Text

Initial Exam-02/2005 Final Written Reference Exam
	ML050890447
Person / Time
Site:	Diablo Canyon
Issue date:	03/31/2005
From:	; Pacific Gas & Electric Co
To:	; Office of Nuclear Reactor Regulation
References
	Download: ML050890447 (532)
	v • d • e

RO QUESTION 01 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 1 _____

K/A # EPE 007 EK2.03 Importance Rating 3.5 3.6 Proposed Question:

PLANT CONDITIONS:

Unit 1 is at full power.

Power range channel N43 has been removed from service and all appropriate bistables tripped in the protection racks.

Control and instrument power fuses have not been removed.

A loss of PY-12 occurs and the reactor trips.

Which of the following describes why the reactor tripped and the bistable status indications?

A. 2/4 OTT, however, only one OTT bistable will be lit.

B. 2/4 OPT, however, only one OPT bistable will be lit.

C. 2/4 OTT, both OTT bistables will be lit.

D. 2/4 OPT, both OPT bistables will be lit.

Proposed Answer: A. 2/4 OTT, however, only one OTT bistable will be lit.

Explanation:

A correct, Per OP-5 only OTT bistables (TC-431C OtdeltaT and TC-431D OTdeltaT Runback) are tripped for the failed NI due to the the I input. OP does not get tripped, (I is zeroed out).

PY-12 provides bistable status light indication for channel 3 and power to channel 2 bistables. When it fails, channel 3 lights go out (loss of OTT bistable status for NI43) and trips channel 2 bistables. The coincidence for a reactor trip is satisfied but only one (channel 2) OTT bistable will be lit. Note, channel 2 bistable status lights are powered from PY-11A.

B incorrect, overpower bistables are not tripped.

C incorrect, the lights for channel 3 are out.

D incorrect, overpower not tripped.

Technical Reference(s): AP-5 attachment 4.1. OP AP-4, Loss of Vital or Nonvital Instrument AC, section 2, Symptoms.

NI-43 OTdeltaT (TC-431C OTdeltaT Trip)

(see Page 15) (TC-431D OTdeltaT Runback)

Proposed references to be provided to applicants during examination: None Learning Objective: 4274 - Explain the consequences of loss of vital instrument bus.

Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level: Memory or Fundamental Knowledge _____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.7 55.43 _____

Comments:

K/A: EPE 007 EK2.03 - Knowledge of the interrelations between a reactor trip and the following: Reactor trip status panel

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP AP-4 NUCLEAR POWER GENERATION REVISION 16 DIABLO CANYON POWER PLANT PAGE 1 OF 1 ABNORMAL OPERATING PROCEDURE UNITS TITLE: Loss of Vital or Nonvital Instrument AC 1 2 AND 11/09/04 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. SCOPE 1.1 This procedure covers the general steps to be taken in the event of a loss of power to a vital or nonvital instrument AC panel. A comprehensive list of particular symptoms precedes each section. However, particular annunciator windows and symptoms are listed below to enable quicker diagnosis of which panel was lost, and the appropriate section of the procedure to refer to. This list is not all-inclusive:

MAJOR SYMPTOMS GO TO Section Postage Stamp Bistable Row Illuminates (VB1) Section A, Loss of Vital Instrument Panel Postage Stamp Row Deenergizes (VB1)

Multiple Hagan Controllers Fail to MANUAL or AUTO-HOLD Multiple Seemingly Unrelated Alarms Including:

PK16-22, PK17-22 or PK18-22 PK19-19 Loss of Indication on Both MFP Startup Stations Section B, Loss of PY-15 (25)

MSR Valve Position Indicators Dead (VB3)

PPC and Westronics Chart Recorders Dead (VB3 & VB4)

Multiple Seemingly Unrelated Alarms Including:

PK01-08 PK10-07 PK15-20 PK15-22 CCW Surge Tank LIs Fail Low Section C, Loss of PY-16 (26)

Multiple Seemingly Unrelated Alarms Including:

PK01-07 PK11-04 PK12-02 PK15-18 Generator Indications Fail Low (H2 Pressure, Density, Seal Oil Section D, Loss of PY-17 (27)

P)

Valve Position Lights on DEH Panel Lost Condensate Booster Pump Set Autostart Multiple Seemingly Unrelated Alarms Including:

PK12-20 PK14-16 PK14-18 PK14-19 ap4.DOC 02 0118.1024

RO QUESTION 02 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 1 _____

K/A # APE 008 AA2.20 Importance 3.4 3.6 Proposed Question:

An automatic reactor trip and safety injection has occurred on Unit 1.

The following plant conditions currently exist:

All RCPs are running

Pressurizer level is 48% and INCREASING

RCS pressure is 1700 psig and DECREASING Which of the following leak locations is consistent with the current plant conditions?

A. A charging header flange.

B. A pressurizer PORV.

C. CRDM Canopy Seal.

D. A weld failure of an RCS flow sensing line.

Proposed Answer:

B. A partially open pressurizer PORV.

Explanation:

A, C and D incorrect, pressurizer level would decrease.

B correct, Increasing pressurizer level and decreasing RCS pressure are the symptoms of a vapor space leak in the pressurizer.

Technical Reference(s): LMCDFRC - Mitigating Core Damage, Core Cooling Proposed references to be provided to applicants during examination: none ro tier 1 group 1_02 rev1.doc

Learning Objective: 3772 Identify the parameter that helps to discriminate between a vapor space and non-vapor space LOCA Question Source: Bank # P-27764, INPO 19184 Question History: Last NRC Exam Braidwood 1 - 2000 Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.5 55.43 Comments: K/A: APE 008 AA2.20 - Ability to determine and interpret the following as they apply to the Pressurizer Vapor Space Accident: The effect of an open PORV on (or?) code safety, based on observation of plant parameters ro tier 1 group 1_02 rev1.doc

LESSON: MITIGATING CORE DAMAGE -CORE COOLING LESSON NO.: LMCDFRC Steam Space versus Liquid Space LOCA Differences Pressurizer level as an indication of inventory can be misleading if:

Obj 18,20,22

RCS subcooling does not exist.

A steam vent path is established from the Pzr vapor space.

A vapor space LOCA would depressurize the RCS and quickly transfer the bubble to the reactor vessel.

Steam generated in the reactor vessel may pass through the Pzr surge line and prevent the water inventory of the Pzr from draining into the RCS loops.

This holdup of water can result in a stable or even increasing indicated Pzr level while RCS water inventory is actually decreasing.

Pzr level should be relied on only with hot leg or core exit subcooling present.

The parameter that helps to discriminate between a vapor space and non-vapor space LOCA is the Pzr level indication.

A vapor space LOCA provides the steam vent path from the Pzr which will cause a depressurization in the Pzr causing an indicated level increase while water flashes to steam and out the vent path.

ro tier 1 group 1_02 rev1.doc

RO QUESTION 03 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 1 _____

K/A # EPE 011 EK1.01 Importance 4.1 4.4 Proposed Question:

PLANT CONDITIONS:

An RCS cold leg break has occurred on Unit 1.

RCS pressure is 800 psig and decreasing slowly.

RCS level is beginning to drop below the top of the steam generator U-tubes.

Steam generator pressures are approximately 1000 psig and decreasing slowly.

Which of the following describes the heat removal mechanism currently occurring?

A. Break flow only.

B. Break flow and reflux cooling.

C. Break flow and natural circulation.

D. Break flow and radiative heat transfer.

Proposed Answer:

A. Break flow only.

Explanation:

A correct, true for large break LOCAs.

B incorrect, this is for a small break, heat removal by the break is insufficient, RCS pressure will remain above steam generator pressure and as the RCS is drained heat removal will be reflux cooling.

C incorrect, this is for a small break, heat removal by the break is insufficient, RCS pressure will remain above steam generator pressure and heat removal will be thru two phase natural circulation or as the RCS is drained, reflux cooling.

D incorrect, the core is still covered.

Technical Reference(s): LMCDFRC - MITIGATING CORE DAMAGE -CORE COOLING page 16 Proposed references to be provided to applicants during examination: none ro tier 1 group 1_03 rev1.doc

Learning Objective:

E598 - Describe the following concepts or conditions as they apply to a LOCA: a.

Mechanisms for removing decay heat from the core during a LOCA.

Question Source:

New X Question History: Last NRC Exam ____________

Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.14 55.43 _____

Comments: K/A: EPE 011 EK1.01 - Knowledge of the operational implications of the following concepts as they apply to the Large Break LOCA : Natural circulation and cooling, including reflux boiling ro tier 1 group 1_03 rev1.doc

LESSON: MITIGATING CORE DAMAGE -CORE COOLING LESSON NO.: LMCDFRC Error! Style not defined., Continued Example An example follows.

FIGURE -04 FIGURE -05 The conditions:

FIGURE -06

a 2 equivalent diameter hole in cold leg

minimum safeguards SI

loss of offsite power assumed at reactor trip

SG safety valves only means of venting steam on secondary side

minimum AFW available one minute after reactor trip Analysis:

rapid depressurization to 1200 psig at 5 minutes

from 5 to 30 minutes:

system repressurizes due to inability to vent steam.

SG primary side and crossover leg drain.

at 30 minutes crossover leg level reaches break and steam passes.

rapid decrease in steam flow.

as steam escapes through break, differential pressure adjusts in reactor vessel such that core is recovered at 32 minutes.

SI flow becomes greater than break flow.

from 32 to 50 minutes:

slow repressurization secondary side pressure drops below S/G safety valve setpoint and continues to drop

after 65 minutes:

break and subcooled SI remove all decay heat secondary pressure above primary system now in stable mode ro tier 1 group 1_03 rev1.doc

RO QUESTION 04 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 1 _____

K/A # APE 015 AA1.10 Importance 2.7 2.6 Proposed Question:

A locked rotor occurs on a running Unit 1 RCP.

Which of the following describes what you would observe from the time the locked rotor occurs until the RCP trips and the RED light goes out and amps fall to zero?

A. Amp indication pegs high and after a time delay the breaker trips on overcurrent -

the green and blue lights are lit.

B. Almost immediately, before amp indication can peg high, the breaker trips on overcurrent - the green and blue lights are lit.

C. Amp indication pegs high and after a time delay the breaker trips on overcurrent -

the green light is lit, the blue light remains out.

D. Almost immediately, before amp indication can peg high, the breaker trips on overcurrent - the green light is lit, the blue light remains out.

Proposed Answer:

A. Amp indication pegs high and after a time delay the breaker trips on overcurrent -

the green and blue lights are lit.

Explanation:

A correct, For a locked rotor, amps will peg high (several times higher than normal running amps). The breaker will trip on overcurrent when the inverse time constant is picked up. The blue light indicating overcurrent on the primary or backup breaker will be lit.

B incorrect, amps will peg high and the breaker does not trip immediately.

C incorrect, blue light will light.

D incorrect, blue light will light.

ro tier 1 group 1_04.doc

Technical Reference(s):

STG A6, Reactor Coolant Pump Proposed references to be provided to applicants during examination: none Learning Objective:

32652 - Describe the following terms/ characterizes as relates to AC induction motor operation:

Slip

Locked rotor

Sheared shaft 6056 - Analyze the control logic for the RCPs.

Question Source:

New X Question History: Last NRC Exam ____________

Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis 10 CFR Part 55 Content: 55.41 41.7 55.43 _____

Comments: K/A: APE 015 AA1.10 - Ability to operate and / or monitor the following as they apply to the Reactor Coolant Pump Malfunctions (Loss of RC Flow): RCP ammeter and trip alarm ro tier 1 group 1_04.doc

Lesson: Basic Electrical Theory Lesson No.: R043C10 Need to know Rotor Slip, continued

When a motor is running unloaded, there is very little slip (typically less than one percent).

As the motor is loaded, the rotor slows down slightly. Slip increases, and the rate at which the rotor windings are cut by the rotating magnetic field also increases. This action results in an increase in rotor voltage and current. The increase in rotor current causes an increase in the force exerted on the rotor, and motor torque increases.

A very small drop in rotor speed produces a considerable increase in torque.

At full load, slip is about 6 percent of the rotating magnetic field speed for a typical motor (rotor speed is approximately 6 percent less than field speed).

Locked Rotor

Stopping of the motor rotor due to an excessive load such as the binding of a pump shaft.

Indications of a locked rotor Instantaneous increase in pump current attempting to supply demanded torque Instantaneous decrease in pump discharge pressure Instantaneous decrease in system flow rate Instantaneous increase in motor winding temperatures Possible breaker trip ro tier 1 group 1_04.doc

Reactor Coolant Pump Trip logic The tripping logic for an RCP is shown below.

Obj 15, 16 CS / Trip (SWGR)

OC 1/3 Inst. OC Control G

BU BKR Trip Room CS / Stop 1/2 M RCP CS / Trip (SWGR)

PRI BKR Trip 12 KV BUS UV Trip 12 KV BUS DIFF Trip 1/7 OC RCP BUS UF (Train A)

RCP BUS UF (Train B)

RCP-12 Notes:

Control room indication indicates that either the primary or backup breaker is tripped.

Undervoltage trip at <8050 V (70% of nominal)

Underfrequency trip at < 54 Hz

Trip testing is done through the SSPS system[GRH1]

Indication The following indications are available for each RCP motor.

Obj 7, 14 VB-1 START/STOP switch Indicating Meaning Normal light status Red Pump motor primary and ON backup breaker closed Green Pump motor primary or backup OFF breaker open White

Potential on 12 kV bus ON

Primary and backup breaker cell interlocks sense breaker in connected position

Primary and backup breaker have 125VDC power[TRP2]

Blue Pump primary or backup OFF breaker tripped on overcurrent ro tier 1 group 1_04.doc

RO QUESTION 05 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 1 _____

K/A # APE 022 G2.1.25 Importance Rating 2.8 3.1 Proposed Question:

PLANT CONDITIONS:

Unit 1 has tripped from full power.

The crew has entered E-0.1, Reactor Trip Response, and addressing 2 rods failing to insert using OP AP-6, Emergency Boration.

Attempts to establish adequate flow through the normal boration flowpath have failed.

The crew has established the minimum required flow through the next preferred path At the minimum flow rate, how long must the boration be in progress?

A. 10 minutes B. 20 minutes C. 30 minutes D. 60 minutes Proposed Answer:

D. 60 minutes Explanation:

A incorrect, If the RWST at minimum flow is used (90 gpm) and candidate uses 1 rod, (900 gallons).

B incorrect, this is 1800 gallons at 90 gpm (RWST)

C incorrect, this is 30 gpm for 900 gallons (1 rod)

D correct, Per AP-6, if normal boration is unsuccessful, the next preferred path is thru CVCS-8104 with a minimum flow of 30 gpm. Per attachment A, the requirement is to borate 900 gallons, PER ROD. At 30 gpm, to borate 1800 gallons would take 60 minutes as a minimum.

Technical Reference(s): OP AP-6 att. A ro tier 1 group 1_05.doc

Proposed references to be provided to applicants during examination: OP AP-6 Learning Objective: 3477 - Describe the major actions of abnormal operating procedures Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level: Memory or Fundamental Knowledge _____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.10 55.43 43.5 Comments: K/A: APE 022 G2.1.25 - Loss of Reactor Coolant Makeup - Ability to obtain and interpret station reference materials such as graphs, monographs, and tables which contain performance data.

ro tier 1 group 1_05.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP AP-6 NUCLEAR POWER GENERATION REVISION 15 DIABLO CANYON POWER PLANT PAGE 1 OF 6 ABNORMAL OPERATING PROCEDURE UNITS TITLE: Emergency Boration 1 2 AND 08/26/04 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. SCOPE 1.1 This procedure covers situations which require emergency boration and the methods for accomplishing this operation. Various options of emergency boration are discussed in this procedure.

1.2 The preferred option is using the VCT Makeup System. The next option is borating through the emergency boration valve (CVCS-8104). The next alternate option is the use of the RWST. The use of manual emergency borate valve CVCS-8471 is too involved and takes so much time that it is ONLY USED as the LAST option.

NOTE: Emergency boration flowrate is not specifically defined. TS 3.1.1 Bases states that the operator should borate with the best source available for plant conditions.

2. SYMPTOMS Any one of the following conditions requires emergency boration.

2.1 Control rods inserted below the low-low insertion limit when critical. Commence boration within 15 minutes to restore rods to above the Lo-Lo Insertion Limit.

ROD LO LO INSERTION LIMIT (PK03-14) 2.2 Failure of any 2 control rods to fully insert following a reactor trip as indicated by rod position indication and rod bottom lights. Commence boration when directed by the Emergency Procedures.

2.3 Uncontrolled Reactor Coolant System cooldown following a reactor trip with no ESF action.

2.4 Uncontrolled or unexplained reactivity increase as indicated by:

2.4.1 Unexplained control rod insertion.

2.4.2 Increasing TAVG or nuclear power with no increased load demand.

2.4.3 Unexpected increasing count rate when shutdown.

2.5 When boration is required and normal boration through the VCT makeup system is not possible. Borate as required per SFM direction.

2.6 Shutdown margin less than acceptable minimum limits per ITS 3.1.1 and 3.9.1.

Commence boration within 15 minutes to restore rods to restore shutdown margin.

00307115.DOC 02 0826.0836

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP AP-6 DIABLO CANYON POWER PLANT REVISION 15 PAGE 2 OF 6 TITLE: Emergency Boration UNITS 1 AND 2 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE 1: 900 gallons of 4% boric acid provides B 100 ppm INCREASE TO THE RCS, BOL. Calculated values may be used in place of this thumbrule.

NOTE 2: If Letdown is NOT in service, then it will be necessary to cool down 50°F per hour while injecting Boric Acid at 30 gpm in order to maintain a constant pressurizer level.

1. INITIATE Emergency Boration:

a. Verify charging is in service a. GO TO OP AP-17, LOSS OF CHARGING.

b. Place VCT make up control in BORATE position

c. Set boron flow controller HC-110 pot c. Increase demand manually to 100% on HC-110.

setting to 9.0 turns

d. Enter the desired gallons of boric acid using the BATCH function and the data entry keys. Refer to Appendix A for boration requirements.

e. Press RESET and START keys to enable the integrator.

f. Place M/U controller 1/MU in START f. Perform the following:

position - Adjust HC-110 pot setting to

1) Verify BA Transfer Pp - HIGH obtain approximately 30 GPM of boric SPEED acid flow

2) Close HCV-104 (BATP 1-1/2-2)

OR HCV-105 (BATP 1-2/2-1)

3) IF VCT pressure GREATER THAN 30 PSIG, THEN Vent the VCT by opening CVCS-8101 until LESS THAN 30 PSIG

4) IF Unable to obtain adequate Boric acid flow, THEN GO TO Step 2.

g. GO TO Step 3 00307115.DOC 02 0826.0836

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP AP-6 DIABLO CANYON POWER PLANT REVISION 15 PAGE 3 OF 6 TITLE: Emergency Boration UNITS 1 AND 2 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE: Emergency Boration Flowmeter FI-113 may peg high at 50 GPM. XFIT-113 in the Cable Spreading room may be used for higher flowrates or to determine total gallons of boric acid added via the Emergency Boration flowpath.

2. INITIATE Alternate Boration Method

a. OPEN CVCS-8104 and verify a. Perform one of the following in order of approximately 30 GPM or greater preference:

Emergency Boration Flow

1) Swap Charging Pp suction to the RWST.

a. OPEN 8805A AND 8805B.

b. CLOSE LCV-112B AND LCV-112C.

c. VERIFY GREATER THAN 90 GPM charging flow.

OR

2) Locally OPEN CVCS-8471 (100' Blender Room).

3. CHECK Sufficient Boric Acid Available:

In Service Boric Acid Tank level GREATER a. Stop the Boric Acid Transfer Pp not aligned to THAN required gallons of Boric Acid per the blender.

Appendix A

b. Locally OPEN CVCS-8476, Boric Acid Transfer Pp crosstie. (100' Behind Suction to BA Transfer Pp 1-1/2-2).

WHEN Sufficient BA inventory restored, THEN Realign the system per OP B-1C:II, 4% BORIC ACID SYSTEM - PLACE IN SERVICE.

00307115.DOC 02 0826.0836

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP AP-6 DIABLO CANYON POWER PLANT REVISION 15 PAGE 6 OF 6 TITLE: Emergency Boration UNITS 1 AND 2 APPENDIX A BORATION REQUIREMENTS Borate prescribed amount according to entry symptom:

Symptom Boration Requirement

1. Rods below RIL while critical. 1. Within 15 minutes, commence and maintain boration until rods above RIL.

2. Two or more stuck rods following reactor trip. 2. Borate 100 ppm (900 gallons, or calculated addition) per stuck rod.

3. Uncontrolled cooldown following Rx Trip 3. Borate until adequate shutdown margin is without ESF Actuation. attained.

4. Uncontrolled or unexplained reactivity increase. 4. Borate until control regained. Refer to EOP FR-S.1 Appendix D to isolate dilution flowpaths, if required.

5. When normal boration methods unavailable. 5. Borate as required to maintain proper boron concentration.

6. SDM less than acceptable. 6. Within 15 minutes, commence and maintain boration until adequate SDM is attained.

00307115.DOC 02 0826.0836

RO QUESTION 06 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 1 _____

K/A # APE 026 AA2.04 Importance Rating 2.5 2.9*

Proposed Question:

The Unit 1 core is being offloaded to the Spent Fuel Pool (SFP). Spent Fuel Pool temperature is 90°F.

A running CCW pump trips and flow to the SFP heat exchanger decreases to 1800 gpm. SFP temperature begins to rise at a rate of 4.0°F /hour.

Without operator action, how long before PK11-04, Spent Fuel Pool Lvl/Temp alarms due to the increasing temperature?

A. 0 to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

B. 7 to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

C. 8 to 9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months .

D. 12 to 13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months .

Proposed Answer:

A. 0 to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

Explanation:

A correct, rate of increase is greater than 2.0 degrees. The alarm will occur as soon as the program executes and determines the change is greater than setpoint.

B incorrect, this would be an increase to 120F, a limit to prevent damage to SFP demins.

C incorrect, this corresponds to the alarm setpoint of 125 degrees.

D incorrect, this corresponds to 140 degrees, a value that requires action in AP-22, Spent Fuel Pool Low Level/High Temp/High Rad.

Technical Reference(s): PK11-04 Proposed references to be provided to applicants during examination: none ro tier 1 group 1_06 rev1.doc

Learning Objective: 5262 - State the Spent Fuel Pool Cooling system parameters that produce alarms.

Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level: Memory or Fundamental Knowledge X Comprehension or Analysis 10 CFR Part 55 Content: 55.41 41.5 55.43 Comments:

K/A: APE: 026 AA2.04 - Ability to determine and interpret the following as they apply to the Loss of Component Cooling Water: The normal values and upper limits for the temperatures of the components cooled by CCW ro tier 1 group 1_06 rev1.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK11-04 NUCLEAR POWER GENERATION REVISION 12 DIABLO CANYON POWER PLANT PAGE 1 OF 4 ANNUNCIATOR RESPONSE UNIT TITLE: SPENT FUEL POOL LVL/TEMP 107/09/02 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. LOGIC DIAGRAM (HI)

LC 650 (LO) ALARM LC 650 TIC 651 T0690C

2. ALARM INPUT DESCRIPTION DEVICE ALARM ANNUNCIATOR TYPEWRITER NUMBER INPUT PRINTOUT SETPOINT LC 650 1063 Spent Fuel Pool Lvl Hi GT 139'0" Elev LC 650 1064 Spent Fuel Pool Lvl Lo LT 137'4" Elev TIC 651 838 Spent Fuel Pool Temp Hi GT 125°F T0690C 0903 SFP Temperature Rate of Change High GT 2°F / hour and GT 80°F

3. PROBABLE CAUSE 3.1 Spent fuel pool level high due to:

3.1.1 Makeup or leakage into spent fuel pool.

3.1.2 Loading of fuel elements or cask into pool.

3.1.3 Tube leak in spent fuel pool heat exchanger.

3.1.4 High pressure in containment with transfer tube open and canal flooded.

0417711.D O C 16 0118.1105

RO QUESTION 07 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 1 _____

K/A # EPE 029 EA1.01 Importance Rating 3.4* 3.1 Proposed Question:

Which of the following is the expected action to be performed to accomplish RCS boration per EOP FR-S.1, "Response to Nuclear Power Generation/ATWS"?

A. Align a CCP to RWST.

B. Initiate normal boration.

C. Actuate Safety Injection.

D. Initiate emergency boration per OP AP-6.

Proposed Answer:

A. Align a CCP to RWST.

Explanation:

A correct, per step 4 of FR-S.1,

a. Perform the following:

1) OPEN 8805 A OR B (RWST suction)

2) CLOSE LCV-112 B OR C (VCT suction)

3) Verify AT LEAST 90 GPM charging flow B incorrect, this is not an option in S.1 C incorrect, this is the option of last resort, because SI trips the MFP, it is not desireable.

D incorrect, this is the option if unable to align to the RWST.

Technical Reference(s): FR-S.1 Proposed references to be provided to applicants during examination: N/A Learning Objective: 9948 - Explain the operator actions on ATWS Question Source:

Modified Bank # DCPP P-47631 ro tier 1 group 1_07 rev1.doc

Question History: Last NRC Exam N/A Question Cognitive Level: Memory or Fundamental Knowledge X Comprehension or Analysis _____

10 CFR Part 55 Content: 55.41 41.10 55.43 _____

Comments:

K/A: EPE 029 EA1.01 - Ability to operate and monitor the following as they apply to a ATWS: Charging pumps ro tier 1 group 1_07 rev1.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER EOP FR-S.1 DIABLO CANYON POWER PLANT REVISION 15 PAGE 4 OF 15 TITLE: Response to Nuclear Power Generation / ATWS UNIT 1 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

4. INITIATE Emergency Boration of RCS:

CAUTION: An SI will trip the Feed Pps and should be avoided if power is high enough to require Feed Pps to supply the heat sink.

a. Perform the following: a. IMPLEMENT OP AP-6, EMERGENCY BORATION

1) OPEN 8805 A OR B OR

2) CLOSE LCV-112 B OR C Initiate SI

3) Verify AT LEAST 90 GPM charging flow -------------------------

b. Check PZR Pressure - LESS b. Perform the following:

THAN 2335 PSIG

1) Verify PZR PORVs and Block Valves Open IF NOT, THEN Open PZR PORVs and Block Valves as necessary until PZR Pressure LESS THAN 2135 PSIG.

5. VERIFY Containment Vent Isol:

a. CVI portion of Monitor Light Box a. Manually Close All CVI alves.

B:

o Red Activated Light- ON o White Status Lights- OFF ro tier 1 group 1_07 rev1.doc

RO QUESTION 08 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 1 _____

K/A # EPE 038 EA2.06 Importance Rating 3.8 4.4 Proposed Question:

UNIT 1 PLANT CONDITIONS:

The crew is performing recovery actions for a steam generator tube rupture using EOP E-3.1, Post-SGTR Cooldown Using Backfill.

RCS temperature is 500ºF

SI is blocked

Chemistry reports current boron concentration is 500 ppm.

Core burnup is 19,000 MWD/MTU

All rods are inserted At step 4, the crew is instructed to Verify Adequate Shutdown Margin.

Without taking credit for Xenon or Samarium, which of the following describes whether adequate SDM has been established?

A. Yes, adequate SDM currently exists. Current boron concentration is approximately 23 ppm more than required.

B. No, SDM is inadequate. Boron concentration must be raised 77 ppm.

C. No, SDM is inadequate. Boron concentration must be raised 257 ppm.

D. No, SDM is inadequate. Boron concentration must be raised 357 ppm.

Proposed Answer:

D. No, SDM is inadequate. Boron concentration must be raised 357 ppm.

ro tier 1 group 1_08.doc

Explanation:

A incorrect, required boron concentration is 857 ppm. It would be adequate if the value for 500F from Table R19-1T-2 was used.

B incorrect, required boron concentration is 857 ppm. It would be adequate if the value for 500ºF from Table R19-1T-2 was used and corrected by adding 100 ppm as required by attachment 9.2 of STP R-19 C incorrect, this is the answer if the 100 ppm correction is not applied.

D correct, the value from R19-1T-2 is 757 ppm. Per STP R-19, attachment 9.2, 100 ppm for conservatism is added, making required boron concentration 857 ppm.

Therefore, to meet the required SDM, boron must be raised 357 ppm.

Technical Reference(s): R19-1T-2 Per STP R-19, with attachments Proposed references to be provided to applicants during examination:

R19-1T-2

STP R-19, attachment 9.2 Learning Objective: 10382 - PERFORM a shutdown margin (SDM) calculation using STP R-19, Data Sheet 2, Volume 9 Curves, and appropriate data Question Source:

New X Question History: Last NRC Exam ____________

Question Cognitive Level: Memory or Fundamental Knowledge _____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.5 55.43 Comments:

K/A: EPE 038 EA2.06 - Ability to determine or interpret the following as they apply to a SGTR: Shutdown margins and required boron concentrations ro tier 1 group 1_08.doc

ro tier 1 group 1_08.doc 69-11137 06/16/04 Page 1 of 1 DIABLO CANYON POWER PLANT TITLE:

STP R-19 ATTACHMENT 9.2 Data Sheet 2, SHUTDOWN MARGIN in MODES 3, 4, and 5, All Rods In or Stuck Rods 1 2 AND A. UNIT CYCLE MODE DATE TIME WARNING : 1. With stuck* rod(s), perform this calculation within ONE hour and every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter.

2. If credit is taken for Xenon (Step C.2), repeat this calculation at least every FOUR hours.

B. CURRENT CORE CONDITIONS E. REQUIRED BORON CONCENTRATION (At the time of this SDM Calculation) 1. Minimum required boron

1. RCS Temperature (TAVG concentration for Temp B.1 and (Enter 200 ºF if in MODE 3 or 4 with SI blocked) __________ºF burnup B.3 from R19-1T-2 or R19-2T-2 ___________ PPM

2. RCS Boron Concentration __________ PPM 2. Add 100 PPM to concentration E.1 ___________ PPM

3. Core Avg Burnup (PEP R-5) MWD NOTE: If Steps C & D = N/A, skip to E.8 and

__________ MTU enter concentration E.2

4. Time Since Plant Shutdown [ ] N/A 3. Boron worth for concentration (N/A startup after refueling) __________ HRS E.2 and Temp B.1 from

___________________________________________________ R19-1T-5 or R19-2T-5 ( )___________ PCM C. XENON AND SAMARIUM WORTH [ ] N/A Circle Table per B.3: BOL MOL EOL (If no credit is taken for Xe/Sm, check N/A, 4. Boron worth multiplier for worth and go to Step D.) C.4 from R17-1F-1 or R17-2F-1 ___________

YES NO N/A (If Step C.4 = Ø pcm, enter 1)

5. Boron worth corrected for

1. Power history determined Xe/Sm (E.3 x E.4) ( )___________ PCM and attached [ ] [ ] [ ] 6. Total worth corrections

2. If at equilibrium, estimated (C.4 + D.5) ( )___________ PCM Xenon worth from R17-1T-2 7. Net required boron worth or R17-2T-2 ( )___________ PCM (E.5 - E.6) ( )___________ PCM Circle Table per B.3: BOL MOL EOL If positive, enter Ø pcm

3. If at equilibrium, Samarium 8. Required boron concentration for worth E.7, worth from R17-1T-3 or and Temp B.1 from R19-1T-5 or R19-2T-5 R17-2T-3 ( )___________PCM or if steps C & D = N/A concentration from E.2. ___________PPM

4. Total Xe & Sm worth Select Table per B.3: BOL MOL EOL (C.2 + C.3) or computer output or zero ( )___________ PCM D. WITHDRAWN ROD/BANK WORTH (N/A if computer or all rods fully inserted) [ ] N/A F. ACCEPTANCE CRITERIA (If any rods not FULLY inserted, do not 1.Is the actual boron concentration B.2 greater than enter Ø pcm in Step D.5.) or equal to the required concentration E.8?

1. Most reactive rod worth [ ] YES (ACCEPTABLE) [ ] NO (NOT ACCEPTABLE) from R19-1T-1 or R19-2T-1 (+) ___________ PCM If this SDM is NOT ACCEPTABLE immediately

2. Number of stuck rods* ___________ follow the appropriate Tech Spec Action Statement,

3. Total stuck rod worth (+) ___________ PCM notify the SFM, and submit an Action Request.

(D.1 x D.2)

4. Worth of withdrawn rod/bank __________________________________________________________

during physics tests N/A [ ](+) ___________ PCM G. OPTIONAL EXPLICIT SDM CALCULATION

5. Total stuck and withdrawn 1. Boron worth for concentration B.2 rod worth (D.3 + D.4) (+) ___________ PCM and Temp. B.1 from R19-1T-5 or (not zero if any rods out) R19-2T-5 ( )___________ PCM

____________________________________________________ Select Table per B.3: BOL MOL EOL

2. Total Present Worth (G.1 + C.4 + D.5 - 1600 pcm) ( )___________ PCM

3. Actual SHUTDOWN MARGIN (G.2 - E.3)/(-1000 x E.4) ( )___________ %

Stuck is defined as untrippable or immovable due to excessive friction or mechanical interference.

REMARKS 00393517.DOC 06 0118.1006

RO QUESTION 09 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 1_ _____

K/A # APE 054 AA1.02 Importance Rating 4.4 4.4 Proposed Question:

The crew is responding to a complete loss of secondary heat sink.

It is determined that AFW pump 1-2 did not start because the control power fuses have blown.

For the current plant conditions, if an operator locally closes the breaker, what indications, if any, should there be in the control room for AFW pump 1-2?

A. No lights, amp, or flow, the pump remains shutdown.

B. Red light, pump amps and flow to steam generators 1 and 2.

C. No lights, but pump amps and flow to steam generators 1 and 2.

D. No pump amps or lights, but indication of flow to all steam generators .

Proposed Answer:

C. No lights, but pump amps and flow to steam generators 1 and 2.

Explanation:

A incorrect, the pump can be started locally.

B incorrect, this is normal indication.

C correct, Due to the loss of control power, all lights on VB-3 will be out and auto starts are defeated. However, the breaker can be closed locally. When the breaker is closed, amps and flow will inform the operator the breaker is closed and the pump is running.

D incorrect, amps will be indicated.

