 3.5.

3.7 IF

- all Containment Spray pumps that are running are not required for Torus cooling, THEN inform the LOS and secure the Containment Spray pumps that are not required for Torus cooling.

(320002/5) E3 -2

AmerGen.. OYSTER CREEK GENERATING STATION PROCEDURE Number 341 1

An Cxcivn Company

\-d Title Revisi; No.

Emergency Diesel Generator Operation ATTACHMENT 341-5 EDG 1 ENGINEEREDSAFEGUARD LOADS AND OTHER CRITICAL LOADS

-- INDICATES ENGINEEREDSAFEGUARD LOAD 0 INDICATES PRIORITY PUMP FOR SAFETY SYSTEM 0 INDICATESALTERNATE PUMP FOR SAFETY SYSTEM A INDICATESVALVE COULD RENDER SYSTEM INOPERABLE SYSTEM BUS EQUIPMENT

-- CORE IC 0 CORE SPRAY MAIN PUMP NZOIA (493KW) SYS 1 SPRAY IC 0 CORE SPRAY MAIN PUMP NZOID (481KW) SYS 2 SYSTEM 1A2 0 CORE SPRAY BOOSTER PUMP NZ03A (247KW) SYS I PUMPS 1A2 0 CORE SPRAY BOOSTER PUMP NZ03D (255KW) SYS 2-AUTO STARTS ONLY IF BOTH NZO3A AND NZ03B NOT RUNNING NOTE: START PREVENTED FOR 200 SECONDS AFTER EDG BREAKER

-- CONT. 1A2 CONTAINMENTSPRAY PUMP 51A (254KW) SYS I SPRAY 1A2 CONTAINMENTSPRAY PUMP 51B (254KW) SYS 1

. , SYSTEM IC ESW PUMP 52A (328KW) SYS 1 v

PUMPS IC ESW PUMP 52B (328KW) SYS I LIQUID 1A21 LIQUID POISON PUMP NP02-A AND SQUIB VALVE NP05-A (25KW)

POISON SYSTEM PUMPS NOTE: PRIORITY SGTS DEPENDS ON SYSTEM SELECTED ON PANEL 1IR ALL ASSOCIATED VALVES ARE AIR OPERATED.

-- STANDBY 1,424 EF-1-8 (SGTS I) (9KW)

GAS TREAT-MENT FANS CRD SYSTEM PUMPS 1A2 CRD SYS. PUMP NC08A (212KW)

SERVICE WATER SYS.

PUMP IA3 SERVICE WATER PUMP 1-1 (187KW)

RBCCW SYS.

PUMP 1A2 RBCCW PUMP 1-1 (163KW)

-- CONTROL ROOM HVAC SYSTEM 1A2 SUPPLY FAN FN-826-008A (9KW)

FAN (DP-A2)

POST ACCIDENT INSTRUMENT 1A2 PANEL PAIPP-1, PDP-733-057 (1.9KW)

POWER PANEL (PAI PP)

E5-1

NRC Exam 2006-1 Reactor Operator Exam Key

46. A large un-isolable leak developed in the torus while the reactor was operating at rated power. The timeline for torus water level is as follows (all (t) times are in minutes):

0 At t = 0, Primary Containment Control entry was required due to low torus water level At t = 10, makeup to the torus was commenced using Core Spray System 1 At t = 30, torus water level was 130 inches At t = 50, torus water level was 120 inches Which statement below is true for these conditions?

a. At t = 70 minutes, PSP will be exceeded

b. At t = 70 minutes, the EMRV tailpipes begin to uncover

c. At t = 80 minutes, Emergency Depressurization will be required

d. At t = 110 minutes, the torus vent header downcomers begin to uncover Answer: a Handouts: EMG-3200.02 Justification: A is correct - the present rate of drop in torus level is 0.5 inches per minute (130 - 120 = 10 inches; 10 inched20 minutes = 0.5 incheslminute).

Therefore, in 20 more minutes (t = 70 minutes), level will have dropped to 110 inches, which is the point at which the torus vent header downcomers are uncovered, and the point at which the pressure suppression function of the primary containment can no longer be assured. It is for this reason that segment A-B of the PSP curve is vertical at 110 inches.

B is incorrect -the EMRV tailpipes are not uncovered until torus level reaches 90 inches, which will occur at t = 110 minutes given the current rate of drop in torus level.

C is incorrect - Emergency Depressurization is required BEFORE reaching 110 inches.. .at t = 80 minutes, level will have dropped to 105 inches.

D is incorrect - the torus vent header downcomers are uncovered at 110 inches.. .at t = 110 minutes, level will have dropped to 90 inches, which is where the EMRV downcomers start to uncover.

NOTE: the above calculations ignore the fact that torus water level will actually drop at a quicker rate due to the round shape of the torus.

295030 EA2.01 NRC RO Exam 2006-1 Key Page 77 of 129

NRC Exam 2006-1 Reactor Operator Exam Key

- Ability to determine and/or interpret the following as they apply to LOW SUPPRESSION POOL WATER LEVEL: Suppression pool level (CFR 41.9, CFR 41 .IO)

OC Learning Objective:

262 1 .828.0.0032, 0biective J :

Identify and interpret normal, abnormal, and Emergency Operating Procedures for Primary Containment.

2621.828.0.0032, Obiective T:

Interpret Primary Containment indications in terms of limits and trends.

Cognitive Level: Comprehension or Analysis Question Type: New

References:

EMG-3200.02, EOP Users Guide NRC RO Exam 2006-1 Key Page 78 of 129

EOP USERS GUIDE I

TORUS WATER m

\ &qGu/

LEVEL N UIi 1

PRIMARY CONTAINMENT CONTROL MAINTAINTORUS WATER L E M L ABOVE 110 IN. USING THE CORE SPRAY SYSTEM NOT REQUIRED FOR ADEQUATE CORE COOLING PER SUPPORTPROC I -37 I I

If Torus water level cannot be maintained above the pumps. If the Torus has been damaged (probable reason Technical Specification low water level LCO, an for Torus water level decrease), running the booster expanded Torus water level control band is given. pumps could cause further damage without increasing Direction is provided to refill the Torus as needed to the flow of water to the Torus. Thus only the main ensure the Drywell vent header downcomer openings do pumps are used to maximize flow to the Torus while not become uncovered. This would occur if Torus water minimizing further damage. Additionally, running level dropped below 110 in. Direction to fill the Torus booster pumps in this condition would cause the main is only given if system used to fill the Torus is not pump to operate further out on the head curve and could required to assure adequate core cooling. add to the NPSH problem caused by decreasing Torus level.

Support Procedure -37 provides instructions for adding water to the Torus using either the Core Spray System Normally, the Core Spray system would be the Main pump with suction fiom the CST or Fire Water preferred method for filling the Torus, since the Fire System injection into a Core Spray loop. In both Water System uses lower quality water that could lineups, the Core Spray Test Return valve is opened to ultimately end up in the Reactor. However, the Fire direct flow to the Torus. The systems used and whether Water System has the following advantages:

I loop or 2 loops are utilized is left to the discretion of the LOS. The Fire Water System is independent of offsite and onsite AC power sources When filling the Torus from the CST via the Core Spray system, only the Core Spray Main pumps are Access to the corner rooms is not required to specified because using the booster pumps does not establish the lineup (with decreasing Torus level the significantly increase the flow to the Torus via the test corner rooms could be flooded) return line. However, the pressure and velocity of the water entering the Torus is increased using the booster The Fire Water System supply is in excess of that available in the CST REVISION 7 2-59

NRC Exam 2006-1 Reactor Operator Exam Key

47. Plant conditions are as follows:

An ATWS is in progress SLC System 1 is injecting RPV water level is being maintained between 0 and -20 inches 0 Fuel Zone level indicators C and D have been turned on at Panel 4F Which Fuel Zone level instrument channels will be used to control RPV water level?

a. AandB

b. B and D C. C ONLY

d. D ONLY Answer: b Handouts: None Justification: A is incorrect - FZLl channel A and C are not accurate when SLC is injecting.

B is correct - B and D are both available and are providing accurate level U

indication. FZLl channels A and C utilize the SLC injection line as the variable leg and are therefore not accurate when SLC is injecting. Note that when all recirc pumps are tripped, FZLl channels A and B automatically turn on.

C is incorrect - FZLl channel A and C are not accurate when SLC is injecting.

D is incorrect - FZLl channel B is also available.

295037 EA2.02 Ability to determine and/or interpret the following as they apply to SCRAM CONDITION PRESENT AND REACTOR POWER ABOVE APRM DOWNSCALE OR UNKNOWN: Reactor water level (CFR 41.5, 41.7)

OC Learning Objective:

2621.828.0.0055, Obiective D:

Given a set of system indications or data, evaluate and interpret them to determine limits, trends and system status.

2621.828.0.0055, Obiective I:

Explain or describe how this system is interrelated with other plant systems.

NRC RO Exam 2006-1 Key Page 79 of 129

NRC Exam 2006-1 Reactor Operator Exam Key Cognitive Level: Comprehension or Analysis u

Question Type: New

References:

EOP Users Guide NRC RO Exam 2006-1 Key Page 80 of 129

08-8 t 1 3 M l NNVl 31s 1VIlINI W31SAS NOSlOd ainoi-i 3 i v i i i N i

NRC Exam 2006-1 Reactor Operator Exam Key

48. The control room has been evacuated due to a fire. The fire has been i_i/

extinguished. ABN-29, Plant Fires, requires the following ventilation systems shutdown prior to purging the control room.

0 A and B 480V Switchgear Room Ventilation System 0 A/B Battery Room, MG Set Room Ventilation System 0 Chemistry Laboratory Ventilation System 0 Reactor Building Ventilation System According to ABN-29, the reason this action is taken is to prevent smoke and fumes purged from the control room from being brought into these areas, which could

a. prevent personnel access

b. cause damage to equipment

c. set off automatic fire suppression systems

d. cause a reaction with other hazardous materials Answer: c Handouts: None Justification: A is incorrect - this is @ the reason stated in ABN-29.

~ L l B is incorrect - this is @the reason stated in ABN-29.

C is correct - this is the reason stated in ABN-29.

D is incorrect - this is @ the reason stated in ABN-29.

600000 AK3.04 Knowledge of the reasons for the following responses as they apply to PLANT FIRE ON SITE: Actions contained in the abnormal procedure for plant fire on site. (CFR 41.1 0)

OC Learning Objective:

2621.828.0.001 9, Obiective E:

Describe and interpret procedure sections and steps for plant emergency or off-normal conditions that involve this system including personnel allocation and equipment operation in accordance with applicable ABN, SDRP, EOP and EOP support procedures, and EPIPs.

NRC RO Exam 2006-1 Key Page 81 of 129

NRC Exam 2006-1 Reactor Operator Exam Key

- : Cognitive Level: Memory or Fundamental Knowledge Question Type: New

References:

ABN-29 NRC RO Exam 2006-1 Key Page 82 of 129

AmerGenn. OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-29 An f-xr.ionCornpnny

.-, Title Revision No.

PLANT FIRES 9

a. When the Control Room fire is extinguished, then PERFORM the following:

NOTE 7

Shutting down the following ventilation systems will prevent smoke and fumes purged from the Control Room from being brought into a Vital Area that contains an automatic fire suppression system (halon and water deluge).

Ensure referenced procedures are adhered to:

- A and B 480V Switchgear Room Ventilation System

- A/B Battery Room, MG Set Room Ventilation System

- Chemistry Laboratory Ventilation System (SF-I-16

& SF-1-17) (MOB North End Ventilation System)

- Reactor Building Ventilation System NOTE With no ventilation to the A/B Battery Room, it will take approximately 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months for hydrogen concentration in the room to reach 1% by volume.

Therefore, no compensatory ventilation measures are required for the 15-minute to I-hour period that A/B Battery Room ventilation may be off, while the Control Room is being purged of smoke.

Reference, Burns and Roe Study No. 3731-013 Study for Compliance of Battery Rooms Ventilation Systems with Appendix R Requirements.

A. 1. SHUT DOWN the B 480V Switchgear Room ventilation system IAW Procedure 331, Section 6.0 (Fan shutdown is all that is required.

17.0

NRC Exam 2006-1 Reactor Operator Exam Key

49. Given the following:

0 A plant startup is in progress with reactor power at 6%

The steam chest and high pressure turbine are being warmed 0 Reactor feed pump (RFP) A is in service feeding through LFRV A A RNLC failure causes RPV level to rise to 183 inches Which of the following occurs as a result of this failure?

a. RFP A trips ONLY

b. The main turbine trips ONLY

c. RFP A the main turbine trip

d. Neither RFP A nor the main turbine trip Answer: b Handouts: None Justification: A is incorrect - RFP A will not trip since ROPS is bypassed.

B is correct -the main turbine must be reset if the steam chest and HP turbine are being warmed and it will trip when RPV level reaches 175 inches. For RFP A to trip, the ROPS logic must see RPV level at 1181 inches and feedwater flow greater than 2.23 E6 Ibdhr. Feedwater flow will not get this high when feeding

through the LFRV, which is rated for a maximum of 1500 gpm (1500 gpm is equal to 0.72 E6 Ibdhr).

C is incorrect - the main turbine will trip; RFP A will not trip.

D is incorrect - the main turbine will trip.

295008 G2.1.27 High Reactor Water Level / Conduct of Operations: Knowledge of system purpose and or function (CFR 41.5, 41.7)

OC Learning Objective:

2621.828.0.001 8, Obiective A:

Given plant operating conditions, describe or explain the purpose(s)/function(s) of the system and its components.

2621.828.0.0018, Obiective D:

Describe the interlock signals and setpoints for the affected system components and expected system response including power loss or failed components.

NRC RO Exam 2006-1 Key Page 83 of 129

NRC Exam 2006-1 Reactor Operator Exam Key

.-J Cognitive Level: Comprehension or Analysis Question Type: New

References:

201,317, RAP-HSd, RAP-H7d, ABN-10 NRC RO Exam 2006-1 Key Page 84 of 129

Group Heading D W PRESS H-5-d ROPS ACTUATE A AND I CONFIRMATORY ACTIONS:

o CHECK Reactor level indications.

(PNL 5F/6F)

AUTOMATIC ACTIONS:

All operating feed pumps trip, if coincident with ROPS Actuate B (H-6-d actuated) AND ROPS is NOT bypassed (H-7-d clear).

MANUAL CORRECTIVE ACTIONS:

o CONFIRM Reactor Scram and Turbine Trip. [ I a ISOLATE the Isolation Condensers. [ I Turbine was in service, THEN CONFIRM Turbine trip in accordance with ABN-10, Turbine Trip. [ I o REFER to ABN-17, Feedwater System and RESTORE RPV level within the normal operating band. [ I a REFER to ABN-1, Reactor Scram. [ I Subject Procedure No.

Page 1 of 2 NSSS RAP-H5d H-5-d Alarm Response Procedures Revision No: 0

Group Heading DW PRESS ROPS ACTUATE A CAUSES: SETPOINTS ACTUATING DEVICES:

Rx Water Level rising. 181" TAF PNL-629-14XRC R1 Reference Drawings:

GU 3D-629-17-002 GU 3E-611-17-010 Subject Procedure No. I Page 2 of 2 I

NSSS RAP-H5d I H-5-d Alarm Response Procedures Revision No: 0

Group Heading DW PRESS H-7-d ROPS BYPASSED CONFIRMATORY ACTIONS:

P CHECK total feed flow indications.

(Recorder ID-75; PCS point HB-FWFLN)

CHECK ROPS Bypass switch position.

(PNL-629-4FCS11)

AUTOMATIC ACTIONS:

NONE MANUAL CORRECTIVE ACTIONS:

P E ROPS manual bypass is not required, THEN CONFIRM the ROPS Manual Bypass Switch is in NORMAL position.

(4F) [ I CAUSES: SETPOINTS: ACTUATING DkVICES:

Total Feedwater Flow Low Auto Bypass: PNL-629-14XRCR3

-~ 2 . 2 3O6~ Ib/hr 1

Reset:

ROPS manual bypass switch 4F in BYPASS -X2.4~1 O6 Ib/hr PNL-629-4FCS11 position Reference Drawings:

GU 3D-629-17-002 GU 3E-611-17-010 Subject Procedure No.

Page 1 of 1 RAP-H7d I H-7-d Alarm Response Procedures Revision No: 0

I AmerGen-An Exelon Corrpany OYSTER CREEK GENERATING Number ABN-10 STATION PROCEDURE u Revision No.

Title TURBINE GENERATOR TRIP 2 ATTACHMENT ABN-10-1 MAIN TURBINE TRIPS NOTE: The following should occur due to a Main Turbine Trip.

1. Main Stop Valves close.

2. Turbine Control Valves close.

3. Reheat and Intercept Valves close.

4. 13'h Stage Low Load Dump Valves open (if closed).

5. Extraction Check Valves close.

6. 3 Stage Extraction Bypass Valves open (if closed).

7. Moisture Removal Valves open.

I I

Main Generator trip.

1. Low Condenser Vacuum

2. Generator Lockout

3. Main or Auxiliary Transformer Lockout

4. Auxiliary Trip Lockout

5. High RPV Water Level

/

6. Moisture Separator Drain Tank Hi-Hi Level

7. Thrust Bearing Wear Detector

8. No Load With 2"d Sage RSCV not Shut

9. 25% Load (decreasing) not Reset.