Technical Reference(s): Drawing 437583 - AFW Pump Schematic Proposed references to be provided to applicants during examination:N/A Learning Objective: 69130 - Describe Auxiliary Feedwater System instrumentation and controls, including symptoms of failure modes.

ro tier 1 group 1_09.doc

Question Source:

New X Question History: Last NRC Exam ____________

Question Cognitive Level: Memory or Fundamental Knowledge _____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.7 55.43 _____

Comments: K/A: APE 054 AA1.02 - Ability to operate and / or monitor the following as they apply to the Loss of Main Feedwater (MFW): Manual startup of electric and steam-driven AFW pumps ro tier 1 group 1_09.doc

RO QUESTION 10 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 1 _____

K/A # EPE 055 EK3.01 Importance Rating 2.7 3.4 Proposed Question:

A vital 125 VDC battery is designed to supply DC loads following a loss of its battery charger with no DC load shedding for a minimum of A. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

B. 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

C. 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

D. 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

Proposed Answer:

B. 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Explanation: Per DCM No. S-67, The vital battery is sized to supply power to its load for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for a design basis accident combined with a loss of a charger or 480V source.

Minimum voltage is designed to be at least 112.1V DC to provide sufficient voltage to connected loads.

Technical Reference(s): STG J9 page 1-8, DCM No. S-67 Proposed references to be provided to applicants during examination: N/A Learning Objective: 7119 - State the design basis of battery capacity.

Question Source:

DCPP P-1368 Question History: Last NRC Exam DCPP 2002 Question Cognitive Level: Memory or Fundamental Knowledge X Comprehension or Analysis _____

10 CFR Part 55 Content: 55.41 41.8 55.43 _____

ro tier 1 group 1_10.doc

Comments:

K/A: EPE 055 EK3.01 - Knowledge of the reasons for the following responses as they apply to the Station Blackout: Length of time for which battery capacity is designed ro tier 1 group 1_10.doc

1 P-1368 Points: 1.00 Multiple Choice WHICH ONE (1) of the following indicates how long the vital 125 VDC batteries can supply DC loads following a loss of all AC with no DC load shedding?

A. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

B. 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

C. 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

D. 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

Answer: B ASSOCIATED INFORMATION:

Associated objective(s):

7119 State the design basis of battery capacity Reference Id: P-1368 Must appear: No Status: Active User Text:

User Number 1: 0.00 User Number 2: 0.00 Difficulty: 1.00 Time to complete: 2 Topic: How long can station batteries supply DC loads.

Cross

Reference:

STG J-9 Comment: Seabrook exam 1994.

ro tier 1 group 1_10.doc

STG J9 page 1-8 Vital 125 VDC Systems Designed to ... Reason be redundant. A single active or passive failure in the DC system will not prevent safety systems from functioning during emergency core cooling.

allow periodic inspection and To ensure DC system components are maintenance of major maintained in an operational status.

components.

allow periodic testing. To periodically ensure DC system integrity and operability.

be operable during and after Ensure system remains capable of fires, tsunamis, and high winds. continuously supplying needed loads during tsunamis, high winds, and fires when emergency and backup loads may be required.

provide necessary DC loads This is the design basis for battery from the vital batteries for 2 capacity. Batteries must provide needed hours during a design basis loads during emergency core cooling until accident coincident with loss of power can be returned to the battery battery charger. chargers.

perform its safety function These are high usage events that place during: large demands on battery systems.

loss of main generator

loss of offsite power

degraded offsite power

loss of battery chargers

loss or start failure of diesel generators.

ro tier 1 group 1_10.doc

DCM No. S-67 System or Topic: 125/250 Volt Direct Current System Revision 13D Page 1 of 1

e. The Vital DC System for each unit is designed with three electrically independent and physically separated buses. To meet the single failure criterion, the Vital loads on any two of the three Vital buses are designed to meet the safe shutdown requirements. [1971GDC17]

f. Each Vital primary battery charger is designed to be fed from an independent 480V Vital bus. Use of the Vital backup battery charger may result in entering an Improved Technical Specification Action Statement to LCO 3.8.4. [1971GDC17,1967GDC39]

g. The Vital DC System nominal battery float voltage, when fed from the battery chargers, is 135V DC. Bus voltage limits range from a minimum allowable battery voltage of 112.1V DC (1.9V/cell) to a maximum equalization voltage of 139.8V DC (2.33V/cell). Utilization voltage ranges for power and control is contained in DCM T-23, Miscellaneous Electrical Devices. [Calc 235A-DC thru 235F-DC].

Note: Initial Battery Sizing calculations took credit for 60 cell and found no voltage drop concerns with battery final voltage of 114V DC (1.9VDC X 60 cells). With the new DC System Database Module (DCSDM),

battery calculations are in place to take credit for a 59 cell bank and a minimum allowable battery voltage of 112.1VDC (1.9VDC x 59 cells).

Although there are 60 cells installed, the battery sizing calculation can now allow one cell to be taken out of service (jumpered out) and still meet the design basis requirements.

h. The Vital DC System is designed to perform its safety function under the following abnormal conditions:

1. Loss of the Main Generator [1971GDC17] (DCM S-63)

2. Loss of offsite power [1971GDC17] (DCM S-63)

3. Degraded offsite power [SER 9] (DCM S-63)

4. Loss of battery chargers or 480V power to battery chargers.

[IEEE Std. 308-1971]

5. Loss or failure to start of the Diesel Generators

i. The Vital battery is sized to supply power to its loads for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for a design basis accident combined with the loss of a charger or 480V source.

Minimum voltage is designed to be at least 112.1V DC to provide sufficient voltage to the connected loads.

PG&E PROPRIETARY INFORMATION S-67.DOC

RO QUESTION 11 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 1 _____

K/A # APE 056 AK1.01 Importance Rating 3.7 4.2 Proposed Question:

Unit 1 trips from full power due to a loss of offsite power. The crew has entered E-0.1 and verifying natural circulation.

Current plant conditions:

Highest Core Exit Thermocouple = 590ºF and stable

RCS pressure = 1450 psig

Steam Generator pressures (all 4) = 985 psig and stable

RCS hot leg (all loops) = 585ºF and stable

RCS cold legs:

1 and 2 = 545ºF and stable 3 and 4 = 535ºF and stable Based on the current plant conditions, natural circulation A. exists in all loops.

B. exists in loops 1 and 2 only.

C. exists in loops 3 and 4 only.

D. does not exist in any loop.

Proposed Answer:

D. does not exist in any loop.

Explanation:

Per E0.1,

1) RCS subcooling based on core exit T/Cs GREATER THAN 20°F.

2) S/G Pressures stable or decreasing.

3) RCS Hot Leg Temperatures stable or decreasing.

4) Core Exit T/Cs stable or decreasing.

5) RCS Cold Leg Temperatures at saturation temperature for S/G Pressure ro tier 1 group 1_11 rev1.doc

A.Incorrect. Less than 20 degrees of subcooling exists. If subcooling was adequate it could be assumed to be occurring in loops 1 and 2.

B. Incorrect. Tcold is appropriate for SG pressure, however, insufficient subcooling currently exists.

C.incorrect. Tcold does not correspond to current SG pressure (Tsat for 1000 psia =

544 F)

D correct. 20 degrees of subcooling required, currently RCS is close to saturation.

Technical Reference(s): E-0.1 step 10 Proposed references to be provided to applicants during examination: Steam Tables Learning Objective: 5432 - Explain the conditions that affect natural circulation cooldown.

Question Source: Modified Bank # DCPP C4P6-5432-1 Question History: Last NRC Exam Question Cognitive Level: Memory or Fundamental Knowledge Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.5 55.43 _____

Comments: K/A: APE 056 AK1.01 - Knowledge of the operational implications of the following concepts as they apply to Loss of Offsite Power: Principle of cooling by natural convection ro tier 1 group 1_11 rev1.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER EOP E-0.1 DIABLO CANYON POWER PLANT REVISION 28 PAGE 14 OF 25 TITLE: Reactor Trip Response UNIT 1 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

10. CHECK RCP 2 - RUNNING Try to start RCP(s) to provide forced cooling and normal spray:

a. IMPLEMENT APPENDIX B to start an RCP.

b. Start RCP 2.

IF RCP 2 can NOT be started, THEN Try to start other RCP(s) as necessary to provide forced cooling and normal spray.

IF No RCP can be started THEN Verify Natural circulation based on:

1) RCS subcooling based on core exit T/Cs GREATER THAN 20°F.

2) S/G Pressures stable or decreasing.

3) RCS Hot Leg Temperatures stable or decreasing.

4) Core Exit T/Cs stable or decreasing.

5) RCS Cold Leg Temperatures at saturation temperature for S/G Pressure.

IF Natural Circulation NOT Verified, THEN Increase Dumping Steam.

AJ0A6228.DOC

1 C4P6-5432-1 Points: 1.00 Multiple Choice A reactor trip from full power occurred about 15 minutes ago. Off-site power is not available.

Highest core exit thermocouples 590°F and stable RCS pressure 2235 psig S/G pressure (all four S/G) 985 psig and stable RCS hotleg temps (all loops) 580°F and stable RCS coldleg temps (loops 1&2) 545°F and stable RCS coldleg temps (loops 3&4) 535°F and stable Based on this information fully developed natural circulation flow:>>

<QQ 36653(1416)><<A. exists in loops 1 and 2 only.

B. exists in all loops.

C. exists in loops 3 and 4 only.

D. does not exist in any loop.

Answer: A ASSOCIATED INFORMATION:

Associated objective(s):

5432 Explain the conditions that affect natural circulation cooldown Reference Id: C4P6-5432-1 Must appear: No Status: Active User Text:

User Number 1: 0.00 User Number 2: 0.00 Difficulty: 3.00 Time to complete: 3 Topic: indications of natural circulation Cross

Reference:

WOGMCD OR1.3.3 Comment: used for r985 6/9/04 CNH4 - See question M-0012, which was made inactive because "cold trapping" was not adequated explained.

ro tier 1 group 1_11 rev1.doc

RO QUESTION 12 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 1 _____

K/A # APE 057 G2.1.32 Importance 3.4 3.8 Proposed Question:

Unit 1 is at full power.

A loss of Vital 120 VAC bus 12 occurs. Troubleshooting is in progress but the bus is unable to be reenergized.

How long can the unit remain at power before it must be in MODE 3?

A. 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

B. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

C. 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

D. 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

Proposed Answer:

C. 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

Explanation:

A incorrect. This is the allowed outage time for the bus at power.

B incorrect, this is the time allowed to get to mode 3.

C correct, this is the time allowed (2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months ) and the time to be in mode 3 (6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months s_.

D incorrect, this would be correct if only the inverter was inoperable.

Technical Reference(s):

Technical Specification 3.8.7, Inverters-Operating Technical Specification 3.8.9, Distribution Systems-Operating Proposed references to be provided to applicants during examination:

Technical Specification 3.8.7, Inverters-Operating Technical Specification 3.8.9, Distribution Systems-Operating ro tier 1 group 1_12 rev1.doc

Learning Objective: 9697H - Identify 3.8 Technical Specification LCOs Question Source: Bank #

Modified Bank # _______

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.10 55.43 Comments:

K/A: APE 057 G2.1.32 - Ability to explain and apply all system limits and precautions.

ro tier 1 group 1_12 rev1.doc

Inverters - Operating 3.8.7 3.8 ELECTRICAL POWER SYSTEMS 3.8.7 Inverters-Operating LCO 3.8.7 Four Class 1E Vital 120 V UPS inverters shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One required inverter A.1 -----------NOTE---------------

inoperable. Enter applicable Conditions and Required Actions of LCO 3.8.9, "Distribution Systems -

Operating" with any vital 120 V AC bus de-energized.

Restore inverter to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE status.

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.7.1 Verify correct inverter voltage and alignment to 7 days required AC vital buses.

Distribution Systems - Operating 3.8.9 3.8 ELECTRICAL POWER SYSTEMS 3.8.9 Distribution Systems-Operating LCO 3.8.9 The required Class 1E AC, DC, and 120 VAC vital bus electrical power distribution subsystems shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One AC electrical power A.1 Restore AC electrical 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months distribution subsystem power distribution inoperable. subsystem to AND OPERABLE status. 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months from discovery of failure to meet LCO B. One 120 VAC vital bus B.1 Restore 120 VAC vital 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months subsystem inoperable. bus subsystem to AND OPERABLE status.

16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months from discovery of failure to meet LCO C. One DC electrical power C.1 Restore DC electrical 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months distribution subsystem power distribution AND inoperable. subsystem to OPERABLE status. 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months from discovery of failure to meet LCO D. Required Action and D.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND D.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months E. Two required Class 1E AC, E.1 Enter LCO 3.0.3. Immediately DC, or 120 VAC vital buses with inoperable distribution subsystems that result in a loss of safety function.

Distribution Systems - Operating 3.8.9 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.9.1 Verify correct breaker alignments and voltage to 7 days required AC, DC, and 120 VAC vital bus electrical power distribution subsystems.

RO QUESTION 13 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 1 _____

K/A # APE 058 AK3.02 Importance Rating 4.0 4.2 Proposed Question:

A loss of vital DC occurs.

If the main feedwater pumps do not trip, they are runback to minimum speed and locally tripped to prevent which of the following?

A. Pump runout.

B. Pump cavitation.

C. Overpressurizing the pump discharge.

D. Running the pump without lubricating oil.

Proposed Answer:

C. Overpressurizing the pump discharge.

Explanation:

C correct, Caution in OP AP-23 states, Since the MFW pump recirc valves fail closed and MFP trip solenoids lose power, immediate action is required to runback and locally trip running MFPs to prevent overpressurization.

Technical Reference(s): OP AP-23 Proposed references to be provided to applicants during examination: N/A Learning Objective: 7116 - Explain the consequences of loss of DC vital bus.

Question Source: Bank # P-26240 Question History: Last NRC Exam N/A ro tier 1 group 1_13.doc

Question Cognitive Level: Memory or Fundamental Knowledge X Comprehension or Analysis _____

10 CFR Part 55 Content: 55.41 41.4 55.43 _____

Comments:

K/A: APE 058 AK3.02 - Knowledge of the reasons for the following responses as they apply to the Loss of DC Power: Actions contained in EOP for loss of dc power ro tier 1 group 1_13.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP AP-23 DIABLO CANYON POWER PLANT REVISION 11 PAGE 2 OF 17 TITLE: Loss of Vital DC Bus UNITS 1 AND 2 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. VERIFY Reactor Tripped:

a Reactor trip and bypass breakers open

b. Rod bottom lights lit

c. Neutron flux decreasing

d. Implement EP E-0, Rx Trip or SI, and continue in this procedure at Step 2

2. After 30 Seconds, Verify Main Generator Not Motoring:

a. PCBs OPEN Initiate manual unit trip.

b. Either 86G1 (86G2) or 86G11 (86G21) tripped, (VB4)

CAUTION: Personnel shall wear protective flash gear if actuating the Exciter Field Breaker as described in the following step.

3. After Main Generator Trips, Verify No Locally trip Exciter Field Breaker.

Gen. Field Voltage on CC3:

CAUTION: Since the MFW pump recirc valves fail closed and MFP trip solenoids lose power, immediate action is required to runback and locally trip running MFPs to prevent over-pressurization.

4. Verify Both MFPs Tripped: Remove MFP from service:

1. Verify MFP turbine speed is at minimum.

2. Locally trip MFP.

00954311.DOC 02 0502.0726

RO QUESTION 14 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 1 _____

K/A # APE 065 G2.1.32 Importance 3.4 3.8 Proposed Question:

With Unit 1 at 100% power, a rupture occurs at Air Receiver 0-1.

As instrument air pressure decreases, the reactor will trip due to.

A. MSIVs failing closed.

B. Pressurizer spray valves failing open.

C. Main Feedwater Regulating valves failing closed.

D. Condensate Demineralizer outlet valves failing closed.

Proposed Answer:

C. Main Feedwater Regulating valves failing closed.

Explanation:

Per AP-9, NOTE: FCV-584 may begin to close at 85 psig, and the Main Feed Reg Valves may begin to close at 75 psig.

A incorrect, MSIVs have backup air and are held open by steam flow.

B incorrect, FCV-584 fails closed, but sprays fail closed.

C correct, FRVs closing results in loss of SG level control.

D incorrect, fail as is.

Technical Reference(s): OP AP-9. OIM K-1-1 Proposed references to be provided to applicants during examination: none Learning Objective: 3541 List the effects that a loss of Instrument Air would have on the plant Question Source: DCPP A-0741 ro tier 1 group 1_14 rev1.doc

Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 41.10 55.43 Comments: K/A: APE 065 G2.1.32 - Loss of Instrument Air, Ability to explain and apply all system limits and precautions.

ro tier 1 group 1_14 rev1.doc

ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE: FCV-584 may begin to close at 85 psig, and the Main Feed Reg Valves may begin to close at 75 psig.

1. CHECK Control of Plant Systems: a. VERIFY Reactor Tripped.

S/G Levels, PZR Levels, PZR Pressure b. IMPLEMENT this procedure in parallel with can be maintained within their normal EOP E-0.

bands

c. IMPLEMENT Appendix B (Page 36) of this

Reactor Trip NOT Initiated procedure in parallel with appropriate steps of additional Emergency Procedures

PK04 OFF (normally EOP E-0.1)

PK04 OFF

d. GO TO EOP E-0.

2. STABILIZE the Plant:

a. Suspend load changes

b. Suspend other plant activities such as fuel movement, Rx vessel level changes, radwaste discharges, etc.

3. VERIFY Air Compressors 0-1 thru 0 RUNNING

4. MAKE Plant P.A. Announcement:

a. Plant is experiencing a loss of instrument air pressure

b. All plant personnel using air are to stop

c. Plant personnel inspect their areas for air leaks. If found, report to the Control Room

d. If any air leaks are reported, GO TO Step 13 (page 7) ro tier 1 group 1_14 rev1.doc

Compressed Air System Rotary Air Compressors 650SCFM/ea Backfeed From U2 Moisture 06 Service Air Air Seperator (11E) 1400 SCFM PS 01 136 Aftercooler 05 SCW Bstr Pps Air (01/02 - 11E/25D) Receiver Air Dryer 02 01 SCW Instrument 05 Air PC Air (25D)

PS U2 135 07 F Air U1 (15E)

F U1 K-1-1 Air Dryer 01 After Filters Reciprocating Air 334SCFM/ea Air U2 Compressors Receiver Service Air (SCW Cooled) 1500 02 F F SCFM Air 01 1500 Pre-filters 1400 SCFM (15D) SCW F 03 SCFM 04 Air 05 Air Dryers Dryer S

Air 01 F (Heat of Compression)

(15E) F F Air 01 Service Air Facility (U2 XFMR Yard) Moisture (25D) SCW Seperator PAC 08 Air 04 650 SCFM (TVDP2)

Air Cooled Air After Cooler Rev 19 (25E) PAC 09 (TVDP2) 1050 SCFM (TVDP2 - U2 Constructio Power) (No Aftercooler) ro tier 1 group 1_14 rev1.doc

A-0741 Points: 1.00 Multiple Choice With the unit at 100% power, a rupture occurs at Air Dryer 0-1. The reactor will trip due to the:

A. Feedwater Regulating valves failing closed.

B. MSIVs failing closed.

C. Condensate Demineralizer outlet valves failing closed.

D. Pressurizer Spray valves failing open.

Answer: A ASSOCIATED INFORMATION:

Associated objective(s):

3541 List the effects that a loss of Instrument Air would have on the plant Reference Id: A-0741 Must appear: No Status: Active User Text: 3541.080513 User Number 1: 3.10 User Number 2: 3.40 Difficulty: 4.00 Time to complete: 3 Topic: Loss of instrument air resulting in a reactor trip Cross

Reference:

DUTY AREA 51 Comment: Revised stem to allow inclusion of a more plausible distractor. Should be validated. 1/11/97 MAP2 Copied from S-1356; 11/11/96; GES1 Validated question IAW TQ2.ID3, increased difficulty to 4.0 1/23/97 RCWf Taken active following review, 1/25/97 JMH1 Checked as part of question review for biennial exam 12/22/98 MTC6 Reviewed for 00 biennial exam 1/17/01 mtc6 Reviewed for 02 biennial exam 1/7/03 mtc6 Reviewed for 04 biennial exam 12/21/04 mtc6 ro tier 1 group 1_14 rev1.doc

RO QUESTION 15 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 1 _____

K/A # W/E 04 EK2.1 Importance 3.5 3.9 Proposed Question:

The crew is performing the steps of ECA-1.2, LOCA Outside Containment.

As part of the attempt to find the leak, valve 8809A, RHR cold legs 1 and 2, is closed.

The operator is instructed to place the series contactor to CUTIN.

What purpose does the series contactor in CUTIN serve?

A. Applies DC control power to the circuit.

B. Allows the valve to torque out, ensuring positive seating.

C. Prevents the valve from being stopped by breakaway torque as it begins to move.

D. Allows the valve motor to be energized when the control switch is taken to open or close.

Proposed Answer:

D. Allows the valve motor to be energized when the control switch is taken to open or close.

Explanation:

A incorrect, control power comes from the AC source.

B incorrect, the full closed contact is jumpered out, accomplishing this.

C incorrect, this is the purpose of the torque switch bypass contact.

D correct, one contact on each phase closes, which allows AC to be applied to the motor when the switch is taken to the open or close position.

Technical Reference(s): STG B2, RHR, page 2-33 ECA-1.2, step 2 Proposed references to be provided to applicants during examination: N/A ro tier 1 group 1_15.doc

Learning Objective: 7053 - Explain the RHR system design features Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis _____

10 CFR Part 55 Content: 55.41 41.7 55.43 _____

Comments: K/A: W/E 04 EK2.1 - LOCA Outside Containment - Components, and functions of control and safety systems, including instrumentation, signals, interlocks, failure modes, and automatic and manual features.

ro tier 1 group 1_15.doc

RHR to Cold Leg Isolations, 8809A/B, Continued Diagram The contact diagram for valve 8809A/B is shown below.

Closes Closes TS Opens Opens

< 10% TS > 90% Full Full Open Open Open Closed 52 Opens Opens Full Full Open Closed G R 42 42 OPEN CLOSE 42-1G-12 (42-1H-45) 49 B OL CS CS OPEN CLOSE 42 42 CLOSE OPEN Series 42 42 Contactor R OPEN CLOSE 49 OL 49 OL 8809A/B RHR-21 Indication The following indications are available for 8809A/B.

8809A/B control switches Indicating Light Meaning Normal Status Red Valve is full OPEN. ON Green Valve is full CLOSED. OFF Note:

If BOTH Indicating lights are LIT simultaneously, then the valve is in an intermediate position.

Both valves are normally OPEN.

8809A/B Monitor Light Box A on VB1 Indicating Light Meaning Normal Status White Valve not fully OPEN OFF Continued on next page B2.DOC 2 - 33 REV. 13

PACIFIC GAS AND ELECTRIC COMPANY NUMBER EOP ECA-1.2 DIABLO CANYON POWER PLANT REVISION 6 PAGE 2 OF 4 TITLE: LOCA OUTSIDE CONTAINMENT UNIT 1 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. VERIFY Proper Valve Alignment: Manually close bkrs and valves.

Verify the following valves - CLOSED IF Valves CANNOT be manually closed, o 8702, RCS RHR Suct LP4 HL THEN Locally close valves as necessary.

o 8701, RCS RHR Suct LP4 HL o 8703, RHR to hot legs 1 and 2 o 8802A, SI to hot legs 1 and 2 o 8802B, SI to hot legs 3 and 4

2. TRY To Identify And Isolate Break:

a. Operate the following valves:

1) 8809A, RHR to cold legs 1 and 2 (a) Series contactor CUTIN (b) Close 8809A (b) Locally Close 8809A.

(c) Check RCS Pressure - (c) Open 8809A AND GO STABLE OR TO Step 2a2.

INCREASING (d) GO TO Step 3 (Next Page)

2) 8809B, RHR to Cold Legs 3 and 4 (a) Series contactor CUTIN (b) Close 8809B (b) Locally Close 8809B.

(c) Check RCS Pressure - (c) Open 8809B.

STABLE OR INCREASING ------------------------------

RO QUESTION 16 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 1 _____

K/A # W/E 05 EK3.1 Importance 3.4 3.8 Proposed Question:

Why is it critical to quickly establish bleed and feed once wide range steam generator levels are less than 23%?

A. To maintain the steam generator U-tubes wet.

B. To ensure adequate ECCS flow to remove decay heat.

C. To extend the time until steam generator dryout occurs.

D. To prevent the steam generators from becoming a heat source.

Proposed Answer:

B. To ensure adequate ECCS flow to remove decay heat.

Explanation:

If Bleed and Feed is not established quickly, and RCS pressure is allowed to rise to the PORV setpoint and reach saturation, ECCS flow will be inadequate to remove decay heat and there will be a deeper and more prolonged core uncovery.

A incorrect, this is why flow is maintained to all steam generators if all are faulted (ECA-2.1)

B Correct. An early initiation of bleed and feed permits a maximum depressurization of the RCS, greater SI flowrate, and ensures effective heat removal. The further the transient is allowed to advance into Period 5 (a period when subcooling is being reduced) before bleed and feed is initiated, the smaller the initial depressurization will be. This results in lower SI flowrate, greater repressurization, and higher net inventory losses.

C incorrect, this is why the RCPs are stopped.

D Incorrect, steam generator temperature is still less than RCS temperature.

Technical Reference(s):

ro tier 1 group 1_16 rev1.doc

Background, FR-H.1 Proposed references to be provided to applicants during examination: none Learning Objective: 7920 - Explain basis of emergency procedure step Question Source:

Modified Bank # DCPP P-1397 Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 41.5/41.10 55.43 _____

Comments: K/A: EPE WE05 EK3.1 - Knowledge of the reasons for the following responses as they apply to the (Loss of Secondary Heat Sink) - Facility operating characteristics during transient conditions, including coolant chemistry and the effects of temperature, pressure, and reactivity changes and operating limitations and reasons for these operating characteristics.

ro tier 1 group 1_16 rev1.doc

P-1397 Points: 1.00 Multiple Choice EOP FR-H.1, "Response to Loss of Secondary Heat Sink," cautions the operators to initiate RCS bleed and feed if certain conditions are reached. Which one of the following indicates why it is vital that the operators not delay these steps?

A. To minimize core uncovery and prevent an inadequate core cooling condition.

B. To prevent a tube rupture due to excessive primary to secondary differential pressure if the S/Gs boil dry.

C. To prevent lifting pressurizer safeties.

D. To prevent caustic stress corrosion from chemical precipitation on uncovered (dry) tubes.

Answer: A ASSOCIATED INFORMATION:

Associated objective(s):

7920 Explain basis of emergency procedure step Reference Id: P-1397 Must appear: No Status: Active User Text:

User Number 1: 0.00 User Number 2: 0.00 Difficulty: 1.00 Time to complete: 2 Topic: LPEH - Basis to not delay actions to BLEED & FEED Cross

Reference:

FR-H.1 BKGRND DOC Comment: IP3 RO exam 7/93 LPE-H Page 20 ro tier 1 group 1_16 rev1.doc

FR-H.1 Background 2.2.2 RCS Bleed and Feed Heat Removal Transient Description Bleed and feed is initiated by starting all high pressure SI pumps, verifying SI delivery, and manually opening and holding open all pressurizer PORVs. This will result in rapid RCS depressurization (Figures 2C, 3CB, 4C) as the pressurizer steam bubble and saturated liquid are quickly vented, the pressurizer fills (Figures 2D, 3D, 4D), and a large subcooled liquid flow is established through the pressurizer PORVs. The core exit fluid temperature when the pressurizer PORVs are opened will govern the degree of depressurization since the RCS pressure will decrease until saturation is reached at the hottest point in the system.

Once the saturation pressure is reached in the core, the RCS fluid will begin to heat up (Figures 2A, 3A, 4A and 2B, 3B, 4B) since initially the energy addition and volume swell due to core decay heat generation will exceed the energy and volume removal capability of the pressurizer PORVs and the SG liquid mass inventory remaining (Figures 2G, 3G, 4G). The flow of saturated liquid through the pressurizer PORVs will not remove enough volume to make up for the RCS fluid swell such that RCS pressure will continue to rise until a balance between pressurizer PORV volumetric flow rate and RCS fluid swell plus SI addition is reached. At that point, the RCS pressure will stabilize and remain relatively stable until either a change to all steam flow out the pressurizer PORVs increases the volumetric removal rate or the core partially uncovers reducing the core heat transfer and steam generation rate. The magnitude of the RCS repressurization and the pressure stabilization point will depend upon RCS fluid temperature and core decay heat level at the time bleed and feed is initiated along with pressurizer PORV flow capacity and SI delivery rates. Therefore, all pressurizer PORVs must be held open to minimize both the RCS repressurization and RCS pressure stabilization point in order that SI flow into the RCS may be maximized.

During the pressure stabilization period, all available pressurizer PORVs should be maintained open and all available high pressure SI pumps should continue to run to maximize RCS feed flow.

ro tier 1 group 1_16 rev1.doc

Even with SI flow maximized, RCS inventory will continue to decrease resulting in an eventual emptying of the reactor vessel upper head and a drain down to the hot leg elevation (Figures 2E, 3E, 4E). At that time, steam will begin to be vented out through the hot leg to the pressurizer and pressurizer level may decrease. When the PORV flow becomes a large fraction of steam, the RCS pressure will begin to decrease steadily. This pressure decrease will permit an important increase in SI flow to prevent or minimize core uncovery. As core decay heat generation continues to decrease with time and SI flow increases, the volume removal capability of the pressurizer PORVs will start to exceed the volume addition due to steam generation from core decay heat and water addition from SI. This will be accompanied by increasing net inventory in the RCS, since SI flow will now exceed PORV flow.

An early initiation of bleed and feed permits a maximum depressurization of the RCS, greater SI flowrate, and ensures effective heat removal. The further the transient is allowed to advance into Period 5 (a period when subcooling is being reduced) before bleed and feed is initiated, the smaller the initial depressurization will be. This results in lower SI flowrate, greater repressurization, and higher net inventory losses.

If bleed and feed is initiated earlier than Period 5, then SG liquid mass will still be available to remove a limited amount of energy. This liquid mass can help reduce the extent of repressurization. For plants with smaller PORV flow to power ratios, the liquid mass remaining in the SG is important to the eventual success of bleed and feed in preventing significant core uncovery.

If action is withheld until the start of Period 6, establishing bleed and feed will not prevent significant core uncovery. This is a result of the steam generation rate within the system due to boiling in the core. The volumetric generation of steam and the resultant pressurization of the RCS will fully open the PORVs and will hold them continuously open. The RCS will remain in a high pressure condition until the core uncovers enough to reduce the steam generation rate. The mass flow rate out the PORVs during Period 6 is 50-100 lbm/sec which exceeds the pumped SI capacity of ro tier 1 group 1_16 rev1.doc

about 40 lbm/sec (290 gpm) for the reference plant. The only possible means for preventing core uncovery once the transient enters into Period 6 is to restore feedwater to the steam generator secondaries (see Reference 1).

ro tier 1 group 1_16 rev1.doc

RO QUESTION 17 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 1 _____

K/A # WE11 EK2.2 Importance 3.9 4.3 Proposed Question:

During the performance of ECA-1.1, "Loss of Emergency Coolant Recirculation Capability" one train of SI flow is established.

What is the establishment of one train of SI flow designed to accomplish?

A. Decrease break flow.

B. Delay the time to RWST depletion.

C. Reduce RCS pressure to allow accumulator injection.

D. Maintain one train of ECCS available for use later, if needed.

Proposed Answer:

B. Delay the time to RWST depletion.

Explanation:

Per ECA-1.1 background: This step instructs the operator to establish one train of SI flow which is one charging/SI, one high-head SI and one low-head SI pump for the reference plant, in order to delay RWST depletion.

The quantified benefit of reducing SI flow is illustrated below in terms of time available before depleting 200,000 gallons of RWST water. These times are typical and are based on containment spray flow of 5600 gpm and SI pumps injecting at zero pressure.

12 minutes - Based on maximum safeguards flow

17 minutes - Based on minimum safeguards flow

150 minutes - Based on decay heat flow and containment spray off A incorrect. This is why depressurization is performed later.

C incorrect, this is a result of the depressurization performed later.

ro tier 1 group 1_17.doc

D incorrect. This is true in procedures such as C.2 when RCPs are stopped to preserve them for use later.

Technical Reference(s): ECA-1.1 step 11, ECA-1.1 background Proposed references to be provided to applicants during examination: N/A Learning Objective: 7920 - Explain basis of emergency procedure step.

Question Source: Bank #

Modified Bank # INPO Bank #22432 New ______

Question History: Last NRC Exam DCPP 2002 Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 41.8 55.43 _____

Comments:

K/A: WE11 EK2.2 - Knowledge of the interrelations between the (Loss of Emergency Coolant Recirculation) and the following: Facility*s heat removal systems, including primary coolant, emergency coolant, the decay heat removal systems, and relations between the proper operation of these systems to the operation of the facility.

ro tier 1 group 1_17.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER EOP ECA-1.1 DIABLO CANYON POWER PLANT REVISION 16 PAGE 7 OF 31 TITLE: Loss of Emergency Coolant Recirculation UNIT 1 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

10. Check if ECCS Is In Service GO TO Step 21 (Page 11) o SI Pps - ANY RUNNING ------------------------------

OR o Charging Injection - NOT ISOLATED OR o RHR Pps - ANY RUNNING NOTE: The CCP and SI Pps should be stopped in alternate trains when possible.

11. ESTABLISH One Train Of SI Flow:

a. Depress Vital 4KV Auto Transfer Relay Resets: Blue Light - OFF

b. Verify CCPs - ONLY ONE RUNNING

c. Verify SI Pps - ONLY ONE RUNNING

d. RCS Pressure - LESS THAN d. Stop Both RHR Pps 300 PSIG AND GO TO Step 12 (Next Page).

e. Verify RHR Pps - ONLY ONE RUNNING 8S9IBE16.DOC

STEP DESCRIPTION TABLE FOR ECA-1.1 Step 12 STEP: Establish One Train Of SI Flow PURPOSE: To establish one train of SI flow BASIS:

This step instructs the operator to establish one train of SI flow which is one charging/SI, one high-head SI and one low-head SI pump for the reference plant, in order to delay RWST depletion.