10. Overspeed

11. Backup Overspeed.

12. Keylock Switch in TEST (Panel 13R)

13. Manual Trips (Panel 7F, Front Standard) c 8.0

NRC Exam 2006-1 Reactor Operator Exam Key

50. The reactor was initially operating at rated power. A feedwater line break inside primary containment resulted in a high drywell pressure scram.

Current plant conditions are as follows:

0 RPV level is 88 inches and rising slowly with both CRD pumps injecting 0 RPV pressure is being maintained at 800-900 psig with Isolation Condensers 0 Drywell pressure is 13 psig and lowering slowly with drywell sprays initiated 0 Torus water temperature is 145 O F and lowering slowly 0 Torus water level is 168 inches and rising slowly Which of the following is the most immediate reason for lowering torus water level?

To prevent exceeding the

a. Torus Load Limit

b. Heat Capacity Temperature Limit

c. Primary Containment Pressure Limit

d. Maximum Pressure Suppression Primary Containment Water Level

~ .4 Answer: a Handouts: EMG-3200.02, or, providing the LARGE figures of the graphs would be preferred Justification: A is correct - based on a torus water level of 168 inches and rising, and a reactor pressure of 800-900 psig, the Torus Load Limit is the most immediate concern since it will be exceeded before any of the other limits. From Figure E (TLL) of EMG-3200.02, the Torus Load Limit that corresponds to an RPV pressure of 800 to 900 psig is -174 to 178 inches.

B is incorrect - since torus water temperature is lowering, the margin to the HCTL is improving.

C is incorrect - for the given torus water level and torus pressure (drywell pressure), the PCPL is of no concern.. .torus pressure would have to rise above 50 psig at the given torus level for this to be a concern.

D is incorrect - the MPSPCWL is 188 inches, which makes it a secondary concern relative to the Torus Load Limit.

NRC RO Exam 2006-1 Key Page 85 of 129

NRC Exam 2006-1 Reactor Operator Exam Key 295029 EK3.02

'U Knowledge of the reasons for the following responses as they apply to HIGH SUPPRESSION POOL WATER LEVEL: Lowering suppression pool water level (CFR 41.9, 41 .lo)

OC Learning Objective:

2621.828.0.0032, Obiective J:

Identify and interpret normal, abnormal and Emergency Operating Procedures for the Primary Containment System Cognitive Level: Comprehension or Analysis Question Type: New

References:

EMG-3200.02, EOP Users Guide NRC RO Exam 2006-1 Key Page 86 of 129

EOP USERS GUIDE PRIMARY CONTAINMENT CONTROL WATER LEVEL \

BELOW F I G 5 TLL L I I

I TORUS WATE LEYEL

-1 ON )

I 1

If Torus water level cannot be maintained below the The Torus Load Limit takes into account the stress Technical Specification high water level LCO (1 54 in.), produced at the EMRV tail pipes for different Reactor an expanded Torus water level control band is given. pressures and Torus levels. Refer to Figure E of the This step directs that Torus level be controlled on the EOP Figures and Limits section of this document for safe side of the Torus Load Limit (TLL) to prevent tail additional details of the TLL.

pipe failure if an EMRV operates.

REVISION 7 2 - 63

NRC Exam 2006-1 Reactor Operator Exam Key

51. Consider an event in which an accident causes a high-energy radioactive

..J system to discharge into the Reactor Building.

Assuming the radioactivity release into the Reactor Building is the same in each case, which of the following results in the hiahest off-site release rate?

Reactor Buildina AP Standbv Gas Treatment flow

a. -0.1 0 inches WG 2600 scfm

b. 0.0 inches WG 0 scfm

d. 0.10 inches WG 0 scfm

c. 0.10 inches WG 2600 scfm Answer: d Handouts: None Justification: A is incorrect - in this case there is a minimal release through SGTS, which is -99% efficient. Since SGTS is able to maintain a negative RB AP, there is no ground level release.

.-/

B is incorrect - with RE3 AP at zero and no SGTS flow there is no release.

C is incorrect - in this case only a ground level release is occurring since there is a positive pressure in the Reactor Building and no SGTS flow.

D is correct - since there is a positive pressure in the Reactor Building a ground level release is occurring, which is equivalent to the ground level release in choice C (based on the same RB AP). In addition, since SGTS is not 100%

efficient (see UFSAR Table 6.5-l), there is some relatively small release through this path. Therefore, this case results in the hiahest off-site release rate.

295035 EK2.03 Knowledge of the interrelations between SECONDARY CONTAINMENT HIGH DIFFERENTIAL PRESSURE and the following: Off-site release rate (CFR 41.8, 41.9)

OC Learning Objective:

2621.828.0.0042, Obiective F:

Given a set of system indications or data, evaluate and interpret them to determine limits, trends and system status.

2621.828.0.0042, Obiective L:

- 4 Explain or describe how this system is interrelated with other plant systems.

NRC RO Exam 2006-1 Key Page 87 of 129

NRC Exam 2006-1 Reactor Operator Exam Key Cognitive Level: Comprehension or Analysis Question Type: New

References:

UFSAR Table 6.5-1 W"

NRC RO Exam 2006-1 Key Page 88 of 129

Oyster Creek Nuclear Generating Station FSAR Update TABLE 6.5-1 (Sheet 1 of3)

MAJOR STANDBY GAS TREATMENT SYSTEM COMPONENTS Inlet and Exhaust Valves Type Flanged, air cylinder operated, butterfly Design Conditions 150 psig, 150°F Material Cast iron body HEPA Filters Filter Media Glass microfiber CM-115 Filtering Efficiency 99% for particles 0.3 micron and larger, as measured by dioctylphthalate smoke test (DOP)

Flow Rate 2600 cfm Clean Pressure Drop 2" W.G. at 2600 cfm (Cambridge) 1.8" W.G. at 2600 cfm (Farr) v' Maximum Operating Differential Pressure 10" W.G.

Charcoal Filter Weight of Charcoal 300 Ibs.

Removal Efficiency 99.9% elemental iodine 90% methyl iodide Total Retention Capacity 400 gm of total iodines, including 40 gm CH3I (methyl iodine)

Charcoal Bed Depth 2 in.

Nominal Residence Time 0.25 sec.

Nominal Flow Rate 2600 cfm Nominal Flow Velocity 40 fpm Clean Filter Pressure Drop 1.1 in. W.G. maximum at 2600 cfm Update 11 04/99

NRC Exam 2006-1 Reactor Operator Exam Key

52. Given the following:

I

The reactor is shutdown due to a forced outage Reactor water level is 165 inches on NR GEMAC Three (3) Shutdown Cooling pumps are in service Total Shutdown Cooling System flow is 7500 gpm According to Procedure 305, Shutdown Cooling System Operation, raising shutdown cooling system flow rate may result in.. .

a. flow-induced vibration of the shutdown cooling heat exchangers

b. damage to the nuclear instrumentation due to flow-induced vibration

c. Spurious trips of the shutdown cooling pumps due to low suction pressure

d. Exceeding the maximum design tube-side flow rate of the SDC heat exchangers Answer: c Handouts: None Justification: A is incorrect - Procedure 309.2 has a P&L to limit RBCCW flow to

\ -

less than 3700 gpm to prevent damage to the RBCCW heat exchanger from flow U

induced vibration. This is not related to SDC (tube side) flow but could be a misconception.

B is incorrect - this is related to a precaution associated with Reactor Recirculation System operation (P&L 5.2.8 of Procedure 301.2), not Shutdown Cooling.

C is correct - as stated in 305, Simultaneous operation of all three (3) SDC Pumps at high flow rates (System Flow >7500 gpm) may result in pump suction pressures near the trip setpoint (4 psig). To avoid spurious pump trips, operation at system flow > 7500 gpm should be minimized.

D is incorrect - according to 305, the maximum design tube side flow rate is 3400 gpm.

205000 Al.02 Ability to predict and/or monitor changes in parameters associated with operating the SHUTDOWN COOLING SYSTEM (RHR SHUTDOWN COOLING MODE) controls including: SDC/RHR pump flow (CFR 41.10)

NRC RO Exam 2006-1 Key Page 89 of 129

NRC Exam 2006-1 Reactor Operator Exam Key OC Learning Objective:

e 2621.828.0.0045, Obiective P:

Identify and explain the normal operating procedures for the Shutdown Cooling System.

Cognitive Level: Memory of Fundamental Question Type: New

References:

301.2, 305, 309.2 NRC RO Exam 2006-1 Key Page 90 of 129

An Cxem Company I OYSTER CREEK GENERATING STATION PROCEDURE I umber 305 i Title Revision No.

Shutdown Cooling System Operation 90

1. CONFIRM one Recirc Loop fully open (Panel 3F).

2. CONFIRM the other four Recirc Loops in the idle or isolated condition (Panel 3F).

3. THROTTLE V-5-106, SD CLG CCW OUTLET valve CLOSED (Panel 1F/ZF), to establish RBCCW outlet temperature between 150°F and 190°F as indicated by TR-RV08 (1F/2F).

4. NOTE High SDC System flow is always preferred, however, high Reactor water level aids in system performance.

The levels specified represent the minimum for that flow range.

ESTABLISH SDC System flow rate in accordance with the following:

CAUTION Simultaneous operation of all three (3) SDC Pumps at high flow rates (System Flow >7500 gpm) may result in pump suction pressures near the trip setpoint (4 psig). To avoid spurious pump trips, operation at system flow > 7500 gpm should be minimized.

Reactor water level is maintained at or above 160 TAF (Gemac)

THEN MAINTAIN SDC System flow >7500 gpm.

e -IF Reactor water level is maintained at or above 165 TAF (Gemac),

THEN MAINTAIN SDC System flow between 6500-7500 gpm.

IF Reactor water level is maintained at or above 170 TAF (Gemac),

THEN MAINTAIN SDC System flow between 6000-6500 gpm.

28.0

NRC Exam 2006-1 Reactor Operator Exam Key

53. Which of the following methods of makeup to the Isolation Condensers

'4 require operation of the A and B Isolation Condenser Makeup Valves, V-11-36 and V-11-34, on Panel 5F/6F?

1. Adding makeup with Demineralized Water IAW 307, Isolation Condenser System

2. Adding makeup with Fire Protection IAW 307, Isolation Condenser System (NOT from local hose stations)

3. Adding makeup with Fire Protection via local hose stations IAW 307, Isolation Condenser System

4. Core Spray makeup to the Isolation Condensers IAW 308, Emergency Core Cooling System Operation

a. 1 and 2

b. 3 and 4 C. 1 and 3

d. 2 and 4 Answer: d Handouts: None Justification: A, B and C are incorrect - makeup with Demineralized Water (choice 1) is the normal method of shell makeup when the IC's are in standby.

u' This method fills the IC shells via grab sample lines.. .this flow path does not utilize V-11-36 and V-11-34. Makeup from Fire Protection via local hose stations (choice 3) utilizes the IC shell drain lines as the makeup flow path.. .does not utilize V-11-36 and V-11-34.

D is correct - adding makeup with Fire Protection IAW 307 (choice 2), and Core Spray makeup IAW 308 (choice 4), are the only methods (of those given) that utilize makeup valves V-11-36 and V-11-34, which are the normal makeup supply valves from the Condensate Transfer System.

207000 A4.06 Ability to manually operate and/or monitor in the control room: Shell side makeup valves (CFR 41.8, 41.1 0)

OC Learning Objective:

2621.828.0.0023, Obiective C:

Describe or trace (given a simplified drawing or P&ID) the basic flow path for the following modes of Isolation Condenser operation:

1. Standby

2. Emergency Operation

3. Sources of Shell Side Makeup NRC RO Exam 2006-1 Key Page 91 of 129

NRC Exam 2006-1 Reactor Operator Exam Key Cognitive Level: Memory of Fundamental

-v Question Type: New

References:

307,308 GE 148F262 L-NRC RO Exam 2006-1Key Page 92 of 129

AmerGen, OYSTER CREEK GENERATING Number A n Cxeh Company STATION PROCEDURE 307 L. Title Revision No.

Isolation Condenser System 92 7.3.2 Makeup from the Fire Protection System NOTE If water cannot be obtained from the Condensate Transfer System, water shall be obtained from the Fire Protection System to fill the Isolation Condenser.

CAUTION Potential overboard discharge path via V-I 1-49 and V-9-2099.

7.3.2.1 CLOSE V-I 1-41, Isolation Condensers Supply Isolation Valve.

(Reactor Building 23 East) 7.3.2.2 CLOSE V-I 1-63, Makeup to isolation Condenser Telltale Drain Valve.

(Reactor Building 23 East) 7.3.2.3 UNLOCK and OPEN V-9-2099, Fire Protection to Isolation Condenser Cross-Tie Isolation Valve.

(Reactor Building 23 East) 7.3.2.4 OPEN V-I 1-49, Fire Protection to Isolation Condenser Makeup Valve.

(Reactor Building 23 East) 7.3.2.5 RECORD initial shell level reading (PCS ID LTIG06A) on makeup to Isolation Condenser Record Sheet, Attachment 307-15.

7.3.2.6 OPEN V-I 1-36, Isolation Condenser Makeup Valve.

(Panel 5F/6F) 7.3.2.7 FILL between 7.3 and 7.7 feet, observing Isolation Condenser Water Level Indicator.

(Panel 1F/2F) 7.3.2.8 WHEN water level in Isolation Condensers is between 7.3 and 7.7 feet, THEN CLOSE V-I 1-36, Condensate Transfer Valve.

26.0

AmerGen, OYSTER CREEK GENERATING Number AR Exew Campany STATION PROCEDURE 308

.- Title Revision No.

Emergency Core Cooling System Operation 76 ATTACHMENT 308-12 (continued)

Core Spray Makeup To The Isolation Condensers Initial /Verify 3.2 START NZOIA if necessary by momentarily placing its respective control switch on Panel 1F/2F to the start position, then release. t 3.3 -IF NZOIA does not start, THEN PLACE the control switch for NZOIC to the start position, then release. i 3.4 NOTE If Core Spray pumps are to be operated for greater than 30 minutes on minimum recirculation flow; and if conditions permit, an operator should be dispatched to check the operating core spray pumps for excessive vibration.

CAUTION If a Core Spray System I Booster Pump is operating refer to Step 3.1 to secure it. This will limit the pressure on the Condensate Transfer System piping.

PERFORM the following valve lineup.

3.4.1 CLOSE valve V-I 1-15, Reactor Building Condensate Transfer Isolation Valve, located RB SW-23.

3.4.2 UNLOCK and OPEN V-I 1-1I O , Condensate Transfer Pressure Regulator Bypass, located RB NW-51.

3.4.3 UNLOCK and OPEN V-I 1-111, Condensate Transfer Pressure Regulator Bypass, located RB NW-51.

3.5 I CAUTION This operation will breach both primary and secondary containment. If conditions occur that will increase torus activity such as fuel damage during the use of this procedure, then secure makeu to the Isolation Condensers.

ADD makeup to the Isolation Condensers as necessary to MAINTAIN shell level between 4.8 and 7.7 feet by OPERATING valve V-I 1-36 for A Isolation Condenser, or V-I 1-34 for the B Isolation Condenser.

E l2-2

NRC Exam 2006-1 Reactor Operator Exam Key

54. Given the following:

An automatic scram occurred while operating at rated power All control rods did NOT fully insert; reactor power is 13%

The SLC tank contains 12 weight percent of boron solution Reactor pressure band is being maintained at 800 to 1000 psig Reactor water level band is being maintained at -20 to +30 inches Standby Liquid Control (SLC) System #1 is injecting into the RPV Which one of the following conditions ensures adequate SHUTDOWN MARGIN?

a. When SLC System #1 has been injecting for 30 minutes

b. When SLC System #1 has been injecting for 60 minutes

c. When at least 650 gallons of liquid poison tank contents have been injected into the RPV

d. When at least 1300 gallons of liquid poison tank contents have been injected into the RPV Answer: b Handouts: Tech Spec 3.2

~4 Justification: A is incorrect - 30 gpm for 30 minutes yields 900 gallons of boron solution at 12 weight percent. This is outside the shaded area of Tech Spec Figure 3.2-1 , which means insufficient boron solution would have been injected to ensure adequate SHUTDOWN MARGIN.

B is correct - SLC pump capacity is 30 gpm. 1800 gallons of boron at 12 weight percent would have been injected after 60 minutes. This is within the shaded area of Tech Spec Figure 3.2-1, which represents the acceptable values of liquid control tank volume and solution concentration which assure that, with one 30 gpm liquid control pump, the reactor can be brought to the cold shutdown condition from a full power steady state operating condition at any time in core life independent of the control rod system capabilities. (The cross-hatched area of Figure 3.2-1 represents the acceptable values of liquid control tank volume and solution concentration which assure that the equivalency requirements of 10 CFR 50.62-ATWS Rule-are satisfied. Note the Tech Spec definition of SHUTDOWN MARGIN is: ...the amount of reactivity by which the reactor would be subcritical when the control rod with the highest reactivity worth is fully withdrawn, all other operable control rods are fully inserted, all inoperable control rods are at their current position, reactor water temperature is 68, and the reactor fuel is xenon free. Determination of the control rod with the highest reactivity worth includes consideration of any inoperable control rods which are not fully inserted.

NRC RO Exam 2006-1 Key Page 93 of 129

NRC Exam 2006-1 Reactor Operator Exam Key C is incorrect - this is outside the shaded area of Tech Spec Figure 3.2-1. It is L-also equivalent to Hot Shutdown Boron Weight (HSBW), which does result in sufficient boron injected to meet the shutdown margin definition. However, based on the HSBW definition in the EOP Users Guide, the tank volume (650 gallons) has been calculated assuming that the boron concentration in the liquid poison tank is as the minimum limit required by Tech Specs, which is not the case for the conditions that are given in the stem of the question.