The quantified benefit of reducing SI flow is illustrated below in terms of time available before depleting 200,000 gallons of RWST water. These times are typical and are based on containment spray flow of 5600 gpm and SI pumps injecting at zero pressure.

o 12 minutes - Based on maximum safeguards flow o 17 minutes - Based on minimum safeguards flow o 150 minutes - Based on decay heat flow and containment spray off ACTIONS:

o Determine if only one charging/SI pump is running o Determine if only one high-head SI pump is running o Determine if RCS pressure is less than (B.07) psig [(B.08) psig for adverse containment]

o Determine if only one low-head SI pump is running o Stop low-head SI pumps o Start or stop charging/SI pumps to establish only one pump running o Start or stop high-head SI pumps to establish only one pump running o Start or stop low-head SI pumps to establish only one pump running INSTRUMENTATION:

o RCS pressure indication o Charging/SI pumps status indication o High-head SI pumps status indication o Low-head SI pumps status indication ECA-1.1 33 HP-Rev. 1C

STEP DESCRIPTION TABLE FOR ECA-1.1 CONTROL/EQUIPMENT:

Switches for:

o Charging/SI pumps o High-head SI pumps o Low-head SI pumps KNOWLEDGE:

N/A PLANT-SPECIFIC INFORMATION:

o (B.07) Shutoff head pressure of the low-head SI pumps, including allowances for normal channel accuracy.

o (B.08) Shutoff head pressure of the low-head SI pumps, including allowances for normal channel accuracy and post accident transmitter errors.

ECA-1.1 34 HP-Rev. 1C

RO QUESTION 18 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 1 _____

K/A # WE 12 EK1.2 Importance 3.5 3.8 Proposed Question:

Which one of the following describes a major difference in strategies between EOP E-2, "Faulted Steam Generator Isolation," and EOP ECA-2.1, "Uncontrolled Depressurization of All Steam Generators?"

A. EOP E-2 attempts to prevent thermal shock of the S/Gs. EOP ECA-2.1 does NOT.

B. EOP E-2 maintains the faulted S/G(s) as a heat sink. EOP ECA-2.1 does NOT.

C. EOP E-2 is concerned with excessive RCS cooldown. EOP ECA-2.1 is NOT.

D. EOP E-2 isolates feed flow to the faulted S/Gs. EOP ECA-2.1 does NOT.

Proposed Answer:

D. EOP E-2 isolates feed flow to the faulted S/Gs. EOP ECA-2.1 does NOT.

Explanation:

A incorrect, this why attempts are made to isolate the faulted steam generators.

B incorrect, attempts are made to restore at least one steam generator as a heat sink.

C incorrect, this one reason feed flow is controlled to faulted steam generators.

D correct, in E-2 faulted steam generators are isolated, including feed flow, in ECA-2.1, 25 gpm is maintained to prevent the internals from drying out.

Technical Reference(s): ECA-2.1 background Proposed references to be provided to applicants during examination:

Learning Objective: 7920 - Explain basis of emergency procedure step Question Source: Bank # P-33611 Question History: Last NRC Exam DCPP RO EXAM 10/94 Question Cognitive Level:

ro tier 1 group 1_18.doc

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.8 55.43 _____

Comments: K/A: WE12 EK1.2 - Knowledge of the operational implications of the following concepts as they apply to the (Uncontrolled Depressurization of all Steam Generators): Normal, abnormal and emergency operating procedures associated with (Uncontrolled Depressurization of all Steam Generators).

ro tier 1 group 1_18.doc

3. RECOVERY/RESTORATION TECHNIQUE An uncontrolled depressurization of all steam generators provides a unique situation to the operator which requires a recovery technique different from that presented in E-2, FAULTED STEAM GENERATOR ISOLATION. The situation is unique since there is no controllable secondary heat sink available to the operator. The objective of the recovery technique contained in ECA-2.1 is to reestablish any secondary pressure boundary, control feed flow, terminate SI and cooldown/depressurize the RCS.

The following subsections provide a summary of the major categories of operator actions and the key utility decision points for guideline ECA-2.1, UNCONTROLLED DEPRESSURIZATION OF ALL STEAM GENERATORS.

3.1 High Level Action Summary A high level summary of the actions performed in ECA-2.1 is given on the following page in the form of major action categories. These are discussed below in more detail.

o Reestablish Any Secondary Pressure Boundary An attempt is made to restore a secondary pressure boundary to the steam generators. If this attempt fails, an operator is dispatched to locally close valves, one loop at a time, while the guideline is continued.

ECA-2.1 17 HP-Rev. 1C

MAJOR ACTION CATEGORIES IN ECA-2.1 o Reestablish Any Secondary Pressure Boundary o Control Feed Flow o Terminate SI Flow o Cool Down and Place RHR System in Operation o Cool Down to Cold Shutdown Conditions ECA-2.1 18 HP-Rev. 1C

RO QUESTION 19 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 1 _____

K/A # APE 001 AK2.05 Importance 2.9 3.1 Proposed Question:

PLANT CONDITIONS:

Unit 1 is at 50% power.

Control Bank D is at 200 steps.

Rods are in automatic.

Tave/Tref deviation is +3.0ºF.

Control Bank D begins to move. The RO notes the rods are moving and that the RED indicating light is lit on CC1.

Which of the following actions would be appropriate for the given plant conditions?

A. Trip the reactor.

B. Take rods to manual.

C. Verify rods stop when Tave/Tref deviation is less than 0.5ºF.

D. Verify rods stop when Tave/Tref deviation is less than 1.5ºF.

Proposed Answer: B. Take rods to manual.

Explanation: With a +3 Tave/Tref deviation, rods should be moving IN. Given indication is the red light is lit, so rods are moving OUT. Therefore, rods should be placed in manual per OP AP-12A, step 1.

A incorrect, this done if rods do not stop once in manual.

B correct.

C incorrect, this would be true if rods were moving in the correct direction.

D incorrect, this would be considered if operator believed dead band was 1.5 vice 0.5 degrees and rods were moving correctly.

Technical Reference(s): OP AP-12A ro tier 1 group 2_19.doc

Proposed references to be provided to applicants during examination: None Learning Objective: 5001 - Identify the normal state of Rod Control system indicating lights during system operation Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.6 55.43 _____

Comments: K/A: APE 001 AK2.05 - Knowledge of the interrelations between the Continuous Rod Withdrawal and the following: Rod motion lights ro tier 1 group 2_19.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP AP-12A NUCLEAR POWER GENERATION REVISION 5C DIABLO CANYON POWER PLANT PAGE 1 OF 4 ABNORMAL OPERATING PROCEDURE UNITS TITLE: Continuous Withdrawal or Insertion of a Control Rod Bank 1 2 AND 07/30/02 EFFECTIVE DATE PRO CED U RE CLA SSIFICA TIO N : Q U A LITY RELA TED

1. SCOPE 1.1 This procedure provides instructions for unwarranted continuous withdrawal or insertion of a control rod bank while at power or during startup.

2. SYMPTOMS This condition may be indicated by one or more of the following:

2.1 Unwarranted rod motion is indicated by DRPI and rod step counters.

2.2 Changing TAVG Indication with no change in TREF.

2.3 Increasing source/intermediate range flux level and/or startup rate during reactor startup (continuous rod withdrawal).

2.4 Possible Main Annunciator Alarms:

2.4.1 For continuous rod withdrawal.

a. ROD BANK D STOP C-11 (PK03-15).

b. TAVG DEVIATION FROM REF (PK04-03).

c. OT DELTA-T C-3 CHANNEL ACTIVATED (PK04-04).

d. OP DELTA-T C-4 CHANNEL ACTIVATED (PK04-05).

e. AUCTIONED TAVG HIGH (PK04-10).

f. PZR PRESSURE HIGH (PK05-16).

g. PZR LEVEL HI LO CONTROL (PK05-22).

h. OT DELTA-T ROD STOP & TURBINE RUNBACK C-3 (PK08-09).

i. OP DELTA-T ROD STOP & TURBINE RUNBACK C-4 (PK08-10).

000957005.D O C 02 0119.0955

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP AP-12A DIABLO CANYON POWER PLANT REVISION 5C PAGE 2 OF 4 TITLE: Continuous Withdrawal or Insertion of a Control Rod UNITS 1 AND 2 Bank 2.4.2 For continuous rod insertion

a. ROD LO INSERTION LIMIT (PK03-13).

b. ROD LO LO INSERTION LIMIT (PK03-14).

c. PPC RX ALM AXIAL FLUX/ROD POS (PK03-25).

d. TAVG DEVIATION FROM REF (PK04-03).

e. PZR PRESS LOW (PK05-17).

f. PZR LEVEL HI-LO (PK05-21).

g. PZR LEVEL HI-LO CONTROL (PK05-22).

000957005.D O C 02 0119.0955

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP AP-12A DIABLO CANYON POWER PLANT REVISION 5C PAGE 3 OF 4 TITLE: Continuous Withdrawal or Insertion of a Control Rod UNITS 1 AND 2 Bank ACTIONS/EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. PLACE Rods In Manual

2. CHECK Rod Motion Stopped Manually trip reactor. GO TO EOP E-0, REACTOR TRIP OR SAFETY INJECTION

3. MATCH TAVG AND TREF:

a. Adjust control rods to match a. Adjust turbine load to match TAVG AND TREF TAVG AND TREF

1) Refer to Technical Specification 3.1.3.1.c (ITS 3.1.4)

2) Have MS initiate troubleshooting and repairs to Rod Control System

b. Adjust turbine load AND boron concentration as necessary to maintain:

1) Control rods ABOVE ROD INSERTION LIMIT

2) Axial flux difference within Tech Spec limits

c. Notify MS of Rod Control failure

4. CONTINUE Normal Plant Operations:

a. Return rod control to auto when automatic rod control is restored to normal operation

5. RETURN To Procedure and Step in Effect

- END -

000957005.D O C 02 0119.0955

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP AP-12A DIABLO CANYON POWER PLANT REVISION 5C PAGE 4 OF 4 TITLE: Continuous Withdrawal or Insertion of a Control Rod UNITS 1 AND 2 Bank

3. APPENDICES None

4. ATTACHMENTS None 000957005.D O C 02 0119.0955

RO QUESTION 20 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 2 _____

K/A # APE 003 AK1.21 Importance 2.7 3.2 Proposed Question:

PLANT CONDITIONS:

Unit 1 is at 100% power

All rods are at 228 steps.

AFD is 0.00 on all quadrants.

Control rod C-3 drops to an indicated position of 108 steps.

Which of the following describes how AFD in the area closest to rod C-3 will be affected?

A. AFD on channel N-41 will be more negative.

B. AFD on channel N-43 will be more negative.

C. AFD on channel N-41 will be more positive.

D. AFD on channel N-43 will be more positive.

Proposed Answer: B. AFD on channel N-43 will be more negative.

Explanation:

A incorrect. This is the location if the alignment of the rod orientation to the NIs is not done properly.

B correct. Rod C-3 is on the periphery between 90 and 180 degrees. That location is closest to NI-43. Flux in the area of the dropped rod will be depressed and AFD will go in the negative direction.

C incorrect. AFD will go negative.

D incorrect. AFD will go negative.

ro tier 1 group 2_20.doc

Technical Reference(s): OP AP-12C step 6.

DC Unit 1 Cycle 12 NDR figure 2-9 Drawing 1020007, Neutron Detector and Temperature Monitor Locations Proposed references to be provided to applicants during examination:

DC Unit 1 Cycle 12 NDR figure 2-9

Drawing 1020007, Neutron Detector and Temperature Monitor Locations Learning Objective: 5024 - Explain the effect of dropped rod(s) on reactor operation Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.6 55.43 _____

Comments: K/A:

APE 003 AK1.21 - Knowledge of the operational implications of the following concepts as they apply to Dropped Control Rod: Delta flux ( I) ro tier 1 group 2_20.doc

RO QUESTION 21 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 2 _____

K/A # APE 033 AK1.01 Importance 2.7 3.0 Proposed Question:

Unit 1 shutdown is being performed.

Intermediate range channel N35 is overcompensated.

Which of the following describes the effect of the overcompensation on P-6 operation?

A. P-6 will energize both source ranges prematurely.

B. P-6 will require manual action to energize both source ranges.

C. P-6 will automatically energize one of the source ranges when N36 reaches the setpoint.

D. P-6 will automatically energize both of the source ranges when N36 reaches the setpoint.

Proposed Answer:

D. P-6 will automatically energize both of the source ranges when N36 reaches the setpoint.

Explanation:

A incorrect. This would be true if the coincidence was 1/2.

B incorrect. This would be true is N35 was UNDERCOMPENSATED.

C incorrect. The SR channels are not train dependent.

D correct. Due to overcompensation, N35 will decrease below the P-6 setpoint ahead of N36, however, both IR channels must be less than 5x10-11 to energize either (both) source ranges. Therefore, when N36 reaches the setpoint, both SR will energize.

Technical Reference(s): OIM pages B-4-3 and B-6-2a Proposed references to be provided to applicants during examination: N/A ro tier 1 group 2_21.doc

Learning Objective: 5229 - Explain the effect of Intermediate Range channel failures in the NIS Question Source:

Modified Bank # INPO 23213 Question History: Last NRC Exam IP2, 2003 Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.7 55.43 _____

Comments:

K/A: APE 033 AK1.01 - Knowledge of the operational implications of the following concepts as they apply to Loss of Intermediate Range Nuclear Instrumentation:

Effects of voltage changes on performance ro tier 1 group 2_21.doc

Intermediate Range Compensation Under-Compensated If the IR detector is Indicated undercompensated, the IR Amps Over- indicated IR neutron

-8 Compensated level will be greater 10 than the actual level.

Ideal Compensated An overcompensated IR

-8 detector the indicated IR 10 neutron level will be less Actual IR Amps than the actual level.

Indicated IR AMPS

-11 -10 -9 -8 10 10 10 10 Stable If power increases on 0

(+) SUR stable +1 DPM startup rate (SUR), the indicated SUR 1 will be less than the actual OverCompensated SUR if the detector is Time, undercompensated.

2 Min Ideal Compensation Overcompensation 3 UnderCompensated has the opposite effect.

4 Indicated IR AMPS

-11 -10 -9 -8 -7 10 10 10 10 10 0

Under- Stable If power decreases on a Compensated (-) SUR stable -.3 DPM startup rate 1 Ideal (SUR), the indicated SUR Compensation will be less than the actual Time, SUR if the detector is 2

Min undercompensated.

3 Overcompensation Over-has the opposite effect.

Compensated 4

B-4-3 Rev 24

Protection Permissives Logics BYA RTA RTB BYB I NC 10-10A NC 10-10A PC PC 10% NC 10%

Open Open Open Open 35D 36D 505A 506A 41M Other T C T C T C T C T C Channels P P P P P PK0801 (Amber) PK0808 2/4 P-4 (A) P-4 (B) PK0805 Protection Permissive P P (Amber)

MG Sets P-6 Protection Permissive P-13 Protection P RTB BYB Intermediate Range Permissive High Flux (Low Power)

C P-10 Protection RTA BYA PK0802 Permissive Rod Drive P/S P I

NC 35% NC I 50% P-7 Protection Permissive 41N 41S Other Other I I PC TC T C Channels T C Channels 1915 psig 412D 455B 543ºF P P Other Other Channels T C (456B, 457B)

T C Channels (422, 432, 442) 2/4 2/4 SG SG C C A

P P 2/3 PK0406 2/4 PK0803 PK0804 P-8 Protection P-9 Protection PK0806 P

Permissive Permissive P PK0807 II III IV P-11 Protection P-12 Protection LC LC LC 75%

519A 518A 517A Permissive Permissive PK0407 PK0407 Trip Status Lights (B/S Lights:

T T T PK0407 T SG=Safeguards, P=Protection)

SG A SG A SG A

From LC-529A (I) Permisive Status Lights 528A (III) & 527A (IV) P (Annunciators, Now Alarm)

From LC-539A (I) 538A (III) & 537A (IV)

B Bypass Status Lights 2/3 From LC-549A (I) A Actuation Signal Lights 548A (III) & 547A (IV)

T C Computer (PPC) Input PK1211 Turbine First-Out T Annunciator Alarm Main Annunciator Alarm P-14 Protection A Permissive B-6-2a Rev 22

RO QUESTION 22 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 2 _____

K/A # APE 036 AK3.02 Importance 2.9 3.6 Proposed Question:

The crew secures refueling operation and closes Fuel Transfer Gate valve SFS-50 due to a high radiation alarm in the Spent Fuel Building.

With the gate still closed, and the PIT position selected, the operator on the reactor side accidentally presses the conveyor start pushbutton on Fuel Transfer Control Panel 1-1.

Which of the following is the expected conveyor system response?

A. The transfer cart moves until it contacts SFS-50, it will then stop due to overload or winch over temperature interlock.

B. The transfer cart moves until it contacts SFS-50, it will then stop due to cable tension interlock.

C. The transfer cart will start but almost immediately stop due to cable tension interlock.

D. The transfer cart will not move due to the gate valve open interlock.

Proposed Answer:

D. The transfer cart will not move due to the gate valve open interlock.

Explanation: Interlock with SFS-50 prevents transfer cart movement until the valve is open.

A, B and C all involve actual conveyor system interlocks which could actuate if the system were in operation.

Technical Reference(s): B8, Fuel Handling System, pages 2.2-13, 14 and 15 Proposed references to be provided to applicants during examination: None Learning Objective: 6586 - Analyze the interlocks associated with refueling equipment controls.

Question Source:

ro tier 1 group 2_22.doc

New X Question History: Last NRC Exam __N/A_____

Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis 10 CFR Part 55 Content: 55.41 41.13 55.43 _____

Comments:

K/A: APE 036 AK3.02 - Knowledge of the reasons for the following responses as they apply to Fuel Handling Incidents: Interlocks associated with fuel handling equipment ro tier 1 group 2_22.doc

Conveyor and Transfer Cart, Continued Interlocks Several interlocks exist that must be satisfied to allow conveyor motion. The Obj 13, 18, 24 table below summarizes the interlocks on the conveyor operation.

Interlock Is active when.. Action (GL is GEMCO switch)

Conveyor at Reactor conveyor is not at the

Stops the conveyor when reactor end of the tracks it reaches its destination.

Conveyor at Pit conveyor is not at the pit

Controls the speed of the end of the tracks conveyor to a:

Slow speed of 7 fpm as it approaches one foot from the ends Fast speed of 20 fpm for normal travel Pit side frame pit side frame is down Prevents conveyor down

operation unless frames are (GL-5, pit) down.

Reactor side frame reactor side frame is down

down (GL-3, reactor)

Cable tension either reactor or pit cable Stops conveyor operation LS-2, LS-4 is under an overload to prevent component condition damage.

Winch over temp winch motor is hot Under voltage an undervoltage condition exists Motor overload motor thermal overloads have tripped Gate valve open, fuel transfer gate valve is Prevents conveyor from POS-162 not full open striking the valve disk.

This interlock may be bypassed at the control panel.

Continued on next page

Conveyor and Transfer Cart, Continued Logic The operating logic of the Containment conveyor is described in the Obj 9, 16, 24 following table.

At the Fuel Transfer Control Panel 1-1 (Reactor Side):

If the .... switch is ... Then the Conveyor will ....

CONVEYOR depressed start if all interlocks are satisfied.

START CONVEYOR stop.

STOP REACTOR in REACTOR go to the reactor when the START position button is pushed.

PIT in PIT position go to the pit when the START button is pushed.

At the Fuel Transfer Control Panel 1-2 (Pit Side):

If the .... switch is ... Then the Conveyor will ....

CONVEYER ON start if all interlocks are satisfied.

CONTROL OFF stop.

Continued on next page

Conveyor and Transfer Cart, Continued Logic diagram The diagram below shows the control logic of the conveyor controls.

Obj 17 Controls Interlocks Actions Reactor To Reactor Pit Position Fast/Slow Limit Switches Release Brake Start PB To Pit Fast/Slow Stop PB On Off Cable Overload Pit and Reactor Frames Not Down Norm Bypass Gate Valve Not Open Winch

- Temp Hi

- Voltage Low

- Overload FHS-42 Continued on next page

RO QUESTION 23 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 2 _____

K/A # APE 060 AA1.02 Importance 2.9 3.1 Proposed Question:

Several Auxiliary Building radiation alarms are received. It is confirmed that a Waste Gas Decay Tank has ruptured, and is depressurizing into the Auxiliary Building.

What action must be taken to prevent the offsite release of radioactive particulate and iodine?

A. Push "Status Reset" at POV1 and POV2, and reset the "S" signal.

B. Locally close dampers that isolate the Waste Gas Decay Tank rooms.

C. Stop all Aux Bldg supply and exhaust fans, and energize charcoal heaters.

D. Select "S" signal test, secure one Aux Bldg Ventilation train, and energize charcoal heaters.

Proposed Answer:

D. Select "S" signal test, secure one Aux Bldg Ventilation train, and energize charcoal heaters.

Explanation:

A incorrect, this is done to return the Aux Bldg ventilation to BLDG and SFGDS mode.

B incorrect, this would not prevent off site release.

C incorrect, this will not completely isolate the release D correct, per OP AP-14 step 3 Technical Reference(s):

OP AP-14, Tank Ruptures step 3A LPA-14, Tank Ruptures, page 7 of 24 Proposed references to be provided to applicants during examination: None Learning Objective: 3477 - Describe the major actions of OP AP-14, Tank Ruptures.

5512 State the alignments for Auxiliary Building Ventilation system ro tier 1 group 2_23.doc

Question Source: Bank # DCPP P-0764 Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 41.13 55.43 _____

Comments:

K/A: APE 060 AA1.02 - Ability to operate and / or monitor the following as they apply to the Accidental Gaseous Radwaste: Ventilation System ro tier 1 group 2_23.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP AP-14 DIABLO CANYON POWER PLANT REVISION 10 PAGE 3 OF 9 TITLE: Tank Ruptures UNITS 1 AND 2 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION: With Aux Bldg ventilation in SFGDS Only Mode, airborne activity will increase. Respiratory protection may be required.

3. SAMPLE Aux Bldg for Airborne Activity:

When radiation protection confirms airborne activity is LESS THAN 10 FR 20 Appendix B limits, THEN return Aux Bldg ventilation to BLDG and SFGDS Mode:

a. Restore control power to Aux Bldg Exhaust Fan at RCV1/RCV2

b. Push "Status Reset" at POV1 and POV2

c. Reset "S" Signal at POV1 and POV2 CAUTION: The SWP for recovery activities must incorporate clothing and respiratory protection requirements from EP RB-2.

4. IMPLEMENT Applicable Radiological Emergency Procedures:

RB-2 EMERGENCY EXPOSURE GUIDES

CP M-13 PERSONNEL INJURY OR ILLNESS WITH RADIOACTIVE CONTAMINATION OR PERSONNEL OVEREXPOSURE

R-3 RELEASE OF RADIOACTIVE LIQUIDS 00362410.DOC 02 1209.0727

Minimize Dose Steps, Continued Steps 1-4 The major actions of steps 1 through 4 are shown in the table below.

Obj 6 Step Action Bases/Discussion 1 Alert Plant Personnel Provide an initial off-site Commence EP R-2 [CNH41]dose assessment, to determine protective action guidelines and emergency classification 2 Evacuate Personnel Minimize dose 3 Place Aux Bldg Ventilation in the Minimize release of radioactive Safeguards Only Mode, iodine to the environment discharging through the Charcoal

S Signal Test at POV1 and 2 filters. puts the system in Bldg and Safeguards mode and puts the charcoal filter in service

Securing a fan at RCV1 or 2 forces the system in Safeguards Only mode

Safeguards only mode does not provide ventilation to the general Aux Bldg areas 4 Sample Aux Bldg for airborne Determine respiratory protection activity. requirements.

When

The CAUTION serves as a Radiation Protection confirms that reminder when personnel are airborne activity is < 10FR20, subsequently sent to identify appendix B limits, and isolate the ruptured then tank[CNH42]

Return Aux Bldg Ventilation to a normal Building and Safeguards Maximizing ventilation will lineup. reduce airborne levels within the Aux Building.

LPA-14 Page 7 of 24 Rev. 9

RO QUESTION 24 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 Group # 2 K/A # APE 061 AA2.04 Importance 3.1 3.5 Proposed Question:

PK11-10, FHB High Radiation RE-58 and 59, alarms in the Unit 1 Control Room.

If the alarming monitor is functioning properly, in addition to the GREEN power available light, what should be the indication on PAM2?

A. Red and Amber lights and audible alarm.

B. Red and Amber lights, only.

C. Red light, only.

D. Red or Amber light lit, either will cause the alarm.

Proposed Answer:

B. Red and Amber lights, only.

Explanation:

A incorrect, the audible alarm is at the local panel.

B correct, as reading exceeds the trip 1 setpoint, the amber light comes on and at trip 2, the red light comes on and the alarm actuates.

C incorrect, amber light remains on.

D incorrect, only trip 2 gives the alarm.

Technical Reference(s): G4A, Radiation Monitoring, pages 2.2-22 and 3-11 Proposed references to be provided to applicants during examination: None Learning Objective: 8504 - Identify the location of Radiation Monitoring system alarm indications in Control Room.

ro tier 1 group 2_24 rev1.doc

Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.11 55.43 Comments:

K/A: APE 061 AA2.04 - Ability to determine and interpret the following as they apply to the Area Radiation Monitoring (ARM) System Alarms: Whether an alarm channel is functioning properly ro tier 1 group 2_24 rev1.doc

Radiation Monitoring RM-58, 59 Fuel Handling Building Monitors, Continued Indications The following indications are available on RM-58 and 59 control modules.

Obj 8, 9, 10, 17 Control Module Lamp Meaning Normal Indication Status RED The measured radiation has exceed the high setpoint. OFF AMBER The measured radiation has exceed the alert setpoint.

GREEN Indicates that the Operate Selector switch is ON in the OPERATE position.

Local Indication Panel Lamp Meaning Normal Indication status RED Measured radiation > high setpoint OFF AMBER Measured radiation > alert setpoint GREEN The following conditions are met: ON

power is available, and

meter reading is greater than 0.1 mR/hr.

Indication Can be read on ... Normal reading RM-58 Control Module meter 0.2 mR/hr Local Indication Panel meter RM-59 Data Logger PPC 0.1 mR/hr Alarms The following alarms exist for RM-58 and 59.

Obj 18 Parameter Source Location FHB High Radiation

RM-58

RM-59 Rad Monitor System failure/CVI

74HRP2G Control Room Bypass

74HRP2H G4A.DOC 2.3 - 22 REV. 6

System Operations Abnormal Operations, Continued Alarm input The annunciators associated with the Rad Monitoring System are listed Obj 36, 37 below.

Control Room Location Title Parameter Setpoint PK11-09 RE-11 AND RE-12 Low flow on: < normal LOW FLOW

RE-11 PK11-10 FHB HIGH High radiation alarm on either:

RADIATION RE-

RE-58 58 AND 59

RE-59 PK11-13 POST ACDNT Either of the following on SMPL ROOM RAD RM-48:

MON

High radiation alarm

Failure alarm PK11-17 S.G. BLOWDOWN High radiation alarm on either:

HI RAD

RE-19

RE-23 PK11-18 MAIN STM LINE High radiation alarm on any of See the I&C HIGH RAD the following: RMS Data

RE-71 Book in the

RE-72 Control

RE-73 Room for

RE-74 setpoints PK11-19 CONTMT High alarm on either of the RADIATION following:

(HI LVL RAD

RE-30 MON SYSTEM)

RE-31 PK11-21 HIGH RADIATION High radiation alarm on any of the following:

RE-01 RE-12 RE-02 RE-13 RE-03 RE-17A RE-04 RE-17B RE-06 RE-18 RE-10 RE-22 RE-11 RE-44A*

RE-44B*

RE-07 These are digital radiation monitors and are covered in STG G-4b.

Continued on next page G4A.DOC 3 - 11 REV. 6

RO QUESTION 25 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 2 _____

K/A # EPE E01 EK3.3 Importance 3.5 3.3 Proposed Question:

PLANT CONDITIONS:

The crew is performing the actions of E-0, Reactor Trip or Safety Injection following SI actuation from full power.

All systems operated as designed.

Tave is being maintained by condenser steam dumps.

No operator actions have been taken, except to throttle AFW for temperature control

At the diagnosis steps in E-0, the crew fails to positively identify the cause of the SI but suspect a tube rupture has occurred.

The SFM directs the BOPCO to open the Blowdown Inside Containment isolations (FCV-760, 761, 762, 763).

The BOPCO reports that when the OPEN/AUTO/CLOSE switch for each isolation valve was taken to OPEN, the valves did not move.

Which of the following explains why the valves will not open?

A. Instrument air to containment is not restored.

B. High Radiation on RE-19 or RE-23.

C. Main Steam isolation.

D. SI not reset.

Proposed Answer:

A. Instrument air to containment is not restored.

ro tier 1 group 2_25 rev1.doc

Explanation: The IC valves close on Main Steam Isolation or loss of air. Because MSI has not occurred and the valves are closed, a loss of air must have occurred. Restoring IA to containment has not been done, so the valves will not open.

B incorrect, this isolates for the OC isolation or sample valves.

C incorrect, temperature control is with the condenser steam dumps, so MSI has not occurred.

D incorrect, resetting SI has no effect on operation of the valves Technical Reference(s):

D-2, Steam Generator Blowdown System.

Proposed references to be provided to applicants during examination: None.

Learning Objective: 8755 State Steam Generator Blowdown system automatic isolation signals Question Source: Bank #

Modified Bank # S-71159 New ______

Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.7 55.43 _____

Comments:

K/A: EPE E01 EK3.3 - Knowledge of the reasons for the following responses as they apply to the (Reactor Trip or Safety Injection/Rediagnosis) - Manipulation of controls required to obtain desired operating results during abnormal, and emergency situations.

ro tier 1 group 2_25 rev1.doc

1 S-71159 Points: 1.00 Multiple Choice Unit 2 has experienced a Hi Rad signal on RE-23 and a Phase A Isolation Signal.

The Shift Chem Tech wishes to sample the Steam Generators.

The Control Operator has all the valves open except the IC Blowdown Isolation Valves.

What is the most likely problem?

A. Air to containment NOT Open B. Phase A NOT RESET C. RE-19/23 CUTOUT Switch is in the CUTOUT position.

D. AFW AUTO start signal NOT RESET.

Answer: A ASSOCIATED INFORMATION:

Associated objective(s):

8755 State Steam Generator Blowdown system automatic isolation signals Reference Id: S-71159 Must appear: No Status: Active User Text: 8724.13049E User Number 1: 3.10 User Number 2: 3.40 Difficulty: 3.00 Time to complete: 2 Topic: D2 SGBD Islation Signal Cross

Reference:

STGD2 Comment: This question was developed for L031, System Phase, rlf1,10/17/03

Steam Generator Blowdown System Containment Isolation Valves, Continued Logic The logic for Containment Isolation Valve operation is described below.

Obj 9,10,11 For FCV-760, 761, 762, and 763 IF the OPEN/CLOSE THEN the valve will...

switch is in...

Neutral after OPEN CLOSE on:

(spring return from OPEN)

Main Steam Isolation.

loss of air.

OPEN OPEN if closed...

OPEN will override close signal as long as switch is held in OPEN and air is available.

CLOSE CLOSE.

For FCV-151, 154, 157, and 160 IF the OPEN/AUTO/CLOSE THEN the valve will...

switch is in...

CLOSE when it receives any of the AUTO following:

(spring return from OPEN)

Containment Isolation Signal Phase A.

y AFW pump auto start signal.

SGBD HIGH radiation signal from either RE-19 or RE-23.

y AMSAC (Actually causes AFW pump auto start which in turn causes isolation.)

loss of power to RE-19 or RE-23.

OPEN OPEN if closed.

overrides the close signal as long as switch is held in OPEN CLOSE CLOSE Continued on next page D2.DOC 2-5 REV. 12

RO QUESTION 26 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 2 _____

K/A # E03 G2.1.23 Importance 3.9 4.0 Proposed Question:

PLANT CONDITIONS:

A LOCA and loss of offsite power has occurred on Unit 1.

The crew has entered EOP E-1.2, Post-LOCA Cooldown and Depressurization.

All AFW pumps are running

Steam generator narrow range levels:

o 1-1 = 22%

o 1-2 = 18%

o 1-3 = 20%

o 1-4 = 6%

The crew is checking if the TDAFW pump is required for heat removal.

Which of the following actions should be taken with the TDAFW pump?

A. Leave the TDAFW pump running, it is needed for heat removal.

B. Shutdown the TDAFW pump by momentarily placing the control switch for FCV-95 in CLOSE.

C. Shutdown the TDAFW pump by placing the control switches for FCV-37 and FCV-38 in CLOSE.

D. Dispatch an operator to open the breaker for FCV-95.

Proposed Answer:

C. Shutdown the TDAFW pump by placing the control switches for FCV-37 and FCV-38 in CLOSE.

ro tier 1 group 2_26 rev1.doc

Explanation:

A incorrect, 16% necessary in 3 of 4 steam generators (incorporates adverse containment values)

B incorrect. Due to the loss of offsite power, closing FCV-95 will not shutdown the pump. When the switch is released, FCV-95 will reopen. This is how it would normally be shutdown.

C correct, to shutdown the pump, both steam supplies must be closed.

D incorrect, opening the breaker removes power from the solenoid but the valve would also have to be manually closed.

Technical Reference(s):

E-1.2, step 8.

D-1, Auxiliary Feedwater System, page 2-18, 2-23, 2-28 Proposed references to be provided to applicants during examination: none Learning Objective:

3891 - Explain the operation of turbine-driven AFW pump.

Question Source: New Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.8 55.43 _____

Comments:

K/A: E03 G2.1.23 - LOCA Cooldown and Depressurization, Ability to perform specific system and integrated plant procedures during all modes of plant operation.

ro tier 1 group 2_26 rev1.doc

Auxiliary Feedwater System Turbine Driven AFW Pump 1, Continued Flowpath The following is a diagram of the steam supply and exhaust flowpath for the diagram TDAFW pump:

Obj 7, 13 Inside Outside Containment Containment Main Steam Lead 3 S/G 4 3 3 FCV-38 PI TTV 84 FCV-95 FCV-152 1

2 FCV-37 T T T T T106 T105 T104 T118 Main Steam Lead 2 S/G ASDR TO MAIN COND 2

TO SUMP SCUPPER TO PLANT VENT FI 208 RECIRC LINE FE HEAT EXCH. S.O.

INSIDE BEARING HOUSING To 5 Atm 6

FI FCV-15 o RO 8 TO ASDR T

CST FI RO FI 100# GOV 9 TO S/Gs 1-1 S.O.

S.O. S.O. PI 426 7 PS PT 420 432 RAW WATER PI RESERVOIR FCV-436 420 AFW-10 Obj 38 Stage Description 1 Steam can be supplied by #2 and/or #3 S/G(s) through motor operated isolation valves FCV-37 and 38.

2

Steam traps on the supply lines remove moisture from the system.

Traps 104, 105, and 106 must be operable to declare the pump operable.

3 The pump is started and stopped with steam supply flow control valve FCV-95.

Continued on next page D1.DOC 2 - 18 REV. 12

Major Components Turbine Steam Supply Control Valves (FCV-37/38), Continued Controls FCV-37 and 38 have control capability from the

Control Room on VB-3 and Obj 9, 10, 25

local handwheel.

In the Control Room:

Control Operation CLOSE/STOP/OPEN 3 position, maintained Indications The following indications are available for FCV-37 and 38:

Obj 9, 10, 11, 23 FCV-37 and 38 control switches Indicating Lights Meaning Normal Status Red Valve is full OPEN. ON Green Valve is full CLOSED. OFF NOTE: If BOTH Indicating lights are LIT simultaneously, then the valve is in an intermediate position.

Alarms The following alarms exist for FCV-37 and 38:

Obj 12, 23 Parameter Source Location CLOSED valve position. POS 425, 433 Control Room D1.DOC 2 - 23 REV. 12

Auxiliary Feedwater System TDAFW Pump Steam Supply Valve FCV-95 Purpose The purpose of FCV-95 is to provide isolation of the steam supply to the Obj 13 TDAFW pump and maintain it in a standby condition.

Location FCV-95 is located in the 115 penetration area.

Obj 8 See figure on page 2-22 Power supplies FCV-95 is powered from DC Pnl 12.

Description FCV-95 is a DC powered MOV.

It is designed to operate during a loss of all AC.

Controls

FCV-95 has control capability from the Control Room on VB-3 Obj 10, 25 HSD Pnl local handwheel

FCV-95 transfer relay has control capability from 480V Bus G.

In the Control Room:

Control for valve: Operation CLOSE/OPEN 3 position, spring return to neutral.

At the HSD Pnl:

Control for valve: Operation CLOSE/OPEN 3 position, spring return to neutral.

CONT RM/LOCAL 2 position, maintained.

At 480 V Bus G:

Control for transfer Operation relay[TG7]:

CUTIN/CUTOUT 2 position, maintained.

TRIP/RESET 2 position, maintained.

Continued on next page D1.DOC 2 - 26 REV. 12

Auxiliary Feedwater System TDAFW Pump Steam Supply Valve FCV-95, Continued Logic (continued)

When controlling FCV-95 from the HSD Pnl,

all automatic trips continue to function normally.

all FCV-95 lights in the Control Room are extinguished.

Logic Diagram The following logic diagram assumes control from the Control Room:

Close S/G Blowdown and Sample O.C.

Isolation Valves Low-Low S/G Level 2/3 Detectors 2/4 S/G's

Open 12 kV Bus U/V 1/2 Relays, 2/2 Buses FCV-95 Close AMSAC Control Room Open Close

S/G Low Level Trip Time Delay May Apply Assume Control Transfer Relay refer to OIM B-6-4b at 480v Bus 1G in reset position AFW-06 Continued on next page D1.DOC 2 - 28 REV. 12

Post LOCA Cooldown and Depressurization U1 EOP E-1.2 REV. 16 PAGE 5 OF 8 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED

8. CHECK Intact S/G Levels:

a. Check S/G NR Level - GREATER a. Maintain TOTAL feedflow GREATER THAN THAN 6% [16%] 435 GPM until S/G NR Level is GREATER THAN 6% [16%] in at least one S/G.

b. Control feedflow to maintain S/G NR b. IF NR Level in any intact S/G Level between 6% [16%] and 44% continues to increase in an uncontrolled manner, THEN GO TO EOP E-3, STEAM GENERATOR TUBE RUPTURE.

c. Check TD AFW Pp - REQUIRED FOR c. WHEN NR Level in at least 3 S/Gs is HEAT REMOVAL GREATER THAN 16 %

THEN Shutdown TD AFW Pp

d. Throttle TD AFW LCVs as necessary to maintain S/G Level.

03A 8S9IAMZ.DOC 0119.1201 Page 5 of 9

RO QUESTION 27 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 2 _____

K/A # W/E 16 G2.4.19 Importance 2.7 3.7 Proposed Question:

The crew is about to exit E-0 and enter E-1.

The following containment conditions exist:

Current containment pressure, 12 psig

Peak containment pressure, 25 psig

Containment Recirc Sump level (VB1), 94 feet

Containment Wide Range Sump level (Pam 1), 91 feet

Containment Radiation, RM-30 & 31, 8 R/hr Assuming all other status trees are GREEN, which of the following actions should be taken as the crew exits E-0?

A. Do not enter E-1, go to FR-Z.1.

B. Do not enter E-1, go to FR-Z.2.

C. Enter E-1 or go to FR-Z.2 at the discretion of the SFM.

D. Enter E-1 or go to FR-Z.3 at the discretion of the SFM.

Proposed Answer:

D. Enter E-1 or go to FR-Z.3 at the discretion of the SFM.

Explanation:

A incorrect, the criteria for entry to Z.1 has cleared.

B incorrect, the criteria for Z.2 is WR sump level, not recirc sump level C incorrect, Z.2 is a magenta path, which if satisfied would have to be entered.

D correct, Z.3 is a yellow path, the option to perform the procedure is up to the operator.

Technical Reference(s):

ro tier 1 group 2_27 rev1.doc

EOP F-0, page 2 and attachment 6 (F-0.5, Containment)

Proposed references to be provided to applicants during examination: F-0.5 Learning Objective: 3855 - Explain the priorities of the CSFSTs.

Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.10 55.43 _____

Comments: K/A: W/E 16 G2.4.19 - High Containment Radiation, Knowledge of EOP layout, symbols and icons.

ro tier 1 group 2_27 rev1.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER EOP F-0 DIABLO CANYON POWER PLANT REVISION 12 PAGE 2 OF 6 TITLE: CRITICAL SAFETY FUNCTION STATUS TREES UNIT 1 3.0 RULES OF USAGE 3.1 The Critical Safety Function Status Trees shall be monitored in the following order of priority:

3.1.1 Subcriticality using Status Tree F-0.1.

3.1.2 Core Cooling using Status Tree F-0.2.

3.1.3 Heat Sink using Status Tree F-0.3.

3.1.4 RCS Integrity using Status Tree F-0.4.

3.1.5 Containment using Status Tree F-0.5.

3.1.6 Inventory

Using Status Tree F-0.6.

3.2 IF an extreme challenge (RED PATH) is diagnosed, THEN the operator shall IMMEDIATELY stop procedure in effect and initiate functional restoration to restore the critical safety function under extreme challenge.

3.3 IF a severe challenge (MAGENTA PATH) is diagnosed, THEN the operator shall continue to check the status of all remaining critical safety functions. IF no extreme challenges exist, THEN the operator shall stop procedure in effect and initiate functional restoration to restore the highest priority critical safety function under severe challenge.

3.4 IF a not satisfied condition (YELLOW PATH) is diagnosed, THEN the operator shall continue to check the status of all remaining critical safety functions. IF no extreme or severe challenges exist, THEN it is the operator's option to continue optimal recovery procedures or to initiate functional restoration of the affected critical safety function challenge.

3.5 IF a satisfied condition (GREEN PATH) is diagnosed, THEN no challenge exists for the affected critical safety function. The operator shall continue to check the status of all remaining critical safety functions.

3.6 IF during function restoration to address a critical safety function challenge, a higher priority challenge is diagnosed, THEN the operator should terminate the ongoing response and initiate function restoration to address the higher priority critical safety function challenge.

3.7 IF an extreme challenge (RED PATH) or a severe challenge (MAGENTA PATH) is diagnosed AND subsequently clears before the status trees are being implemented or during the performance of a higher priority function restoration, THEN that challenge is to be considered satisfied.

5/21/98 DIABLO CANYON POWER PLANT PAGE 1 OF 1 EOP F-0 ATTACHMENT 6 F-0.5 CONTAINMENT GO TO FR-Z.1 GO TO CONTMT NO FR-Z.1 PRESS < 47 PSIG YES GO TO CONTMT NO FR-Z.2 PRESS < 22 PSIG YES CONTAINMENT WR NO SUMP LVL < 94 FT- EL LR-942A/943A (PAM 1) YES GO TO FR-Z.3 CONTMT RAD < 6 R/HR NO RM-30 OR RM-31 (SPDS OR PAM 2) YES CSF SAT

RO QUESTION 28 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 003 K4.07 Importance 3.2 3.4 Proposed Question:

During the response to a loss of all A/C power, a maximum rate S/G depressurization is performed to 240 PSIG.

What is the benefit of performing the secondary depressurization?

A. It reduces RCS pressure and seal delta P and thus RCS leakrate.

B. It minimizes thermal stress across the steam generator tube sheet.

C. It prevents the formation of a void in the upper head of the reactor vessel.

D. It ensures that sufficient heat transfer capability exists to remove heat from the RCS.

Proposed Answer:

A. It reduces RCS pressure and seal delta P and thus RCS leakrate.

Explanation:

A correct, the step in ECA-0.0 depressurizes the intact SGs, thereby reducing RCS temperature and pressure to reduce RCP seal leakage and minimize RCS inventory loss.

B incorrect, sufficient level is maintained in the S/Gs such that they are not challenged.

C incorrect, it is assumed a void may occur during the depressurization but the depressurization continues.

D incorrect, this is why level must be maintained in the S/Gs during the depressurization.

Technical Reference(s): Background ECA-0.0, Loss of All AC Power Proposed references to be provided to applicants during examination: none Learning Objective: 7920 Explain basis of emergency procedure step ro tier 2 group 1_28 rev1.doc

Question Source: Bank # B-0144 Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 41.3 55.43 _____

Comments:

K/A: 003 K4.07 - Knowledge of RCPS design feature(s) and/or interlock(s) which provide for the following: Minimizing RCS leakage (mechanical seals) ro tier 2 group 1_28 rev1.doc

1 B-0144 Points: 1.00 Multiple Choice During the response to a loss of all A/C power, a maximum rate S/G depressurization is performed to 240 PSIG.

How does this secondary depressurization minimize the RCS inventory loss?

A. It reduces RCS pressure and seal delta P and thus RCS leakrate.

B. It ensures that NO RCP seal failures will occur.

C. It will cause the RCP No. 1 seal to go from a film riding to face rubbing seal thus reducing RCS leakage.

D. It will cause the No. 1 seal to "uncock" and reseat properly.

Answer: A ASSOCIATED INFORMATION:

Associated objective(s):

7920 Explain basis of emergency procedure step Reference Id: B-0144 Must appear: No Status: Active User Text: 7920.130494 User Number 1: 3.00 User Number 2: 3.40 Difficulty: 3.00 Time to complete: 3 Topic: EP ECA-0.0, Minimize RCS inventory loss by secondary depres Cross

Reference:

ECA 0.0, STEP 17 Comment: 0000060501 REF: EP ECA-0.0, "Loss of All A/C" step #17 note, and BGD VALIDATION DATE: 2/6/916

STEP DESCRIPTION TABLE FOR ECA-0.0 Step 16 STEP: Depressurize Intact SGs To (O.08) PSIG PURPOSE: To depressurize the intact steam generators BASIS:

Step 16 depressurizes the intact SGs, thereby reducing RCS temperature and pressure to reduce RCP seal leakage and minimize RCS inventory loss. The advantages to performing this action, as well as restrictions that apply during the action, are detailed in Subsection 2.3.

During SG depressurization, SG level must be maintained above the top of the SG U-tubes in at least one SG. Maintaining the U-tubes covered in at least one SG will ensure that sufficient heat transfer capability exists to remove heat from the RCS via either natural circulation or reflux boiling after the RCS saturates. Step 16a requires that SG level be in the narrow range in at least one SG before SG depressurization is initiated in Step 16b. If level is not in the narrow range in at least one SG, RNO 16a instructs the operator to maintain maximum AFW flow until narrow range level is established in one SG. When narrow range level is established, SG depressurization can be started or continued via Step 16b.

Step 16b instructs the operator to reduce SG pressures by depressurizing the intact SGs.

Depressurization should be accomplished by opening the PORVs on the intact SGs to establish a maximum steam dump rate, consistent with plant specific constraints. The step is structured assuming that the operator can open and control SG PORVs from the control room. This structure assumes that the PORVs are air-operated and have dc control power and pneumatic power (i.e., either air reservoirs or nitrogen bottles) available. Some plants may not have the capability to open the SG PORVs from the control room. These plants should evaluate their capability to accomplish this step locally via PORV handwheels. Such an evaluation should consider accessibility and communications necessary to accomplish local PORV operation.

Once depressurization is initiated, maintenance of a specified rate is not critical. The depressurization rate should be sufficiently fast to expeditiously reduce SG pressures, but not so fast that SG pressures cannot be controlled. It is important that the depressurization not reduce SG pressures in an uncontrolled manner that undershoots the pressure limit, thus permitting potential introduction of nitrogen from the accumulators into the RCS.

During SG depressurization, AFW flow may have to be increased to maintain the required SG narrow range level. Control of AFW flow will have to be performed from the control room or locally depending on plant specific design. Full AFW flow should be established to any SG in which level drops out of the narrow range.

RO QUESTION 29 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 004 K2.01 Importance 2.9 3.1 Proposed Question:

A loss of offsite power has occurred. Emergency diesel generators 1-1, 1-2 and 1-3 are running, and supplying their respective 4 KV bus.

Diesel 1-1 trips.

Which of the following describes the effect on the Reactor Makeup System Boric Acid pumps?

A. Boric Acid pump 1-1 has lost power.

B. Boric Acid pump 1-2 has lost power.

C. Both Boric Acid pump 1-1 and 1-2 have lost power.

D. No effect, both boric acid pumps 1-1 and 1-2 still have power.

Proposed Answer:

D. No effect, both boric acid pumps 1-1 and 1-2 still have power.

Explanation:

Unit 1 Bus F, G, H - EDG 1-3, 1-2, 1-1 A incorrect, BA pump 1-1 powered from Bus F (EDG 1-3)

B incorrect, For Unit 1, EDG 1-2 supplies bus G. Bus G powers Boric Acid pump 1-2.

C incorrect, one pump per bus prevents this.

D correct, pump 1-1 is powered from bus F (EDG 1-3) and 1-2 is powered from bus G (EDG 1-2).

Technical Reference(s):

B1B - Reactor Makeup System, page 2.2-10 Proposed references to be provided to applicants during examination: none ro tier 2 group 1_29 rev1.doc

Learning Objective:

5681 - Explain the impact on boration flowpaths if a loss of 480V Bus G occurs.

Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.6 55.43 _____

Comments:

K/A: 004 K2.01 - Knowledge of bus power supplies to Boric Acid Makeup Pumps ro tier 2 group 1_29 rev1.doc

Reactor Makeup Control System Boric Acid Transfer Pumps Purpose The purpose of the boric acid transfer pumps is to:

Obj 5, 8

Direct flow to the boric acid tanks from the boric acid batching tank.

Direct flow from the boric acid tanks to the blender upon demand from the makeup system or to the charging pump suction for emergency boration.

Recirculate fluid in the boric acid tank to prevent stratification.

Location The pumps are located east of the filter gallery on the 100 elevation of the Obj 6 Auxiliary Building.

North Aux Building 100' Elevation Boric Acid Transfer Pumps Unit Unit 1 2 Grating Grating UP UP RMU-09 Power supplies The table below lists the power supplies to the pumps BAT Pump 480 VAC vital bus 1-1 F 1-2 G 2-1 F 2-2 G Continued on next page B1B.DOC 2.2 -10 REV. 11

RO QUESTION 30 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 004 A4.17 Importance 2.7 2.7 Proposed Question:

CVCS Cation Demin 1-1 is to be placed in service for pH control using OP B-1A:XIII, CVCS Demineralizers. The bed was last used 2 days ago.

Which of the following is verified to prevent a possible reactivity excursion?

A. Letdown temperature is normal.

B. Effluent samples of the demineralizer have been taken to verify effects on RCS chemistry.

C. No deborating demineralizer is in service.

D. Automatic makeup to the VCT is in service at the current boron concentration.

Proposed Answer:

C. No deborating demineralizer is in service.

Explanation: per OP B-1A:XIII, attachment 9.3 Place CVCS Cation Demin 1-1 in Service for RCS Lithium Removal (pH control)

A incorrect, abnormal letdown temperature can cause a reactivity excursion if flow is through a deborating demineralizer.

B incorrect, this applies to deborating demins.

C correct, Caution: Placing Cation demin 1-1 in service while the Deborating demin is in service could result in a reactivity excursion. Switch in normal and bypass light lit indicates no deborating demin in service.

D incorrect, this is a caution but not to prevent a reactivity excursion, this is to ensure makeup to the VCT available if a rinse is performed and letdown is diverted.

Technical Reference(s): OP B-1A:XIII Proposed references to be provided to applicants during examination: None ro tier 2 group 1_30.doc

Learning Objective: 76912 - Explain the precautions taken in the control room when placing CVCS demineralizers in service.

Question Source: Bank #

Modified Bank # _______

New X Question History: Last NRC Exam ____________

Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 41.6 55.43 _____

Comments: K/A: 004 A4.17 - Ability to manually operate and/or monitor in the control room: Deborating demineralizer ro tier 2 group 1_30.doc

08/19/04 Page 1 of 2 DIABLO CANYON POWER PLANT TITLE:

OP B-1A:XIII ATTACHMENT 9.3 1

Place Cation Demin 1-1 In Service for RCS Lithium Removal (pH Control)

Duration Cation Demin 1-1 is to be in service per chemistry guidance: ________________

CAUTION: Placing Cation Demin 1-1 in service while the Deborating demin is in service could result in a reactivity excursion. (Ref AR A0581707)

SFM authorizes the use of this procedure attachment: SFM Signature: ________________ DATE: ________

1. Verify that neither Deborating demin is currently in service.

2. Check if Cation Demin 1-1, which is to be placed in service, has been in service at least once in the previous seven (7) days by reviewing the date and time on the Abnormal Status Board.

NOTE: If a date is not written on the Abnormal Status Board and cannot be verified by some other means (i.e., a log entry), it must be assumed that the Cation Demin has NOT been used within the last seven (7) days, and the rinse to the LHUT aligned for RCS letdown must be performed as specified below.

CAUTION: PRIOR to diverting letdown to an LHUT, ensure automatic makeup to the VCT is in service.

3. Notify the control operator and shift chemistry technician that Cation Demin 1-1 is now being placed in-service.

4. Align the demin as follows:

a. If Cation Demin 1-1 has NOT been in-service within the last seven (7) days, align for a demin rinse to an LHUT as follows:

1) Verify that automatic makeup to the VCT is in service.

2) Notify the control operator to select "DIVERT" on CVCS-1-LCV-112A to align demin effluent to an LHUT.

b. Verify open CVCS-1-8535, Cation Demin 1-1 Inlet.

c. Verify open CVCS-1-8516, 1-1 Cation Demin Inlet.

d. Open CVCS-1-8518, 1-1 Cation Demin Outlet.

e. Close CVCS-1-8514, 1-1 Cation Demin Bypass.

f. If rinsing demin to an LHUT, select "AUTO" on CVCS-1-LCV-112A after rinsing for a minimum of 10 minutes (based on 75 gpm letdown).

00969421.DOC 02 1115.0746

08/19/04 Page 2 of 2 OP B-1A:XIII (UNIT 1)

ATTACHMENT 9.3 TITLE: Place Cation Demin 1-1 In Service for RCS Lithium Removal (pH Control)

5. Monitor the in-service RCS Letdown Filter D/P while Cation Demin 1-1 is in service.

6. Record date/time Cation Demin 1-1 placed in-service: __________/_________

7. When the required length of time has elapsed, perform the following:

a. Open CVCS-1-8514, Cation Demin 1-1 Bypass.

b. Close CVCS-1-8518, 1-1 Cation Demin Outlet.

8. Record date/time Cation Demin 1-1 removed from service: __________/_________

9. Notify the control operator and shift chemistry technician that Cation Demin 1-1 has been removed from service.

10. Update the CO's Abnormal Status Board to reflect the last in-service date/time of Cation Demin 1-1.

11. Return completed attachment to the chemistry foreman.

00969421.DOC 02 1115.0746

RO QUESTION 31 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 005 K6.03 Importance 2.5 2.6 Proposed Question:

10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months ago a design basis LOCA occurred on Unit 1. All equipment is running as designed and aligned per the emergency procedures.

CCW Cooling is lost to RHR heat exchanger 1-1.

As a result cooling is lost to RHR flow going to which of the following?

A. The suction of the safety injection pumps and hot legs 1 and 2.

B. The suction of the safety injection pumps and cold legs 1 and 2.

C. The suction of the charging pumps and hot legs 1 and 2.

D. The suction of the charging pumps and cold legs 1 and 2.

Proposed Answer:

D. The suction of the charging pumps and cold legs 1 and 2.

Explanation:

A incorrect, hot leg recirc is not established until 10.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months and SI pumps are supplied by HX 1-2.

B incorrect, SI pumps are supplied by HX 1-2 C incorrect, the unit is still in cold leg recirc D correct, the charging pumps are supplied by HX 1-1 and RHR HX 1-1 cools water being injected into cold legs 1 and 2.

Technical Reference(s):

E-1, Loss of Reactor or Secondary Coolant, step 20 E-1.4, Transfer to Hot Leg Recirculation, steps 1 and 2 B2, Residual Heat Removal, page 3-18 Proposed references to be provided to applicants during examination: none ro tier 2 group 1_31 rev1.doc

Learning Objective: 7012 - Explain the operation of RHR system valves.

Question Source:

New Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.3 55.43 _____

Comments:

K/A: 005 K6.03 - Knowledge of the effect of a loss or malfunction of the following will have on the RHRS: RHR heat exchanger ro tier 2 group 1_31 rev1.doc

Residual Heat Removal System Emergency Operations, Continued Cold Leg When the RWST level reaches [33%], the RHR pumps will trip. At this Recirculation point, the RHR system is realigned to take a suction from the Containment Alignment sump and discharge to:

Obj 19

RCS cold legs

Charging pump suction

SI Pump suction

Containment Spray headers The diagram below shows the valve alignment.

Refueling To Charging Water Pump Suction Storage 8804A Tank Loop 1&2 Hot Legs Spray 8703 9003A FCV-641A Loop 1 RHR HX FIC 8700A 8809A HCV-638 8734A 8726A 1 8980 Loop 2 CVCS HCV-133 Residual Heat Cold Legs HCV-670 Removal Pumps Loop 3 8734B 8726B 2

8809B HCV-637 RHR FIC 8700B Loop 4 9003B HX Spray Containment Recirc Sump 8804B FCV-641B 8982B SI Pump 2 Suction Loop 4 8982A Hot Leg 8702 8701 RHR-09 Continued on next page B2.DOC 3 - 17 REV. 13

Residual Heat Removal System Emergency Operations, Continued Hot Leg Reason for Hot Leg Recirculation:

Recirculation

Cold leg recirculation is performed for 10-1/2 hours.

Alignment ECCS fluid enters the bottom of the reactor core, Obj 19 flows upward over the core, absorbs decay and sensible heat, leaves the reactor vessel.

Initially, the ECCS fluid may be boiling, leaving boric acid behind as the vapor is swept away.

If the boric acid is permitted to build up on the fuel rods, increased fuel temperatures could result.

Also, since boric acid solubility is a function of fluid temperature, boric acid may start to precipitate near the bottom of the core (the coldest portion of the core).

Excessive precipitation could result in blocked flow passages, which could reduce the emergency core cooling flow to the core.

When the ECCS is shifted to hot leg recirculation; the fluid enters the top of the reactor core, flows downward over the core, absorbs decay and sensible heat, washes plated-out boric acid off the fuel rods, washes the concentrated boric acid out of the lower part of the core, prevents flow restriction and heat transfer problems.

The diagram below shows the valve alignment.[GRH1]

Refueling To Charging Water Pump Suction Storage 8804A Tank Loop 1& 2 Spray Hot Legs 8703 9003A FCV-641A Loop 1 RHR HX FIC 8700A 8809A HCV-638 8734A 8726A 1 8980 Loop 2 8716A CVCS Residual Heat H C V -1 3 3 Cold Legs H C V -6 7 0 Removal Pumps Loop 3 8716B 8734B 8726B 2

8809B HCV-637 RHR FIC 8700B 9003B HX Loop 4 Spray Containment Recirc Sump 8804B FCV-641B 8982B SI Pump 2 Suction Loop 4 8982A Hot Leg 8702 8701 RHR-10 Continued on next page B2.DOC 3 - 17 REV. 13

PACIFIC GAS AND ELECTRIC COMPANY NUMBER EOP E-1 DIABLO CANYON POWER PLANT REVISION 19 PAGE 21 OF 30 TITLE: Loss of Reactor or Secondary Coolant UNIT 1 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

18. DETERMINE If Reactor Vessel Head Should Be Vented:

a. Consult TSC for venting approval a. GO TO Step 19.

b. REFER TO EOP FR-I.3, RESPONSE TO VOIDS IN REACTOR VESSEL

19. CHECK Containment Hydrogen Concentration:

(PAM 1)

a. Check H2 analyzer - IN a. Contact the Chemistry Dept to SERVICE (PAM 1) place the Hydrogen Monitoring System in service.

CAUTION: Operation of the Containment Hydrogen Recombiner with Containment Hydrogen Concentrations GREATER THAN 4.0% could result in ignition of the hydrogen.

b. Hydrogen concentration - LESS b. Consult Plant Engineering Staff THAN 3.5% (TSC) when manned for additional recovery actions with potential explosive H2 mixture in containment. GO TO Step 20.

c. Hydrogen concentration - LESS c. IMPLEMENT OP H-9, INSIDE THAN 0.5% CONTAINMENT H2 RECOMBINATION SYSTEM, to reduce Hydrogen Concentration.

20. At 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months After Event Initiation Prepare For Hot Leg Recirculation:

GO TO EOP E-1.4, TRANSFER TO HOT LEG RECIRCULATION

- END -

PACIFIC GAS AND ELECTRIC COMPANY NUMBER EOP E-1.4 DIABLO CANYON POWER PLANT REVISION 15 PAGE 2 OF 11 TITLE: TRANSFER TO HOT LEG RECIRCULATION UNIT 1 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE: It is important during this phase that two separate and redundant trains of recirculation outside containment are established unless an inoperable 4 KV vital bus prevents total separation.

1. PREPARE For Hot Leg Recirculation 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months After Event Initiation:

a. Check the following control a. Place the Valve Control Switches in switches in their required position: the required position.

o 8802A - CLOSED, SI to Hot ------------------------------

Legs 1 & 2 o 8835 - OPEN, SI Pp to Cold Leg o 8703 - CLOSED, RHR to Hot Legs 1 & 2 o 8802B - CLOSED, SI to Hot Legs 3 & 4

b. Close the following 480V breakers:

o 52-1F-48, 8802A o 52-1G-24, 8835 o 52-1G-56, 8703 o 52-1G-56R, 8703 o 52-1H-26, 8802B

PACIFIC GAS AND ELECTRIC COMPANY NUMBER EOP E-1.4 DIABLO CANYON POWER PLANT REVISION 15 PAGE 3 OF 11 TITLE: TRANSFER TO HOT LEG RECIRCULATION UNIT 1 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

2. At 10.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months ALIGN SI Pp 1 For Hot Leg Recirculation:

a. Verify both RHR Pps are running a. Manually Start any RHR Pp NOT running.

IF RHR Pp 1 is NOT Operable, THEN Close 8804A AND GO TO Step 2f.

IF RHR Pp 2 is NOT Operable, THEN Continue with Step 2b.

b. Verify 8804A, RHR Hx No. 1 to Chg and SI Pps Suction - OPEN

c. Cutin 8809A series contactor toggle switch

d. Close 8809A, RHR to Cold Legs 1 and 2

e. Verify Closed 9003A, RHR Pp 1 to Spray Hdr A - CLOSED

f. Verify SI Pp 1 - STOPPED

g. Close 8821A, SI Pp No. 1 Disch Crosstie Vlv

h. Open 8802A, SI to Hot Legs 1 and 2

i. Perform the following i. IF SI Pp 1 is NOT Operable, THEN GO TO Step 2k (Next

1) Start SI Pp 1 Page).

2) Verify operating RHR Pp ------------------------------

motor current LESS THAN 57 AMPS THIS STEP CONTINUED ON NEXT PAGE

RO QUESTION 32 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 006 K1.02 Importance 4.3 4.6 Proposed Question:

Some time after an accident, containment pressure indicates the following on VB1:

PI-934 = 20 psig

PI-935 = 23 psig

PI-936 = 20 psig

PI-937 = 24 psig Containment spray does not actuate.

Which of the following would explain why spray did not actuate?

A. Safety Injection signal has been reset.

B. RWST is below the low level alarm setpoint.

C. Containment Isolation Phase A has failed to actuate.

D. Not enough channels of containment pressure are at/above the nominal setpoint.

Proposed Answer:

A. Safety Injection signal has been reset.

Explanation:

A correct, an SI signal must be present B incorrect, RWST level would not inter with actuation.

C incorrect, no interface.

D incorrect, setpoint is 2/4 at 22 psig Technical Reference(s):

Drawings 4014233, SSPS Functional Diagram and 498006 Containment Pressure STG I2, Containment Spray System, page 2-9 ro tier 2 group 1_32 rev1.doc

Proposed references to be provided to applicants during examination: None Learning Objective: 5422 Explain the consequences of SSPS failures on plant operation Question Source: Bank #

Modified Bank # P-49415 New ______

Question History: Last NRC Exam DCPP RO Exam 1995 Question Cognitive Level:

Memory or Fundamental Knowledge Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.7 55.43 _____

Comments: K/A: 006 K1.02 - Knowledge of the physical connections and/or cause effect relationships between the ECCS and the following: ESFAS ro tier 2 group 1_32 rev1.doc

1 P-49415 Points: 1.00 Multiple Choice An operator attempts to initiate containment spray manually by actuating the switches "Containment Isol Phase B/ Containment Spray Train A" and "Containment Isol Phase B/ Containment Spray Train B" on VB-1. The spray fails to actuate. WHICH ONE of the following is a possible cause of the failure of spray to initiate?

A. A Safety Injection signal was NOT present.

B. The two switches were operated simultaneously.

C. The Spray Additive Tank was below the low level alarm setpoint.

D. Containment Isolation Phase B failed to actuate.

Answer: A ASSOCIATED INFORMATION:

Associated objective(s):

5422 Explain the consequences of SSPS failures on plant operation Reference Id: P-49415 Must appear: No Status: Active User Text: 013K1.01 User Number 1: 4.20 User Number 2: 4.40 Difficulty: 3.00 Time to complete: 2 Topic: 23 ESFAS: Containment Spray Actuation requires SI signal Cross

Reference:

STG B6A,REV 8,PG 2.2-25 Comment: History: DCPP RO Exam 1995

Containment Spray Pumps, Continued Logic The logic associated with the Containment Spray Pump is described in the Obj 10, 27 following table.

If the VB-1 pump switch is in ... Then the pump breaker will ...

STOP Open NEUTRAL Close on:

Safety Injection Actuation AND either:

HI HI Containment Pressure signal OR

MANUAL spray actuation Open on:

Overcurrent

Bus transfer to diesel (load shed).

START Close Continued on next page I2.DOC 2-9 REV 9

RO QUESTION 33 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 006 K6.03 Importance 3.6 3.9 Proposed Question:

Which of the following ECCS equipment out of service configurations would result in entry into Technical Specification 3.0.3?

A. Train A CCP and Train B RHR pump.

B. Train A SI pump and Train B SI pump.

C. Train A CCP and Train B SI pump.

D. Train A CCP and Train A SI pump.

Proposed Answer:

B. Train A SI pump and Train B SI pump.

Explanation:

A incorrect, still have 100% flow equivalent to a single train.

B correct, per 3.5.2 bases: Due to the redundancy of trains and the diversity of subsystems, the inoperability of one component in a train does not render the ECCS incapable of performing its function. Neither does the inoperability of two different components, each in a different train, necessarily result in a loss of function for the ECCS. The intent of this Condition is to maintain a combination of equipment such that 100% of the ECCS flow equivalent to a single OPERABLE ECCS train remains available. (i.e. minimum of one OPERABLE CCP, SI, and RHR pump and applicable flow paths capable of drawing from the RWST and injecting into the RCS cold legs).

This allows increased flexibility in plant operations under circumstances when components in opposite trains are inoperable.

With one or more component(s) inoperable such that 100% of the flow equivalent to a single OPERABLE ECCS train is not available, the facility is in a condition outside the accident analysis. Therefore, LCO 3.0.3 must be immediately entered.

C incorrect, still have 100% flow equivalent to a single train.

D correct, still have 100% flow equivalent to a single train.

Technical Reference(s): Tech Spec Bases 3.5.2 ro tier 2 group 1_33 rev1.doc

Proposed references to be provided to applicants during examination: Tech Spec 3.5.2 Learning Objective: 9694E - Discuss 3.5 Technical Specification bases Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.10 55.43 43.5 Comments:

Resampled KA due to inability to test original KA. No effective tie between Loss of annunciators and ECCS (006 G2.4.32)

K/A: 006 K6.03, ECCS - Knowledge of the effect of a loss or malfunction of the Safety Injection Pumps will have on the ECCS ro tier 2 group 1_33 rev1.doc

ECCS - Operating 3.5.2 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.2 ECCS - Operating LCO 3.5.2 Two ECCS trains shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

NOTE-------------------------------------------------------------

In MODE 3, both safety injection (SI) pump flow paths may be isolated by closing the isolation valve(s) for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to perform pressure isolation valve testing per SR 3.4.14.1.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more trains A.1 Restore train(s) to ---------NOTE-------

inoperable. OPERABLE status The Completion Time may be extended to AND 7 days for Unit 1 cycle At least 100% of the ECCS 12 for centrifugal flow equivalent to a single charging pump 1-1 OPERABLE ECCS train seal replacement available. -------------------------

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND B.2 Be in MODE 4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

ECCS - Operating 3.5.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.2.1 Verify the following valves are in the listed position 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months with power to the valve operator removed.

Number Position Function 8703 Closed RHR to RCS Hot Legs 8802A Closed Safety Injection to RCS Hot Legs 8802B Closed Safety Injection to RCS Hot Legs 8809A Open RHR to RCS Cold Legs 8809B Open RHR to RCS Cold Legs 8835 Open Safety Injection to RCS Cold Legs 8974A Open Safety Injection Pump Recirc.

to RWST 8974B Open Safety Injection Pump Recirc.

to RWST 8976 Open RWST to Safety Injection Pumps 8980 Open RWST to RHR Pumps 8982A Closed Containment Sump to RHR Pumps 8982B Closed Containment Sump to RHR Pumps 8992 Open Spray Additive Tank to Eductor 8701 Closed RHR Suction 8702 Closed RHR Suction SR 3.5.2.2 Verify each ECCS manual, power operated, and 31 days automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.5.2.3 Verify ECCS piping is full of water. 31 days (continued)

ECCS - Operating 3.5.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.5.2.4 Verify each ECCS pump's developed head at the test In accordance with flow point is greater than or equal to the required the Inservice developed head. Testing Program.