D is incorrect - 1300 gallons of 12 weight percent of boron is outside the shaded area of Tech Spec Figure 3.2-1.

21 1000 K5.03 Knowledge of the operational implications of the following concepts as they apply to STANDBY LIQUID CONTROL SYSTEM: Shutdown margin (CFR 41.6)

OC Learning Objective:

2621.828.0.0046, Obiective A:

Given plant operating conditions, describe or explain the purpose(s)/function(s) of the system and its components.

2621.828.0.0046, Obiective N:

Given Technical Specifications, identify and explain associated actions for each section of the Technical Specifications relating to this system including personnel allocation and equipment operation.

v Cognitive Level: Comprehensive or Analysis Question Type: New

References:

UFSAR 9.3.5, EOP Users Guide, Tech Spec 1.45/3.2.C, 612.4.001 NRC RO Exam 2006-1 Key Page 94 of 129

- AmerGem An xclon Company I OYSTER CREEK GENERATING STATION PROCEDURE I Number 612.4.001 i I

'v Title Revision No.

Standby Liquid Control Pump and Valve Operability and In-Service 30 Test INIT1ALNERI FY 6.12.3 REPLACE Test Tank top cover -J cv 6.12.4 REPLACE Standby Liquid Control Tank Manway cover. f cv 6.12.5 E Temporary test gage was installed (Attachment 6I2.4.001-7).

THEN REMOVE temporary test gage.

6.13 TRANSFER required data from the body of this procedure to Data Sheet and IST Summary Sheet as applicable.

6.14 REVIEW the results of the surveillance against section 7.0 acceptance criteria.

6.14.1 RECORD commentsfdiscrepancies on the Data Sheet.

7.0 ACCEPTANCE CRITERIA 7.1 The components tested by this procedure meet Technical Specification requirements for operability if the following criteria are met. If not met, consider the affected components inoperable and follow the requirements of Technical Specification Section 3.2.C and Procedure LS-AA-I20.

7.1 .I Standby Liquid Control pumps start and operate as specifiedin the procedure.

-+ 7.1.2 Measured pump flow is equal to or greater than 30 GPM. (This requirement also satisfies IST requirements for operability test of V-I 9-37 and V-I 9-38.)

7.2 The pumps tested by this procedure meet In-Service Test (IST) requirements for operability if the following criteria are met. If any are not met consider the component inoperable and follow the requirements of Procedure LS-AA-120.

7.2.1 Pump flow is between low action and high action range.

7.2.2 Pump vibration is below the action range.

21.o

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NRC Exam 2006-1 Reactor Operator Exam Key

55. Given the following:

0 A reactor startup is in progress 0 Reactor pressure is 500 psig 0 Reactor water level is 160 inches 0 Reactor power is 20% on IRM Range 8 Two steam jet air ejectors (SJAE) are in service The steam chest and high-pressure turbine are being warmed A spurious reactor isolation occurs Which of the following describes the plant response and/or the correct action for this event?

a. Commence a normal plant shutdown IAW 203, Plant Shutdown

b. An automatic scram occurs, enter ABN-1, Reactor Scram ONLY C. An automatic scram occurs, enter ABN-1, Reactor Scram RPV Control - No ATWS

d. Place the startup on hold until the failure is corrected, then re-open the MSlVs IAW 301 .l, Main Steam Supply System Answer: b Handouts: None

\*r Justification: A is incorrect - an automatic scram will occur.

B is correct - the reactor isolation results in closure of all MSlVs and main steam line drains (in addition to some other valves). At 500 psig (<600 psig), the MSlV closure scram is bypassed. Although there is relatively little steam flow, the reactor isolation will cause reactor pressure to rise. As pressure rises, power will also rise due to collapsing steam voids. The pressure rise will cause reactor power to increase to the IRM Hi-Hi scram setpoint, which is 38% on IRM Range

8. This will occur before pressure rises to the high-pressure scram setpoint of 1045 psig. The automatic scram will terminate the pressure rise. NOTE: as stated in Tech Spec 2.3 (LSSS) Bases, Below 600 psig, when the MSlV closure scram is bypassed, scram protection is provided by the IRMs. For the given conditions (at this point in the startup), there would be one feedwater pump in service and with relatively low steam flow and feed flow, there would not be a significant change in RPV level due to the MSlV closure. Since RPV level remains above 138 inches, and RPV pressure remains below 1060 psig, there are no EOP entry conditions.

C is incorrect - the transient will not result in any EOP entry conditions.

D is incorrect - an automatic scram will occur.

.LJ NRC RO Exam 2006-1 Key Page 95 of 129

NRC Exam 2006-1 Reactor Operator Exam Key 21 2000 A2.11

.-11/ Ability to (a) predict the impacts of the following on the REACTOR PROTECTION SYSTEM; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those abnormal conditions or operations: Main steamline isolation valve closure (CFR 41.5, 41.6)

OC Learning Objective:

2621.828.0.0037, Obiective D:

Describe all RPS scram logic trip signals, including the following:

1. Purpose / Design Basis

2. Setpoints

3. Conditions that allow bypassing scram signals

4. How bypassing scram signals is accomplished 2621.828.0.0037. Obiective F:

Given a set of system indications or data, evaluate and interpret them to determine limits, trends and system status.

2621.828.0.0037, Obiective N:

Describe and interpret procedure sections and steps for plant emergency or off-normal conditions that involve this system including personnel allocation and equipment operation IAW applicable ABN, SDRP, EOP & EOP support procedures, and EPIPs.

Cognitive Level: Comprehensive or Analysis

~,

Question Type: New

References:

ABN-1, EMG-3200.01A, Tech Spec 2.3 Bases, 237E566 NRC RO Exam 2006-1 Key Page 96 of 129

The low pressure isolation of the main steam line at 825 psig was provided to give protection against fast reactor depressurization and the resulting rapid cool-down of the vessel. The low-pressure isolation protection is enabled with entry into IRM range 10 or the RUN mode. In addition, a scram on 10% main steam isolation valve (MSIV) closure anticipates the pressure and flux transients which occur during normal or inadvertent isolation valve closure. Bypass of the MSlV closure scram function below 600 psig is permitted to provide sealing steam and allow the establishment of condenser vacuum. Advantage is taken of the MSlV scram feature to provide protection for the low-pressure portion of the fuel cladding integrity safety limit. To continue operation beyond 12% of rated power, the IRM's must be transferred into range 10.

Reactor pressure must be above 825 psig to successfully transfer the IRM's into range 10.

Entry into range 10 at less than 825 psig will result in main steam line isolation valve closure and MSlV closure scram. This provides automatic scram protection for the fuel cladding integrity safety limit which allows a maximum power of 25% of rated at pressures below 800 psia. Below 600 psig, when the MSlV closure scram is bypassed, scram protection is provided by the IRMs.

Operation of the reactor at pressure lower than 825 psig requires that the mode switch be in the STARTUP position and the IRMs be in range 9 or lower. The protection for the fuel clad integrity safety limit is provided by the IRM high neutron flux scram in each IRM range. The IRM range 9 high flux scram setting at 12% of rated power provides adequate thermal margin to the safety limit of 25% of rated power. There are few possible significant sources of rapid reactivity input to the system through IRM range 9:effects of increasing pressure at zero and low void content are minor; reactivity excursions from colder makeup water, will cause an IRM high flux trip; and the control rod sequences are constrained by operating procedures backed up by the rod worth minimizer. In the unlikely event of a rapid or uncontrolled increase in reactivity, the IRM system would be more than adequate to ensure a scram before power could exceed the safety limit. Furthermore, a mechanical stop on the IRM range switch requires an operator to pull up on the switch handle to pass through the stop and enter range I O . This provides protection against an inadvertent entry into range 10 at low pressures. The IRM scram remains active until the mode switch is placed in the RUN position at which time the trip becomes a coincident IRM upscale, APRM downscale scram.

The adequacy of the IRM scram was determined by comparing the scram level on the IRM range 10 to the scram level on the APRMs at 30% of rated flow. The IRM scram is at 38.4% of rated power while the APRM scram is at 59.3% of rated power. The minimum flow for Oyster Creek is at 30% of rated flow and this would be the lowest APRM scram point. The increased recirculation flow to 65% of flow will provide additional margin to CPR Limits. The APRM scram at 65% of rated flow is 100.8% of rated power, while the IRM range 10 scram remains at 38.4%

of rated power. Therefore, transients requiring a scram based on flux excursion will be terminated sooner with a IRM range 10 scram than with an APRM scram. The transients requiring a scram by nuclear instrumentation are the loss of feedwater heating and the improper startup of an idle recirculation loop. The loss of feedwater heating transient is not affected by the range 10 IRM since the feedwater heaters will not be put into service until after the LPRM downscales have cleared, thus insuring the operability of the APRM system. This will be administratively controlled. The improper startup of an idle recirculation loop becomes less severe at lower power level and the IRM scram would be adequate to terminate the flux excursion.

OYSTERCREEK 2.3-5 Amendment No.: ??,293,211,235

Procedure EMG-3200.01A Support P roc- 1 Rev. 12 Attachment B Page 1 of 3 SUPPORT PROCEDURE 1 CONFIRMATION OF AUTOMATIC INITIATIONS AND ISOLATIONS 1.0 PREREQUISITES Confirmation of automatic initiations and isolations has been directed by the Emergency Operating Procedures.

2.0 PREPARATION None 3.0 PROCEDURE Confirm the following isolations/starts not required to by bypassed by the Emergency Operating Procedures:

SYSTEM OPERATING DETAILS Reactor -

IF Any of the following conditions exist:

Isolation RPV water level at or below 86 in. and not bypassed Steam tunnel temperature at or above 180°F Any steam line flow at or above 4 . 0 ~ 1 0 6lbm/hr Reactor mode switch in RUN and RPV pressure at or below 8 5 0 psig Main steam line radiation at or above 800 units no ATWS condition exists THEN Confirm closed the following:

MSIVs IC VENTS RX SAMPLE

- NS03A - V-14-1,-19 V-24-30 (11F)

- NSO4A - V-14-5,-20 V-24-29 ( 1 1 F )

___NS03B DW AIR SUPPLY

___NSO4B V-6-395 (11F)

Scram -

IF A Reactor Scram is initiated Discharge Volume AND Isolation SDV H I - H I LVL SCRAM switch is not in BYPASS, THEN Confirm closed the following:

NORTH SDV Vents & Drains SOUTH SDV Vents & Drains OVER

( 3 2 0 0 0 1A/S4 ) E2-1

Group Heading REACTOR PRESS H-I-f MANUAL CORRECTIVE ACTIONS: (continued from Page I of 2)

OE full scram condition occurs, THEN REFER to ABN-I, Reactor Scram.

NOTE This alarm indicates that a parameter has exceeded or has the potential to exceed an Emergency Action Level (EAL).

o REFER to EP-OC-1010, Radiological Emergency Plan to determine EAL classification.

CAUSES: SETPOlNTS: ACTUATING DEVICES:

High reactor pressure trip to Reactor Protection 1045 psig PT-RE03A System Channel I. PT-RE03C Reference Drawings:

GE 237E566 Sh. 1 GU 3E-611-17-010 Subject Procedure No.

RAP-HIf H-I-f Alarm Response Procedures Revision No: 0

Group Heading REACTOR NEUTRON MONITORS G - I -e CAUSES: SETPOINTS: ACTUATING DEVICES:

Flux level greater than 118% on 125% scale 118% on 125% Relays: RHOGA (KI,KIO) or greater than 38% on 40% scale. IRM scale 1OK35 Channel hop indicates high voltage lost to 38% on 40% 1OK37 detector, module removed or mode switch scale 1OK39 on channel drawer not in OPERATE or unit inoperative 1OK41 position. These trips are inputs to Reactor Protection System Channel I.

Reference Drawings:

GE 706E812, Sh. 9, IO, 11, 12, and 39 GU 3E-611-17-009 Sh. 1 Subject Procedure No. I NSSS RAP-Gle I Page40f4 G - I -e Alarm Response Procedures Revision No: 1

NRC Exam 2006-1 Reactor Operator Exam Key

56. Given the following:

I 0 A reactor startup is in progress 0 IRM Range 6/7 correlation is required by Procedure 201, Plant Startup Which of the following support personnel, if any, are required to be notified prior to performing this task IAW Procedure 402.2, IRM Operation During Startup?

a. An I&C Technician ONLY

b. A Reactor Engineer ONLY

c. An I&C Technician and a Reactor Engineer

d. No support personnel are needed, this task is performed by Operations ONLY Answer: a Handouts: None Justification: A is correct - Prerequisite 3.2 of Procedure 402.2 requires I&C to be notified to perform the IRM Range 6/7 correlation.

B is incorrect - a Reactor Engineer is not needed for IRM Range 6/7 correlation, i .- .,'

but is needed to perform IRM calibration IAW Procedure 1001.9.

C is incorrect - only an I&C Technician is needed for IRM Range 6/7 correlation.

D is incorrect - an I&C Technician is required to support performance of this task. Specifically, they perform any required IRM adjustments.

215004 G2.1 .I4 Intermediate Range Monitor (IRM) System / Conduct of Operations: Knowledge of system status criteria which require the notification of plant personnel. (CFR 41.1 0)

OC Learning Objective:

2621.828.0.0029, Obiective K:

Given Technical Specifications, identify and explain associated actions for each section of the Technical Specifications relating to this system including personnel allocation and equipment operation.

Cognitive Level: Memory or Fundamental Question Type: New

References:

201, 402.2 u'

NRC RO Exam 2006-1 Key Page 97 of 129

AmerGen,. OYSTER CREEK GENERATING Number AP rxeoi Company STATION PROCEDURE 402.2 Title Revision No.

IRM Operation During Startup 17 This revision involves significant reorganization of the procedure. No change bars are included.

1.o Purpose To provide instructions for the operation of the Intermediate Range Monitoring (IRM)

System during Plant Startup.

2.0 References 2.1 Procedures 201, Plant Startup 0 402.1, Energizing the IRM System for Operation 0 402.3, IRM Operation During Plant Shutdown 0 620.4.005, Intermediate Range Monitor Test and Calibration (Front Panel Test)

-b-1001.9, IRM Calibration to Reactor Power 2.2 Technical Specifications 0 Section 3.0, Limiting Conditions for Operations Section 4.1, Protective Instrumentation Table4.1.1 2.3 Updated FSAR, Chapter 7, Section 7.5.1.8.4.

3.0 PREREQUISITES 3.1 Intermediate Range Monitoring System is energized in accordance with Procedure 402.1. [ I

++ 3.2 Instrumentation Department personnel have been notified and are available to support the performance of this procedure. [ I 2.0

NRC Exam 2006-1 Reactor Operator Exam Key

57. Given the following:

'--\

Reactor power is 70%

Five recirc loops are in service and total recirc flow on panel 4F is 15.0E4 gpm The "C"recirc loop flow transmitter that feeds the Total Recirc Flow indicator on panel 4F fails to 0 (zero)

Recirc flow as displayed on panel 4F will read -(l)- E4 gpm, and will result in a -(2)-.

a. (1)12.0 (2)rod block

b. (1)12.0 (2)scram

c. (1)13.5 (2)rod block

d. (1)13.5 (2)scram Answer: a Handouts: Attachment 202.1-2 Justification: A is correct - the total recirc flow indicator on Panel 4F receives a signal from the flow monitor on Panel 5R, which inputs to APRM Channels 5 through 8. Prior to the failure, each flow transmitter was sensing approximately 3.0 E4 gpm, which is summed to produce 15.0E4 total recirc flow. One transmitter failing to zero results in a total indicated recirc flow of 12.0E4 gpm.

This produces a 10% mismatch between the RPS Division 1 and RPS Division 2 recirc flow monitors, causing a flow comparator rod block.

B is incorrect - reactor power at 70% is well below the scram setpoint for recirc flow at 12.0E4 gpm.. .the scram setpoint from Attachment 202.1-2is approximately 104% power.

C and D are incorrect - one could arrive at 13.5gpm if they thought there were 10 recirc flow inputs to the total recirc flow indicator on 4F, vice only 5.

215005 Al.04 Ability to predict and/or monitor changes in parameters associated with operating the AVERAGE POWER RANGE MONITOWLOCAL POWER RANGE MONITOR SYSTEM controls including: SCRAM and rod block trip setpoints (CFR 41.7)

-u-NRC RO Exam 2006-1 Key Page 98 of 129

NRC Exam 2006-1 Reactor Operator Exam Key OC Learning Objective:

'-' 2621.828.0.0029, Obiective F:

Describe the interlock signals and setpoints for the affected system components and expected system response including power loss or failed components.

2621.828.0.0029. Obiective G:

Given a set of system indications or data, evaluate and interpret them to determine limits, trends and system status.

Cognitive Level: Comprehension or Analysis Question Type: Bank

References:

202.1, 420, UFSAR 7.5.1.8.7, RAP-H7a NRC RO Exam 2006-1 Key Page 99 of 129

Procedure 202.1 Rev. 99 ATTACHMENT 202.1-2 Oyster Creek Power Operations Curve 120 I I I I I I I I I I I I I ,t-I-*

- -Scram Setpoint Rod Block Setpoini 100

-Max Power Line Max Flow Line

- 100% Rod Line 0 1 2 3 4 5 6 7 8 t 9 10 11 12 13 14 15 16 17 t18 8.5 17.7 Recirculation Flow (x I O 4 GPM)

Oyster Creek Nuclear Generating Station FSAR Update The APRM high power trip and rod block set points are flow biased. That is, they vary with recirculation flow, Consequently, the APRM system requires recirculation flow signals to compare with the APRM power level signals.