SR 3.5.2.5 Verify each ECCS automatic valve in the flow path 24 months that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

SR 3.5.2.6 Verify each ECCS pump starts automatically on an 24 months actual or simulated actuation signal.

SR 3.5.2.7 Verify, for each ECCS throttle valve listed below, 24 months each mechanical position stop is in the correct position.

Charging Injection Safety Injection Throttle Valves Throttle Valves 8810A 8822A 8810B 8822B 8810C 8822C 8810D 8822D SR 3.5.2.8 Verify, by visual inspection, each ECCS train 24 months containment recirculation sump suction inlet is not restricted by debris and the suction inlet trash racks and screens show no evidence of structural distress or abnormal corrosion.

Seal Injection Flow B 3.5.5 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

B 3.5.2 ECCS - Operating BASES APPLICABILITY requirements are addressed by LCO 3.9.5, "Residual Heat Removal (continued) (RHR) and Coolant CirculationHigh Water Level," and LCO 3.9.6, "Residual Heat Removal (RHR) and Coolant CirculationLow Water Level."

ACTIONS A.1 With one or more trains inoperable and at least 100% of the ECCS flow equivalent to a single OPERABLE ECCS train available (capable of injection into the RCS, if actuated), the inoperable components must be returned to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is based on an NRC reliability evaluation (Ref. 5) and is a reasonable time for repair of many ECCS components.

An ECCS train is inoperable if it is not capable of delivering design flow to the RCS. Individual components are inoperable if they are not capable of performing their safety function or supporting systems are not available.

The LCO requires the OPERABILITY of a number of independent subsystems. Due to the redundancy of trains and the diversity of subsystems, the inoperability of one component in a train does not render the ECCS incapable of performing its function. Neither does the inoperability of two different components, each in a different train, necessarily result in a loss of function for the ECCS. The intent of this Condition is to maintain a combination of equipment such that 100% of the ECCS flow equivalent to a single OPERABLE ECCS train remains available. (i.e. minimum of one OPERABLE CCP, SI, and RHR pump and applicable flow paths capable of drawing from the RWST and injecting into the RCS cold legs). This allows increased flexibility in plant operations under circumstances when components in opposite trains are inoperable.

The intent of this Condition, to maintain a combination of equipment such that 100% of the ECCS flow equivalent to a single OPERABLE ECCS train remains available, applies to both the injection mode and the recirculation mode.

An event accompanied by a loss of offsite power and the failure of an EDG can disable one ECCS train until power is restored. A reliability analysis (Ref. 5) has shown that the impact of having one full ECCS train inoperable is sufficiently small to justify continued operation for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

Reference 6 describes situations in which one component, such as an RHR cross-tie valve can disable both ECCS trains. With one or more component(s) inoperable such that 100% of the flow equivalent to a (continued)

RO QUESTION 34 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 007 A2.03 Importance 3.6 3.9 Proposed Question:

The plant is at full power. PRT parameters are all at normal steady state values.

The following events occur:

The turbine trips

The reactor fails to automatically trip but is manually tripped.

All other systems operate as expected.

The Emergency procedures have been performed

The plant is stable at no load Tave and NOP

It is noted that on the transient RCS pressure peaked at 2370 psig.

Containment parameters are normal

PK-05-25, PZR Relief Tank Press, Lvl and Temp is in alarm

PRT Temperature - 140ºF,

PRT Level - 85%

PRT Pressure - 12 psig Which of the following actions should be taken by the crew to address the current PRT conditions?

A. Reduce temperature by opening PRT primary water supply RCS-8030.

B. Restore level to normal by opening PRT primary water supply RCS-8030.

C. Investigate a possible failure of the N2 supply regulator.

D. Check closed PRT primary water supply RCS-8030 and drain the PRT to the RCDT.

Proposed Answer:

A. Reduce temperature by opening PRT primary water supply RCS-8030.

ro tier 2 group 1_34.doc

Explanation:

A correct, PRT temperature is high and is reduced by opening RCS-8030.

B incorrect, level is not low (56%)

C incorrect, this action is taken if temperature and level are normal.

D incorrect, this action is done if PRT level is high (89%)

Technical Reference(s): PK-05-25.

Proposed references to be provided to applicants during examination: PK05-25 Learning Objective: 4946, 93963 - State the normal readings of PRT system indications.

4946 - State the PRT parameters that produce alarms.

Question Source: Bank #

Modified Bank # _______

New X Question History: Last NRC Exam Question Cognitive Level:

Memory or Fundamental Knowledge Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.10 55.43 Comments:

K/A: 007 A2.03 - Ability to (a) predict the impacts of the following malfunctions or operations on the PRTS; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those malfunctions or operations:

Overpressurization of the PZR ro tier 2 group 1_34.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK05-25 NUCLEAR POWER GENERATION REVISION 13 DIABLO CANYON POWER PLANT PAGE 1 OF 4 ANNUNCIATOR RESPONSE UNIT TITLE: PZR RELIEF TANK PRESS, LVL, TEMP 101/31/03 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. LOGIC DIAGRAM LC 470C PC 472X ALARM LC 470B TC 471

2. ALARM INPUT DESCRIPTION DEVICE ALARM ANNUNCIATOR TYPEWRITER NUMBER INPUT PRINTOUT SETPOINT LC 470A 367 PZR Relief Tk Lvl Hi GT 89%

LC 470B 1394 PZR Relief Tk Lvl Lo LT 56%

TC 471 318 PZR Relief Tk Temp Hi GT 130°F PC 472X 545 PZR Relief Tk Press Hi and Vent Hdr Isol GT 10 Psig 25142513.DOC 16 0131.0833

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK05-25 DIABLO CANYON POWER PLANT REVISION 13 PAGE 2 OF 4 TITLE: PZR RELIEF TANK PRESS, LVL, TEMP UNIT 1

3. PROBABLE CAUSE 3.1 Pressurizer power relief valves PCV-474, 455C, and/or 456 leaking through or lifting.

3.2 Pressurizer safety valves 8010A, 8010B, or 8010C leaking through or lifting.

3.3 Malfunction of pressurizer pressure control system.

3.4 Relief valve (from outside containment) lifting or leaking through:

3.4.1 Containment Spray Hdr. 9007A 260 psig 3.4.2 SIS Pump Suct. Hdr. 8858 220 psig 3.4.3 RHR Ht. Exch. 1-2 8856B 600 psig 3.4.4 Charging Pps Suct. Hdr. 8125 220 psig 3.4.5 SIS Pp. 1-2 Disch. Hdr. 8853B 1750 psig 3.4.6 SIS Pp. 1-1 Disch. Hdr. 8853A 1750 psig 3.4.7 SIS Pps. Disch. Hdr. 8851 1750 psig 3.4.8 RHR Ht. Exchg. 1-1 8856A 600 psig 3.4.9 Contmt. Spray Hdr 9007B 260 psig 3.5 Relief Valve (from inside containment) lifting or leaking through:

3.5.1 Seal Wtr. Ret. Hdr. 8121 150 psig 3.5.2 CVCS Letdown Hdr. 8117 600 psig 3.5.3 RHR Pp. Suct. Hdr. 8707 450 psig 3.5.4 RHR Pp. Inj. Loops 1 & 2 600 psig 3.5.5 RHR to RCS Hot Legs Hdr. 8708 600 psig 3.6 Valve Stem Leak-off:

3.6.1 8000 A, B, C, - PZR PORV ISO 3.6.2 PCV-455 A, B - PZR SPRAY 3.6.3 8701 and 8702 - LOOP 4 to RHR SYSTEM 3.6.4 8033 A, B, C, D - PZR SPRAY ISO VLVS 3.6.5 8076 - CVCS LTDN ISO VLV 3.6.6 8143 - EXCESS LTDN DIVERT VLV 3.6.7 HCV-123 - EXCESS LTDN FLOW CONTROL 25142513.DOC 16 0131.0833

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK05-25 DIABLO CANYON POWER PLANT REVISION 13 PAGE 3 OF 4 TITLE: PZR RELIEF TANK PRESS, LVL, TEMP UNIT 1 3.7 Pressurizer safety valve loop seal drain header valve(s) leaking through.

3.8 Primary water supply valve 8030 leaking through (high PRT level).

3.9 PRT to RCDT 8031 leaking through (low PRT level) or leak in PRT or level tap below the water line.

3.10 Malfunction of N2 supply PCV 8035.

4. AUTOMATIC ACTIONS 4.1 Vent header isolation at 10 psig (PCV-472 closed).

5. OPERATOR ACTIONS 5.1 Check annunciator typewriter printout and PPC computer alarm typewriter printout or CRT.

5.2 Check PRT level, pressure and temperature.

5.3 Monitor PORV Discharge HEADER temperature (TI-463) and Safety Valves Discharge Temperatures (TI-465, 467, or 469).

5.4 Check if PK05-08 is in alarm.

5.5 Monitor Sonic Flow Indicator, PDI-116A, 117A and 118A.

5.6 If source of discharge is a safety valve or PORV, refer to TS 3.4.11 or TS 3.4.13.

5.7 Refer to OP AP-1 Excessive RCS Leakage.

5.8 Determine and identify source of leakage. Refer to STP R-10 if PK05-08 is in alarm.

Make preparations for entering containment to check valve stem leak-off indicating light panel.

5.9 High Level Alarm on PRT 5.9.1 CLOSE or check closed RCS-8030.

CAUTION: Overfill of the RCDT (>100% indicated) will cause filling of the LI reference legs and will require draining by MS. Due to the PRT drain RCS-1-8031 being a slow acting valve, it must be closed early to prevent overfill of the RCDT.

5.9.2 Drain the PRT to the RCDT.

a. Run both RCDT pumps in manual to keep up with the drain rate.

b. Maintain communication with the Aux. Senior during draining.

c. Open RCS-1-8031 and drain to approximately 84% level, closing RCS-1-8031 as necessary when RCDT level reaches 60% on LI-188 to prevent overfilling.

25142513.DOC 16 0131.0833

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK05-25 DIABLO CANYON POWER PLANT REVISION 13 PAGE 4 OF 4 TITLE: PZR RELIEF TANK PRESS, LVL, TEMP UNIT 1 5.10 High Temp Alarm on PRT 5.10.1 OPEN PRT primary water supply RCS-8030.

5.10.2 Reduce PRT temperature to 120°F THEN CLOSE RCS-8030.

CAUTION: Overfill of the RCDT (>100% indicated) will cause filling of the LI reference legs and will require draining by MS. Due to the PRT drain RCS-1-8031 being a slow acting valve, it must be closed early to prevent overfill of the RCDT.

5.10.3 Drain the PRT to the RCDT.

a. Run both RCDT pumps in manual to keep up with the drain rate.

b. Maintain communication with the Aux. Senior during draining.

c. Open RCS-1-8031 and drain to approximately 84% level, closing RCS-1-8031 as necessary when RCDT level reaches 60% on LI-188 to prevent overfilling.

5.11 Low Level Alarm on PRT 5.11.1 OPEN PRT primary water supply RCS-8030 to increase level to 84%.

5.11.2 Check RCS-8031 closed. If necessary, cycle RCS-8031. If level continues to drop, check PRT and instrument taps for leaks.

5.12 High Pressure Alarm on PRT 5.12.1 If pressure has increased without increased temp and or level, THEN the N2 supply regulator may have failed. If this is the case, close 8045, and either lower PRT level or remove blank flange from manual vent valve 8048 and bleed pressure off slowly to less than 10 PSIG at which time PCV-472 should be available.

5.12.2 If pressure has increased along with temp and/or level, follow appropriate steps as addressed in Step 5.7 and 5.8 above.

25142513.DOC 16 0131.0833

RO QUESTION 35 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 008 K3.03 Importance 4.1 4.2 Proposed Question:

PLANT CONDITIONS:

Unit 1 is at full power

FCV-749 (RCP Lube Oil cooler CCW Return Valve) indicates fully closed

Highest Motor bearing temperature is 180ºF, increasing at 2ºF/min

Highest Stator winding temperature is 240ºF, increasing at 5ºF/min What is the maximum amount of time the plant can remain at power?

A. 5 minutes B. 10 minutes.

C. 12 minutes.

D. 22.5 minutes.

Proposed Answer:

A. 5 minutes.

Explanation:

A correct, per the foldout page of AP-28, for a loss of to the RCP motor coolers, the trip criteria is 5 minutes.

B incorrect, Foldout page, RCP have exceeded the limit of 200°F in 10 minutes at current rate, but must be tripped at 5.

C incorrect, this is the time until winding temperature reaches 300ºF D incorrect, this is the time at 2ºF /min, 225ºF is reached (limit on RCP radial bearing),

limit is not applicable, but candidate may remember it as a limit.

Technical Reference(s): OP AP-28 Proposed references to be provided to applicants during examination: none ro tier 2 group 1_35 rev 1.doc

Learning Objective: 3477 - Describe the major actions of abnormal operating procedures Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level: Memory or Fundamental Knowledge _____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.5 55.43 _____

Comments: K/A: 008 K3.03 - Knowledge of the effect that a loss or malfunction of the CWS will have on the following: RCP ro tier 2 group 1_35 rev 1.doc

DCPP (09/25/03) FOLDOUT PAGE FOR PAGE 1 OF 1 U1&2 OP AP-28 IF Any of the following criteria is met THEN Trip the reactor AND trip the affected RCP AND Go To EOP E-0 WHILE completing foldout actions if applicable.

1.0 No. 1 SEAL REACTOR TRIP CRITERIA TRIP CRITERIA FOLDOUT ACTIONS

1. RCP Seal #1 Return Flow GREATER THAN 6.0 GPM GO TO step 1 of section 4 (pg 10)

AND Pump Bearing OR Seal #1 Return Temps are INCREASING

2. RCP Seal #1 Return Flow is GREATER THAN 8.0 GPM GO TO step 2 of section 4 (pg 11)

3. RCP Seal #1 Return Flow LESS THAN 0.8 GPM GO TO step 1 of section 4 (pg 10)

AND Pump Brg OR Seal return Temps are INCREASING 2.0 RCP MOTOR REACTOR TRIP CRITERIA

1. Any Motor Bearing Temperature GREATER THAN 200°F

2. Motor Stator Winding Temperature GREATER THAN 300°F

3. CCW Temperature GREATER THAN 120°F

4. Loss of CCW to RCP Motor Coolers for GREATER THAN 5 Minutes 3.0 RCP PUMP REACTOR TRIP CRITERIA

1. RCP Radial Bearing Outlet Temperature GREATER THAN 225°F

2. RCP #1 Seal Outlet Temperature GREATER THAN 225°F

3. Loss of RCP Seal Flow AND Loss of Thermal Barrier Cooling 4.0 RCP VIBRATION REACTOR TRIP CRITERIA

1. Any Valid RCP Seal flow OR Motor/Pump bearing temperature alarm concurrent with a vibration alarm.

RO QUESTION 36 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 008 G2.2.13 Importance 3.6 3.8 Proposed Question:

While at power, CCW pump 1-1 was cleared for maintenance. As part of the clearance, several normally sealed open valves listed in OP K-10E1, Sealed Valve Checklist for Component Cooling Water Pump 1-1, are closed.

During restoration what type of seal should be reapplied to the valves?

A. YELLOW or GREEN seals.

B. YELLOW seals.

C. GREEN or RED seals.

D. RED seals.

Proposed Answer:

D. RED seals.

Explanation:

A incorrect, Yellow is flow balancing and Green indicates a valve sealed out of position.

B incorrect, YELLOW seal identifies a flow balancing throttle valve.

C incorrect, A GREEN seal is used to identify a valve sealed out of position.

D correct, Valves listed in the 10K series are considered Category I valves and as such should be sealed with a RED seal.

Technical Reference(s):

OP1.DC20, Sealed Components Proposed references to be provided to applicants during examination: None Learning Objective: 3598, Explain the characteristics of the Sealed Valve Program ro tier 2 group 1_36 rev1.doc

Question Source: Bank #

Modified Bank # _______

New X Question History: Last NRC Exam ____________

Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis X

10 CFR Part 55 Content: 55.41 41.10 55.43 _____

Comments:

K/A: 008 G2.2.13 - CCW, Knowledge of tagging and clearance procedures ro tier 2 group 1_36 rev1.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP1.DC20 DIABLO CANYON POWER PLANT REVISION 13 PAGE 3 OF 7 TITLE: Sealed Components 2.2 Categories of Sealed Components 2.2.1 In general, when it is desired to assure non-operation of a component in an operational system, a CAUTION tag is normally used as directed by OP2.ID2.

For components that are important to the proper functioning of a safeguards system, a seal shall be used rather than a CAUTION tag to assure non-operation.

2.2.2 The first category of sealed components consists of the plant components which are sealed to directly or indirectly satisfy Technical Specification requirements or to maintain reactor safety. The majority of these components are sealed to satisfy surveillance requirements where manual flowpath valves, transfer switch handles or breakers must be "locked, sealed, or otherwise secured in position." This category of sealed components is procedurally controlled by the K-10 series of operating procedures. For the purposes of this administrative procedure, all sealed components identified in the K-10 series of the plant operating procedure manual shall be considered CATEGORY 1 SEALED COMPONENTS.

2.2.3 A second broad category of sealed components consists of those components which have been selected to be sealed in position for reasons other than those discussed in Step 2.2.2. These components are sealed to indicate that, for some reason, the position of the sealed component requires administrative controls more stringent than those imposed on unsealed plant components. Typically, these components are identified as being sealed on OVID drawings. For the purpose of this procedure, these components shall be classified as CATEGORY 2 SEALED COMPONENTS.

2.2.4 A third category of sealed components consists of controlled flow balancing throttle valves. The seals on these valves are controlled by Engineering procedures as described in Section Error! Reference source not found..

3. RESPONSIBILITIES{ TC "RESPONSIBILITIES" \F C \L "1" }

3.1 The operations manager is responsible for ensuring that all plant operators are trained in the requirements of this procedure, and that the associated operating procedures and OVID drawings are in compliance with this procedure.

3.2 The manager of the appropriate engineering group is responsible for ensuring the controlled flow balancing throttle valves are sealed in accordance with the following procedures:

3.2.1 STP V-14 and V-15 for ECCS flow balancing throttle valves (NSSS Systems).

3.2.2 STP V-13A for CCW to CFCU flow balancing throttle valves (BOP Systems).

3.2.3 STP M-54 for RCP Seal Injection throttle valves (NSSS Systems).

01136013x.DOC 01B 0119.0137

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP1.DC20 DIABLO CANYON POWER PLANT REVISION 13 PAGE 5 OF 7 TITLE: Sealed Components 4.1.6 This procedure applies to a variety of components having a number of different operating mechanisms (e.g., handles, levers, handwheels, chain drives, etc.).

With the exception of throttled valves, an acceptable seal configuration is one that is both visible and physically impedes operation such that a broken seal will result when other than minor movement of the operating mechanism has occurred.

NOTE: Minor movement is defined as movement that will not change the process being controlled by the component.

Throttled valves should be sealed such that minor handwheel movement will break the seal. If a valve cannot be so sealed, it shall be:

a. Sealed as well as possible, and

b. The valve shall be plainly marked as being a sealed valve with the desired valve sealed position indicated.

4.1.7 Seals should be installed so that only a single seal is needed to impede component operation. When the size or configuration of the component is such that a single seal cannot effectively impede its operation, a chain, cable, wire, or other appropriate means may be used in conjunction with a seal. Usually this involves:

a. Chaining the handwheel to the bonnet for valves

b. Using a seal or other equivalent means to join the ends of the chain 4.1.8 Supplies of unused seals must be controlled. It is acceptable to maintain supplies of new seals in the areas such as the control room, operations watch office, auxiliary building control board, and intake auxiliary operator's office.

It is unacceptable to store new seals in the plant areas near where they are used.

4.1.9 Discarded broken component seals shall be properly disposed of in appropriate waste containers, at no time shall used or discarded seals be left on plant equipment or on equipment area floors.

4.2 Category 1 Sealed Components{ TC "Category 1 Sealed Components" \f C \l "2" }

4.2.1 All category 1 sealed components shall be identified in the form of a sealed component checklist in the K-10 series of the operating procedures.

4.2.2 Prior to changing plant operating modes, the shift foreman shall verify that all sealed component checklists required to be complete for that mode are current and complete, per OP L-O.

01136013x.DOC 01B 0119.0137

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP1.DC20 DIABLO CANYON POWER PLANT REVISION 13 PAGE 6 OF 7 TITLE: Sealed Components 4.2.3 To ensure sealed component checklists are current for mode transitions, the administrative controls required for sealed components shall be complied with following issuance of the sealed component checklist for completion.

Attachment Error! Reference source not found. provides a sheet which may be filed in the SFM sealed components binder in the associated checklist tab to signify that the checklist controls are in effect. For example, if a sealed component checklist is in progress and a component on the checklist must be repositioned for a clearance, a sealed component change form (see Step Error!

Reference source not found.) is to be issued to track that the sealed component is out of position.

4.2.4 All category 1 sealed components should be sealed with RED plastic seals, except for the following:

a. When a component must be sealed in a position other than the normal sealed component checklist position. In this case, the component shall be sealed with a GREEN seal or lockwire, such that the abnormal position is evident until restored to its normal position by the procedure. Installation and removal of the GREEN seal or lockwire shall be controlled in a procedure, as well as restoration of the red seals if the K-10 checklist is in effect.

b. Engineering controlled throttled component may use yellow seals.

c. If, for some reason, red plastic seals are temporarily unavailable, any sealing device may be substituted providing it must be physically broken to open the seal and cannot be re-used.

1. Substitute seals, if used, must be documented in the remarks section of the sealed component checklist and shall be replaced with the appropriate red plastic seal as soon as possible.

2. An AT OPPR type action request shall be initiated on any checklist where substitute seals are utilized. This action request shall remain open until the seals are replaced with the appropriate plastic seals.

4.2.5 Category 1 seals may be broken during plant modes when the associated sealed component checklist is required to be current only when authorization by the appropriate shift foreman is received.

a. This authorization may consist of an approved sealed component change form or a plant procedure authorized by the shift foreman which clearly indicates that component seals are to be broken.

b. In cases of emergencies, the shift foreman may issue a verbal authorization to allow an immediate repositioning of the sealed component. This is acceptable providing the required forms and verifications are performed as soon as possible following the actual seal removal and component repositioning.

01136013x.DOC 01B 0119.0137

RO QUESTION 37 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 010 K6.02 Importance 3.2 3.5 Proposed Question:

The plant is operating at 100% power. All systems are lined up and operating normally.

PZR pressure transmitters PT-455/PT-456 are selected for control.

PT-455 fails low.

Which of the following describes the expected plant response? Assume no operator action.

A. PORV 474 eventually opens and plant trips on high pressurizer pressure.

B. PORV 474 eventually opens and pressure cycles on the PORV.

C. PORV 456 eventually opens and plant trips on high pressurizer pressure.

D. PORV 456 eventually opens and pressure cycles on the PORV.

Proposed Answer:

D. PORV 456 eventually opens and pressure cycles on the PORV.

Explanation:

A incorrect, PORV 474 will not open due to the failure and plant trip setpoint is above PORV open setpoint.

B incorrect, PORV 474 will not open, 456 opens.

C incorrect, PORV open and trip setpoint are not the same.

D correct, PORV 456 will operate, pressure will cycle on the PORV.

Technical Reference(s): OIM A-4-4-b Proposed references to be provided to applicants during examination: none Learning Objective: 4573 - Analyze Pressurizer control logic.

ro tier 2 group 1_37.doc

Question Source: Bank # INPO 24653 Modified Bank # _______

New ______

Question History: Last NRC Exam Seabrook 2003 Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.7 55.43 _____

Comments:

K/A: 010 K6.02 - Knowledge of the effect of a loss or malfunction of the following will have on the PZR PCS: PZR ro tier 2 group 1_37.doc

Pressurizer Pressure Channel Failures Control/Backup Channel Failure Indications Alarms Plant Response Channel Selected PT-455/PT-456 PT-455 Fails HIGH PI-455 fails high Pzr Press High PK05-16 PCV-455C will OPEN, independent of controller or channel selector (normally selected) (controlling channel) Pzr Press recorder fails Pzr Safety/Relief Temp switch position (PC-474B intlk CLOSES it at 2185 psig) high if PT-455 selected PK05-23 PCV-474 will OPEN due to high controller output (PC-474B intlk Prot Chan Activated PK04-06 CLOSES it at 2185 psig)

PORV and safety valve Pzr Relief/Safety Vlvs Open Spray valves will open (manual action needed to avoid trip and/or SI) tailpipe temps increase PK05-20 Heaters will turn off (proportional htrs at min - bkr still closed)

Pzr Low Press PK05-17 If press is restored to >2185 psig, PORVs will re-open and cycle near the (small delay) interlock press (2185 psig)

PT-455 Fails LOW PI-455 fails low Pzr Low Press PK05-17 Heaters will turn on (all); Spray valves cannot open in auto (controlling channel) Pzr Press recorder fails OTT C-3 Activated PK04-04 PCV-455C will not open due to PT-455 failure (independent of controller) low if selected to PT-455 Prot Chan Activated PK04-06 PCV-474 will not open due to low ctrlr signal; PCV-456 will still function Safeguard Chan Act PK02-04 Press will slowly increase to 2335 psig and PORV will cycle PT-456 Fails HIGH PI-456 fails high Pzr Press High PK05-16 PCV-456 will OPEN independent of controller or channel selector switch (backup channel) PORV and safety valve Pzr Safety/Relief Temp position (PC-457E intlk CLOSES it at 2185 psig) tailpipe temps increase PK05-23 Heaters will turn on due to low press from ctrl channel Prot Chan Activated PK04-06 When press is restored to >2185 psig, PCV-456 will re-open and cycle Pzr Relief/Safety Vlvs Open near the interlock press (2185 psig)

PK05-20 Pzr Low Press PK05-17 A-4-4b (small delay)

PT-456 Fails LOW PI-456 fails low OTT C-3 Activated PK04-04 PCV-455C and PCV-474 will still function, but PCV-456 will not function (backup channel) PZR Press recorder fails Prot Chan Activated PK04-06 due to PT-456 failure (independent of controller) low if selected to PT-456 Safeguard Chan Act PK02-04 No plant transient occurs due to this failure PT-457/PT-456 PT-457 Fails HIGH PI-457 fails high Pzr Press High PK05-16 PCV-474 will OPEN due to high controller output (PC-474B intlk (controlling channel) PZR Press recorder fails Pzr Safety/Relief Temp CLOSES it at 2185 psig); PCV-456 intlk PC-457E is not effective (failed high if PT-457 selected PK05-23 high)

PORV and safety valve Prot Chan Activated PK04-06 Spray valves will open (manual action needed to close these to avoid tailpipe temps increase Pzr Relief/Safety Vlvs Open trip and/or SI)

PK05-20 Heaters will turn off (proportional htrs at min - bkr still closed)

Pzr Low Press PK05-17 If press is restored to >2185 psig, PORV will re-open and cycle near the (small delay) interlock press (2185 psig)

PT-457 Fails LOW PI-457 fails low Pzr Low Press PK05-17 Heaters will turn on (all); Spray valves cannot open in auto (controlling channel) PZR Press recorder fails OTT C-3 Activated PK04-04 PCV-474 will not open due to controlling chan failure, and PCV-456 will low if selected to PT-457 Prot Chan Activated PK04-06 not open due to interlock chan failed low; PCV-455C will still function Safeguard Chan Act PK02-04 Pressure will slowly increase until PORV lifts and cycles PT-456 Fails HIGH or See PT-456 response See PT-456 response above as See PT-456 response above as backup channel LOW (backup chan) above as backup channel backup channel PT-455/PT-474 PT-455 Fails HIGH or See PT-455 response See PT-455 response above as See PT-455 response above as controlling channel LOW (ctrl chan) above as ctrl channel ctrl channel PT-474 Fails HIGH PI-474 fails high Pzr Press High PK05-16 PCV-455C and PCV-474 intlk from PC-474B is not effective (backup channel) No plant transient occurs due to this failure PT-474 Fails LOW PI-474 fails low OTT C-3 Activated PK04-04 PCV-455C and PCV-474 will not open due to intlk PC-474B failed low; (backup channel) Prot Chan Activated PK04-06 PCV-456 will still function Rev 24 Pzr Low Press PK05-17 No RCS pressure transient will occur Safeguard Chan Act PK02-04 Note: If a controlling pressurizer pressur channel has failed low, ensure that the master pressure controller (HC-455K) is placed in manual prior to selecting an operaable control channel; not selecting manual first could

RO QUESTION 38 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 012 K5.01 Importance 3.3 3.8 Proposed Question:

Which of the following describes the type of core protection afforded by the Reactor Protection System Overtemperature DeltaT trip?

A. Power density B. Fuel Overheating C. KW per linear foot D. Departure from nucleate boiling Proposed Answer:

D. Departure from nucleate boiling Explanation:

A incorrect, This is for Overpower DT B incorrect, This is for Overpower DT C incorrect, This is for Overpower DT D correct, The inputs to the Overtemperature DT trip include pressure, coolant temperature, axial power distribution, and reactor power as indicated by loop DT assuming full reactor coolant flow. Protection from violating the DNBR limit is assured for those transients that are slow with respect to delays from the core to the measurement system.

Technical Reference(s): TS 3.3.1 bases Proposed references to be provided to applicants during examination: none Learning Objective: 9942 Analyze the reactor trip logic, inputs and setpoints Question Source: Bank # INPO 22988 Modified Bank # _______

ro tier 2 group 1_38.doc

New ______

Question History: Last NRC Exam Prairie Island 2, 2002 Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 41.5 55.43 _____

Comments: K/A: 012 K5.01 - Knowledge of the operational implications of the following concepts as the apply to the RPS: DNB ro tier 2 group 1_38.doc

BASES APPLICABLE 5. Source Range Neutron Flux (continued)

SAFETY Above the P-6 setpoint, the NIS source range neutron flux trip may ANALYSES, LCO, be manually blocked and the high voltage to the detectors may be and de-energized. Below the P-6 setpoint, the source range neutron APPLICABILITY flux trip is automatically reinstated and the high voltage to the detectors is automatically energized. In MODES 3, 4, and 5 with the reactor shut down, but with the Rod Control System capable of rod withdrawal or one or more rods not fully inserted, the Source Range Neutron Flux trip Function must also be OPERABLE (1-out-of-2 coincidence) to provide core protection against a rod withdrawal accident. If the Rod Control System is not capable of rod withdrawal, the source range detectors are not required to trip the reactor. However, their monitoring Function must be OPERABLE to monitor core neutron levels and provide indication of reactivity changes that may occur as a result of events like an uncontrolled boron dilution. The requirements for the NIS source range detectors in MODE 6 are addressed in LCO 3.9.3, "Nuclear Instrumentation."

6. Overtemperature T The Overtemperature T trip Function is provided to ensure that the design limit DNBR is met. This trip Function also limits the range over which the Overpower T trip Function must provide protection and it protects against vessel exit bulk boiling and ensures that the exit quality is within the limits defined by the DNBR correlation. The inputs to the Overtemperature T trip include pressure, coolant temperature, axial power distribution, and reactor power as indicated by loop T assuming full reactor coolant flow. Protection from violating the DNBR limit is assured for those transients that are slow with respect to delays from the core to the measurement system. The Overtemperature T trip Function uses each loop's T as a measure of reactor power and is compared with a setpoint that is automatically varied with the following parameters:

reactor coolant average temperaturethe Trip Setpoint is varied to correct for changes in coolant density and specific heat capacity with changes in coolant temperature;

pressurizer pressurethe Trip Setpoint is varied to correct for changes in system pressure; and

axial power distributionf(I), the Trip Setpoint is varied to account for imbalances in the axial power distribution as detected by the NIS upper and lower power range detectors.

(continued)

BASES APPLICABLE 6. Overtemperature T (continued)

SAFETY If axial peaks are greater than the design limit, as indicated by ANALYSES, LCO, the difference between the upper and lower NIS power range and detectors, the Trip Setpoint is reduced in accordance with Note APPLICABILITY 1 of Table 3.3.1-1.

Dynamic compensation is included for system piping delays from the core to the temperature measurement system.

T0, as used in the overtemperature and overpower T trips, represents the 100 percent RTP value of T as measured for each loop. For the initial startup of a refueled core, T0 is initially assumed to be the same as the measured T value from the previous cycle until T is once again measured at full power.

Accurate determination of the loop specific T values are made quarterly when performing the incore/excore recalibration at steady-state conditions (i.e., power distribution conditions not affected by xenon or other transient conditions). The indicated T variation between loops is due to the difference between hot leg temperatures and hot leg temperature measurement biases. The hot leg temperature variance between loops is primarily caused by asymmetrical flow in the upper plenum, and the difference in hot leg temperature measurement biases primarily caused by differences in hot leg temperature streaming error between loops.

The loop Ts change with burn up which result from the change in the hot leg streaming biases as the radial power distribution changes.

The Overtemperature T trip Function is calculated for each loop as described in Note 1 of Table 3.3.1-1. Trip occurs if Overtemperature T is indicated in two loops. The pressure and temperature signals are used for other control functions; thus the actuation logic must be able to withstand an input failure to the (continued)

BASES APPLICABLE 6. Overtemperature T (continued)

SAFETY control system, which may then require the protection function ANALYSES, LCO, actuation, and a single failure in the other channels providing the and protection function actuation. Note that this Function also provides APPLICABILITY a signal to generate a turbine runback prior to reaching the Trip Setpoint. A turbine runback will reduce turbine power and reactor power. A reduction in power will normally alleviate the Overtemperature T condition and may prevent a reactor trip.

The LCO requires all four channels of the Overtemperature T trip Function to be OPERABLE . Note that the Overtemperature T Function receives input from channels shared with other RTS Functions.

Failures that affect multiple Functions require entry into the Conditions applicable to all affected Functions. In MODE 1 or 2, the Overtemperature T trip must be OPERABLE to prevent DNB (2-out-of-4 coincidence). In MODE 3, 4, 5, or 6, this trip Function does not have to be OPERABLE because the reactor is not operating and there is insufficient heat production to be concerned about DNB.

7. Overpower T The Overpower T trip Function ensures that protection is provided to ensure the integrity of the fuel (i.e., no fuel pellet melting and less than 1% cladding strain) under all possible overpower conditions for Condition I and II events (Ref. 12). This trip Function also limits the required range of the Overtemperature T trip Function and provides a backup to the Power Range Neutron FluxHigh Setpoint trip. The Overpower T trip Function ensures that the allowable heat generation rate (kW/ft) of the fuel is not exceeded. The Overpower T trip also provides protection to mitigate the consequences of small steamline breaks, as reported in WCAP-9226, Ref. 16, and steamline breaks with coincident control rod withdrawal (Ref. 3). It uses the T of each loop as a measure of reactor power with a setpoint that is automatically varied with the following parameters:

reactor coolant average temperaturethe Trip Setpoint is varied to correct for changes in coolant density and specific heat capacity with changes in coolant temperature; and

rate of change of reactor coolant average temperature including dynamic compensation for the delays between the core and the temperature measurement system.

(continued)

BASES APPLICABLE 7. Overpower T (continued)

SAFETY ANALYSES, LCO, T0 , as used in the overtemperature and overpower T trips, and represents the 100 percent RTP value of T as measured for each APPLICABILITY loop. For the initial startup of a refueled core, T0 is initially assumed to be the same as the measured T value from the previous cycle until T is once again measured at full power.

Accurate determination of the loop specific T values are made quarterly when performing the incore/excore recalibration at steady-state conditions (i.e., power distribution conditions not affected by xenon or other transient conditions). The indicated T variation between loops is due to the difference between hot leg temperatures and hot leg temperature measurement biases. The hot leg temperature variance between loops is primarily caused by asymmetrical flow in the upper plenum, and the difference in hot leg temperature measurement biases is primarily caused by differences in hot leg temperature streaming error between loops.

The loop Ts change with burn up which result from the change in the hot leg streaming biases as the radial power distribution changes.

The Overpower T trip Function is calculated for each loop as per Note 2 of Table 3.3.1-1. Trip occurs if Overpower T is indicated in two loops. The temperature signals are used for other control functions; thus, the actuation logic must be able to withstand an input failure to the control system, which may then require the protection function actuation and a single failure in the remaining channels providing the protection function actuation. Note that this Function also provides a signal to generate a turbine runback prior to reaching the trip setpoint. A turbine runback will reduce turbine power and reactor power. A reduction in power will normally alleviate the Overpower T condition and may prevent a reactor trip.

The LCO requires four channels of the Overpower T trip Function to be OPERABLE (2-out-of-4 coincidence). Note that the Overpower T trip Function receives input channels shared with other RTS Functions. Failures that affect multiple Functions require entry into the Conditions applicable to all affected Functions.

In MODE 1 or 2, the Overpower T trip Function must be OPERABLE. These are the only times that enough heat is generated in the fuel to be concerned about the heat generation (continued)

BASES APPLICABLE 7. Overpower T (continued)

SAFETY rates and overheating of the fuel. In MODE 3, 4, 5, or 6, this trip ANALYSES, LCO, Function does not have to be OPERABLE because the reactor is and not operating and there is insufficient heat production to be APPLICABILITY concerned about fuel overheating and fuel damage.

8. Pressurizer Pressure The same sensors provide input to the Pressurizer PressureHigh and Low trips and the Overtemperature T trip. The Pressurizer Pressure channels are also used to provide input to the Pressurizer Pressure Control System; thus, the actuation logic must be able to withstand an input failure to the control system, which may then require the protection function actuation, and a single failure in the other channels providing the protection function actuation.

a. Pressurizer PressureLow The Pressurizer PressureLow trip Function ensures that protection is provided against violating the DNBR limit due to low pressure.

The LCO requires four channels of Pressurizer Pressure Low to be OPERABLE (2-out-of-4 coincidence).

In MODE 1, when DNB is a major concern, the Pressurizer PressureLow trip must be OPERABLE. This trip Function is automatically enabled on increasing power by the P-7 Low Pressure Permissive interlock (NIS power range P-10 or turbine impulse pressure greater than approximately 10% of full power equivalent (P-13)). On decreasing power, this trip Function is automatically blocked below P-7. Below the P-7 setpoint, there is insufficient heat production to be concerned about DNB.

b. Pressurizer PressureHigh The Pressurizer PressureHigh trip Function ensures that protection is provided against overpressurizing the RCS. This trip Function operates in conjunction with the pressurizer relief and safety valves to prevent RCS overpressure conditions.

The LCO requires four channels of the Pressurizer Pressure High to be OPERABLE (2-out-of-4 coincidence).

The Pressurizer PressureHigh LSSS is selected to be below the pressurizer safety valve actuation pressure and above the power operated relief valve (PORV) setting. This setting

RO QUESTION 39 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 013 K5.01 Importance 2.8 3.2 Proposed Question:

Unit 1 is at power, in a normal SSPS lineup.

PK02-02, Safety Injection Initiate, alarms.

What does this PK alarm mean to the operator?

A. At least one safeguard channel has actuated.

B. At least two safeguards channels for same parameter have actuated.

C. The minimum number of channels for SI initiation has been met and at least one Train of SI has actuated.

D. The minimum number of channels for SI initiation has been met and both Trains of SI have actuated.

Proposed Answer:

B. At least two safeguards channels for same parameter have actuated.

Explanation:

A incorrect, one channel trip actuates PK02-04, Safeguard Channel Activated.

B correct, all SI actuate signals need 2 (or more) bistables to trip. When the coincidence is met, SI Initiate signal is generated and the PK actuates.

C incorrect, this generates PK08-21, SI Actuation D incorrect, this will generate PK08-21 Technical Reference(s): PK02-02, PK02-04 and PK08-21 Proposed references to be provided to applicants during examination: none ro tier 2 group 1_39.doc

Learning Objective:

5410 - Identify the SSPS parameters that produce alarms Question Source: Bank #

Modified Bank # _______

New X Question History: Last NRC Exam ____________

Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 41.7 55.43 _____

Comments:

K/A: 013 K5.01 - Knowledge of the operational implications of the following concepts as they apply to the ESFAS: Definitions of safety train and ESF channel ro tier 2 group 1_39.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK02-04 NUCLEAR POWER GENERATION REVISION 12A DIABLO CANYON POWER PLANT PAGE 1 OF 3 ANNUNCIATOR RESPONSE UNIT TITLE: SAFEGUARD CHANNEL ACTIVATED 108/10/99 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. LOGIC DIAGRAM 04256812A .D O C 16 1

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK02-04 DIABLO CANYON POWER PLANT REVISION 12A PAGE 2 OF 3 TITLE: SAFEGUARD CHANNEL ACTIVATED UNIT 1

2. ALARM INPUT DESCRIPTION DEVICE ALARM ANNUNCIATOR TYPEWRITER NUMBER INPUT PRINTOUT SETPOINT K0605 44 Stmline Press Low Loop 1 1/3 LT 600 PSIG K0606 44 K0607 44 K0608 45 Stmline Press Low Loop 2 1/3 LT 600 PSIG K0609 45 K0610 45 K0611 46 Stmline Press Low Loop 3 1/3 LT 600 PSIG K0612 46 K0613 46 K0701 48 Stmline Press Low Loop 4 1/3 LT 600 PSIG K0702 48 K0703 48 K0512 42 Contmt Hi Press 1/3 GT 3 PSI K0513 42 Contmt Hi Press 1/3 GT 3 PSI K0514 42 Contmt Hi Press 1/3 GT 3 PSI K0601 43 Contmt Hi-Hi Press 1/4 GT 22 PSI K0602 43 Contmt Hi-Hi Press 1/4 GT 22 PSI K0603 43 Contmt Hi-Hi Press 1/4 GT 22 PSI K0604 43 Contmt Hi-Hi Press 1/4 GT 22 PSI K0907 1316 Pzr Press Lo Ch IV LT 1850 PSIG K0909 1317 Pzr Press Lo Ch II LT l850 PSIG K0908 59 Pzr Press Lo Ch I LT l850 PSIG K0910 1318 Pzr Press Lo Ch III LT l850 PSIG K1211 63 RCS Loop 1-2 Lo-Lo Tavg LT 543°F K1210 75 RCS Loop 1-1 Lo-Lo Tavg LT 543°F K1212 69 RCS Loop 1-3 Lo-Lo Tavg LT 543°F K1213 64 RCS Loop 1-4 Lo-Lo Tavg LT 543°F K1301 76 Stm Press Rate Hi 1/3 Loop 1 100 PSI K1303 77 Stm Press Rate Hi 1/3 Loop 2 100 PSI Kl305 78 Stm Press Rate Hi 1/3 Loop 3 100 PSI Kl307 79 Stm Press Rate Hi 1/3 Loop 4 100 PSI 04256812A .D O C 16 2

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK02-04 DIABLO CANYON POWER PLANT REVISION 12A PAGE 3 OF 3 TITLE: SAFEGUARD CHANNEL ACTIVATED UNIT 1

3. PROBABLE CAUSE 3.1 One or more safeguard channel Bi-stables activated due to a channel failure or a plant upset resulting in any one or more of the following conditions:

3.1.1 Steamline pressure decrease 3.1.2 Steamline Lo pressure 3.1.3 Lo-Lo TAVG 3.1.4 Pressurizer Lo Pressure 3.1.5 Contmt. Hi pressure 3.1.6 Contmt. Hi-Hi pressure

4. AUTOMATIC ACTIONS 4.1 Possible safety injection actuation.

4.2 Possible reactor trip.

5. OPERATOR ACTIONS 5.1 Check main annun. printout.

5.2 Check control room status lights, main annun's., and instrumentation for plant conditions.

5.3 If a reactor trip or safety injection occurs, go to EOP E-0.

5.4 If plant conditions require a reactor trip or safety injection, initiate same and go to EOP E-0.

5.5 If alarm is due to an upset in plant conditions, determine cause of upset and restore plant conditions to the normal range.

5.6 If alarm is due to a channel failure:

5.6.1 Refer to OP AP-5 Malfunction of Protection or Control Channel.

5.6.2 Refer to the Technical Specifications 3.3.2 (ITS 3.3.2) for required restrictions on Plant Operation.

5.7 If an alarm is reflashing due to a SSPS problem in one train (as indicated by a status light flashing on and off at a constant interval), the reflashing can be stopped by placing the SSPS Train A multiplexer test switch in "NORMAL." Refer to STP I-38AB.5, Appendix 10.2 for guidance. Notify MS of the SSPS problem.

04256812A .D O C 16 3

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK02-02 NUCLEAR POWER GENERATION REVISION 9 DIABLO CANYON POWER PLANT PAGE 1 OF 2 ANNUNCIATOR RESPONSE UNIT TITLE:

APPROVED:

SAFETY INJECTION INITIATE (RED) 04/13/94 104/18/94 DATE EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. LOGIC DIAGRAM

2. ALARM INPUT DESCRIPTION DEVICE ALARM ANNUNCIATOR TYPEWRITER NUMBER INPUT PRINTOUT SETPOINT 1 SI/CS 1133 Manual S.I.

2 SI/CS 1133 Manual S.I.

K0201 15 Pzr. Lo Press. 2/4 SI LT l850 PSIG K0206 20 Stmline Press Low S.I. 1/4 LT 600 PSIG K0207 20 Stmline Press Low S.I. 1/4 LT 600 PSIG K0208 20 Stmline Press Low S.I. 1/4 LT 600 PSIG K0209 20 Stmline Press Low S.I. 1/4 LT 600 PSIG K0205 19 Contmt Hi Press 2/3 SI GT 3 PSIG 022568ZZZ.DOC 16 1

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK02-02 DIABLO CANYON POWER PLANT REVISION 9 PAGE 2 OF 2 TITLE: SAFETY INJECTION INITIATE (RED) UNIT 1

3. PROBABLE CAUSE 3.1 Pressurizer Low pressure.

3.2 Low steamline pressure.

3.3 Containment hi pressure.

3.4 Manual S.I. initiation.

4. AUTOMATIC ACTIONS 4.1 Safety injection actuation.

4.2 Reactor trip.

4.3 Possible steam line isolation

5. OPERATOR ACTIONS 5.1 Go to EP E-0 Reactor Trip or Safety Injection.

022568ZZZ.DOC 16 2

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK08-21 NUCLEAR POWER GENERATION REVISION 0 DIABLO CANYON POWER PLANT PAGE 1 OF 1 ANNUNCIATOR RESPONSE UNIT TITLE:

APPROVED:

SAFETY INJECTION ACTUATION (RED) 04/19/94 104/21/94 DATE EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. LOGIC DIAGRAM

2. ALARM INPUT DESCRIPTION DEVICE ALARM ANNUNCIATOR TYPEWRITER NUMBER INPUT PRINTOUT SETPOINT K1811 1371 Safety Injection Actuation

3. PROBABLE CAUSE 3.1 Safety injection initiate signal.

4. AUTOMATIC ACTIONS 4.1 Safety injection actuation.

5. OPERATOR ACTIONS 5.1 Go to EP E-0.

012433ZZZZ.DOC 16 1

RO QUESTION 40 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 022 A1.02 Importance 3.6 3.8 Proposed Question:

Unit 1 is at full power.

The following events occur:

A cold leg LOCA and complete loss of offsite power occurs

Bus F and H become de-energized.

All other equipment operate as designed Which of the following describes why containment design pressure may or may not be exceeded?

A. Not exceeded - because the minimum requirement of one train of Containment spray and 2 CFCUs will be met.

B. Not exceeded - because the minimum requirement of one train of Containment spray and 3 CFCUs will be met.

C. Exceeded - because the minimum requirement of one train of Containment spray and 2 CFCUs will not be met.

D. Exceeded - because the minimum requirement of one train of Containment spray and 3 CFCUs will not be met.

Proposed Answer:

A. Not exceeded - because the minimum requirement of one train of Containment spray and 2 CFCUs will be met.

Explanation:

A correct. Minimum requirement is 1 train of CS and 2 CFCUs. Train A CS and CFCU 3 and 5 will have power from Bus G.

B incorrect. Only 2 CFCUs will be energized.

C incorrect, the minimum requirements are met.

D incorrect, this is not the minimum requirement.

ro tier 2 group 1_40.doc

Technical Reference(s): H2 - CFCU and I2 - Contaiment Spray Proposed references to be provided to applicants during examination:

Learning Objective: 6141 - State the power supplies to CFCU system components.

6022 - State the power supply to Containment Spray pumps.

3417 - State the purpose of the CFCU system.

Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.5 55.43 _____

Comments: K/A: 022 A1.02 - Ability to predict and/or monitor changes in parameters (to prevent exceeding design limits) associated with operating the CCS controls including: Containment pressure ro tier 2 group 1_40.doc

Containment Fan Cooler Units Containment Fan Cooler Units (CFCUs), Continued Power Supplies Power supplies for the CFCUs are shown below.

Obj 8 CFCU 480 V vital bus 1 F 2 F 3 G 4 H 5 G Physical The physical description of the CFCUs are described in the following table.

description CFCU

Description:

Characteristic Details Type Single stage, centrifugal Rated flow (LOW) 47,000 to 57,000 CFM Rated flow (HIGH) 99,000 to 121,000 CFM Fan drive 480 VAC 300 hp induction motor Fan assembly is protected by a vacuum relief Other characteristics damper to limit the pressure differential across the CFCU enclosure.

Material Carbon steel covered by a protective coating to prevent corrosion of the assembly.

Continued on next page H2.DOC 2-2 REV. 10

CS System Design Information Design basis The design bases are tabulated below.

Obj 5 The Containment Spray system is designed Reason to...

operate in conjunction with the Containment The spray is used to help condense the steam Fan Cooler Units (CFCUs). resulting from a LOCA or MSLB.

One train of Containment Spray and two of The CFCUs further reduce the temperature of five CFCUs provide sufficient heat removal to the air and water vapor mixture.

maintain Containment pressure below its design value of 47 psig following a design basis LOCA or MSLB.

provide post-accident Containment heat This design accommodates all postulated removal, and is therefore designated Design events.

Class I.

provide a time delay on starting CSS pumps:

The spray piping needs to remain dry until

A minimum time delay of 23 seconds after the maximum seismic loading has subsided after an earthquake,

A maximum delay of 41 seconds

Cooling is needed in the Containment atmosphere in a LOCA. [JJ1]

A Containment Spray piping fill time of 39 to 44 seconds is required for flow to reach the The piping in Containment is normally dry.

spray nozzles.

The Containment Spray system Non Safety- Benefit...

related functions during the re-circulation phase are...

continued heat removal from the

The spray is used to continue to lower Containment atmosphere Containment temperature.

continued removal of fission products from

The spray further reduces fission products in the Containment atmosphere the Containment atmosphere.

enhanced mixing of the Containment

Mixing of Containment atmosphere atmosphere minimizes hydrogen pockets.

Continued on next page I2.DOC 1-6 REV 9

RO QUESTION 41 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 022 G2.4.34 Importance 3.8 3.6 Proposed Question:

The crew is performing the actions of OP AP-8A, Control Room Inaccessibility -

Establishing Hot Standby.

The operator is directed to start CFCU 1-2.

What minimum condition(s) must be met for CFCU 1-2 to start when the operator takes the Control Switch to ON?

A. At the HSDP - Control Transfer Switch to LOCAL.

B. At the 480V Auxiliary Relay Panel - Control Transfer Relay to CUTIN.

C. At the HSDP - Control Transfer Switch to LOCAL.

At the HSDP - Control Transfer Relay to CUTIN.

D. At the HSDP - Control Transfer Switch to LOCAL.

At 480V Auxiliary Relay Panel - Control Transfer Relay to CUTIN.

Proposed Answer:

D. At the HSDP - Control Transfer Switch to LOCAL.

At 480V Auxiliary Relay Panel - Control Transfer Relay to CUTIN.

Explanation:

A incorrect, Control Transfer Relay must also be in CUTIN.

B incorrect, Control Transfer Switch must be CUTIN C incorrect, Control Transfer Relay switch on 480V Aux Relay Panel.

D correct, Control switch in LOCAL at HSDP and Transfer Relay in CUTIN at 480V Aux Relay panel.

ro tier 2 group 1_41.doc

Technical Reference(s):

A8 - Remote/Hot Shutdown Panels OP 8A, Appendix F Proposed references to be provided to applicants during examination:

OP 8A, Appendix F Learning Objective: 4480 Explain the operation of CFCU system at hot shutdown panel Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis 10 CFR Part 55 Content: 55.41 41.7 55.43 Comments:

K/A: 022 G2.4.34 - Containment Cooling - Knowledge of RO tasks performed outside the main control room during emergency operations including system geography and system implications.

ro tier 2 group 1_41.doc

Control Room Inaccessibility - Establishing Hot U1 OP AP-8A Standby REV. 16 PAGE 44 OF 46 APPENDIX F 480V Bus Alignment

1. 480V Vital Bus F

a. Place Control Transfer Cutout Switches (green Lamicoids) to CUT-IN EQUIPMENT SWITCH POSITION CFCU 1-2 43X-1F-1 CUT-IN Letdown Orifice 43BX CUT-IN

b. Open the following breakers to prevent spurious operation.

FCV-430 52-1F-11 OPEN LCV-112B 52-1F-12 OPEN 8805A 52-1F-19 OPEN FCV-750 52-1F-23 OPEN

2. 480V Vital Bus G

a. Place Control Transfer Cutout Switches (green Lamicoids) to CUT-IN EQUIPMENT SWITCH POSITION CFCU 1-5 43X-1G-2 CUT-IN BATP 1-2 43X-1G-4 CUT-IN AFW Pp 1, FCV-95 43X-12-30 CUT-IN LCV-106 43X-1G-44 CUT-IN Emerg Borate 8104 43X-1G-57 CUT-IN LCV-107 43X-1G-68 CUT-IN

b. Open the following breakers to prevent spurious operation.

LCV-112C 52-1G-11 OPEN 8805B 52-1G-14 OPEN FCV-363 52-1G-23 OPEN FCV-431 52-1G-28 OPEN FCV-356 52-1G-36 OPEN 9003A 52-1G-48 OPEN 8982A 52-1G-58 OPEN 02 010524116.DOC 0119.0229 Page 44 of 46 Phone Nos. HSDP x3107, x3781 DSDP x1355, x3179 D/G 1-1 x1249 D/G 1-2 x1251, D/G 1-3 x1438 12kV Rms x1247 4kV Rms x1747 480 V Rms 1372

Control Room Inaccessibility - Establishing Hot U1 OP AP-8A Standby REV. 16 PAGE 45 OF 46 APPENDIX F (Continued)

3. 480V Bus H

a. Open the following breakers to prevent spurious operation.

9003B 52-1H-6 OPEN 8982B 52-1H-12 OPEN FCV-355 52-1H-16 OPEN FCV-357 52-1H-17 OPEN FCV-749 52-1H-18 OPEN

4. 480V Bus Section 13D

a. Place Control Transfer Cutout Switches (green Lamicoids) to CUT-IN (located inside panel behind control transfer relay).

EQUIPMENT SWITCH POSITION PZR Htr Group 2 43X-3D-6 CUT-IN

5. Inform the HSDP Operator that 480V Bus Alignment is complete.

02 010524116.DOC 0119.0229 Page 45 of 46 Phone Nos. HSDP x3107, x3781 DSDP x1355, x3179 D/G 1-1 x1249 D/G 1-2 x1251, D/G 1-3 x1438 12kV Rms x1247 4kV Rms x1747 480 V Rms 1372

Remote/Hot Shutdown Panels CFCU Control Switches Purpose The purpose of the CFCU Control Switches is to operate the CFCUs 1 Obj 7 through 5 after control has been transferred to the HSDP.

Location The CFCU Control Switches are located inside of the HSDP. Refer to the Basic Description Section for the specific location of the switch inside of the HSDP.

Controls The CFCU Control Switches shown below are available at the HSDP.

Obj 24 Control G R G R G R G R G R 1-1 1-2 1-3 1-4 1-5 OFF ON OFF ON OFF ON OFF ON OFF ON RSD-27 Control Operation OFF/ON 2 position, spring return to neutral Logic The logic associated with the CFCU Control Switches at the HSDP is Obj 9,24 described in the table below:

With the CONTROL TRANSFER SWITCH in the LOCAL position and the Control Transfer Relay CUTIN If the control switch is in ... Then the CFCU will ...

ON Start in high speed.

OFF Stop Neutral Start on a SI signal in slow speed.

Continued on next page A8.DOC 2.1 - 44 REV 3

RO QUESTION 42 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 026 K4.01 Importance 4.2 4.3 Proposed Question:

Unit 1 was at 100% in a normal lineup when a large LOCA occurs.

While performing the actions of EOP E-1.3, Transfer to Cold Leg Recirculation, the crew opens 9003A, RHR Pp 1 to Spray Hdr A.

When is the logic satisfied to open 9003A?

A. When the RWST decreases to less than 4%.

B. When 8809A, RHR to Cold Legs 1 and 2 is closed.

C. When 9001A and B, Containment Spray Pp Discharge Vlvs, are closed.

D. When 8982A, RHR Pp No. 1 Suct From Contmt Recirc Sump, is opened.

Proposed Answer:

D. When 8982A, RHR Pp No. 1 Suct From Contmt Recirc Sump, is opened.

Explanation:

A incorrect, this is a prerequisite for opening the valve, but not an interlock.

B incorrect, this is a prerequisite for opening the valve, but not an interlock. The loop suctions are closed at power and 8982B is opened at step 6.

C incorrect, this is a prerequisite for opening the valve, but not an interlock.

D correct, to open 9003A, 8982A/B must be open and 8701or 8702, (loop suction valves) closed (which they are at power).

Technical Reference(s): B2 - Residual Heat Removal I2 - Containment Spray Proposed references to be provided to applicants during examination: none Learning Objective: 6043 - Analyze interlocks associated with Containment Spray System valves.

ro tier 2 group 1_42.doc

Question Source:

New X Question History: Last NRC Exam ____________

Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 41.7 55.43 _____

Comments:

K/A: 026 K4.01 - Knowledge of CSS design feature(s) and/or interlock(s) which provide for the following: Source of water for CSS, including recirculation phase after LOCA ro tier 2 group 1_42.doc

Residual Heat Removal System RHR to Containment Spray Isolations, 9003A/B, Continued Logic The logic for 9003A/B is described below.

If the switch is in... Then the valve will...

OPEN open if:

8701 or 8702 loop suction valve, is closed, and

8982A/B, Containment suction, is open.

Interlock is designed to prevent inadvertent spray of the Containment from RCS during normal operation and to insure RHR is in recirc mode during accident conditions.

STOP will stop valve movement.

CLOSE close.

Other features Description Closing interlock The full closed contact is jumpered out, the valve is allowed to torque out in the closed direction to assure positive seating.

Torque switch bypasses Each torque switch is bypassed by a contact that closes when the valve is within 10% of its opposite position, e.g., the open torque switch is bypassed by a contact that closes when the valve is > 90% closed.

This prevents the valve from being stopped if the torque switch opens on breakaway torque as it starts to move open.

Continued on next page B2.DOC 2 - 51 REV. 13

CS System RHR to Containment Spray Valves (CS-9003A/B), Continued Controls Valves CS-9003A/B have control capability from the

Control Room on VB1 and

local handwheel.

Control at VB1 Operation CLOSE/STOP/OPEN 3 position, maintain position.

Logic The logic associated with valves CS-9003A/B is described in the following Obj 16 tables If the VB1 control switch is in ... Then valve CS-9003A will ...

CLOSE Close OPEN Open IF both

RHR-8982A, RHR pump 1 suction from Containment sump is open AND

RHR-8701 OR -8702, RHR suction from RCS loop 4 is closed If the VB1 control switch is in ... Then valve CS-9003B will ...

CLOSE Close OPEN Open IF both

RHR-8982B, RHR pump 2 suction from Containment sump is open AND

RHR-8701 OR -8702, RHR suction from RCS loop 4 is closed Continued on next page I2.DOC 2 - 32 REV. 9

RO QUESTION 43 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 039 A1.05 Importance 3.2* 3.3 Proposed Question:

PLANT CONDITIONS:

Unit 1 is at 3% power, EOL

Steam Dumps are maintaining RCS Tave in AUTOMATIC in Steam Pressure mode Which of the following describes the effect of the Steam Dump pressure controller, HC-507 pot setting being changed from 8.38 turns to 9.10 turns?

A. Tavg would INCREASE and reactor power would DECREASE.

B. Tavg would INCREASE and reactor power would REMAIN THE SAME.

C. Tavg would DECREASE and reactor power would DECREASE.

D. Tavg would DECREASE and reactor power would REMAIN THE SAME.

Proposed Answer:

A. Tavg would INCREASE and reactor power would DECREASE.

Explanation:

A correct, raising the setpoint causes Tavg to increase the negative feedback with rods in manual would cause power to decrease.

B incorrect, power would decrease.

C incorrect, Tavg would increase.

D incorrect, Tavg would increase, power would decrease.

Technical Reference(s): C-2B - Steam Dump Proposed references to be provided to applicants during examination: none Learning Objective: 8006 - Explain the effects of operating Steam Dump System controls ro tier 2 group 1_43 rev1.doc

Question Source: Bank #

Modified Bank # DCPP A-0731 New Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.5 55.43 _____

Comments:

K/A: 039 A1.05 - Ability to predict and/or monitor changes in parameters (to prevent exceeding design limits) associated with operating the MRSS controls including: RCS T-ave ro tier 2 group 1_43 rev1.doc

1 A-0731 Points: 1.00 Multiple Choice A reactor start up is in progress with the following plant conditions:

Control rods Manual

Reactor power 5%

IR SUR 0

Steam Dumps Pressure mode

HC-507 AUTO What would happen if the steam dump pressure controller HC-507 pot setting were to be changed to 9.10? (Normal setting is 8.38)>>

A. Tavg would increase and reactor power would decrease.

B. Tavg would remain the same and reactor power would decrease.

C. Tavg would remain the same and reactor power would increase.

D. Tavg would decrease and reactor power remain the same.

Answer: A ASSOCIATED INFORMATION:

Associated objective(s):

8006 Explain the effects of operating Steam Dump System controls Reference Id: A-0731 Must appear: No Status: Active User Text: 8006.130741 User Number 1: 3.00 User Number 2: 3.70 Difficulty: 3.00 Time to complete: 3 Topic: SDS - Steam dump steaming rate affect on power and Tavg Cross

Reference:

DUTY AREA 74, LC-2B Comment: Checked OK, 1/10/97. No changes. MAP2 Copied from S-1311; 11/11/96, GES1 Validated question IAW TQ2.ID3 1/23/97 RCWf Taken active following review, 1/25/97 JMH1 LC-2B Reviewed by R973 test review group, reformatted stem, 8/29/97, jmb1

Checked as part of question review for biennial exam 12/22/98 MTC6 Reviewed for 00 biennial exam 1/17/01 mtc6 Reviewed for 02 biennial exam 1/7/03 mtc6 Reviewed for 04 biennial exam 12/21/04 mtc6

Steam Dump System Major DCPP Events, Continued LER 323- On September 14, 2000, operators were preparing for the Diablo Canyon Unit 000914 2 plant startup following a mode 3 forced outage. In order to place the 40 Obj 32 percent condenser steam dumps in service, the potentiometer (POT) setting for the steam dump controller HC-507 was required to be set at 1,005 psig (8.38 turns). With the controller in manual, the POT setting was peer-checked following adjustment by the control operator. After HC-507 was placed in automatic, the 40 percent steam dumps opened with a subsequent secondary pressure and reactor coolant system (RCS) pressure and temperature transient.

The transient was terminated quickly after HC-507 was taken back to manual and the steam dumps were closed. During the transient, steam header pressure dropped to 924 psig and the rate sensitive low steam line pressure safety injection (SI) setpoint reached 797 psig (600 psig setpoint). Two additional licensed individuals observed the HC-507 POT setting following the transient and believed it to have been set correctly.

The control room contacted technical maintenance (TM) personnel and requested HC-507 troubleshooting. Prior to the start of controller troubleshooting on the following shift, the relieved control operator decided that the HC-507 POT setting warranted another look; this time using a magnifying glass to enhance viewing of the small numbering. Operators determined that the POT setting had been set to 6.38 turns instead of the required 8.38 turns C2B.DOC 4-7 REV. 11

Integrated Operations Normal Operations, Continued Control Refer to OIM figures C-2-3, 4 & 5 for normal control system alignment of the system Steam Dump system.

alignment diagram Pressure Refer to OIM figures C-2-3, 4 & 5 for the following discussion.

Control mode The Steam Pressure mode of Steam Dump control is normally used when Obj 17 reactor power is less than approximately 10%. This includes plant cooldown and stabilizing temperature on heatup.

Group 1 and group 2 Steam Dump valves only are affected in Steam Pressure mode.

In automatic pressure sensed by PT-507 is compared to the setpoint selected on the Steam Pressure controller. This is normal set at 1005 psig at Hot Standby and above. The set point could be varied below Hot Standby to control heatup/cooldown. However, the preferred method for cooldown is to place HC-507 in manual and use the up/down pushbuttons (direct control of controller output) to adjust valve position for a more constant cooldown/heatup rate[TRP2].

Steam Pressure mode is selected by the Mode Selector switch 43/SDI on CC-

2. The other requirements for operation in Steam Pressure mode are:

Main condenser available C-9.

Bypass switch not in OFF/RESET.

Tavg not less than 543°F P-12. P-12 can be bypassed for control of group 1 valves only.

Manual or Auto selected at HC-507 on CC-3 Total valve demand from the Steam Pressure controller can be read on UI-500 on VB-3 or HC-507 demand with the following relationships.

Group Controller Demand Group Position 1 0 - 15.625% 0 - 100%

2 15.625 - 46.875% 0 - 100%

3 46.875 - 87.5% 0 - 100%

4 87.5 - 100% 0 - 100%

Continued on next page C2B.DOC 3-3 REV. 11

RO QUESTION 44 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 039 A4.03 Importance 2.8* 2. 8*

Proposed Question:

What is the programmed auto setpoint delta-P for the Digital Feedwater Control System Feed Pump Speed Control?

A. Ramps from 74 psid to 170 psid from 0-100% load. Load is indexed from total feedwater flow.

B. Constant at 74 psid from 0-20% load, ramps from 74 psid to 170 psid from 20-100%

load. Load is indexed from total feed flow.

C. Ramps from 74 psid to 170 psid from 0-100% load. Load is indexed from total steam flow.

D. Constant at 74 psid from 0-20% load, ramps from 74 psid to 170 psid from 20-100%

load. Load is indexed from total steam flow.

Proposed Answer:

D. Constant at 74 psid from 0-20% load, ramps from 74 psid to 170 psid from 20-100%

load. Load is indexed from total steam flow.

Explanation:

A incorrect, constant from 0 to 20%. indexed to total steam flow B incorrect, indexed to total steam flow C incorrect, constant from 0 to 20%

D correct, see graph Technical Reference(s): C-8B - DFWCS Proposed references to be provided to applicants during examination: none Learning Objective: 4330 - Explain the operations associated with DFWCS Question Source: Bank # P-0172 ro tier 2 group 1_44.doc

Modified Bank # _______

New ______

Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis 10 CFR Part 55 Content: 55.41 41.4 55.43 _____

Comments:

K/A: 039 A4.03 - Ability to manually operate and/or monitor in the control room: MFW pump turbines ro tier 2 group 1_44.doc

1 P-0172 Points: 1.00 Multiple Choice What is the programmed auto setpoint delta-P for the Digital Feedwater Control System Feed Pump Speed Control?

A. Constant at 74 psid from 0-20% load, ramps from 74 psid to 170 psid from 20-100% load. Load is indexed from total steam flow.

B. Constant at 74 PSID from 0-20% load, ramps from 74 psid to 170 PSID from 20-100% load. Load is indexed from total feedwater flow.

C. Ramps from 74 psid to 170 psid from 0-100% load. Load is indexed from total feedwater flow.

D. Ramps from 74 psid to 170 psid from 0-100% load. Load is indexed from total steam flow.

Answer: A ASSOCIATED INFORMATION:

Associated objective(s):

4330 Explain the operations associated with DFWCS Reference Id: P-0172 Must appear: No Status: Active User Text: 4330.050593 User Number 1: 3.00 User Number 2: 3.10 Difficulty: 1.00 Time to complete: 2 Topic: prog auto stpt of delta P for DFWCS Cross

Reference:

STG C-8B Comment:

Section 2.3 Main Feed Pump Control Overview MFP P The main feed pumps (MFPs) are operated according to the programmed P considerations from steam pressure and feed pressure. The P program is a function of total steam flow. The discharge pressure required to feed water into the S/Gs is a function of the following factors:

The feedwater pump must raise the pressure of the water entering its suction to value that is at least as high as S/G pressure. Steam pressure drops with plant load so pump discharge pressure will drop as well.