Processing of Recirculation Flow Signals

a. Recirculation Flow Transmitters Oyster Creek's five recirculation loops each have two flow transmitters (one per I2PS division). The transmitters are physically located on instrument rack RK04.

These transmitters monitor the differential pressure across the flow venturis. The differential pressure is proportional to the square of the flow rate. The transmitters perform a square root function internally and provide output current signals that are proportional to flow. These flow signals are sent to the Control Room panels 3R (division 1 ) and 5R (division 2) where the remaining electronics are located.

b. Current-to-Voltage (I-to-V) Converters These modules provide input isolation and convert the current signal from each transmitter to proportional voltage signals. The I-to-V converters also act as power supplies for the transmitters.

C. Summers Two summers are used in each division to develop total recirculation flow signals as follows. Since each summer has only four inputs, flow summing must be done in stages. The voltage outputs fi-om three of the five I-to-V converters are input into the first summer. Its output, along with outputs from the remaining two I-to-V converters is input into the second summer. The output from the second summer is a voltage signal proportional to the total flow rate.

The individual loop and total flow voltage signals are used to provide output signals as described below.

d. Output Flow Signals Individual Loop Flow Signals The individual loop flow voltage signals from the I-to-Vs go through Voltage-to-Current (V-to-I) converters. These isolated current signals are provided to the plant computer (division l), and to individual loop flow indicators on panel 3F (division 2).

7.5- 15 Update 11 04/99

Oyster Creek Nuclear Generating Station FSAR Update Total Flow Indication The total flow voltage signals in each division go through V-to-I converters.

These isolated total flow current signals are provided to a recorder on panel 3F (division 1) and to an indicator on panel 4F (division 2).

Total Flow Signals to APRM Trip Bias Units The total flow voltage signals in each division go through V-to-I converters that act as output isolators. The output current signals are sent through dropping resistors. The resulting total flow voltage signals are sent to the APRM trip bias units channels 1 , 2 , 3 and 4 (division l), and channels 5 , 6, 7 and 8 (division 2).

Total Flow Signal to Other Division The total flow voltage signals in each division are provided to the other division through output and input isolators. These signals are used for the comparator mismatch function as described below.

e. Trip Functions Upscale Trip The total flow voltage signal in each division is sent to a respective absolute alarm module. Recirculation flow in excess of 120% rated flow results in an upscale trip which is provided as an input to the Reactor Manual Control System (RMCS).

This input to the RMCS from each division of the recirculation flow monitoring electronics produces a rod block and a rod block display.

h o p Trip Isolated total flow voltage signals (identical to the signals provided to the APRM trip bias units) are sent to respective absolute alarm modules. Loss of power to the signal processing modules would cause this signal to go downscale. The absolute alarm module detects this downscale condition and provides an inop trip.

This input to the RPS from each division of the recirculation flow monitoring electronics produces a half scram. In addition, a rod block, rod block display, and alarm are produced by the inop trip.

7.5- 16 Rev. 13 04/03

CONTROL RODSlDRlVES ROD CNTR ROD BLOCK l__ I CAUSES: SETPOINTS: ACTUATING DEVICES:

These trips are inputs to Rod Block: Relays:

RWM: Rod not withdrawn or inserted in 4K12 accordance with programmed pre- 21K20 condition. 21K21 21K22 APRM lnop Recirc flow monitoring Difference OR inoperative or flow comparator between FlowTias: trip. channels

>I

- 0% (16000 gpm)

Drawer Mode Switch not in operate.

Module unplugged.

Recirc Flow Recirc Flow Equal to or 120% or FY-622-0042A (Relay C)

Upscale Rod greater than 120% Rated Flow 19.2 x i o 4 FY-622-0042B (Relay C)

Block: GPM IRM Inop: Intermediate Range Monitor module inoperative and mode switch in STARTUP or REFUEL.

SRM Inop: Source Range Monitor module inoperative and mode switch in Reference Drawings:

STARTUP or REFUEL (below IRM Range 8). GE 729E838 GU 3E-611-17-010 Subject Procedure No.

Page 12 of 14 NSSS RAP-H7a H-7-a Alarm Response - 1 Procedures Revision No: 2

NRC Exam 2006-1 Reactor Operator Exam Key

58. Given the following:

u The plant was initially operating at rated power 0 The control room was subsequently evacuated due to a fire The remote shutdown panel was placed into operation Reactor pressure is being controlled in accordance with the EOPs The EMRV fuses have been removed in accordance with ABN-30, Control Room Evacuation If the plant were to experience a subsequent small-break LOCA, how will this effect the ability to emergency depressurize the reactor to restore RPV water level?

Manual emergency depressurization with EMRV's -( 1)- available; automatic emergency depressurization via ADS -(2)- available.

a. (1) is (2) is

b. (1) is (2) is NOT

c. (1) is NOT (2) is

d. (1) is NOT (2) is NOT Answer: d Handouts: None Justification: A, B and C are incorrect - manual operation of the Eh RV's is not available with the fuses removed. In addition, since the control room is the only place where the EMRV's can be manually operated, and it has been evacuated, there is no ability to emergency depressurize with the EMRV's. Automatic operation of the EMRV's in the ADS mode is also defeated since the solenoids will not energize with the fuses removed.. .the ADS mode is not available.

D is correct - as stated in the CAUTION in Attachment ABN-30-8, removal of the EMRV fuses defeats both the high pressure and ADS functions of the EMRV's.

218000 K3.01 Knowledge of the effect that a loss or malfunction of the AUTOMATIC DEPRESSURIZATION SYSTEM will have on following: Restoration of reactor NRC RO Exam 2006-1 Key Page 100 of 129

NRC Exam 2006-1 Reactor Operator Exam Key water level after a break that does not depressurize the reactor when required

'- (CFR 41 -7)

OC Learning Objective:

2621.828.0.0005, Obiective I:

Describe the operation of the ADS controls including: Removal of ADS control logic fuses to close EMRVs.

Cognitive Level: Memory or Fundamental Question Type: New

References:

ABN-30, GE 729E182 NRC RO Exam 2006-1 Key Page 101 of 129

AmerGem OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-30 All t*clonCurrp;rny Title Revision No.

CONTROL ROOM EVACUATION 5 ATTACHMENT ABN-30-8 DISABLING THE EMRVS CAUTION This attachment involves pulling fuses to disable the EMRVs. While it is not expected that a fire in the Control Room complex will result in any EMRVs opening, the fuses can be removed as a precautionary action to remove power from the EMRVs. This action disables the ADS function as well.

I. If all of the following conditions are met:

1. There is a fire in the Control Room proper, resulting in a control room evacuation, and

2. The RSP has been actuated and pressure/level control is established, or it is suspected than an EMRV has spuriously actuated, and

3. An SRO on shift authorizes pulling the fuses, then PULL the following fuses at the specified panel, using the fuse pullers located in the 480V Switchgear room at RSP padlock:

EMRV Panel I- Fuses (located top center of PNL)

NR108A ERl8A 16F301A 16F302A 1

16F303A 16F304A NR108C ER18A 16F301C 16F302C 1

16F303C 16F304C NR108E ERI8A 16F301E 16F302E 1

16F303E 16F304E NR108B ER18B 16F301B 16F302B 1

16F303B 16F304B NRl08D ER18B 16F301D 16F302D 1

16F303D 16F304D 39.0

NRC Exam 2006-1 Reactor Operator Exam Key

59. Given the following:

The reactor is operating at rated power Pressure switch PS-1A83A fails low Using the attached drawing, GE 148F712 (see coordinates G-8), what is the effect of this failure?

a. One of the five ADS/EMRVs will NOT actuate in the ADS mode

b. One of the five ADS/EMRVs will NOT actuate in the relief mode C. Two of the five ADS/EMRVs will NOT actuate in the ADS mode

d. Two of the five ADS/EMRVs will NOT actuate in the relief mode Answer: b Handouts: GE 148F712 (ensure large enough to read)

Justification: A is incorrect - since the failed pressure switch senses reactor pressure, and ADS functions on RPV level and Drywell pressure only, the ADS mode is not affected by this failure.

6 is correct - PS-1A83A provides a high reactor pressure signal to EMRV NR108A. If this pressure switch fails low, EMRV A will not open on high reactor

=--J I pressure (1065 psig).

C is incorrect - since the failed pressure switch senses reactor pressure, and ADS functions on RPV level and Drywell pressure only, the ADS mode is not affected by this failure.

D is incorrect - although 2 of 5 EMRV's open at 5 1085 psig, and 3 of 5 EMRV's open at 5 1105 psig, each EMRV has a dedicated pressure switch that provides a high reactor pressure signal to the respective EMRV actuation logic. PS-1A83A provides a reactor pressure signal to EMRV NR108A only.

239002 K6.01 Knowledge of the effect that a loss or malfunction of the following will have on the RELIEFKAFETY VALVES: Nuclear boiler instrument system (pressure indication) (CFR 41.7)

NRC RO Exam 2006-1 Key Page 102 of 129

NRC Exam 2006-1 Reactor Operator Exam Key L e

, OC Learning Objective:

2621.828.0.0005. Obiective E:

Describe the EMRV initiation logic for both over-pressure operation and operation in the ADS mode. Include the following:

1. Initiation signals and setpoints

2. Timers and setpoints

3. Control switches

4. Panel indications 2621.828.0.0005, Obiective J:

State how the following systems interrelate with ADS:

1. Vessel and Primary Containment Instrumentation

2. Core Spray

3. NSSS

4. Vital AC Power

5. 125 VDC Power Cognitive Level: Comprehension or Analysis Question Type: New

References:

GE 148F712, GE 729E182, sh. 1, UFSAR 5.2.2.4 NRC RO Exam 2006-1 Key Page 103 of 129

1 1 I 1 I if I I \

WOE RANGE INDICATOR REACTOR PRESSURE/

E7 5F/6F 1613 LEVEL RECOROER

NRC Exam 2006-1 Reactor Operator Exam Key

60. Given the following:

0 The reactor is operating at rated power when a small leak develops inside the drywell Drywell temperature is 175 OF and drywell pressure is 2.6 psig; both are rising slowly The Unit Supervisor directs venting the primary containment using the Standby Gas Treatment System (SGTS) IAW Support Procedure 31 Which statement below describes how venting the primary containment IAW Support Procedure 31 affects the suppression chamber-to-drywell vacuum breakers and the reactor building-to-suppression chamber vacuum breakers? Assume the venting evolution causes containment pressure to lower.

Venting from the -( 1)- could cause the -(2)- vacuum breakers to open.

a. (1) torus (2) suppression chamber-to-drywell

b. (1) torus (2) reactor building-to-suppression chamber

c. (1) drywell (2) suppression chamber-to-drywell

d. (1) drywell (2) reactor building-to-suppression chamber Answer: c Handouts: None Justification: A is incorrect - for the suppression chamber-to-drywell vacuum breakers to open, suppression chamber pressure must exceed drywell pressure by at least 0.5 psid. For the given conditions, venting from the torus will cause suppression chamber pressure to remain below drywell pressure.

B is incorrect - for the reactor building-to-suppression chamber vacuum breakers to open, suppression chamber pressure must be at least 0.5 psid less than Reactor Building pressure, which is approximately at atmospheric pressure (-

0.25 WG). For the given conditions, venting the torus (to atmosphere) will not cause suppression chamber pressure to go below Reactor Building pressure by 0.5 psid.

NRC RO Exam 2006-1 Key Page 104 of 129

NRC Exam 2006-1 Reactor Operator Exam Key C is correct - venting from the drywell will cause drywell pressure to lower relative to suppression chamber pressure and if drywell pressure is 0.5 psid less than suppression chamber pressure, the suppression chamber-to-drywell vacuum breakers will open.

D is incorrect - for the given conditions, venting from the drywell will not cause suppression chamber pressure to go below Reactor Building pressure.

261000 Al.06 Ability to predict and/or monitor changes in parameters associated with operating the STANDBY GAS TREATMENT SYSTEM controls including: Drywell and suppression chamber differential pressure: Mark-I (CFR 41.7, 41.9)

OC Learning Objective:

2621.828.0.0042, Obiective M:

Describe and interpret procedure sections and steps for plant emergency or off normal conditions that involve this system including personnel allocation and equipment operations IAW applicable ABN, SDRP, EOP and EOP support procedures and EPIPs.

Cognitive Level: Comprehension or Analysis Question Type: New

References:

EMG-3200.02, EOP Users Guide, Fundamentals NRC RO Exam 2006-1 Key Page 105 of 129

AmerGen. OYSTER CREEK GENERATING Number An tuim Company STATION PROCEDURE 312.11 Title Revision No.

Nitrogen System and Containment Atmosphere Control 31 4.2.3 Stack and Reactor Building radiation monitors shall be monitored whenever the primary containment is being vented. If the primary containment requires venting and the potential exist for airborne activity to be higher than normal consideration should be given to vent through the standby gas treatment system.

4.2.4 Drywell pressure shall be maintained 1. I to 1.3 psig.

-== 4.2.5 p Torus to Drywell vacuum breakers relieve to Drywell at 0.5 psid.

Torus to Drywell delta pressure shall be maintained 5 0.2 psid.

4.2.6 The use of Torus Vent valves to lower Drywell pressure is preferred as it allows Torus water to scrub the vented gas.

4.2.7 When Primary Containment is required, simultaneous opening of Drywell and Torus valves listed together in Groups I or II or Ill in the table below is prohibited. Operating with both Drywell and Torus valves open creates a pathway to bypass the Torus to Drywell Vacuum Breakers (CM-1).

Group Drywell Torus V-23-13 V-23-15 I Nz Purge (12XR)

V-23-14 V-23-16 V-23-17 V-23-19 It NZMakeup (12XR)

V-23-18 V-23-20 V-27-1 V-28-17 Ventilation Valves V-27-2 V-28-18 Ill (Exhaust) V-23-21 V-28-47 V-23-22 23.0

Procedure EMG-3200.02

- * < Support Proc. 31 Rev. 17 Attachment H Page 1 of 3 U SUPPORT PROCEDURE 31 VENTING THE PRIMARY CONTAINMENT TO MAINTAIN PRESSURE BELOW 3.0 PSIG 1.0 PREREQUISITES Venting of the Primary Containment has been directed by the Emergency Operating Procedures.

2.0 PREPARATION None 3.0 PROCEDURE 3.1 Determine method to be used to vent the Primary Containment.

Vent via SGTS - continue at Step 3.2 Vent via Normal Building Ventilation -continue at Step 3.3.

3.2 -

IF the LOS directs venting the Primary Containment via SGTS, THEN perform the following:

1. Select a SGTS Train for operation by placing the STANDBY GAS SELECT switch in position SYSTEM 1 or SYSTEM 2.

2. Place the fan control switch for the train selected in the HAND position.

3. Close the SGTS CROSSTIE V-28-48 (Panel 11R)

4. Secure operating Reactor Building Supply Fans by placing the respective control switches in OFF position (Panel 11R).

5. Immediately secure Exhaust Fan EF 1-5 (or EF 1 - 6 ) by placing control switch in STOP position (Panel 11R).

6. Close V-28-21 and V-28-22 by placing the EXH VALVES TO MAIN EXHAUST control switch in CLOSE position (Panel 11R).

OVER (320002/10) E8-1

Procedure EMG-3200.02 Support Proc. 31 Rev. 17 Attachment H Page 2. of 3

'i/ 3.3 IF the LOS directs venting the Primary Containment via Rx. Bldg. ventilation, THEN perform the following:

1. Open Torus Vent valve V-28-18 (Panel 11F).

2. Cycle Torus Vent valve V-28-47 (Panel 11F) to maintain Drywell pressure below 3.0 psig.

3. IF

- the Torus cannot be vented, THEN perform the following:

a. Inform the LOS.

b. Open the Drywell Vent valves V-23-21 and V-23-22 (Panel 12XR).

c. Cycle Drywell Vent valve V-23-21 or V 22 to maintain Drywell pressure below 3.0 p s i g .

(320002/10) E8-3

Procedure EMG-3200.02

- * < Support Proc. 31 Rev. 17 Attachment H Page 1 of 3 U SUPPORT PROCEDURE 31 VENTING THE PRIMARY CONTAINMENT TO MAINTAIN PRESSURE BELOW 3.0 PSIG 1.0 PREREQUISITES Venting of the Primary Containment has been directed by the Emergency Operating Procedures.

2.0 PREPARATION None 3.0 PROCEDURE 3.1 Determine method to be used to vent the Primary Containment.

Vent via SGTS - continue at Step 3.2 Vent via Normal Building Ventilation -continue at Step 3.3.