Feed pump pressure must also overcome the pressure due to the elevation difference from pump to feed ring.

As a result of flow, there is a throttling (head) loss across the partially open feedwater control valve. The pressure drop will rise as the flow through the valve increases.

As a result of fluid flow, there are frictional (head) losses through all the various piping and components from the feedwater system to the S/Gs.

The P program allows main feedwater reg valve position to remain within the middle band of the total valve stroke over the entire range of turbine load.

An advantage to this is a linear relationship between % of valve opening and % of total flow through the valve (improved throttling characteristics).

Another advantage is reduced erosion of valve internals and thereby improved reliability.

Continued on next page C8B.DOC 2.3 - 1 REV. 12

Digital Feedwater Control System Overview, Continued MFP P The MFP P program is shown below.

program diagram P (psid)

Obj 8 200 180 1 160 (170 psid) 140 120 3

100 80 60 2

40 (74 psid) 20 0

20 40 60 80 100 Percent Load DFWCS-16 Stage Description 1 The programmed P for full load (170 psid), is designed to overcome all the head losses incurred between the feedwater pumps and the S/Gs.

2 The programmed P for no load, (74 psid), is based on:

minimizing erosion of control valve seats and discs,

erratic steam flow measurements at low power levels.

3 The feedwater pump speed control system automatically regulates the speed of the feed pumps to maintain the programmed P.

C8B.DOC 2.3 - 2 REV. 12

RO QUESTION 45 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 059 K3.04 Importance 3.6 3.8 Proposed Question:

Unit 1 is at 75% power when MFP 1-1 trips. The plant operates as designed.

Which of the following describes the initial RCS temperature and pressurizer level response?

A. Power mismatch causes RCS temperature to decrease, which causes pressurizer level to decrease.

B. Power mismatch causes RCS temperature to increase, which causes pressurizer level to increase.

C. Program response of steam dumps and control rods causes both RCS temperature and pressurizer level to decrease.

D. Rod insertion causes RCS temperature to decrease while charging mismatch causes pressurizer level to increase.

Proposed Answer:

B. Power mismatch causes RCS temperature to increase, which causes pressurizer level to increase.

Explanation:

small load rejection resembles a normal ramp when looking at only the end points of the transient. During the transient, however, TAVG will rise several degrees above normal, prior to stabilizing at its final value. Pressurizer level will initially rise, from a beginning value of 42%, and then decrease to a final value of 35%. An accompanying change in pressurizer pressure will also occur.

A incorrect, the power mismatch is primary greater than secondary, the RCS will heat up.

B correct, the primary to secondary mismatch will cause an initial heat up and swell on the primary side.

C incorrect, the control systems will eventually take over but not initially.

D incorrect, RCS temperature increases.

ro tier 2 group 1_45 rev1.doc

Technical Reference(s): TH18T - Transient Analysis page 25, 26 Proposed references to be provided to applicants during examination: none Learning Objective:

10583 - DESCRIBE the reactor, RCS and Secondary System responses to each of the following transients:

a. Partial load rejection with rods in automatic.

b. Partial load rejection with rods in manual.

Question Source: Bank #

Modified Bank # INPO 24632 New ______

Question History: Last NRC Exam Seabrook 5/2003 Question Cognitive Level:

Memory or Fundamental Knowledge Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.5 55.43 _____

Comments:

K/A: 059 K3.04 - Knowledge of the effect that a loss or malfunction of the MFW will have on the following: RCS ro tier 2 group 1_45 rev1.doc

TH18T PAGE 25, 26 3.1 PLANT RESPONSES TO SPECIFIC TRANSIENTS Data for the transients analyzed in this section is listed in Section 1.1 and Section 1.2 of this chapter.

Only the middle of cycle (MOC) transients are evaluated. In instances where the BOC or EOC transients are more significant, supportive descriptions are provided.

Partial Load Rejection with Rods in Automatic The most common type of load rejection is one in which the Main Generator output breakers open (termed a Full Load Rejection). This results in electrical load being reduced to about 5% of full load, and reactor power stabilizing near 30% by dumping steam through the steam dumps. For this analysis, only a partial load rejection is considered. This simplifies the analysis and provides a range of values compatible with both automatic and manual modes of rod control.

During a partial load rejection, control rods insert automatically, at a speed of 72 steps per minute, due to the mismatch between the rate of change of turbine load and reactor power. Once this rate of change dissipates, the rods continue to insert due to TAVG being greater than its programmed value (TREF). The steam dumps open, during the transient, to simulate the turbine load being lost. As TAVG approaches TREF, the steam dumps start throttling closed. For this analysis, no steam dump actuation is assumed. But, since TAVG returns to TREF, due to rod motion, no steam dump actuation is actually required In fact, this small load rejection resembles a normal ramp when looking at only the end points of the transient. During the transient, however, TAVG will rise several degrees above normal, prior to stabilizing at its final value. Pressurizer level will initially rise, from a beginning value of 42%, and then decrease to a final value of 35%. An accompanying change in pressurizer pressure will also occur. On the secondary side, TSAT will increase about 10°F, and steam generator pressure will increase about 50 psid ro tier 2 group 1_45 rev1.doc

INPO Licensed Operator Exam Bank - PWR Questions ID: 24632 The following plant conditions exist:

- The plant is operating at 80% power.

- B steam generator feed pump (SGFP) trips.

What is the expected response of the RCS?

Ans Turbine setback causes power mismatch that causes control rods to insert; RCS temperature rise causes an initial PZR level swell before returning to program level.

D1 Turbine setback causes power mismatch that cools RCS thus PZR level initially shrinks before returning to program level.

D2 Turbine setback causes power mismatch that causes control rods to insert; RCS temperature rise causes an initial PZR level shrink before returning to program level.

D3 Turbine setback causes power mismatch that causes control rods to insert. No pressurizer level change observable due to action of steam dumps and rod insertion.

AbbrevLocName Seabrook 1 ExamDate 5/30/2003 Vendor WEC Type PWR Distract1Comment A) Does not cool RCS C) Causes swell initially D) incorrect Distract2Comment A) Does not cool RCS C) Causes swell initially D) incorrect Distract3Comment A) Does not cool RCS C) Causes swell initially D) incorrect ExamType ILO QuestionComment Explanation of answer: Power mismatch will cause RCS temperature increase, and rods to insert, initial swell causes PZR level to increase.

Cog Level 2

ExamLevel R

RefMaterial ParentId KaNumber

..059.K3.04 KaSegment1 KaSegment2 KaSegment3 059 KaSegment4 K3 KaSegment5 04 KaRevision Tuesday, September 21, 2004 Page 9388 of 9479 ro tier 2 group 1_45 rev1.doc

RO QUESTION 46 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 061 K5.05 Importance 2.7 3.2 Proposed Question:

Subsequent to a reactor trip from 100% power, a severe water hammer causes the aux feedwater line to Feed Lead 2-1 to break.

The break is just upstream of the check valve that isolates main feedwater from aux feedwater.

How do the following AFW LCVs respond to this malfunction?

LCV-110 AFW PP 2-2 discharge to S/G 2-1

LCV-111 AFW PP 2-2 discharge to S/G 2-2

LCV-106 AFW PP 2-1 discharge to S/G 2-1 A. High AFW flow to S/G 2-1 will result in LCV-110 throttling. LCV-111 will open in an attempt to feed S/G 2-2. LCV-106 will remain open until closed by operator action.

B. Low pressure on the AFW line to S/G 2-1 will send a signal to close LCV-110 and LCV-106. LCV-111 will be available to feed S/G 2-2.

C. Low AFW PP 2-2 discharge pressure will result in throttling LCV-110 and LCV-111.

LCV-106 will remain open until closed by operator action.

D. Low pressure on the AFW line will send a close signal to LCV-110. LCV-111 will open in an attempt to feed S/G 2-2. LCV-106 will remain open until closed by operator action.

Proposed Answer:

C. Low AFW PP 2-2 discharge pressure will result in throttling LCV-110 and LCV-111. LCV-106 will remain open until closed by operator action.

Explanation:

A incorrect, valves throttle on low pressure.

B incorrect, valves will not receive a close signal.

C correct, as pressure decreases, both 110 and 111 will throttle to prevent runout. 106 is operated manually.

ro tier 2 group 1_46.doc

D incorrect, valve will not receive a close signal.

Technical Reference(s): D1 - Auxiliary Feedwater Proposed references to be provided to applicants during examination: none Learning Objective: 8401 - Explain automatic actions associated with AFW system valves.

Question Source: Bank # DCPP A-0688 Modified Bank # _______

New ______

Question History: Last NRC Exam ____________

Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.7 55.43 _____

Comments: K/A: 061 K5.05 - Knowledge of the operational implications of the following concepts as the apply to the AFW: Feed line voiding and water hammer ro tier 2 group 1_46.doc

1 A-0688 Points: 1.00 Multiple Choice

<QQ 34655(1410)><<Subsequent to a reactor trip from 100%

power, a severe water hammer causes the aux feedwater line to Feed Lead 2-1 to break.

The break is just upstream of the check valve that isolates main feedwater from aux feedwater.

How do the following AFW LCVs respond to this malfunction?

LCV-110 AFW PP 2-2 discharge to S/G 2-1

LCV-111 AFW PP 2-2 discharge to S/G 2-2

LCV-106 AFW PP 2-1 discharge to S/G 2-1>>

A. Low AFW PP 2-2 discharge pressure will result in throttling LCV-110 and LCV-111. LCV-106 will remain open until closed by operator action.

B. High AFW flow to S/G 2-1 will result in LCV-110 throttling.

LCV-111 will open in an attempt to feed S/G 2-2. LCV-106 will remain open until closed by operator action.

C. Low pressure on the AFW line will send a close signal to LCV-110. LCV-111 will open in an attempt to feed S/G 2-2. LCV-106 will remain open until closed by operator action.

D. Low pressure on the AFW line to S/G 2-1 will send a signal to close LCV-110 and LCV-106. LCV-111 will be available to feed S/G 2-2.

Answer: A ASSOCIATED INFORMATION:

Associated objective(s):

8401 Explain automatic actions associated with AFW system valves Reference Id: A-0688 Must appear: No Status: Active User Text: 8401.050614 User Number 1: 3.30 User Number 2: 3.60

Difficulty: 3.00 Time to complete: 5 Topic: AFW Pump response to low discharge pressure Cross

Reference:

LD-1, 61 Comment: copied over from S-2836, que. needs validation 1/15/97 EAD1 Entered KA pedigree, increased difficulty level to 3.0, took to REVISE status 1/19/97.

Validated IAW TQ2.ID3. Taken to Review. 1/23/97 jpsj Taken active following review, 1/25/97 JMH1 Checked as part of question review for biennial exam 12/22/98 MTC6

Auxiliary Feedwater System Basic Description, Continued Basic flowpath The basic block and flow diagram of the AFW system is shown here.

Obj 2 Condensate Storage Firewater Tank Tank Outside Inside Recirc Containment Containment EH To Raw Water CST Reservoir LCV-110 LCV-106 MFW S/G 1

EH Motor Driven 2 LCV-111 LCV-107 Motor Driven MFW S/G 3 2 EH LCV-115 Turbine Driven LCV-108 1 MFW S/G 3

EH LCV-113 FCV-95 Exhaust To LCV-109 MFW S/G S/G Atmosphere 4

2&3 Steam Supply D-1-1 D1.DOC 1-5 REV. 12

Auxiliary Feedwater System TDAFW Pump LCVs (LCV-106, 107, 108, and 109)

Purpose The purpose of the TDAFW pump LCVs is to control AFW flow to all four Obj 13 S/Gs and to provide isolation capability of a faulted S/G.

Location LCV-106 and 107 are located in 115 pipe rack area.

Obj 8 LCV-108 and 109 are located in the 115 penetration area.

Power The power supply to all four LCVs is 480 V bus G.

supplies

The bus is located on the 100' elevation of area H below Control Room.

Obj 8 Diagram The following is a diagram of the flowpath from the TDAFW pump to the S/Gs:

Outside Inside Containment Containment S/G 1 LCV-106 S/G 2 LCV-107 AFW Pump 1 Terry S/G 3 Turbine LCV-108 S/G 4 LCV-109 AFW-12 Continued on next page D1.DOC 2 - 36 REV. 12

Major Components TDAFW Pump LCVs (LCV-106, 107, 108, and 109), Continued Description LCV-106 through -109 are motor operated limitorque valves. The valves are manually controlled and are normally left full open.

Controls

LCV-106 through -109 have control capability from the:

Obj 10, 18 Control Room on VB-3 HSD Pnl local handwheel

The LCV transfer relays (described in HSD Panel STG A-8) have[TG8]

control capability from 480V Bus G.

In the Control Room:

Control Operation CLOSE/STOP/OPEN 3 position, spring return to STOP At the HSD Pnl:

Control for valve: Operation CLOSE/STOP/OPEN 3 position, spring return to STOP CONT RM/LOCAL 2 position, maintained At 480 V Bus G:

Control for transfer Operation relay[TG9]

CUTIN/CUTOUT 2 position, maintained TRIP/RESET Indications The following indications are available for LCV-106 through 109 in the Control Room and the HSD Pnl:

Obj 9 LCV-106 through 109 control switch indications Indicating Lights Meaning Normal Status Red Valve is full OPEN. ON Green Valve is full CLOSED. OFF NOTE: If BOTH Indicating lights are LIT simultaneously, then the valve is in an intermediate position.

D1.DOC 2 - 37 REV. 12

Major Components MDAFW Pump LCVs (LCV-110, 111, 113, and 115), Continued Logic The logic associated with the MDAFW pump LCVs Auto/Manual operation is described in the following tables:

Obj 20, 27, 28 Logic input Function MDAFW pump

Provides actual pump discharge pressure to a pressure discharge comparator.

pressure

Pressure comparator converts the pump discharge PT-433, 434 pressure signal to an equivalent inverse level signal (see drawing AFW-15 on page 2-44), and sends this level signal to the high select circuit described below.

This input is used as runout protection for the pump, and will cause the valve to close on low pump discharge pressure.

S/G Level

Provides actual S/G level input to a high select circuit.

LT-519, 529,

High select allows the highest S/G level input to control 539, 549 valve.

S/G level signal input is from either:

actual S/G level from LT-519 (529, 539, 549) or AFW pump discharge pressure comparator (converted to an inverse level signal)

Output of high select circuit is sent to a proportional level controller.

Valve Position

Provides feedback of actual valve position to both Transmitter controllers and meters.

Continued on next page D1.DOC 2 - 43 REV. 12

Auxiliary Feedwater System MDAFW Pump LCVs (LCV-110, 111, 113, and 115), Continued Logic Diagram The following diagrams depict the logic and interlocks associated with MDAFW pump LCVs:

Aux FWP 2 PC-86 LT Discharge PT High 519 433 Select Pressure LM-86A SG 1 Pressure Level Comparator Proportional LC-86 HC-86 Level Aux Feed Pp 2 VB-3 Controller Bkr Closed M A Setpoint (LREF)

Interlock 52-1H-62 Bypass Cut In HIC-70 480V HSD Pnl M

Valve 120V POT Position Transmitter A Analog Gate Electro-Valve Power Hydraulic Operator LCV-110 Power to LCV-111 Fail Open AFW-14 S/G Level (%)

100 (0.5 Volt)

Operating Area 60 Output of PC

45 0%

Valve Position

32.5 100%

20 Control Span 1325 1150 (1 Volt) 0 1500 1400 1300 1200 1100 1000 Motor-Driven AFW Pump Discharge Pressure AFW-15 Continued on next page D1.DOC 2 - 44 REV. 12

RO QUESTION 47 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 062 K2.01 Importance 3.3 3.4 Proposed Question:

With Unit 1 at 100% power, how does the 12 KV Bus D/E protection circuitry interface with the RCPs?

A. If 2 out of 3 relays on bus E sense < 54 Hz, a trip signal is sent to RCP 1-1 and 1-3 breakers.

B. If 2 out of 3 relays on either bus D or E sense < 54 Hz, a trip signal is sent to all 4 RCP breakers.

C. If 1 out of 2 relays on buses D and E sense < 70% voltage, a trip signal is sent to all 4 RCP breakers.

D. If 1 out 2 relays on bus D sense < 70% voltage, a trip signal is sent to RCP 1-2 and 1-4 breakers.

Proposed Answer:

A. If 2 out of 3 relays on bus E sense < 54 Hz, a trip signal is sent to RCP 1-1 and 1-3 breakers.

Explanation:

A correct, Bus E supplies RCPs 11 and 13.

B incorrect, only the RCPs on the bus get trip signal.

C incorrect, low voltage on both buses results in a reactor trip signal.

D incorrect, does not trip RCPs.

Technical Reference(s): J5 - 12 KV Electrical System Proposed references to be provided to applicants during examination: none Learning Objective: 6249 Analyze the logic associated with 12 kV Protection Relay indication lights ro tier 2 group 1_47.doc

Question Source: Bank # DCPP S-44862 Modified Bank # _______

New ______

Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis 10 CFR Part 55 Content: 55.41 41.7 55.43 Comments:

K/A: 062 K2.01 - Knowledge of bus power supplies to the following: Major system loads ro tier 2 group 1_47.doc

1 S-44862 Points: 1.00 Multiple Choice How does the 12 KV Bus D/E protection circuitry interface with the RCPs?

(Assume that the reactor is at 100% power)>>

A. If 2 out of 3 relays on bus E sense < 54 Hz, a trip signal is sent to RCP 1-1 and 1-3 breakers.

B. If 2 out of 3 relays on either bus D or E sense < 54 Hz, a trip signal is sent to all 4 RCP breakers.

C. If 1 out of 2 relays on buses D and E sense < 70% voltage, a trip signal is sent to all 4 RCP breakers.

D. If 1 out 2 relays on bus D sense < 70% voltage, a trip signal is sent to RCP 1-2 and 1-4 breakers.

Answer: A ASSOCIATED INFORMATION:

Associated objective(s):

6249 Analyze the logic associated with 12 kV Protection Relay indication lights Reference Id: S-44862 Must appear: No Status: Active User Text: 6249.070621 User Number 1: 2.60 User Number 2: 3.10 Difficulty: 3.00 Time to complete: 2 Topic: Analyze the logic associated with 12 kV Protection Relay ind Cross

Reference:

LJ-5 Comment:

12 kV Buses D and E, Continued Power supply The 12 kV Bus D and E are supplied through the feeder breakers listed below.

12 kV bus D and E supplies:

Load Startup bus feeder Auxiliary transformer breakers 1-1 (2-1)

Bus D 52VD4 (52VD6) 52VD8 (52VD2)

Bus E 52VE6 (52VE4) 52VE2 (52VE8)

Unit 1 12 kV The 12 kV bus D and E diagram is shown below for Unit 1.

bus D and E diagram From 25 kV Main 12 kV Startup Generator Bus Unit 1 Auxiliary Transformer 11 52VD8 52VD4 52VE6 52VE2 VB-5 VB-5 VB-5 VB-5 12 kV Bus D 12 kV Bus E 52VD5 52VD6 52VD7 52VE3 52VE4 52VE5 VB-4 VB-2 VB-2 VB-2 VB-2 VB-4 52VD6R 52VD7R 52VE3R 52VE4R Circ Circ Water Water Pump Pump RCP RCP RCP RCP 11 12 14 12 11 13 12KV-08 Continued on next page J5.DOC 2 - 53 REV. 9

12 kV Buses D and E, Continued 12 kV Buses D Relays that activate Bus D and E Reactor Protection are described below.

and E Reactor Protection Relay and Protection Parameter Under Each 12 kV bus that supplies the RCPs is equipped with two voltage undervoltage (UV) sensing relays.

condition on

Should a UV relay associated with one bus sense that pump 12 kV Buses supply voltage has dropped to [70%] of normal (8050 V), a D and E UV signal is produced for that bus.

A UV signal from each bus is required to produce a 27VDR1 reactor trip.

27VDR2

A time delay pickup relay is used to prevent spurious 27VER1 trips from short term voltage perturbations.

27VER2

This trip is blocked below 10% reactor power.

If one of two undervoltage trip relays on each bus senses an undervoltage condition (undervoltage on both Buses D and E), the turbine driven auxiliary feedwater pump starts automatically.

Under Each 12 kV bus that supplies the RCPs is equipped with three frequency underfrequency (UF) sensing relays.

(81 relay)

Should two of three UF relays associated with a bus sense condition on that pump supply frequency has dropped to [54 Hz], a UF 12 kV Buses signal is produced for that bus.

D and E

A UF signal from either bus will produce a reactor trip.

A UF signal from a bus will trip the RCP breakers associated with the bus.

A time delay pickup relay is used to prevent spurious trips from short term perturbations.

This trip is blocked below 10% reactor power.

Note:

If relays associated with the 12 kV Bus D are being tested, the 12 kV BUS D RCP UV & UF RLY ON TEST annunciator on PK19-08 is actuated.

For the 12 kV Bus E relays in test, the 12 kV BUS E RCP UV & UF RLY ON TEST annunciator PK19-13 is actuated.

Continued on next page J5.DOC 2 - 62 REV. 9

RO QUESTION 48 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 063 K3.01 Importance 3.7* 4.1 Proposed Question:

The Unit 1 CO is unable to shutdown Diesel Generator 1-1 due to a total loss of DC power.

You are instructed to shutdown the Diesel locally.

This is accomplished by performing which of the following actions?

A. Operating the local trip lever on the overspeed trip device.

B. Taking local control of the Diesel and going to STOP on the local control switch.

C. Pushing the Emergency shutdown pushbutton located just outside of the D/G room.

D. Placing the local mode control switch in TEST and depressing the local Voltage Shutdown pushbutton.

Proposed Answer:

A. Operating the local trip lever on the overspeed trip device.

Explanation:

A correct, Per OP J-6B:IV Diesel Generator 1-1, Manual Operations Normal shutdown of a D/G requires DC control power. If it becomes necessary to shutdown the D/G without control power, manually operate the trip lever on the north west corner of the engine, forward of the fuel oil filters. (this is the overspeed trip device)

A incorrect, air motors will not cause the diesel to stop.

B, C and D incorrect, are ineffective without control power.

Technical Reference(s): OP J-6B:IV Diesel Generator 1-1, Manual Operations Drawings 437579 and 437580 (separate PDF file)

Proposed references to be provided to applicants during examination: none ro tier 2 group 1_48 rev1.doc

Learning Objective: 69182 - Describe Diesel Generators instrumentation and controls, including symptoms of failure modes.

Question Source: Bank # DCPP C-61753 Modified Bank #

New Question History: Last NRC Exam ____________

Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis 10 CFR Part 55 Content: 55.41 41.10 55.43 Comments:

K/A: 063 K3.01 - Knowledge of the effect that a loss or malfunction of the DC electrical system will have on the following: ED/G ro tier 2 group 1_48 rev1.doc

5. PRECAUTIONS AND LIMITATIONS 5.1 Paralleling the diesel to Startup power defeats both 2nd level UV relays. Refer to Tech Spec 3.3.5.

5.2 If the D/G is paralleled to the auxiliary transformer and the main unit trips, the aux bus feeder breaker will automatically open and the D/G will carry the bus load.

Verify that the bus feeder breaker opened and place the D/G MODE SEL switch into AUTO.

5.3 If the D/G is paralleled to startup power and a loss of offsite power occurs, the startup feeder breaker will not automatically open. The D/G will attempt to supply power to loads connected to the grid. Open the startup feeder breaker or verify the D/G breaker tripped. Place the D/G MODE SEL switch into AUTO if the feeder breaker was opened.

5.4 When paralleling a D/G to any off site power source or the D/G MODE SEL switch is in MANUAL and the D/G is not running, declare the D/G inoperable. In MODES 1, 2, 3, and 4, perform the actions required for Tech Spec 3.8.1. In MODES 5, 6, and irradiated fuel movement, perform the actions required for Tech Spec 3.8.2.

5.5 The D/G should not be operated for an extended period of time below 0.65 MW.

5.5.1 If a D/G is operated < 0.65 MW for < one hour, no action is necessary.

5.5.2 If a D/G is operated < 0.65 MW for ³ one hour but < 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months , then the D/G should be operated ³ 1.30 MW for ³ one hour.

5.5.3 If the D/G is to be operated for longer than 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months £ 0.65 MW, the D/G should be loaded to ³ 1.3 MW for > one hour at the end of each 10 hour1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months period.

NOTE: Operation of D/G < 0.65 MW for an extended period of time can expose the engine to undesirable conditions which may be detrimental to engine performance and component life.

5.5 Do not operate the D/G below rated speed with the field energized. Excessive field currents and rotor temperatures may occur.

5.6 When paralleling a D/G, pick up load (0.50 MW) as soon as possible (< 15 seconds) after the breaker is closed. This will prevent the D/G breaker from tripping on directional power (DIR PWR).

5.7 There should be fuel oil in the priming tank. If there is not, the priming tank should be filled using the magnetic pump. Document problem in an AR.

ro tier 2 group 1_48 rev1.doc

5.9 The fuel oil pressure should increase to above 40 PSIG within 60 seconds of engine start. Gauge response is about 15 seconds.

5.10 Do not violate the following limits during normal steady -state operation:

5.10.1 Maximum continuous generator current is 451 amperes.

5.10.2 Maximum stator temperature is 240°F.

5.10.3 Minimum lube oil pressure is 60 PSIG.

5.10.4 Maximum lube oil temperature is 195°F.

5.10.5 Power factor: 1.0 to 0.8 lag.

5.10.6 Load: 2.60 MW at 0.8.

5.11 Normal shutdown of a D/G requires DC control power. If it becomes necessary to shutdown the D/G without control power, manually operate the trip lever on the north west corner of the engine, forward of the fuel oil filters.

5.12 Do not operate more than one D/G at a time paralleled to any transformer (startup or unit auxiliary) in MODE 1, 2, 3, or 4 (SR 3.8.1.3 Note 3).

ro tier 2 group 1_48 rev1.doc

1 C-61753 Points: 1.00 Multiple Choice The Unit 1 CO is unable to shutdown Diesel Generator 1-2 due to a total loss of D.C. power. He instructs you to shutdown the Diesel locally. How can that be accomplished?

A. By operating the local trip lever on the overspeed trip device.

B. By isolating all starting air motors.

C. By pushing the Emergency shutdown pushbutton located just outside of the D/G room.

D. By taking local control of the Diesel and going to STOP on the local control switch.

Answer: A ASSOCIATED INFORMATION:

Associated objective(s):

69182 Describe Diesel Generators instrumentation and controls, including symptoms of failure modes.

Reference Id: C-61753 Must appear: No Status: Active User Text:

User Number 1: 0.00 User Number 2: 0.00 Difficulty: 2.00 Time to complete: 3 Topic: D/G shutdown with no D.C control power Cross

Reference:

Comment: created for R011C12, jpl1, 5/31/01.

RO QUESTION 49 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 064 A3.10 Importance 2.8 2.8*

Proposed Question:

Diesel DG 13 is carrying 4160V bus F following a loss of normal power to the bus and SI actuation.

The Operator goes to RAISE on the diesel's speed control for three (3) seconds.

Which of the following represents the effect this action has on indicated bus voltage, frequency, Mwe and Kvar?

VOLTS FREQ Mwe Kvar A. UP SAME SAME SAME B. SAME SAME UP UP C. UP UP UP UP D. SAME SAME SAME SAME Proposed Answer:

D. SAME SAME SAME SAME Explanation:

A incorrect, this is true if volts is raised (previous answer on question)

B incorrect, load is set by sequencer C incorrect, this is if in DROOP mode and volts are raised as well.

D correct, Volts set by voltage control switch, freq set at 60 hz, load determined by bus loading.

Technical Reference(s): J6B - Diesel Generator System ro tier 2 group 1_49.doc

Proposed references to be provided to applicants during examination: none Learning Objective: 4158 - Explain the Isochronous/Droop modes of operation.

Question Source: Bank #

Modified Bank # DCPP P-1228 New ______

Question History: Last NRC Exam DCPP SRO 2/94 Question Cognitive Level:

Memory or Fundamental Knowledge Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.7 55.43 _____

Comments:

K/A: 064 A3.10 - Ability to monitor automatic operation of the ED/G system, including:

Function of ED/G megawatt load controller ro tier 2 group 1_49.doc

1 P-1228 Points: 1.00 Multiple Choice Given the following:

- Diesel DG 13 is carrying 4160V Bus F following a loss of normal power to the bus. (Normal inputs open and NO other loads added).

- A Safety Injection actuation has loaded the bus.

- The operator goes to RAISE on the diesel's speed AND voltage controls for three (3) seconds.

Which of the following best represents the results of this action?

VOLTS FREQ Mwe Kvar A. UP SAME SAME SAME B. SAME SAME UP UP C. UP UP UP UP D. UP UP SAME SAME Answer: A ASSOCIATED INFORMATION:

Associated objective(s):

6214 Demonstrate the ability to diagnose AC Distribution system malfunctions Reference Id: P-1228 Must appear: No Status: Active User Text: 6214.070525 User Number 1: 2.90 User Number 2: 3.70 Difficulty: 2.00 Time to complete: 3 Topic: Predict DG op parameters for single source supply Cross

Reference:

Comment: DCPP NRC SRO Exam 2/16/94

Diesel Generator System Normal Operations, Continued Normal Operations, Continued Diesel load The tables below list how diesel parameters are controlled when the diesel generator control is operating isolated, and when it is operating paralleled:

Obj 33 If the D/G is carrying the 4 kV bus by itself (i.e., if D/G is not paralleled):

Parameter Control Control Mode ISOC Frequency Controlled to maintain 60 hertz Voltage Raised or lowered by the D/G Voltage Control Switch MW Determined by bus loading MVAR Determined by bus loading If the D/G is paralleled to the bus (i.e., sharing load):

Parameter Control Control Mode DROOP Frequency Determined by Aux. or Startup power (i.e., 60 Hz).

Voltage Determined by Aux. or Startup power.

MW Determined by torque applied to the generator by the diesel engine; raised or lowered by the D/G Speed Control switch.

MVAR Determined by diesel generator excitation; raised or lowered by the D/G Voltage Control switch.

Shifting control For normal steady-state diesel generator operation, the diesel will always be in:

Droop control when paralleled, or

ISOC control when operating isolated.

However, for certain lineup changes, diesel generator control may momentarily be in the opposite configuration. Examples:

When shifting a diesel from paralleled to isolated operation in OP J-6B:IV:

the diesel is initially in Droop control, the Aux. feeder breaker or Startup feeder breaker is opened, placing the entire bus load on the diesel, the diesel is placed in AUTO (i.e., shifted from Droop to ISOC control).

When shifting diesel from isolated operation to paralleled operation in STP M-15, the diesel is shifted to MANUAL (i.e., Droop) prior to paralleling.

When diesel is isolated in Droop control, frequency drop could occur:[WKD21]

If bus frequency lowers, the speed of all the pumps on the bus lowers If pump speed lowers, pump flow rate lowers (for example, if bus frequency lowers, RHR flow rate would lower)

Operator should immediately check frequency when shifting control modes.

Continued on next page J6B.DOC 3 - 10 REV. 14

RO QUESTION 50 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 064 A3.03 Importance 3.4 3.3 Proposed Question:

Unit 1 is at 100% power.

The crew is preparing to parallel 11 EDG to its vital bus.

The operator is preparing to close the generator breaker.

To properly close the breaker, what should be the synchroscope indication when the breaker is closed?

A. Rotating slowly in the SLOW direction, lights OFF.

B. Rotating slowly in the SLOW direction, lights FULL BRIGHT.

C. Rotating slowly in the FAST direction, lights OFF.

D. Rotating slowly in the FAST direction, lights FULL BRIGHT.

Proposed Answer:

C. Rotating slowly in the FAST direction, lights OFF.

Explanation:

C correct: OP J-6B:IV, Diesel Generator 1-1, Manual Operations states:

6.2.4 Verify synchroscope working

a. Lights OFF at the 12 o'clock position.

b. Lights FULL BRIGHT at the 6 o'clock position.

6.2.5 Adjust engine speed up and down to verify the manual governor is in control. Set engine speed so the synchroscope is turning slowly in the clockwise (FAST) direction. This will allow the diesel to pick up load when paralleled to the bus.

ro tier 2 group 1_50 rev1.doc

6.2.7 When the synchroscope pointer is slightly before the 12 o'clock position, turn generator breaker 52-HH-7 control switch to the CLOSE position.

Technical Reference(s):

OP J-6B:IV, Diesel Generator 1-1, Manual Operations Proposed references to be provided to applicants during examination: none Learning Objective:

4158 - Explain the Isochronous/Droop modes of operation.

Question Source: Bank #

Modified Bank # _______

New X Question History: Last NRC Exam ____________

Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis 10 CFR Part 55 Content: 55.41 41.7 55.43 _____

Comments:

K/A: 064 A3.03 - Ability to monitor automatic operation of the ED/G system, including:

Indicating lights, meters, and recorders ro tier 2 group 1_50 rev1.doc

STP M-9A

6. INSTRUCTIONS 6.1 Manually Start/Stop Diesel From Control Room.

6.1.1 Verify that cardox fire protection to Diesel Generator 1-1 is not aborted (D/G Room 1-1 Abort Valve Close alarm not in) using the Fire Protection Computer.

(Refer to OP K-2C) 6.1.2 Check main annunciator windows associated with the Diesel Generator not in alarm. At minimum, consider the effects of each alarm on diesel operation before proceeding.

6.1.3 Dispatch an operator to engine room with at least these instructions:

a. Make cardox available, if aborted.

b. Establish communication with Control Room, as needed.

6.1.4 At Diesel 1-1 Control Panel (VB-4)

a. Place the D/G 1-1 MODE SEL switch in the MANUAL position.

b. CUT-IN or verify cut-in the Generator Protective Relays.

c. START the Diesel by momentarily turning the start/stop switch to the start position.

d. Verify diesel cranks up to speed of about 900 RPM in 10 seconds or less and 4160V (120V on indicator) in 13 seconds or less.

e. Adjust engine speed to 900 RPM with governor speed control switch if needed.

f. Adjust generator output voltage to 120 volts indicated using the voltage control switch, if needed.

ro tier 2 group 1_50 rev1.doc

STP M-9A 6.1.5 To Shutdown diesel without paralleling to a Bus perform the following:

a. Adjust the DG speed to ~60 Hz.

b. Adjust the DG voltage to ~119VAC.

c. Shutdown the DG.

d. Verify Generator Protective Relays are Cut Out.

e. When DG speed reaches zero, place the DG 11 Mode Sel switch to AUTO.

f. Remove the poly bottles at the DFO leak off lines per STP M-9A, if installed.