3.2 -

IF the LOS directs venting the Primary Containment via SGTS, THEN perform the following:

1. Select a SGTS Train for operation by placing the STANDBY GAS SELECT switch in position SYSTEM 1 or SYSTEM 2.

2. Place the fan control switch for the train selected in the HAND position.

3. Close the SGTS CROSSTIE V-28-48 (Panel 11R)

4. Secure operating Reactor Building Supply Fans by placing the respective control switches in OFF position (Panel 11R).

5. Immediately secure Exhaust Fan EF 1-5 (or EF 1 - 6 ) by placing control switch in STOP position (Panel 11R).

6. Close V-28-21 and V-28-22 by placing the EXH VALVES TO MAIN EXHAUST control switch in CLOSE position (Panel 11R).

OVER (320002/10) E8-1

Procedure EMG-3200.02 Support Proc. 31 Rev. 17 Attachment H Page 2. of 3

'i/ 3.3 IF the LOS directs venting the Primary Containment via Rx. Bldg. ventilation, THEN perform the following:

1. Open Torus Vent valve V-28-18 (Panel 11F).

2. Cycle Torus Vent valve V-28-47 (Panel 11F) to maintain Drywell pressure below 3.0 psig.

3. IF

- the Torus cannot be vented, THEN perform the following:

a. Inform the LOS.

b. Open the Drywell Vent valves V-23-21 and V-23-22 (Panel 12XR).

c. Cycle Drywell Vent valve V-23-21 or V 22 to maintain Drywell pressure below 3.0 p s i g .

(320002/10) E8-3

NRC Exam 2006-1 Reactor Operator Exam Key

61. The reactor is operating at rated power when Bus 1C undervoltage relay 27-13C fails low. Annunciator BUS 1C VOLTS LO aoes into alarm. Bus 1C indications on Panel 8F/9F are normal.

How does EDG # 1 respond to this event?

EDG #1

a. remains in standby

b. is prevented from starting

c. fast starts, output breaker closes

d. fast starts, output breaker does NOT close Answer: a Handouts: None Justification: A is correct - the Bus 1C (and 1D) undervoltage relays are arranged in a two-out-of-three logic scheme, which requires any two relays to trip to disconnect the bus from its normal source (Bus 1A), actuate bus load shedding, and start the EDG. If a single relay drops out on undervoltage, the annunciator will go into alarm, but the automatic actions described above will not occur until a second relay drops out on undervoltage (or fails low).

B'is incorrect - EDG #1 will idle or fast start as needed.

C and D are incorrect - EDG #1 will not fast start until/unless at least one of the other two bus undervoltage relays (27-1 1C,27-12C) drop out on low voltage.

262001 K3.02 Knowledge of the effect that a loss or malfunction of the A.C. ELECTRICAL DISTRIBUTION will have on following: Emergency generators (CFR 41.7)

OC Learning Objective:

2612.828.0.0013, Obiective C:

Given a set of system indications or data, evaluate and interpret them to determine limits, trends and system status.

261 2.828.0.0013, Obiective I:

Describe the interlock signals and setpoints for the affected system components and expected system response including power loss or failed components.

2612.828.0.0013, Obiective N:

State the function and interpretation of system alarms, alone and in combination, as applicable in accordance with the system RAPS.

NRC RO Exam 2006-1 Key Page 106 of 129

NRC Exam 2006-1 Reactor Operator Exam Key Cognitive Level: Comprehension or Analysis

--4 Question Type: New

References:

RAP-T3a, UFSAR 8.3.1.1.1 NRC RO Exam 2006-1 Key Page 107 of 129

4160V STATION POWER BUS I C VOLTS LO CONFIRMATORY ACTIONS:

NOTE This alarm should only occur when there is a degraded system voltage condition or sudden excess load drawn on power sources. will annunciate for Bus Loss of Power and Loss of Power Surveillances a CHECK Bus voltage. [ I a VERIFY trip of 4160V Bus I C Main Breaker IC. [ I voltages are low on 2 out of 3 Relays, THEN VERIFY Fast start of DG-1. [ I AUTOMATIC ACTIONS:

In 10 seconds with 2 out of 3 relays tripped the following occurs:

Trip of:

0 4160 V Breaker I C 0 4160 V Bus Tie Breaker EC (if Closed)

Emergency Service Water Pumps A and B (if running 0 4160 V Breaker 1Al P 0 Bus Tie Breaker US3T Fast start of DG-1.

Subject Procedure No.

Page Iof 2 ELECTRICAL RAP-T3a I T-3-a Alarm Response Procedures Revision No: 1

4160V STATION POWER BUS I C V O L T S LO VlANUAL CORRECTIVE ACTIONS:

NOTE This alarm indicates that a parameter has exceeded or has the potential to exceed an Emergency Action Level (EAL).

3 REFER to EP-OC-1010, Radiological Emergency Plan for Oyster Creek Generating Station to determine EAL classification. [ I 3 MONITOR Diesel Generator load to prevent overloading. [ I 1 INVESTIGATE cause of alarm. [ I 1 REFER to Procedure 337, 4160 Volt Electrical System. [ I

AUSES: SETPOINTS: ACTUATING DEVICES:

NOTE Definite Time Solid 27-11C via 27-1IXTD (trip)

State, BBC Voltage 27-12C via 27-12XTD (trip)

Alarm actuates on initial relay dropout Relays Type 27N 27-13C via 27-13XTD (trip) trip is actuated 10 seconds later if 27-11C via 27-11X (alarm) voltage has not been restored to (D.O.= 3830 volts)27-12C via 27-11X (alarm) normal on 2 of the 3 relays.27-13C via 27-1 1X (alarm)

NOTE: (2 out of 3 logic for trip, 1 out of 3 for alarm)

/oltage on bus I C less than 3830 volts.

Reference Drawings:

GU 3E-611-17-020 GE 223R0173, S h . 15 I I

u bject ELECTRICAL I Procedure

).

RAP-T3a T-3-a Alarm Response Procedures Revision No: 1

NRC Exam 2006-1 Reactor Operator Exam Key

62. Which one of the following annunciators would be accompanied by a loss of power to Main Steam Line Radiation Monitors RNO6A & RNO6B on 4

Panel 2R?

a. IP-4 PWR LOST

b. CIP 3 PWR LOST C. 24VDC PP-A PWR LOST

d. PROT SYS PNL 1 PWR LOST Answer: d Handouts: None Justification: A is incorrect - none of the MSL radiation monitoring equipment is powered by IP-4 (see ABN-58).

B is incorrect - CIP-3 provides power to the MSL radiation monitor recorders on Panel 1OF (see ABN-58).

C is incorrect - none of the MSL radiation monitoring equipment is powered by 24 VDC (see 340.2).

D is correct - MSL Radiation Monitors RNO6A & B on Panel 2R are powered from Protection System Panel #1, breaker #10 (see 406.1).

-u 262002 K1.14 Knowledge of the physical connections and/or cause-effect relationships between UNINTERRUPTABLE POWER SUPPLY (A.C./D.C.) and the following:

Main steam line radiation monitors (CFR 41.7)

OC Learning Objective:

2621.828.0.033A, Obiective G:

Explain or describe how this system is interrelated with other plant systems.

2621.828.0.033A, Obiective L:

State the function and interpretation of system alarms, alone and in combination, as applicable in accordance with the system RAPS.

Cognitive Level: Memory or Fundamental Question Type: New

References:

ABN-58, 406.1, 340.2, ABN-50 NRC RO Exam 2006-1 Key Page 108 of 129

AmerGen- OYSTER CREEK GENERATING STATION PROCEDURE Number An C x e h Company 406.1

. .uj Title Placing the Process Radiation Monitoring System in Operation ATTACHMENT 406.1-5 I Revision No.

52 Process Rad Monitoring System Electrical Lineup Section 5.2.1.3 Part I BREAKER INIT. I IV POWER SUPPLY ITEM LOCATION POSITION LINEUP lnst Pnl4C Bkr. 3, Stack RAGEMS Pump 460 V and Detectors Swgr. Rm. ON I lnst Pnl 3 Bkr. 12, Pnl. 2R, Power Supplies RN37, ROI I A , 460 V B, C & Vent Monitors Swgr. Rm. ON I lnst Pnl 3 Bkr. 16, Pnl. IOF, RN31A/B, 460 V RN28, RN32NB, RN30, R006NB460 Swgr. Rm. ON I lnst Pnl4B Bkr. 14, Pnl. I R , Log, Rad. 460 V Monitors RNI 2NB Swgr. Rm. ON I L

lnst Pnl4B Bkr. 18, Pnl. IOF, RK06, Offgas & Stack Gas Mon. 460 V Purge Control & Check Source Swgr. Rm. ON I Prot Sys Bkr. I O , Pnl2R, Log Rad. Mon.

7 _Pnl NO. I RNOGNB, Area. Eff. Mon. Power Lower Cable Supply Spread Rm. ON I Prot Sys Bkr. 10, Pnl. IR, Log Rad. Mon.

Pnl No. 2 RNO6CID Area Eff. Mon. Power Lower Cable Supply Spread Rm. ON I 24 VDC Bkr. 4, Pnl-IR, Proc. Rad. Mon.

Pnl A RN08, RNIOA, Log Rad. Mon. Lower Cable RN12NB Spread Rm. ON I 24 VDC Bkr. 2, Pnl. 2R, Area Rad. Lower Cable Pnl A Spread Rm. ON I MP-1A Bkr. 10, Outlet Receptacle Outside Pnl. RK06 Rear, Local Power Lower Cable Supply Spread Rm. ON I 125 VDC Bkr. 8 5F/6F Panel Lower Cable Pnl E Annunciates Spread Rm. ON /

C E5-1

Sroup Heading 9XF-3-a VITAL POWER AC PWR LOST PROT SYS PNL I PWR LOST SAUSES: SETPOINTS: ACTUATING DEVICES:

Loss of power to Protection System Panel None Relay K1

I (PSP-1).

Reference Drawings:

GU 3E-611-17-022 BR 3013, Sh. 1 GU 3C-733-11-010 GE 913E91I Subject Procedure No. 1 Page 3 of 3 ELECTRICAL RAP-9XF3a 9XF-3-a Alarm Response

.---- , Procedures Revision No: 0

OYSTER CREEK GENERATING Number AmerGem An t x e b i Company STATION PROCEDURE ABN-50

/

d Title Revision No.

LOSS OF VMCC l A 2 2

6. PLACE the POWER SELECT switch in the TRANS position. [ I 3.3 When power has been restored to PSP-1, then RESET the following:

Action Verify e Half scram trip signal I [ 1 e Main steam isolation 1 1 1 0 APRM lights on Panel 3R 1 1 1 0 APRM flow converters in Panels 3R and 5R [ 1 1 1 Main Steam Line Rad Monitors RN-6 A and B r e drawers 1 1 1 Associated annunciators [ 1 1 1 3.4 VERIFY the status LED on FCTR card is GREEN. [ I 3.5 If the status LED on FCTR card is red,

[ I then PUSH reset and VERIFY LED is green.

1. If the status LED can not be reset to GREEN,

[ I then NOTIFY I & C.

3.6 VERIFY the Curve Select display on FCTR card is 0 and the active LED is GREEN. [ I

1. If the Curve Select Display is not 0 ,

then PUSH the SELECT button until the 0 is displayed [ 3 and NEXT HOLD the SET button for at least two seconds.

2. VERIFY active LED is now GREEN. [ I 7.0

NRC Exam 2006-1 Reactor Operator Exam Key

63. Which one of the following shows the correct correlation between the Emergency Diesel Generator governor mode of operation (droop, u

isochronous) and the positions of the EDG Mode Selector (PTD) Switch?

P = Peaking T = Transfer D = Deadline DrOOD Isochronous

a. P T and D

b. P and T D C. D P and T

d. T and D P Answer: b Handouts: None Justification: B is correct - the three-position PTD switch has the following functions: (1) PEAKING - sets up EDG to assume 2750 Kw on a normal start.

Since this operation is in parallel with the grid, the governor would be in the d

DROOP mode. (2) TRANSFER - sets up governor control circuitry for load transfer. Load transfer occurs between the EDG and the grid, which again means parallel operation and the governor is in the DROOP mode. (3)

DEADLINE - sets up EDG control circuits for isochronous operation.

A, C and D are incorrect - these are all incorrect combinations of the Mode Selector (PTD) Switch positions and the EDG governor modes of operation.

264000 K4.03 Knowledge of EMERGENCY GENERATORS (DIESEUJET) design feature(s) and/or interlocks which provide for the following: Speed droop control (CFR 41.7)

OC Learning Objective:

2621.828.0.0013, Obiective H:

Identify and explain system operating controls/indications under all plant operating conditions.

Cognitive Level: Memory or Fundamental Question Type: New

References:

341

.-.-J NRC RO Exam 2006-1 Key Page 109 of 129

Content/S kiI Is Activi ties/Notes b) STOP - EDG unloads, output breaker trips, unit idles for 15 minutes and shuts down Lu 2) Emergency Start Pushbutton a) EMERGECY START - EDG fast-starts and assumes emergenc y bus 1oads b) Use of Emergency start pushbutton bypasses 1C (1D) 86 lockout relay contacts in the EDG Fast-Start logic circuit.

3) Fault Logic Reset Pushbutton LO L a) Remotely resets engine fault logic in the event that the EDG must be started in an emergency with a fault present.

4) Mode Selector Switch ("I'D) - 3 position switch; normally in PEAKING a) PEAKING - sets up EDG governor controls to assume 2750 KW on normal start b) TRANSFER - sets up governor control circuitry for load transfer c) DEADLINE - sets up EDG control circuits for isochronous operation

5) Auto-Resynch Activate Pushbutton a) Automatically synchronizes EDG to power grid, transfers load, and shuts-down EDG.

b) Interlocked with Mode Selector (FTD) switch TRANSFER position

6) Voltage / KVAR Control Switch - 3 positions; RAISE, OFF,LOWER a) Allows remote control of EDG voltage or KVAR loading when operating in parallel with the power grid

7) Governor Control Switch - 3 positions; RAISE, OW, LOWER a) Allows remote control of EDG speed (frequency)

/

i/ or load when operating in parallel with the power grid k:\training\admin\word\2621\828000 13.doc Page 29 of 47

NRC Exam 2006-1 Reactor Operator Exam Key

64. The plant was at rated power with all systems normally aligned, when the following annunciator came into alarm:

ROD CNTRL - CONTROL AIR PRESS LO The Operator verifies instrument air pressure at 75 psig on Panel 7F, and notes air pressure is going down very slowly. One NLO in the field reports the instrument air receiver pressure indicates 105 psig and steady. Two other NLOs in the field report finding no air system leaks.

Which one of the following actions will be most effective in restoring instrument air pressure (assume no mis-positioned air system valves)?

a. Place the standby set of air dryers in service

b. Confirm the lag compressor starts and start the third compressor

c. Bypass the air dryers, pre-filters and post-filters

d. Confirm service air valve V-6s-2 automatically isolates Answer: c Handouts: None Justification: The question stem shows that upstream air pressure is normal (105 psig), but that downstream air pressure is degraded (75 psig). Between the measured points of good and bad air pressure are where the pre-filters, air dryers, and post-filters reside. Any single failure or a combination of failures of these components will result in the poor air pressure downstream. Not enough information is provided to determine which component has failed.

Answer a is incorrect. Although the air dryers could be one of the failed components, it may not be the failed component and thus, we are not assured that this action will allow for air pressure to recover.

Answer b is incorrect. The air compressors load and unload on pressure sensed at the air receivers. With a normal air pressure sensed at the receivers, there is no call for compressor loading. If another compressor is started, it too will not load since it senses adequate air pressure. Even if it were to load, this will have no effect on recovering air pressure downstream of the failed component.

Answer c is correct. Regardless of which component failed (pre-filter, dryer, post-filter), this step will bypass all of the potentially failed components. This will restore air pressure downstream of the filters and dryers.

Answer d is incorrect. This valve is located upstream of the fiIters/dryers. Its closure will have no impact on the air pressure downstream of the filterddryers.

NRC RO Exam 2006-1 Key Pagelloof129

NRC Exam 2006-1 Reactor Operator Exam Key Also, there is no indication that a leak in the service air system is adversely 4

affecting instrument air since the receivers all show normal pressure.

300000 A2.01 Ability to (a) predict the impacts of the following on the INSTRUMENT AIR SYSTEM and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those abnormal operations: Air dryer and filter malfunctions (CFR 41.7, 41.1 0)

OC Learning Objective:

2621.828.0.0043, Obiective G:

Describe the interlock signals and setpoints for the affected system components and expected system response including power loss or failed components.

2621.828.0.0043. Obiective H:

Given a set of system indications or data, evaluate and interpret them to determine limits, trends and system status.

2621.828.0.0043, Obiective I:

Identify and explain the system operating controls/indications under all plant operating conditions.

2621.828.0.0043, Obiective K:

State the function and interpretation of system alarms, alone and in combination, as applicable in accordance with the system RAPS.

~,

Cognitive Level: Comprehension or Analysis Ll Question Type: New

References:

RAP-HI a, ABN-35, BR 2013, sh. 1 NRC RO Exam 2006-1 Key Page 111 of 129

Group Heading CONTROL RODSlDRlVES ROD CNTRL H - I -a CONTROL AIR PRESS LO CONFIRMATORY ACTIONS:

o CHECK pressure indication PI-RD13.

(23' El.) [ I o CHECK Instrument Air supply pressure at PT-3.

(Panel 7F) [ I AUTOMATIC ACT10NS :

NONE MANUAL CORRECTIVE ACTIONS:

[ I o REFER to ABN-35, Loss of Instrument Air.

OE control air pressure as indicated on PT-3 lowers to 55 psig, OR Two or more Control Rods begin to drift into the Core, THEN manually SCRAM the reactor in accordance with ABN-1, Reactor [ I Scram.

Subject Procedure No.

Page 1 of 2 NSSS RAP-HI a H-1-a Alarm Response Procedures Revision No: 0

AmerGen,. OYSTER CREEK GENERATING STATION PROCEDURE Number ABN-35 An ExelonlBritish Energy Company I

W Title Revision No.

LOSS OF INSTRUMENT AIR 0

-+ 3.4 If Service Air pressure drops to 80 psig, then PERFORM the following:

1. START the third air compressor. [ I

2. BYPASS the Air Dryers, Pre-filters, and Post-filters. [ I

3. VERIFY all air compressors are operating normally. [ I 3.5 If Instrument Air pressure drops to 75 psig, then PERFORM the following:

1. CONFIRM Service Air Valve V-6s-2 has isolated and is not bypassed.

2. ANNOUNCE the following:

Attention all personnel, anyone presently utilizing the [ I Service Air system shall secure all work at this time.

3. DETERMINE and ISOLATE the source of the air loss. [ I 3.6 If Instrument Air pressure drops to 55 psig, or two or more control rods begin to drift into the core,

[ I then SCRAM the Reactor in accordance with ABN-1, Reactor Scram.

3.7 EXECUTE the operator actions listed in Attachment ABN-35-1, Major Systems Affected by Loss of Instrument Air. [ I 3.8 REFER to Attachment ABN-35-2, Other Plant Systems Affected. [ I

4.0 REFERENCES

4.1 ABN-1 , Reactor Scram 5.0 ATTACHMENTS

5. I ABN-35-1, Major Systems Affected by Loss of Instrument Air 5.2 ABN-35-2, Other Plant Systems Affected 4.0

I i

8

NRC Exam 2006-1 Reactor Operator Exam Key

65. Given the following:

0 The reactor is operating at rated power with the ACRD pump in service 0 The Unit Supervisor directs swapping to the B CRD pump so maintenance can be performed on the ACRD pump Which of the following actions, if any, must be performed prior to starting CRD pump B?

a. Close ByCRD pump discharge valve

b. Open B CRD pump suction valve ONLY

c. Open B CRD pump suction discharge valves

d. Take manual control of the in-service flow control valve Answer: d Handouts: None Justification: A is incorrect - this is only required during initial pump startup when placing the CRD system in service.

B and C are incorrect - as stated in Procedure 302.1, NOTE 4.3.1, during normal operation, both CRD pumps are usually valved to the system so that pump changeover for purposes other than maintenance may be made from the control room.

D is correct - for routine pump changeover, Procedure 302.1 requires taking manual control of the in-service flow control valve (NC03A or NC03B) prior to starting the standby (alternate) CRD pump in service.

201001 A4.01 Ability to manually operate and/or monitor in the control room: CRD pumps (CFR 41.1 0)

OC Learning Objective:

2621.828.0.0011, Obiective 13:

Given normal operating procedures and documents for the system, describe or interpret the procedural steps.

Cognitive Level: Memory or Fundamental Question Type: New

References:

302.1 NRC RO Exam 2006-1 Key Page112of129

AmerGen_ OYSTER CREEK GENERATING STATION PROCEDURE Number An Fu:mCompany

. I 302.1

--/ I Title Revision No.

Control Rod Drive System 92 4.3 NOTE The procedures that follow describe placing standby equipment in service.

The exact nature of the requirement (malfunction, maintenance, etc.) will ultimately dictate if draining and total electrical isolation is required. Refer to the appropriate Maintenance Procedures and Technical Manual references for appropriate instructions. In general, these procedures may be accomplished during Reactor operation; however, they must be coordinated with Control Room operations to preclude the possibility of Control Rod movement while such procedures are in progress.

Procedure 4.3.1 NOTE During normal system operation, both CRD pumps are usually valved to the system so that pump changeover for purposes other than maintenance may be made from the Control Room.

CRD Pump 4.3. I.I PERFORM the following to swap CRD Supply Pumps:

1. E an immediate pump start is not required, THEN ESTABLISH communications between the Control Room and the CRD Pump Room.

2. TAKE manual control of the in-service Flow Control Valve (FCV) (NC30A or NC30B)

(Panel 4F).

3. PLACE the alternate CRD PUMP control switch to START (Panel 4F).

4. WHEN the alternate pump has been verified to be operating satisfactorily, THEN PLACE the in-service CRD PUMP control switch to STOP.

24.0

NRC Exam 2006-1 Reactor Operator Exam Key

66. Given the following:

The reactor is operating at rated power Annunciator CCW FLOW LO goes into alarm for the A reactor recirc Pump The crew has entered ABN-19, RBCCW Failure Response Which one of the following describes (1) when a reactor scram is required by ABN-19, and (2) the limiting reactor recirculation system component that this action is based on?

a. (1) when one CCW FLOW LO annunciator has been in alarm for >

1 minute (2) recirc pump seals

b. (1) when more than one CCW FLOW LO annunciator has been in alarm for > 1 minute (2) recirc pump seals C. (1) when one CCW FLOW LO annunciator has been in alarm for >

1 minute (2) recirc pump.motor

d. (1) when more than one CCW FLOW LO annunciator has been in alarm for > 1 minute (2) recirc pump motor Answer: b Handouts: None Justification: A is incorrect - ABN-19 directs a reactor scram when there are two or more CCW FLOW LO alarms for greater than one minute.

B is correct - when RPV temperature is > 212 OF, the mode switch is in STARTUP or RUN, and there are two or more CCW FLOW LO alarms for clreater than one minute, ABN-19 directs a reactor scram and trip of all operating recirc pumps. Recirc pumps seals are the limiting component since (1) the seal temperature limits specified in ABN-19 are lower for the seals than for the pump motors and (2) high seal temperatures can cause seal failure, which is of higher consequence than high motor bearing and/or winding temperatures.

C is incorrect - ABN-19 directs a reactor scram when there are two or more CCW FLOW LO alarms for greater than one minute. Recirc pump seals are the limiting component.

NRC RO Exam 2006-1 Key Page 113of 129

NRC Exam 2006-1 Reactor Operator Exam Key D is incorrect - recirc pump seals are the limiting component.

'.d 202001 A2.17 Ability to (a) predict the impacts of the following on the RECIRCULATION SYSTEM; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those abnormal conditions or operations: Loss of seal cooling water (CFR 41 -3, 41.1 0)

OC Learning Objective:

2621.828.0.0035, Obiective M:

Using the procedure, identify and explain normal and emergency operations of the RBCCW system.

Cognitive Level: Memory or Fundamental Question Type: New

References:

RAP-E7d, RAP-E7b, ABN-19 NRC RO Exam 2006-1 Key Page 114 of 129

AmerGen. OYSTER CREEK GENERATING Number ABN-19

-- A? Exelon Company STATION PROCEDURE I

Title Revision No.

RBCCW FAILURE RESPONSE 3 3.0 OPERATOR ACTIONS If while executing this procedure, any entry condition for any EOP occurs, then EXECUTE this procedure concurrently with the appropriate EOP.

NOTE: If the RBCCW pumps have tripped due to a loss of power and a LOCA condition exists, I then the pumps will automatically restart on the diesel generators.

If the diesel generators can accept the load, then the pumps may be manually restarted after bypassing the trip logic on the respective switchgear, USS-IAZ (1B2).

3.1 ;If a RBCCW pump tripped, L-then START any available RBCCW pump, if allowed.

I ? . . 3.2 If RPV temperature is greater than 212 OF and any of the following conditions exist for more than one minute:

All RBCCW flow is lost.

Any RBCCW Drywell Isolation valve has closed and can not be re-opened (V-5-147, -166, -167).

CCW FLOW LO alarms for more than one recirculation Pump A major, unisolable RBCCW leak occurs.

then PERFORM the following:

1. If the reactor is in STARTUP or RUN mode, then SCRAM the reactor and EXECUTE ABN-1.

6.0

X RECIRC PUMPSlDRlVES RECIRC PUMP A MANUAL CORRECTIVE ACTIONS:

CCW FLOW LO Alarm Received for Multiple Recirc Pumps multiple CCW FLOW LO alarms cannot be cleared within one minute, THEN PERFORM the following:

RPV Temperature is greater than 212°F o E the reactor is in the Startup or Run modes, THEN PERFORM the following:

c1 SCRAM the Reactor in accordance with ABN-1, Reactor Scram.

o CONFIRM Suction -Main Discharge Valves in at least one Recirc loop are Open.

o TRIP all Recirc Pumps.

o REFER to ABN-2, Recirculation System Failures.

o REFER to ABN-19, RBCCW Failure Response.

RPV Temperature is less than or euual to 212°F Q REFER to ABN-19, RBCCW Failure Response.

CCW FLOW LO Alarm Received for a Sinqle Recirc Pump ENTER ABN-19, RBCCW Failure Response.

Subject Procedure No.

Page 2 of 3 NSSS RAP-E7d E-7-d Alarm Response Procedures Revision No: 0

Group Heading RX RECIRC PUMPS/DRIVES E-7-d RECIRC PUMP A ccw FLOW LO A

CAUSES: SETPOINTS: ACTUATING DEVICES:

Low RBCCW flow to Recirc Pump seal and 20 GPM FS-2 10-0032A bearing cavities.

Reference Drawings:

GE 107C5339 GU 3E-611-17-007 Subject Procedure No. --r----

RAP-E7d I Page30f3 E-7-d Alarm Response Procedures Revision No: 0

NRC Exam 2006-1 Reactor Operator Exam Key

-- 67. The reactor was operating at rated power with the B RWCU pump in service when a turbine trip occurred. The following conditions currently exist:

An ATWS is in progress Reactor pressure is 950 psig 0 The Reactor Operator initiates Standby Liquid Control System 1 The following indications are observed:

o System 1 PUMP ON light on Panel 4F is lit o System 1 SQUIBS light on Panel 4F is NOT lit o Pump discharge pressure on Panel 4F is 1080 psig o FLOW ON annunciator on Panel 3F is NOT in alarm o SQUIB VALVE OPEN annunciator on Panel 3F is NOT in alarm What is the status of the Reactor Water Cleanup (RWCU) System?

RWCU is (1) and the B RWCU pump is (2) .

a. (1) isolated (2) tripped

b. (1) isolated (2) NOT tripped

c. (1) NOT isolated (2) tripped

d. (1) NOT isolated (2) NOT tripped Answer: d Handouts: None Justification: A is incorrect - RWCU is not isolated and the B RWCU pump is not tripped.

B is incorrect - RWCU is not isolated.

C is incorrect - the B RWCU pump is not tripped.

D is correct - the given conditions indicate SLC System 1 pump started (PUMP ON light is lit; 1080 psig discharge pressure) but the squib valve did not fire (SQUIBS light not lit; SQUIB VALVE OPEN annunciator not in alarm) and there is no liquid poison flow into the reactor (FLOW ON annunciator not in alarm).

RWCU isolation on SLC initiation occurs based on system flow > 15 gpm as Ll NRC RO Exam 2006-1 Key Page 115 of 129

NRC Exam 2006-1 Reactor Operator Exam Key sensed by FS-ILO6. This flow switch also inputs to the FLOW ON annunciator.

i-c Since the squib valve did not fire, system flow to the reactor did not reach the 15 gpm setpoint required to isolate RWCU. Since RWCU did not isolate, the B RWCU pump is still running.

204000 K6.07 Knowledge of the effect that a loss or malfunction of the following will have on the REACTOR WATER CLEANUP SYSTEM: SBLC logic (CFR 41 .6,41.7)

OC Learning Objective:

2621.828.0.0039, Obiective D:

Describe the interlock signals and setpoints for the affected system components and expected system response including power loss of failed components.

2621.828.0.0039, Obiective F:

Explain or describe how this system is interrelated with other plant systems.

Cognitive Level: Comprehensive or Analysis Question Type: New

References:

304, RAP-G1b, RAP-G2b NRC RO Exam 2006-1 Key Page 116 of 129

FLOW ON CONFIRMATORY ACTIONS:

P VERIFY the following:

0 Standby Liquid Control PUMP ON and SQUIBS lights Lit.

(Panel 4F). [ I Standby Liquid Control Pump discharge pressure greater than reactor pressure.

(Panel 4F). [ I 0 Cleanup System is tripped and isolated.

(Panels 3F and 11F). [ I Standby Liquid Control Tank level is lowering approximately 30 gpm.

(Panel 4F). [ I

~~

AUTOMATIC ACTIONS:

Isolates and trips Reactor Cleanup System by closing V-16-1, V-16-2, and V-16-14.

MANUAL CORRECTIVE ACTIONS:

3 In the event of inadvertent injection, SCRAM the reactor in accordance with ABN-1 , Reactor Scram. [ I 0 FOLLOW actions defined in ABN-5, Inadvertent SLC Initiation. I 1 Subject Procedure No.

Page 1 of 2 NSSS RAP-GI b G-I-b Alarm Response Procedures Revision No: 0

I_ AmerGen OYSTER CREEK GENERATING STATION PROCEDURE Number A n Exc:un Company 304

~-,'

I I Title Revision No.

Standby Liquid Control System Operation 36 5.0 INITIATING THE STANDBY LIQUID CONTROL SYSTEM 5.1 Prerequisites Standby Liquid Control System is in standby readiness IAW section 4.0 of this procedure. [ I 5.2 Precautions and Limitations 5.2.1 Standby Liquid Control System is initiated and secured when required by the Emergency Operating Procedures (EOPs). If a conflict arises between this procedure and the EOPs, the EOPs take precedence.

5.2.2 Due to pressure fluctuations, Fuel Zone Level Indicator Channel "A" will not provide accurate indication of reactor water level if a Standby Liquid Control pump is injecting to the RPV and should not be used. Variable leg for Channel "A1ties into the Standby Liquid Control injection line.

J '

5.3 Instructions for Initiation of System "1" 5.3.1 INITIATE Standby Liquid Control System "1" as follows: [ I 5.3.1.I START Pump A by rotating the keylock switch on Panel 4F to FIRE SYS 1. [ I 5.3.1.2 VERIFY the following events occur: [ I

1. PUMP ON light for System 1 on (4F). [ I

2. SQUIBS light for System 1 on (4F). [ I

3. Greater than Reactor pressure reading as indicated on Pump Disch Press indicator (4F). [ I

4. G-I-b, FLOW ON, alarm. [ I

5. G-2-b, SQUIB VALVE OPEN, alarm. [ I

6. Cleanup System Inlet Valves V-16-1, V-I 6-2 and V-16-14 close (I IF). [ I

7. Tank level lowers as indicated on Tank Level indicator (4F)

(approximately 100 gallons every three minutes). [ I 10.0

Group Heading STDBY LIQ CNTRL G-2-b SQUIB VALVE OPEN AUTOMATIC ACTIONS:

NOTE Reactor Cleanup System will trip and isolate if Liquid Poison flow is >I5 gpm.

NONE MANUAL CORRECTIVE ACTIONS:

o In the event of inadvertent injection, 0 SCRAM the reactor in accordance with ABN-1, Reactor Scram. [ I 0 FOLLOW actions defined in ABN-5, Inadvertent SLC Initiation. [ I CAUSES: SETPOINTS: ACTUATING DEVICES:

Actuation of either Standby Liquid Control Valve NPO5A or 14MR1 or 14MR2 Squib Valve, NP05A or NP05B. NPO5B open OR 2 mA 14MR1 or 14MR2 Loss of continuity/control circuit power Reference Drawings:

supply in the system.

GE 15786350 Sh. 188 GU 3E-611-17-009 Sh. 1 Subject Procedure No.

Page 2 of 2 NSSS RAP-G2b I G-2-b Alarm Response Procedures Revision No: 0

NRC Exam 2006-1 Reactor Operator Exam Key

68. Given the following:

0 The reactor is operating at rated power 0 LPRM detector calibrations are in progress 0 One TIP detector is IN-CORE 0 A leak occurs inside the drywell, causing drywell pressure to exceed 3.5 psig As the TIP detector retracts from the reactor, when will its ball valve automatically close?

As soon as the detector

a. is outside the reactor vessel

b. is outside the primary containment.

c. has moved past the ball valve

d. has moved into the shield chamber Answer: d Handouts: None Justification: A, B and C are incorrect - the ball valve will not close until the

..-/ detector is in the shield chamber, as indicated by the in-shield limit switch.

D is correct - when the TIP system receives a containment isolation signal due to high drywell pressure, all detectors not in-shield will retract to the in-shield position, the associated ball valves will close, and the purge valve will close. The ball valve receives a close signal from the detector in-shield limit switch (see 405.2, P&L 4.17, among other places in 405.2).

215001 A3.03 Ability to monitor automatic operations of the TRAVERSING IN-CORE PROBE including: Valve operation (CFR 41.7)

OC Learning Objective:

2621.828.0.0029, Obiective F:

Describe the interlock signals and setpoints for the affected system components and expected system response including power loss or failed components.

Cognitive Level: Memory or Fundamental Question Type: New

References:

405.2 NRC RO Exam 2006-1 Key Page 117of 129

AmerGen. OYSTER CREEK GENERATING Number An Excon Company STATION PROCEDURE 405.2 U

Title Revision No.

Operation of the TIP System 22 4.1 1 Drive cable can be completely inserted or retracted by using manual hand crank. However, drive chain must be removed to use crank; therefore, manual-hand operation shall be limited to maintenance, drive cable installation or if required to move probe should automatic withdrawal fail.

4.12 Shear Valve is only for emergency use when upon receipt of a Containment Isolation signal the associated ball valve fails to close.

---+-4.13 Ensure Manual Valve Control Switch is position to CLOSED and Ball Valve closes when Detector reaches IN-SHIELD position to prevent moisture buildup in TIP tube.

4.14 Ensure MANUAL Switch is OFF when TIP is IN-SHIELD.

4.15 If detector fails to insert normally, do not jog repeatedly in an attempt to reach Core Top; instead retract, select another channel and attempt to insert in that channel. Withdraw TIP and return to original channel; repeat twice if required. Notify Work Week Manager if assistance is required.

4.16 Notify Work Week Manager immediately if any malfunction of TIP machines during operation.

4.17 TIP switch, (TIP VLV ISOL. RESETICONT SWITCH) on Panel 1I F in CLOSED will cause any TIPS inserted to retract and will close TIP ball valves when IN-SHIELD Limit Switch is satisfied. TIP system purge valves will also close.

4.1 8 Operating TIPS may cause TIP cable to become activated. This may cause radiation levels in area of TIP machines to elevate above alarm level.

4.19 TIP guide tubes must be purged with either nitrogen or air at all times as the sermetal lubricant within guide tubes has an affinity for moisture and will turn to paste when exposed to ambient air. Swapping TIP purge from nitrogen to air or from air to nitrogen is controlled IAW Procedure 312.1 1.

Maintain TIP purge flow IAW Procedure 405.1.

5.0

AmerGen- OYSTER CREEK GENERATING Number An W o n Company STATION PROCEDURE 405.2

-4 Title Revision No.

Operation of the TIP System 22 CAUTION Frequent operation of TIPS may result in activation of TIP cable. This known condition can result in TIP area radiation levels exceeding alarm setpoint.

NOTE Position indication when IN-SHIELD should be three or four.

Position indication is not as important as IN-SHIELD indication. If position indication is not correct when TIP is IN-SHIELD an N R should be initiated. Do not jog to attain a position indication.

? - .

5.1.2.15 VERIFY the following on DCU when Detector retracts to In Shield:

0 In Shield lamp Illuminates [ 1 I

1. scan light is illuminated, THEN momentarily PLACE Mode Switch in AUTO then back to MANUAL. [ 1 5.1 2.16 CONFIRM Manual Valve Control Switch in CLOSED. [ 1 5.1.2.17 VERIFY the following:

0 Valve Indicator lamp is dimly illuminated on DCU [ 1

--+ 0 Ball Valve Closed lamp illuminated on VCM 1 5.1.2.18 additional TIP trace from another channel available with this DCU required, THEN RETURN to step 5.1.2 to scan another channel available on this Drive Control Unit, OTHERWISE CONTINUE at step 5.1.2.19 of this procedure. [ I 11.0

NRC Exam 2006-1 Reactor Operator Exam Key

69. Which of the following is a Fuel Pool Cooling System design feature that

..--- prevents inadvertent draining of the spent fuel storage pool?

a. Spent fuel storage pool liner telltale drain system

b. No penetrations in the spent fuel storage pool wall

c. Fuel pool cooling pumps trip on Lo-Lo skimmer surge tank level

d. Anti-siphon check valves in the spent fuel storage pool diffuser lines Answer: d Handouts: None Justification: A is incorrect - the telltale drain system provides indication of a spent fuel storage pool liner leak. ..it does not prevent inadvertent draining of the pool.

B is incorrect - there are penetrations in the spent fuel storage pool wall, however none are below the level. of 1 foot above the top of the stored fuel.

C is incorrect - the FPC pumps do trip on Lo-Lo skimmer surge tank level, but the purpose of this trip is to prevent loss of NPSH to the FPC pumps. Based on the design of the system (weir overflow of SFSP to SST, among others), the FPC pumps cannot drain the spent fuel storage pool.

. d D is correct - the diffuser lines (SFSP return) are the only lines that go below the top of the stored fuel. The anti-siphon check valves prevent inadvertent draining of the SFSP during reactor cavity letdown (siphoning from the spent fuel storage pool to the reactor cavity).

233000 K4.06 Knowledge of FUEL POOL COOLING AND CLEAN-UP design feature(s) and/or interlocks which provide for the following: Maintenance of adequate pool level (CFR 41.7, 41.9)

OC Learning Objective:

2621.828.8.0020, Obiective A:

Given plant operating conditions, describe or explain the purpose(s)/function(s) of the system and its components.

2621.828.8.0020, Obiective II:

Describe the operation of the anti-siphon check valves and analyze how the system may respond if they fail to perform their design function.

Cognitive Level: Memory or Fundamental Question Type: New

~I

.u NRC RO Exam 2006-1 Key Page 118 of 129

NRC Exam 2006-1 Reactor Operator Exam Key

References:

UFSAR 9.1.2.2, 9.1-3, 205, 31 1, 237E756 NRC RO Exam 2006-1 Key Page 119 of 129

OCNGS FSAR UPDATE 9.1.2.2 System Description 9.1.2.2.1 SDent Fuel Storage Pool The spent fuel storage pool is a reinforced concrete structure, completely lined with seam welded stainless steel sheets, themselves welded to reinforcing members embedded in the concrete. The pool was designed to withstand the anticipated earthquake loadings as a Class I structure. The spent fuel storage pool consists of 6 foot thick reinforced concrete walls and a 4 foot 6 inch reinforced concrete floor slab supported by reinforced concrete beams up to 13 feet 7 inches deep. The inside face of the pool is lined with Type 304 stainless steel. The liner is % thick on the bottom of the pool, the north wall, and at the opening to the reactor cavity. The liner is a nominal 1/8 thick on the remaining walls. The liner is liquid tight, serving as a barrier to any moisture loss from the concrete. The top of the pool is at El. 1 19 in the Reactor Building.

The spent fuel storage pool is 27 feet by 39 feet in plan with a total water depth of approximately 37 feet 9 inches, and an actual physical depth of 38-9. The depth of water to the top of the stored fuel is approximately 25 feet, providing some 200,000 gallons of water above the fuel.

(Drawing GE237E5 16)

The drainage system beneath the stainless steel pool liner detects and collects leakage between the liner and concrete, preventing leakage even in the unlikely event the concrete develops cracks. Water collected by the system drains into the Reactor Building Equipment Drain Tank, where it can be recycled via the liquid radwaste system to the Condensate Storage Tank.

To avoid unintentional draining of the pool, there are no penetrations that would permit the pool to be drained below one foot above the active fuel. All lines extending below this level are A equipped with suitable valving to prevent backflow. The passage between the fuel storage pool and the refueling cavity above the reactor vessel is provided with two double sealed gates with a monitored drain between the gates. This arrangement permits detection of leaks from the passage and repair of the gates in the event of such leakage. A liquid level switch monitoring pool water level is provided to detect loss of water and permit refilling of the pool from the condensate transfer system. In addition, a second level switch in the pool surge tank is provided to permit almost instantaneous water loss detection. Both detectors alarm locally and in the Control Room. A low-low level switch is provided to automatically trip the SFPCS pumps upon reaching set point. Radiation monitors on the operating floor near the spent fuel pool alarm on high radiation and initiate isolation of the Reactor Building and operation of the Standby Gas Treatment System.

9.1-3 Rev. 12 04/01

Oyster Creek Nuclear Generating Station FSAR Update and high pressure drop is annunciated. Filter flow is remotely indicated near the Original SFPC System pumps. A pump and a tank serve to add a precoat of powdered resin and fiber to the filter prior to operation. Resin type and volume for the fuel pool and condensate demineralizers are the same, thus the demineralizer resins are new o r partially exhausted condensate demineralizer resins that are slurried in the Condensate Demineralizer Regeneration System and transferred to the FP demineralizer.

The water from the Original SFPC System is returned to the SFSP through a single line. Flow is indicated locally on RB El 75'-3". At the SFSP, the return header branches into two lines which discharge through diffusers near the bottom of the pool, at the southeast and southwest corners. The diffusers are positioned to sweep return cooling water flow horizontally across the pool, providing optimum circulation without distortion due to temperature or flow patterns. The

.+ cooling system return pipes each have a check valve at the pool to prevent siphoning through these lines.

A trench sump in the pool, with a portion of the pool floor sloped to the trench, allows crud to collect in the trench. An underwater vacuum cleaner can be used to clean the trench, walls, floor and objects within the SFSP.

9.1.3.2.2 Augmented SFPC System Operation During a refuel outage, the Reactor Cavity and Equipment Storage Cavity are filled, and the gate is removed from the SFSP. The Augmented SFPC System removes decay heat from the spent fuel assemblies that are stored within the SFSP, as well as, decay heat from the water inventory contained within the Reactor Cavity and Equipment Storage Cavity. The system circulates the SFSP water inventory and maintains the SFSP water inventory at a temperature of T< 125"F, near the water surface. Water flows from the SFSP, over two adjustable skimmer weirs located in the SFSP, four skimmer weirs located in the Reactor Cavity and skimmer weirs located in the Equipment Storage Cavity and into the skimmer surge tanks. The water is pumped through the augmented plate heat exchanger and returns to the SFSP through two diffusers and the Reactor Cavity through two diffusers.

The pump design flowrate is throttled to establish a system operating flowrate of 800 GPM as limited by the system operating procedure; therefore, either pump can supply SFSP water to the augmented plate heat exchanger.

The maximum normal decay heat load corresponds to the decay heat from a normal refuel offload (-188 spent fuel assemblies) with the SFSP full from successive normal refuel offloads. The maximum normal decay heat load, ten days after a reactor shutdown, has been calculated at 8.66 MBTU/HR. The heat removal capacity of the Augmented SFPC System, ten days after a reactor shutdown, has been calculated at 9.65 MBTUMR. This heat removal capacity is based upon a maximum flowrate from the SFSP of 800 GPM, a maximum SFSP water inventory temperature of 125°F (near the water surface), a maximum RBCCW System cooling 9.1-28 Update 11 04/99

Oyster Creek Nuclear Generating Station FSAR Update the SFSP water inventory to heat-up from an initial temperature of 125°F and reach the boiling temperature. The boil-off rate of the SFSP water inventory would be -14.2 GPM.

The total elapsed time to heat-up and boil-off the SFSP water inventory to the top of the spent fuel storage rack is -83.5 HRS and -79.3 HRS when the SFSP water inventory is at an initial temperature of 90°F and 125OF, respectively. A loss of the SFSP System will require compensatory operator actions in accordance with station procedures to prevent heat-up and eventual boil-off of the SFSP water inventory.

During refueling activities, the SFSP water inventory can reach a temperature of T=llO°F -

115°F. A Control Room alarm will annunciate prior to the SFSP water inventory reaching a temperature of T = 120°F. Furthermore, station procedures instruct the plant operators to maintain the SFSP water inventory a t a temperature of T 5125OF, near the water surface.

The specific design criteria listed in Subsection 9.1.3.1 are met as follows:

a. The SFPC System is designed to operate with the failure of a single active component, The system has redundant components operated from redundant onsite power supplies.

b. The SFPC System is provided the capability of isolating components for periodic inspection and maintenance.

. , c. Portions of the SFPC System are in continuous operation, therefore their components do not require additional surveillance. The augmented fuel pumps and heat exchanger operate intermittently, and so surveillance activities are conducted prior to each anticipated use such that satisfactory performance can be verified. Sufficient instrumentation has been provided to monitor performance during operation and surveillance activities. Instrumentation and controls for the SFPCS are presented in Table 9.1-3.

+ d. The SFPC System is designed to prevent the loss of pool water inventory by providing suction for the system flow from the surface of the pool, and returning the coolant through diffusers, which are provided with backflow prevention devices to eliminate the potential for siphoning.

e. The SFPC System is provided with sufficient instrumentation (see Table 9.1-3) to detect and alarm loss of heat removal capability.

9.1-32 Update 11 04/99

I

-.-- I REACTOR CAVITY I

NRC Exam 2006-1 Reactor Operator Exam Key

70. Given the following:

0 The plant is operating at rated power on four (4) recirc loops 0 Recirc pump B is out of service due to an oil leak in the motor 0 The 41 60V BUS 1B UV annunciator goes into alarm Which of the following is the correct action to take for this event?

a. Scram the reactor and enter ABN-1, Reactor Scram

b. Confirm operating recirc pump speeds reduced to 20 to 30 Hz

c. Perform a rapid power reduction as directed by the Unit Supervisor

d. Enter 301.2, Reactor Recirculation System, for a scoop tube lockup on recirc pump D Answer: a Handouts: None Justification: A is correct - an undervoltage condition on bus 1B causes a trip of recirc pump D, a trip of condensate pumps B & C, and a trip of feedwater pumps B & C. For multiple condensate and/or feedwater pump trips, ABN-17 (Feedwater System Abnormal Conditions) directs scramming the reactor and entering ABN-1. The correct action from ABN-2 (Recirculation System Failures) is to close the D pump discharge valve.

B is incorrect - this action is directed by ABN-2 for a single recirc pump trip with only 3 loops initially in service (2 pumps remaining in service). This action would not be taken when there are 3 or 4 pumps remaining in service. ABN-2 does require recirc pump speed to be less than 33 Hz when only 3 recirc pumps are in service, but it does not direct action to lower speed to the 20 - 30 Hz range.

C is incorrect - as stated in ABN-17, this is the correct action to take for a single condensate pump or single feedwater pump trip.

D is incorrect - an undervoltage condition on bus 1B causes a scoop tube lockup on the D recirc pump and this action would be necessary to control the speed of the D recirc pump if it were still running. Since it tripped on the UV condition, this action would not be taken.

259001 K2.01 Knowledge of electrical power supplies to the following: Reactor feedwater pump(s): Motor-Driven-Only (CFR 41.7)

NRC RO Exam 2006-1 Key Page 120 of 129

NRC Exam 2006-1 Reactor Operator Exam Key

-- OC Learning Objective:

2621.828.0.001 7, Obiective C:

Given the system logic/electrical drawings describe the system trip signals, setpoints and expected system response including power loss or failed components.

Cognitive Level: Comprehensive or Analysis Question Type: Modified Bank

References:

RAP-T~c,ABN-2, ABN-17 NRC RO Exam 2006-1 Key Page 121 of 129

AmerGen- OYSTER CREEK GENERATING Number An Exckm Campany STATION PROCEDURE ABN-17 e

Title Revision No.

FEEDWATER SYSTEM ABNORMAL CONDITIONS 3

2) PLACE the affected valve in local-manual control in accordance with Procedure 317, Condensate and Feed System. [ I C. BALANCE flows through each of the feedwater trains. [ I D. RESTORE and MAINTAIN RPV level 155-165. 1 E. DIAGNOSE the cause of the failure in accordance with section 3.3 of this procedure. [ I 3.3 Loss of Feed/Feed Flow Abnormalities A. Feed Pump Trip PERFORM a rapid power reduction as directed by the Unit

-- Supervisor.

B. Condensate Pump Trip PERFORM a rapid power reduction as directed by the Unit Supervisor.

-. c. Multiple Feed Pumps Trip

1) SCRAM the reactor and EXECUTE ABN-1. [ I D. Multiple Condensate Pumps Trip

1) SCRAM the reactor and EXECUTE ABN-1. [ I E. Feed Flow Abnormalities

1) CHECK feed pump and associated valves lined up correctly. [ I 13.0

her-,Ar: fxelcm Company 1 OYSTER CREEK GENERATING STATION PROCEDURE I Number 317 I

Title Revision No.

Feedwater System (Feed Pumps to Reactor Vessel) 74 ATTACHMENT 317-3 FEEDWATER SYSTEM PRE-STARTUP ELECTRICAL LINEUP POWER BREAKER SUPPLY EQUIPMENT LOCATION POSITION PERFORMNERIFY 4160VlA Feed Pump 1A TB 4160V RM Close I

--+4160VlB 4160VlB IBIIA Feed Pump 1B Feed Pump I C A String Heater (V-2-10)

TB 4160V RM TB 4160V RM TB MEZ Close Close Close I

I I

Bank Outlet Valve 1B11A B String Heater (V-2-11) TB MEZ Close I Bank Outlet Valve IBIIA C String Heater (V-2-12) TB MEZ Close I

-<--.. Bank Outlet Valve 1A12A MFRV A Block Valve V-2-740 TB MEZ Close I 1B12A MFRV C Block Valve V-2-741 TB MEZ Close I DC-E ROPS (Panel 14XR) Lower Cable Close I Bkr. 15 Spreading Rm IP-4B ROPS (Panel 14XR) 480V Room Close I Bkr. 1 Performed By: Date: Time:

Verified By: Date: Time:

Approved By: Date: Time:

os E3-1

NRC Exam 2006-1 Reactor Operator Exam Key

71. The following communication takes place over the radio between the

--=

Reactor Operator and the Reactor Building Operator while adding makeup to the A Isolation Condenser from the Fire Protection System:

RO: Open V eleven forty nine, makeup valve from Fire Protection to the Isolation Condensers NLO: I understand, open V eleven forty nine, Fire Protection to Isolation Condenser Makeup RO: That is correct.

This communication is

a. INCORRECT because the NLO paraphrased the direction given by the RO

b. INCORRECT because the RO and NLO did not use the phonetic alphabet for V C. INCORRECT because the RO and NLO did not address each other by name or title

d. CORRECT because it meets the requirements of HU-AA-101, Human Performance Tools and Verification Practices Answer: c

\--.

Handouts: None Justification: A is incorrect - paraphrasing is allowed by HU-AA-101.

B is incorrect - HU-AA-101 only requires use of the phonetic alphabet as required, to ensure proper component identification.

In this case, C is correct - HU-AA-101 requires the sender to address the receiver by name or title. HU-AA-101 also states: For non-face-to-faceverbal communication, the sender and receiver shall IDENTIFY themselves by stating their name or title.

D is incorrect - this communication does not meet the requirements of HU-AA-101.

G2.18 Conduct of Operations: Ability to coordinate personnel activities outside the control room. (CFR 41 -10)

NRC RO Exam 2006-1 Key Page 122 of 129

NRC Exam 2006-1 Reactor Operator Exam Key u'

OC Learning Objective:

2621-PBIG.0002, Obiective 3:

Demonstrate proper communications, in accordance with Conduct of Operations Manual and Human Performance procedural requirements, including:

a. Clear and concise communications

b. Three-way communications

c. Use of phonetic alphabet

d. Specifying correct componenVuniVtrain

e. Creating understanding

f. verifying understanding (clarificatiodconfirmation)

Cognitive Level: Memory or Fundamental Question Type: New

References:

HU-AA-101 NRC RO Exam 2006-1 Key Page 123 of 129

HU-AA-101 Exelon Lu Revision 3 Page 9 of 20 Nuclear NOTE: Determination of the correct train, component rack, panel, or cabinet shall be made by both workers, however, independence required for the concurrent verification applies only to the individual component to be manipulated.

2. The performer and the verifier independently identify the component and review the intended action. Prior to component identification and the intended action, the verifier will take no physical or verbal cues from the performer.

3. The performer shall independently, with use of the controlling document:

A. LOCATE the component and IDENTIFY each unique identifier on the component label.

B. REVIEW the intended action.

4. The verifier shall independently, with use of the controlling document:

A. LOCATE the component and identify each unique identifier on the component label.

B. REVIEW the intended action.

C. If conditions are such that direct observation of the verification and action are impractical, then the desired component should be physically flagged with tape or other suitable device by the verifier.

5. Component Manipulation:

A. The verifier will physically TOUCH or POINT at the correct component.

B. The performer will then AGREE with the component identified or STOP and contact their supervisor if they do not agree with the identified component.

C. Both individuals DISCUSS the requested action to be performed and AGREE on the action and expected outcome.

D. The performer will TAKE the action while being directly observed by the verifier, if practical.

6. When the action is complete, then the verifier will VERIFY the desired action was performed correctly on the correct component and REMOVE any marking device placed as part of the Concurrent Verification process if not controlled by another process. (CM-3) 4.4. 3-Wav Communication 4.4.1. ENSURE all communications are clear, concise, and free of ambiguity.

HU-AA-I 01 Exelon 51*

Revision 3 Page 10 of 20 Nuclear

~4 4.4.2, For non-face-to-face verbal communication, the sender and receiver shall IDENTIFY themselves by stating their name or title.

4.4.3. USE Phonetic alphabet (shown in Attachment 3), as required, to ensure proper component identification.

1. USE 3-way communications for all information exchanges that will result in decision making, direction being given or actions being taken..

4.4.4. AVOID words during verbal communication that could be mistaken for each other, such as increase and decrease.

4.4.5. Communication of indicator readings should be provided in the format of PARAMETER -VALUE - TREND (with rate when appropriate).

FOR EXAMPLE Reactor pressure is 1000 psig and going down.

4.4.6. AVOID the use of sign language.

4.4.7. USE the appropriate unit designator, system designator, or noun name and appropriate phonetic alphabet component or train designator when communicating equipment nomenclature.

FOR EXAMPLE 1MSOOSA should be verbalized as one MS zero zero nine alpha FOR EXAMPLE HV-2-10-71A should be verbalized as HV two ten seventy-one alpha 4.4.8. Sender Responsibilities (Direction)

.-? 1. ADDRESS intended receiver by name or title.

2. SPEAK clearly and OBTAIN the attention of the intended receiver

3. SEND the intended message in just enough words to minimize the chance of receiver misunderstanding.

4. REQUIRE confirmation from the intended receiver of the information.

NRC Exam 2006-1 Reactor Operator Exam Key

72. Given the following:

J The reactor is in COLD SHUTDOWN and pre-startup evolutions are in progress The B recirc pump is being placed in service and is aligned as follows:

o The MG set drive motor breaker is shut o The scoop tube is positioned at 100%

o The WARM light has just illuminated Which one of the following describes what happens when the STRT/NORM pushbutton is depressed?

a. The field breaker will close immediately and the scoop tube will remain at 100%.

b. The field breaker will close immediately and the scoop tube will start running back

c. The scoop tube will start running back and the field breaker will close when the scoop tube reaches the low speed position

d. The scoop tube will start running back and the field breaker will close when the scoop tube passes through the 40% to 30% range Answer: d Handouts: None

-4 Justification: A, B and C are incorrect - the scoop tube will run back and the field breaker will not close until the scoop tube reaches the 40-30% range.

D is correct - as soon as the STRT/NORM pushbutton is depressed the scoop tube begins to run back. When it reaches the 40-30% position, the field breaker will close and the recirc pump will start. The scoop tube will continue to run back to the low speed position.

G2.2.1 Equipment Control: Ability to perform pre-startup procedures for the facility / including operating those controls associated with plant equipment that could affect reactivity. (CFR 41.7)

OC Learning Objective:

2621.828.0.0040, Obiective G:

Explain the starting logic for the reactor recirc MG sets Cognitive Level: Memory or Fundamental Question Type: Bank

References:

301.2 ij NRC RO Exam 2006-1 Key Page 124 of 129

AmerGenu An Excbn Company I OYSTER CREEK GENERATING STATION PROCEDURE I Number 301.2 L/ Title Revision No.

Reactor Recirculation System 46 5.3.12 I NOTE Speed control using the manual adjustment knob is lost when the STRTINORM pushbutton is selected to the STRT position.

CAUTION Minimize the time that reactor recirculation pumps are operated with the discharge valve closed. Vibration levels significantly increase during this mode and any extended operation should be avoided.

START the recirculation pump sequence by pressing the STRT/NORM pushbutton AND as directed by the OS, PLACE and HOLD the DRIVE MOTOR Control switch in START. E l 5.3.13 VERIFY that the field breaker closes and the pump start sequence is activated as the scoop tube passes through the

? 40% to 30% range. [ I 5.3.13.1 -IF used, THEN RELEASE the DRIVE MOTOR Control switch after generator amps have stabilized. [ I 5.3.13.2: WHEN the scoop tube reaches the low speed position (E further movement observed as indicated on the V display),

THEN DEPRESS the STRT/NORM push button on the speed control unit to reactivate the manual adjustment knob. [ I 16.0

NRC Exam 2006-1 Reactor Operator Exam Key

73. Per RP-AA-203, Exposure Control and Authorization, occupational ij workers at Oyster Creek have an Administrative Dose Control Level (ADCL) of -( 1)- mrem TEDE per year.

This limit can be raised to -(2)- mrem TEDE with written approval by the Radiation Protection Manager and the work group supervisor.

a. (1) 1000 (2)2000

b. (1)2000 (2) 3000

c. (1) 1000 (2) 4000

d. (1)2000 (2) 4000 Answer: b Handouts: None Justification: A is incorrect - the initial ADCL limit is 2000 mrem TEDE.

-4 B is correct - RP-AA-203 states: Administrative dose control levels have been established for Total Effective Dose Equivalent Limits of 2000 mrem routine cumulative TEDE/yr. And, To raise the ADCL to 3000 mrem TEDE in a calendar year, written approval is required by the Radiation Protection Manager and the work group supervisor.

C and D are incorrect - the initial ADCL limit is 2000 mrem TEDE; this can be raised to 4000 mrern TEDE with written approval from the Radiation Protection Manger, a work group supervisor, and the Station/Plant Manager. The RPM and work group supervisor can only authorize an extension to 3000 mrem TEDE.

G2.3.4 Radiation Control: Knowledge of radiation exposure limits and contamination control / including permissible levels in excess of those authorized.

(CFR 41.12)

OC Learning Objective:

Exelon GET RWT Module (Rev. 31), Obiective 17:

State the Exelon Administrative Dose Control Level for TEDE and the administrative does guidelines for LDE, SDE, and TODE.

Exelon GET RWT Module (Rev. 31), Obiective 18:

NRC RO Exam 2006-1 Key Page 125 of 129

NRC Exam 2006-1 Reactor Operator Exam Key State the actions to be taken if an Exelon Administrative Dose Control Level or

..L-*

/

administrative guidelines are being approached.

Cognitive Level: Memory or Fundamental Question Type: Modified Bank

References:

RP-AA-203 NRC RO Exam 2006-1 Key Page 126 of 129

RP-AA-203 Revision 2 Page 3 of 12 NOTE: Any request to raise the administrative dose control level for a minor shall be approved and documented by the Radiation Protection Manager.

Administrative dose control levels have been established for Total Effective Dose Equivalent Limits as follows:

- 2000 mrem routine cumulative TEDE/yr.

- 200 mrem TEDE for minors.

NOTE: In the Midwest Regional Operating Group, controls for High Lifetime Exposure are not applicable for non-Exelon employees due to the limitations of the Exposure Tracking System.

4.1.3. An administrative dose control level of I000 mrem TEDE plus PSE has been established for employees with High Lifetime Exposure.

4.1 -4. The Radiation Protection Manger shall review an individuals occupational exposure when the dose equivalent reaches 80% of the NRC Limits for Lens Dose Equivalent (LDE), Shallow Dose Equivalent (SDE), and Total Organ Dose Equivalent (TODE).

The 80% threshold values are as follows:

- 12 rem LDE.

- 40remSDE.

- 40remTODE.

4.1.5. If an individuals current year dose history documentation includes an absent/ no record (A) dose type, then REDUCE the individuals allowable exposure (normally 2000 mrem TEDE for the year) by 1250 mrem TEDE for each quarter of the current year for which dose history documentation is absent/ no record (A), until all of that dose is resolved.

4.1.6. If an individual is suspected of exceeding any of the NRC exposure limits in Table 1, then PROHIBIT the individual from entering the RCA until a detailed evaluation of the individuals actual dose equivalent has been conducted. Future access will depend upon the results of the evaluation.

1. If an exposure in excess of the applicable exposure limit has occurred, then PROHIBIT the individual from entering the RCA until the end of the current calendar year.

2. If an exposure in excess of the applicable exposure limit has not occurred, then the individual may be permitted to re-enter the RCA.

RP-AA-203 Revision 2 Page 4 of 12 4.1.7. During a condition where the Generating Stations Emergency Plan has been initiated, emergency exposure authorizations shall be performed in accordance with the stations Emergency Plan Implementing Procedures.

4.2. Authorization To Raise Administrative Dose Control Levels (ADCLs) 4.2.1. USE Attachment I,Dose Control Level Extension Form, or a computerized equivalent, to authorize exposures for adult individuals in excess of 2000 mrem routine TEDE in a year.

4.2.2. A supervisor from the department requesting approval shall complete Section I of Attachment 1 and submit the request to the Radiation Protection Department indicating:

- The name, identification number, and signature of the individual for whom a dose extension is being requested.

- Whether or not other qualified individuals with lower dose are available to perform the work.

- A detailed explanation of why the dose extension is necessary.

- The requested annual TEDE limit for the individual (expressed in 500 mrem increments, Le. 2500 mrem, 3000 mrem, etc.)

4.2.3. The Radiation Protection Department shall complete Section II Attachment 1 or

computerized equivalent.

4.2.4. Pending investigations or calculations of internal exposure shall be reviewed and evaluated to determine the individuals TEDE.

4.2.5. Non-Exelon Nuclear and non-ROG dose equivalent shall be included in the dose to determine the workers current TEDE.

NOTE: An individual shall not be approved to receive greater than 2000 mrem TEDE if that person has any absent/ no record (A) dose equivalent for the year.

- 7 4.2.6. To raise the ADCL to 3000 mrem TEDE in a calendar year, written approval is required by the Radiation Protection Manager and the work group supervisor.

4.2.7. To raise the ADCL to 4000 mrem TEDE in a calendar year, written approval is required by the Radiation Protection Manger, a work group supervisor, and the StationlPlant Manager.

NOTE: An individual being considered for approval greater than 4000 mrem TEDE for the year should not have significant estimated dose equivalent.

To raise the ADCL above 4000 mrem, not to exceed 5000 mrem, written approval is required by the Site Vice President.

NRC Exam 2006-1 Reactor Operator Exam Key

74. The primary containment is being purged with air in preparation for a plant shutdown.

Why does procedure 312.9, Primary Containment Control, prohibit the simultaneous opening of Drywell and Torus vent and purge valves?

To prevent.. .

a. over-pressurizingthe Reactor Building ventilation ducts

b. exceeding the Reactor Building ventilation exhaust fan capacity

c. loss of the positive differential pressure between the Drywell and Torus

d. creating a pathway for steam to bypass the suppression pool during a LOCA Answer: d Handouts: None Justification: A is incorrect - there is no reason to believe this would occur and this is not the reason for the limitation given in 312.9.

B is incorrect -there is no reason to believe this would occur and this is not the reason for the limitation given in 312.9.

C is incorrect - this is not the reason for the limitation given in 312.9, but could be a misconception based on the requirement in 312.9 to monitor Drywell and Torus pressure during purging to maintain a positive d/p.

D is correct - as stated in P&L 7.2.6 of 312.9, When primary containment is required, simultaneous opening of drywell and torus vent and purge valves is prohibited. Operating with both the drywell and torus valves open creates a pathway to bypass the torus-to-drywell vacuum breakers. Procedure 312.9 also references LER 97-014, which states: On October 27, 1997, while reviewing industry events, it was discovered that a suppression pool bypass leak path existed during purging and venting of the primary containment. Two operating procedures allowed venting and purging of the torus and drywell simultaneously.

I f a LOCA were to occur during this time, a pathway for steam to bypass the suppression pool was created. Calculations indicated that the allowable bypass area was exceeded but, in the unlikely event of a LOCA, the peak torus and dry-well pressure would not increase.

G2.3.9 Radiation Control: Knowledge of the process for performing a containment purge. (CFR 41.1 0)

NRC RO Exam 2006-1 Key Page 127 of 129

NRC Exam 2006-1 Reactor Operator Exam Key OC Learning Objective:

\--,' 2621.828.0.0065, Obiective F:

Given normal operating procedures and documents for the system, describe or interpret the procedural steps.

Cognitive Level: Memory or Fundamental Question Type: Modified Bank

References:

312.9, LER 97-014 NRC RO Exam 2006-1 Key Page 128 of 129

her-,.

A n ix&n Company I OYSTER CREEK GENERATING STATION PROCEDURE DCC FILE #:20.1812.0010 Number 312.9 I.

i Title Revision No.

Primary Containment Control 37 7.2.4 Stack and Reactor Building Radiation Monitors shall be monitored whenever the Primary Containment is being vented. If the Primary Containment requires venting and the potential exist for airborne activity to be higher than normal, consideration should be given to vent through the Standby Gas Treatment System.

7.2.5 Primary Containment de-inerting may commence 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months prior to a scheduled shutdown in accordance with Tech.

Spec. 3.5.A.6.

7.2.6 When Primary Containment is required, simultaneous opening of Drywell and Torus valves listed together in Groups I or II or Ill in the table below is prohibited. Operating with both Drywell and Torus valves open creates a pathway to bypass the Torus to Drywell Vacuum Breakers (CM-2).

Group I I

Drywell I I

Torus I I I

'V' V-23-13 V-23-15 I N2 Purge (12XR)

V-23-14 V-23-16 V-23-17 V-23-19 I1 N2 Makeup (12XR)

V-23-18 V-23-20 Ventilation V-27-1 V-28-17 V-27-2 V-28-18 111 Valves V-23-21 V-28-47 (Exhaust)

V-23-22 21.o

f NRC Exam 2006-1 Reactor Operator Exam Key

75. The reactor is operating at rated power.

b Which of the following annunciators correspond to an EOP entry condition? (Assume the alarms are received individually and are valid.)

a. RX PRESS HI

b. DW TEMP HI C. DW PRESS HVLO

d. ISOL COND AREA TEMP HI Answer: d Handouts: None Justification: A is incorrect - this annunciator alarms when reactor pressure reaches 1030 psig; the EOP entry condition for high reactor pressure is 1045 psig.

B is incorrect - this annunciator alarms at 115" F on the air outlet of the Drywell coolers (which corresponds to approximately 150" F).

C is incorrect - this annunciator alarms at a low DW pressure of 1.O psig or a high DW pressure of 1.4 psig. The EOP entry conditions for DW pressure are 3 psig.

-d D is correct - this annunciator alarms at 160 OF and requires entry into EMG-3200.1 1, Secondary Containment Control.

G2.4.2 Emergency Procedures/Plan: Knowledge of system set points / interlocks and automatic actions associated with EOP entry conditions. (CFR 41.10)

OC Learning Objective:

2621.828.0.0023, Obiective K:

State the function and interpretation of system alarms, alone and in combination, as applicable in accordance with system RAPS.

Cognitive Level: Memory or Fundamental Question Type: New

References:

RAP-H3f, RAP-G~c,RAP-CSe, RAP-C8b NRC RO Exam 2006-1 Key Page 129 of 129

Group Heading ISOL COND CAUSES: SETPOINTS: ACTUATING DEVICES:

High temperature in the Isolation Condenser 160°F T.S. IB06A, B, C, D Area indicating possible pipe rupture.

Reference Drawings:

GE 112C3701 Sh. 9 GU 3E-611-17-005 S h . 2 Subject Procedure No.

Page 3 of 3 NSSS RAP-C8b C-8-b Alarm Response Procedures Revision No: 1

ML063060323

Text

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