6.1.6 Inform SFM of the Diesel Generator status.

6.2 Paralleling/Separating Diesel To/From Bus H 6.2.1 Verify steps 6.1.4a and 6.1.4b have been performed.

6.2.2 Check diesel generator output voltage on each phase. Otherwise, when synchroscope is turned ON (next step) the voltmeter will lock on to phase C.

6.2.3 Cut in the D/G 1-1 FEEDER SYNC Switch.

6.2.4 Verify synchroscope working

a. Lights OFF at the 12 o'clock position.

b. Lights FULL BRIGHT at the 6 o'clock position.

6.2.5 Adjust engine speed up and down to verify the manual governor is in control. Set engine speed so the synchroscope is turning slowly in the clockwise (FAST) direction.

This will allow the diesel to pick up load when paralleled to the bus.

NOTE: VARs should be slightly out, ~0.3 MVARS OUT, while the DG is paralleled in the Droop mode.

6.2.6 Adjust generator voltage to within +/-2 volts of bus voltage.

6.2.7 When the synchroscope pointer is slightly before the 12 o'clock position, turn generator breaker 52-HH-7 control switch to the CLOSE position.

ro tier 2 group 1_50 rev1.doc

RO QUESTION 51 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 1 _____

Group # 2 _____

K/A # 073 K1.01 Importance 3.6 3.9 Proposed Question:

Unit 2 is at full power. A small steam generator tube leak is causing steam line radiation monitor RM-73 to read 1000 cpm.

If the monitor is functioning properly, what should happen to the indication if power is reduced to 50%?

A. Indication should decrease due to the decrease in N-16 production.

B. Indication should decrease due to the decrease in iodine production.

C. Indication should remain the same due to the continued tube leakage.

D. Indication should increase because there is less steam flow but the same amount of radiation.

Proposed Answer:

A. Indication should decrease due to the decrease in N-16 production.

Explanation:

The steam line radiation monitors detect N-16 from the tube leakage. Once the unit is shutdown, N-16 production ceases and the indication will decrease.

Technical Reference(s): G4A - Radiation Monitoring, SOE-93-001 Proposed references to be provided to applicants during examination: None.

Learning Objective: 8485 Explain the conditions that effect Radiation Monitoring system radiation monitor indications Question Source: Bank #

Modified Bank # S-1207 New ______

Question History: Last NRC Exam N/A ro tier 2 group 1_51.doc

Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ___

10 CFR Part 55 Content: 55.41 41.11 55.43 _____

Comments: K/A: 073 K1.01 - Knowledge of the physical connections and/or cause effect relationships between the PRM system and the following systems:Those systems served by PRMs ro tier 2 group 1_51.doc

1 S-1207 Points: 1.00 Short Answer Steam line Rad monitor RM-73 was reading 1000 cpm with reactor power at 100%. During the rampdown, to take the unit off-line, the reactor tripped. RM-73 is now reading normal background (equal to other steam line Rad Monitors). Why did the reading decrease after the reactor trip?

Answer:

Prior to trip the rad monitor was detecting N-16 gamma from reactor coolant in-leakage. After reactor trip there is effectively no production of N-16 (to decay or be dectected by steam line Rad Monitors.

ASSOCIATED INFORMATION:

Associated objective(s):

8485 Explain the conditions that effect Radiation Monitoring system radiation monitor indications 69298 Explain the basic principles of operation for the Radiation Monitoring System.

69298 Explain the basic principles of operation for the Radiation Monitoring System.

5747 State RADIATION MONITORING system use for diagnosing a SGTR Reference Id: S-1207 Must appear: No Status: Active User Text:

User Number 1: 0.00 User Number 2: 0.00 Difficulty: 0.00 Time to complete: 3 Topic: Steam Line Rad Monitor response after a trip Cross

Reference:

LG-4 Comment:

Integrated Operations Industry Events SOE-93-001 Palo Verde 2 (March 14, 1993)

Event A S/G tube ruptured causing a leak of approximately 240 gpm. Plant operators used the emergency operating procedures to diagnose and mitigate the event but twice failed to diagnose a tube rupture. The radiation monitors that would have led to that diagnosis were not in an alarm status when the applicable step in the procedure was reached. As a consequence, the operators did not isolate the affected S/G until almost 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months after the rupture occurred.

Discussion The Main Steam Line Monitors are sensitive to N16 gamma radiation which decays off quickly after shutdown. By the time the procedure called for monitoring these instruments, the readings were down to near normal, inferring no S/G tube rupture.

Corrective Action The equivalent monitors RM-71 through 74 are recorded on the PPC recorders on VB-2 to identify trends or spikes that might not have been seen during the initial phases of the event.

SGTR Rapid Identification Blowdown Sample Guide: Chemistry analysis procedure CAP AP-1, Prompt Steam Generator Leak Identification Procedure provides a method of promptly identifying any leaking/ruptured S/Gs within 30 min. or if the leak rate and/or RCS activity is sufficiently high, the affected S/G(s) may be identified more quickly by using a frisker to determine the highest count rate(s).

Main Steam Line Radiation Monitor Response to a DBA LOCA: Radiation shine from containment will alarm all four (4) main steam line radiation monitors during a DBA LOCA without a SGTR in progress. A knowledge item has been added to six (6) EOP background documents to exclude entering EOP E-3 if all four (4) main steam line radiation monitors exhibit the same order of magnitude response. The six emergency procedures affected are EOP E-0, E-1, E-1.2, E-2, ECA-2.1, and FR-H.3.

Continued on next page G4A.DOC 4-5 REV. 6

RO QUESTION 52 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 073 A4.02 Importance 3.7 3.7 Proposed Question:

Which of the following is the minimum action(s) necessary to defeat CVI actuation due to a high radiation signal from Containment Exhaust Radiation Monitor RM-44A?

A. Place the CVI selector switch in MODE 6.

B. Place the ENABLE/BYPASS for RM-44A in BYPASS.

C. Place the ENABLE/BYPASS for RM-44A in BYPASS and CVI selector switch in MODE 6.

D. Place the CVI selector switch in MODE 6 and open breaker PJRM-11 on 1G.

Proposed Answer:

B. Placing the ENABLE/BYPASS for RM-44A in BYPASS.

Explanation:

A incorrect, CVI selector defeats SSPS input.

B correct, in BYPASS, CVI due to high radiation is defeated.

C incorrect, CVI selector defeats SSPS input.

D incorrect, not necessary to de energize the monitor.

Technical Reference(s): G4B - Digital Radiation Monitoring System Proposed references to be provided to applicants during examination: none Learning Objective: 3279 - Explain the operation of Digital Radiation Monitoring System controls in control room.

Question Source:

New X Question History: Last NRC Exam N/A ro tier 2 group 1_52.doc

Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 41.11 55.43 _____

Comments:

K/A: 073 A4.02 - Ability to manually operate and/or monitor in the control room:

Radiation monitoring system control panel ro tier 2 group 1_52.doc

RM-44A and 44B Ctnmt Exhaust Monitors, Continued Control The controls associated with the Containment Exhaust Radiation Monitors are shown in the tables below.

For controls that are common to all LRP and RDU refer to the section LRP and RDU in this STG.

RNRMS1 and 2 Control Operation CVI RE-44A ENABLE/BYPASS 2 position maintained keyswitch CVI RE-44B ENABLE/BYPASS 2 position maintained keyswitch Logic The logic associated with Containment Exhaust Radiation Monitors are shown in the table below.

If the CVI RM-44A switch is in ... Then ...

ENABLE the automatic actuation of CVI is enabled from a high alarm on RM-44A.

BYPASS the automatic actuation of CVI is blocked from a high alarm on RM-44A.

If the CVI RM-44B switch is in ... Then ...

ENABLE the automatic actuation of CVI is enabled from a high alarm on RM-44B.

BYPASS the automatic actuation of CVI is blocked from a high alarm on RM-44B.

Continued on next page G4B.DOC 2 - 44 REV. 4

Reactor Protection System Containment Ventilation Isolation Actuation, Continued Logic (continued)

IF CVI Mode 6 selector Then switch is in NORMAL and...

the Train A (B) CVI signal is reset as follows.

the manual Phase A or B actuation signals go through a retentive memory unit and will seal in until reset, the CVI cannot be reset until the initiating signal has been reset.

the SI and RM-44A/B actuation signals go through retentive memory with manual reset CVI Train A (B) is units and will also seal in until reset.

RESET The signal can be reset even though the initiating signal is still present.

NOTE: If the unit is reset with one rad monitor in alarm, the signal from the other rad monitor is disabled until both clear.

PK02-06, CVI will clear.

Red light for Train A (B) above Monitor Light Box B goes out.

IF CVI Mode 6 selector Then switch is in MODE 6 and...

CVI will be actuated.

RM-44A or B alarm on

PK02-06, CVI will alarm.

high radiation

Red light for Train A (B) above Monitor Light Box B is illuminated.

Phase A CI is manually actuated Phase B CI is manually CVI will not be actuated. (TS violation if in actuated Modes 1 through 4) any SI signal is generated Continued on next page B6A.DOC 2.2 - 27 REV. 13

RO QUESTION 53 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 076 K3.05 Importance 3.0* 3.2*

Proposed Question:

PLANT CONDITIONS:

RHR cooldown initiated using RHR pump 1-1 and 1-1 heat exchanger

RHR flow is 3000 gpm

A cooldown rate of 30 ºF/hr has been established Which of the following failures will cause the cooldown rate to decrease?

A. Loss of Aux Saltwater.

B. Loss of power to FCV-641A (RHR Pump Recirc valve).

C. Loss of control air to HCV-133 (RHR HX Outlet to CVCS control valve).

D. Maximum control air signal is applied to HCV-670 (RHR HX Bypass FCV).

Proposed Answer:

A. Loss of Aux Saltwater.

Explanation:

A, correct, results in less cooling to the CCW heat exchanger which will lead to less cooling for RHR heat exchanger.

B incorrect, loss of power to the recirc valve (MOV) will result in the valve maintaining its current position.

C incorrect, valve fails closed on loss of air but will have no effect on cooldown rate.

D incorrect, valve will close, all flow thru the heat exchanger, cooldown will increase.

Technical Reference(s): B-2, RHR, pages 1-5, 2-30, 2-38 Proposed references to be provided to applicants during examination: None Learning Objective: 7009 - Analyze the control logic for RHR system valves.

8089 - Analyze control logic for CCW components.

ro tier 2 group 1_53.doc

Question Source:

Modified Bank # INPO 20643 Question History: Last NRC Exam Kewaunee 09/2002 Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.4 55.43 _____

Comments:

076 K3.05 - Knowledge of the effect that a loss or malfunction of the SWS will have on the following: RHR components, controls, sensors, indicators, and alarms, including rad monitors ro tier 2 group 1_53.doc

INPO Licensed Operator Exam Bank - PWR Questions ID: 20643 Given the following plant conditions:

- Reactor Coolant System temperature is 320F.

- Reactor Coolant System pressure is 370 psig.

- RHR cooldown operations has been established with both RHR pumps and heat exchangers in service.

- A cooldown rate of 80F/hr has been established.

Which one of the following failures will cause the cooldown rate to increase?

Ans Loss of control air to RH-626 (RHR HX Bypass FCV).

D1 Loss of power to CC-738A (HX-11A RHR HX-Shell Side Inlet Valve).

D2 Maximum control air signal to RH-624 (HX-11A RHR HX Outlet FCV).

D3 The bellows in FT-626 (RHR System Return Line Flow) fails by rupturing.

AbbrevLocName ExamDate Vendor Type ExamType Cog Level ExamLevel RefMaterial ParentId Point Beach 1 2/2/2002 WEC PWR ILO R QuestionComment Distract1Comment Distract2Comment Distract3Comment KaNumber KaSegment1 KaSegment2 KaSegment3 KaSegment4 KaSegment5 KaRevision

..005.a1.01 005 a1 01 Tuesday, September 21, 2004 Page 7771 of 9479

Residual Heat Removal System Basic Description Purpose of the The purpose of the Residual Heat Removal (RHR) system is to transfer decay RHR System (residual) heat and sensible heat under normal and emergency conditions Obj 1 from the Reactor Coolant System (RCS) (and the core) to the Component Cooling Water (CCW) system, where it is transferred to the Auxiliary Salt Water (ASW) system and then to the ultimate heat sink, the Pacific Ocean.

Other purposes are as follows:

Inject into the RCS during a Loss of Coolant Accident (LOCA) (discussed in the ECCS chapter)

Prevent boron stratification in the RCS

Transfer water between the Refueling Water Storage Tank (RWST) and the refueling cavity

Transfer water to the Chemical and Volume Control System (CVCS) for cleanup and pressure control

Transfer water from the Containment Recirculation Sump to the Containment Spray Headers for continuing post-accident spray after the Containment Spray System has emptied the RWST.

Basic The RHR system consists of:

Description Obj 2 Two parallel, redundant flow paths, each consisting of:

One RHR pump

One RHR to CCW Heat Exchanger

One flow control valve to control heat exchanger flow rate

Each path physically and electrically separated Each flowpath can take suction from:

The RWST

Loop 4 Hot Leg

Its own suction on the Containment Recirculation Sump Each flowpath can discharge to:

Two cold legs

Hot legs 1 and 2

A Containment Spray Header

Safety Injection (SI) Pumps or Centrifugal Charging Pumps (CCP)

The RWST

The CVCS Continued on next page B2.DOC 1-8 REV. 13

RHR Flow Control Valves, HCV-637, 638, 670 Purpose The purpose of HCV-637, 638, and 670 is to control flow through or around the heat Obj 7 exchangers for RCS temperature control.

Location The RHR Flow Control Valves are located as follows:

Obj 8, 11

HCV-637 and 638 are on the 85 elevation in the penetration area.

HCV-670 is located on the 100 elevation in the penetration area.

Physical HCV-637, 638, and bypass valve 670 are air operated, fail open ball valves.

description

HCV-637 and 638 are used to control flow through the heat exchanger.

HCV-670 is used to adjust bypass flow to maintain total flow constant.

HCV-637 and 638 have mechanical full open stops that ensure:

the RHR system is capable of delivering the required minimum flow rate, and

to prevent RHR pump runout.

The 100% open stop for each valve is set via STP V-4A, Functional Test of RHR Check Valves, to get a flow rate of 3976 gpm and < 4319 gpm. [dab1]

Control HCV-637, 638, and 670 have control capability from the:

Obj 20

Control Room on VB1, and

local jacking mechanism.

Control for the valve Operation Hand controller 0-100%

Indication The following indications are available for HCV-637, 638, and 670.

HCV-637, 638 and 670 controller Indication Meaning Normal Status HCV-637 Indicates the controller demand to 100%

the valve (0% closed, 100% open)

HCV-638 Indicates the controller demand to 100%

the valve (0% closed, 100% open)

HCV-670 Indicates the controller demand to 0%

the valve (0% closed, 100% open)

HCV-637, 638 Monitor Light Box A on VB1 Indicating Light Meaning Normal Status White Valve not fully OPEN OFF B2.DOC 2 - 30 REV. 13

Major Components RHR HX Outlet to CVCS Control Valve, HCV-133 Purpose The purpose of HCV-133 is to control flow to the CVCS letdown line for RCS chemistry control during RHR cooldown operations, and to aid in pressure control during solid plant operation.

Physical The HCV-133 is an air operated, fail closed valve used to letdown flow from description the RHR system to the CVCS system (upstream of the letdown heat exchanger) when RCS pressure is too low to provide sufficient flow through the normal letdown system.

Control HCV-133 has control capability from the Control Room on VB2.

Control for the valve Operation Hand controller 0-100%

Indication The following indication is available for HCV-133.

HCV-133 controller Indication Meaning Normal Status HCV-133 Indicates the controller demand to 0%

the valve (0% closed, 100% open)

B2.DOC 2 - 38 REV. 13

RO QUESTION 54 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 078 K4.01 Importance 2.7 2.9 Proposed Question:

Unit 1 was at 100% power when a total loss of instrument air occurred.

What must be done so that the 10% steam dumps can be controlled, and what is the source of control pressure to operate the valves?

A. Cut in toggle switch on VB-3, control is via backup nitrogen.

B. Leave Hagan controller in auto, control is via backup nitrogen.

C. Leave Hagan controller in auto, control is via backup air bottles.

D. Place Hagan controller in manual, control is via backup air bottles.

Proposed Answer:

B. Leave Hagan controller in auto, control is via backup nitrogen.

Explanation:

A incorrect, cutout switch associated with backup air.

B correct, nitrogen will operate the valves as pressure decreases below 85 psig.

C incorrect, backup air bottles operate if pressure decreases below 80 psig (once nitrogen depleted).

D incorrect, backup air is placed in service by operating the cutout switch on VB3. Even if nitrogen pressure went to 0, no steam dumps could be operated without operating the cutout switch.

Technical Reference(s): C2B - Steam Dump System page 2.1-14 Proposed references to be provided to applicants during examination: none ro tier 2 group 1_54.doc

Learning Objective: 8042 - Explain physical connections and/or cause effect relationships between the Steam Dump System and other systems.

Question Source: Bank # INPO 22521 Question History: Last NRC Exam DCPP 10/2002 Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 41.7 55.43 _____

Comments: K/A: 078 K4.01 - Knowledge of IAS design feature(s) and/or interlock(s) which provide for the following: Manual/automatic transfers of control ro tier 2 group 1_54.doc

INPO Licensed Operator Exam Bank - PWR Questions ID: 22521 Unit 1 was at 100% power when a total loss of instrument air occurred.

What must be done so that the 10% steam dumps can be controlled, and what is the source of control pressure to operate the valves?

Ans Leave Hagan controller in auto, control is via backup nitrogen.

D1 Leave Hagan controller in auto, control is via backup air bottles.

D2 Place Hagan controller in manual, control is via backup air bottles.

D3 Cut in toggle switch on VB-3, control is via backup nitrogen.

AbbrevLocName ExamDate Vendor Type ExamType Cog Level ExamLevel RefMaterial ParentId Diablo Canyon 1 10/1/2002 WEC PWR ILO 2 S QuestionComment Distract1Comment Distract2Comment Distract3Comment KaNumber KaSegment1 KaSegment2 KaSegment3 KaSegment4 KaSegment5 KaRevision

..065.AA2.07 065 AA2 07 Tuesday, September 21, 2004 Page 8468 of 9479

10% Steam Dump Valves, Continued Air control valves (continued)

Direct Control solenoid valves*

Key Solenoid status Position of ports number 8 Solenoid de-energized (switch not in open valve is closed position)

Solenoid energized (switch selected to valve is open open) 9 Solenoid de-energized (switch not in close valve is closed position)

Solenoid energized (switch selected to valve is open close)

When direct control is enabled the operator may control valve position by applying air to the actuator through (8) or venting air from the actuator through (9).

Backup Valve actuation pressure is normally from instrument air (supplied at 100 psig).

actuator backup sources are shown in the figure above and in the table below.

supplies Obj 15 Source Supply When in service pressure Nitrogen 85 psig If instrument air pressure drops to less than 85 psig the pressure from the nitrogen system will seat the instrument air check valve and begin to supply the actuator.

Backup air 80 psig The backup air bottles are not available unless the bottles* supply is cut in on VB-3.

Note that when the backup air supply is cut in it is the only source of control air to the valve and is controlled by the operator manually on VB-3.

When backup air bottles are cutin the air bottle supply can operate the Steam Dump valve through ten complete cycles for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months at the minimum pressure, (260psig) normally pressure is 1000 to 2250 psig.

T.S.LCO The back-up air bottle for each 10% Steam Dump valve must be greater than Obj 28 260 psig for the Steam Dump valve to be Operable.

Continued on next page C2B.DOC 2.1 - 14 REV. 11

RO QUESTION 55 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 103 A2.03 Importance 3.5* 3.8*

Proposed Question:

You are performing the actions of Appendix E, ESF Auto Actions, Secondary and Auxiliaries Status.

At step 2, Verify Containment Isolation Phase A, you note that one Red light is lit, the other is out and approximately half the White lights are lit.

Which of the following describes the probable failure and action necessary to address the failure?

A. The train of Phase A with the Red light lit failed to actuate. Manually actuate Containment Isolation Phase A or manually reposition the components corresponding to the lights that are out.

B. The train of Phase A with the Red light lit failed to actuate. Manually actuate Containment Isolation Phase A or manually reposition the components corresponding to the lights that are lit.

C. The train of Phase A with the Red light out failed to actuate. Manually actuate Containment Isolation Phase A or manually reposition the components corresponding to the lights that are out.

D. The train of Phase A with the Red light out failed to actuate. Manually actuate Containment Isolation Phase A or manually reposition the components corresponding to the lights that are lit.

Proposed Answer:

D. The train of Phase A with the Red light out failed to actuate. Manually actuate Containment Isolation Phase A or manually reposition the components corresponding to the lights that are lit.

ro tier 2 group 1_55 rev1.doc

Explanation:

A and B incorrect, the Red light indicates that train has actuated, no action required for that train.

C incorrect, the white lights that are out correspond to the train that actuated.

D correct, the light out indicates that train has failed to actuate. The action is to actuate Containment Phase A or manually close valves with white lights lit.

Technical Reference(s):

E-0, Appendix E B6A, ESFAS pages 2.2-17 Proposed references to be provided to applicants during examination: none Learning Objective: 4006 - Explain the conditions that affect Monitor Light Box lights.

Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.7 55.43 Comments:

K/A: 103 A2.03 - Ability to (a) predict the impacts of the following malfunctions or operations on the containment system and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those malfunctions or operations: Phase A and B isolation ro tier 2 group 1_55 rev1.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER EOP E-0 DIABLO CANYON POWER PLANT REVISION 28 PAGE 21 OF 33 TITLE: Reactor Trip or Safety Injection UNIT 1 APPENDIX E ESF AUTO ACTIONS, SECONDARY AND AUXILIARIES STATUS ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. CHECK Main Generator Tripped:

a. PK14-01, Unit Trip - ON a. Manually initiate a Main Unit Trip.

b. Verify 500KV Brkrs - Both Open b. Notify 500KV Switchyard to locally open the failed 500KV Brkrs.

o Green lights - ON OR o Turbine speed - decreasing

c. Check Exciter Field Breaker - OPEN c. WHEN Both 500KV Brkrs are open, THEN Open the Exciter Field Brkr manually or locally.

2. VERIFY Containment Isolation Do one of the following:

Phase A:

o Manually actuate CONTMT ISOL

a. Phase A portion of Monitor Light PHASE A Box B:

OR o Red Activated Light-ON o Manually Close the Phase A Isol o White Status Lights-OFF vlvs with White Status Lights-ON.

3. VERIFY Containment Vent Isol: Do one of the following:

a. Containment Vent Isol portion of o Actuate CVI by Manual CONTMT M onitor LightBox B: ISO L PH A SE A o Red Activated Light - ON OR o White Status Lights - OFF o Manually Close the CVI vlvs with White Status Lights-ON.

Reactor Protection System Phase A Containment Isolation Actuation Purpose The purpose of the Phase A Containment Isolation (CI) Actuation signal is to Obj 25 isolate all non-essential process lines into or out of the Containment, to provide Containment integrity during accident conditions.

Description The Phase A CI is either automatically actuated by a Safety Injection signal Obj 13 or can be manually actuated with control switches in the Control Room.

Controls The following controls are available for the Phase A CI Actuation signal.

Obj 32, 33 In the Control Room:

Control Operation ACTUATE Trains A&B on VB-1 2 position, spring return to neutral ACTUATE Trains A&B on CC-2 RESET Train A pushbutton RESET Train B Logic The following logic applies to the Phase A CI Actuation signal.

Obj 27, 29 IF Then Phase A CI will be actuated.

PK02-01, CI Phase A/B will alarm.

Safety Injection

Red light for Train A above Monitor Light Box B is is actuated illuminated.

Red light for Train B above Monitor Light Box B is illuminated.

Phase A CI will be actuated.

manual Phase A

Containment Ventilation Isolation is actuated.

CI is actuated

PK02-01, CI Phase A/B will alarm.

from either

Red light for Train A above Monitor Light Box B is switch illuminated.

Red light for Train B above Monitor Light Box B is illuminated.

Continued on next page B6A.DOC 2.2 - 17 REV. 13

RO QUESTION 56 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 2 _____

K/A # 001 K6.13 Importance Rating 3.6* 3.7*

Proposed Question:

The DRPI Accuracy Mode Switch is in the A + B position. Indicated Control Bank D rod position on VB-2 is 12 steps.

Which of the following states what indicated rod position on VB-2 will be if the Accuracy Mode switch is taken to Data A only or Data B only positions?

Switch in Data A only Switch in Data B only Indication on VB-2 is: Indication on VB-2 is:

A. 6 steps 6 steps B. 6 steps 18 steps C. 12 steps 12 steps D. 18 steps 6 steps Proposed Answer:

C. 12 steps 12 steps Explanation: The resolution of the detector is six steps (3.75 inches).

The tables below describe how detector accuracy is obtained for various detector configurations.

ro tier 2 group 2_56.doc

Coil Data VB-2 Indicated True Rod (When Penetrated) Rod Position Position A&B A Data B Data A Only B Only (Steps)

Data Etc Etc Etc Etc Etc Etc (B3) (2) 24 24 24 21 (A3) (2) 18 24 12 15 (B2) (1) 12 12 12 9 (A2) (1) 6 12 0 3 0

(B1) 0 0 0 (A1)

Rod Drive Assembly Technical Reference(s): System text Digital Rod Position Indication System.

Vision questions S-0879 and S-0880 Proposed references to be provided to applicants during examination: None Learning Objective: 4913 - Explain the operation of DRPI Question Source:

Modified Bank # S-0879 and S-0880 (attached)

New _______

Question History: Last NRC Exam: N/A Question Cognitive Level: Memory or Fundamental Knowledge Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.6 55.43 _____

Comments:

K/A: 001 K6.13 - Knowledge of the effect of a loss or malfunction on the following CRDS components: Location and operation of RPIS ro tier 2 group 2_56.doc

1 S-0879 Points: 1.00 Multiple Choice Given that Bank D is at 6 steps, What will indicated rod position be if Data A fails?

A. 0 steps B. 4 steps C. 6 steps D. 12 steps Answer: A ASSOCIATED INFORMATION:

Associated objective(s):

4913 Explain the operation of DRPI Reference Id: S-0879 Must appear: No Status: Active User Text: 4913.010013 User Number 1: 3.00 User Number 2: 3.90 Difficulty: 3.00 Time to complete: 2 Topic: rod position indication if data A fails Cross

Reference:

STG A3B Comment: Checked OK, 2/25/96, GES VALIDATION DATE: 4/3/95 DLH4 (no changes)

2 S-0880 Points: 1.00 Multiple Choice Given that Control Bank D is at 6 steps, What will indicated position be if Data B fails?

A. 0 steps B. 4 steps C. 6 steps D. 12 steps Answer: D ASSOCIATED INFORMATION:

Associated objective(s):

4913 Explain the operation of DRPI Reference Id: S-0880 Must appear: No Status: Active User Text: 4913.010013 User Number 1: 3.00 User Number 2: 3.90 Difficulty: 3.00 Time to complete: 2 Topic: rod position indication if Data B fails Cross

Reference:

STG A3B Comment: Checked OK, 2/25/96, GES LA-3B VALIDATION DATE: 4/3/95 DLH4 (no changes)

Section 2.0 Major Components Rod Position Detectors Purpose The purpose of the Rod Position Detectors is to locate the position of the Obj 4 control rod drive mechanism shaft within the drive housing so the position of the control rod within the core can be known.

Location The Rod Position Detectors are located around the CRDM housing of each Obj 5 rod.

Description Each detector unit is composed of 42 coils of wire divided into two groups (21 group A and 21 group B).

Each coil is located at a 3.75 interval along a stainless steel tube.

Eye Bolt Top Plate B21 A21 B2 Flanged Bobbin Spacing Locking Bolt Rods A2 Coil Assemblies B1 Cylinder A1 Bottom Plate RPI-02 Continued on next page A3B.DOC 2-1 REV 9

Major Components Rod Position Detectors, Continued Detector The resolution of the detector is six steps (3.75).

accuracy Obj 11

When true rod position is 0 steps the top of the CRDM shaft will be mid-way between coils B1 and A2.

This provides a nominal accuracy of +/- 3 steps.

Due to potential positioning errors and temperature effects another 1 step is subtracted from the accuracy making assumed accuracy +/- 4 steps.

The tables below describe how detector accuracy is obtained for various detector configurations.

Coil Data VB-2 Indicated True Rod (When Penetrated) Rod Position Position A&B A Data B Data A Only B Only (Steps)

Data Etc Etc Etc Etc Etc Etc (B3) (2) 24 24 24 21 (A3) (2) 18 24 12 15 (B2) (1) 12 12 12 9 (A2) (1) 6 12 0 3 0

(B1) 0 0 0 (A1)

Rod Drive Assembly RPI-03 Full accuracy rod position (group A and group B coils operable)

Stage Description 1 Determine highest coil penetrated in each group (e.g. A4 and B3) 2 Add together numeric values assigned to each coil (one less than the identifying number e.g. 3 and 2).

3 Add the values together and multiply by 6. (2+3)x6=30 steps.

4 The rod may actually be located at 30 steps +/- 4 (26 steps to 34 steps).

Continued on next page A3B.DOC 2-3 REV 9

Digital Rod Position Indication System Rod Position Detectors, Continued Detector accuracy (continued)

Half accuracy rod position (Data B coils only).

Stage Description 1 Operable coils are only located every 12 steps.

2 Determine the highest B group coil penetrated (e.g. B2).

3 Double the value for B2 (1) and multiply by 6. 2x1x6=12 steps.

4 The rod may actually be located between the actual position of B2 (9 steps) -1 additional step for accuracy and just below the actual position of B3 (21 steps) +1 additional step for accuracy. So the rod is between 8 steps and 22 steps, giving you an assumed accuracy of +10 to -4 steps from indicated position (12 steps).

Half accuracy rod position (Data A coils only).

Stage Description 1 Operable coils are only located every 12 steps.

2 Determine the highest A group coil penetrated (e.g. A2).

3 Double the value for A2 (1) and multiply by 6. 2x1x6=12 steps.

4 The rod may actually be located between the actual position of A2 (3 steps) -1 additional step for accuracy and just below the actual position of A3 (15 steps) +1 additional step for accuracy. So the rod is between 2 steps and 16 steps, giving you an assumed accraracy of -10 to +4 steps from indicated position (12 steps).

A3B.DOC 2-4 REV 9

Major Components Control Board Display Unit, Continued Control (continued)

Control Operation Accuracy Mode 3 position, maintain contact selector switch.

A+B

Selects full and half accuracy for the

A only entire system.

B only Manual Disconnect 4 position, maintain contact selector switch.

Off/I/II/III

Disconnects an individual central control card.

Logic The logic associated with the Accuracy Mode switch is shown below.

Obj 9 Switch position Result A+B Both group A and Group B detectors are used to determine rod position.

Gives full accuracy indication (+/-4 steps).*

A only Only group A detectors are used to determine rod position.

Gives half accuracy indication (+4 steps -10 steps).*

B only Only group B detectors are used to determine rod position.

Gives half accuracy indication (+10 steps -4 steps).*

See the detector section for a discussion of detector accuracy.

Continued on next page A3B.DOC 2-9 REV 9

RO QUESTION 57 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 2 _____

K/A # 014 A4.04 Importance Rating 2.7 2.7 Proposed Question:

PLANT CONDITIONS:

A Unit 1 startup is in progress following a reactor trip.

All equipment is operable.

The crew is placing Rod Control in service.

The operator takes the Rod Control Startup Reset switch to RESET to zero the Group Step Demand counters.

What additional change(s) should occur solely as a result of going to RESET?

A. Indicated Rod Speed goes to approximately 48 spm.

B. PK03-17, Rod Cont Urgent Failure annunciator clears.

C. PK03-18, Rod Cont Non Urgent Failure annunciator clears.

D. PK03-21, DRPI Failure/Rod Bottom annunciator clears.

Proposed Answer:

B. PK03-17, Rod Cont Urgent Failure annunciator clears.

Explanation:

A incorrect, rod speed goes to 48 spm when rods are placed in Manual.

B correct, the Urgent Failure alarms clears due to the reset.

C incorrect, the Non-Urgent failure should not be in.

D incorrect, rods are still on the bottom. The alarms clears during control bank withdrawal.

Technical Reference(s): A3A, Rod Control System, page 3-5 Proposed references to be provided to applicants during examination: None Learning Objective: 9917 - Explain the operation of ROD CONTROL system Question Source:

ro tier 2 group 2_57.doc

Modified Bank #

New X Question History: Last NRC Exam: N/A Question Cognitive Level: Memory or Fundamental Knowledge X Comprehension or Analysis 10 CFR Part 55 Content: 55.41 41.6 55.43 _____

Comments: Resampled KA. Original KA selected (A4.03) is not applicable. Randomly selected from KAs 014 A4.01, A4.02 and A4.04.

K/A: 014 A4.04 Ability to manually operate and/or monitor in the control room: Re-zeroing of rod position prior to startup ro tier 2 group 2_57.doc

Integrated Operations Normal Operations, Continued Effects of Equipment operating effects on system indications are summarized below.

operation, Although numerous possibilities exist for the initial conditions of operating a switches, Rod component, the information below assumes operation from a normal Control System configuration.

Effect of operating ... Consequence The operator should expect to see ...

Urgent Failure Alarm

Urgent Failure Alarm annunciator will clear Reset switch

Rod Motion if rods are in AUTO and a temperature deviation exists Manual Rod Control

Rod height to change In/Out Select switch

RCS temperature to change Control Rod Lift Coil

Rods will NOT move Disconnect switches

Group step counters reset to 0

Master cycler resets to 0 Rod Control Startup

Slave cyclers reset to 0 switch

Bank Overlap resets to 0

Urgent Failure Alarm resets

P/A converters reset to 0 Switch Consequence position If Manual Rod Control IN/OUT is operated then...

SBA, SBB The selected shutdown bank will SBC or SBD move.

The control rod banks will move Rod Bank/Mode Select MAN in their normal sequence and with switch correct bank overlap.

CBA, CBB, The selected control rod bank will CBC or CBD move with no programmed sequence or bank overlap Control rods will move as AUTO determined by the Reactor Control Unit.

Continued on next page A3A.DOC 3-5 REV. 11

RO QUESTION 58 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 1 _____

K/A # 016 K3.01 Importance 3.4* 3.6*

Proposed Question:

Which of the following events would cause Tave to decrease approximately 4ºF?

A. Power is reduced from 100% to 90% maintaining Tave on program.

B. 10% atmospheric steam dump valve fails open at 100% power, EOL, all rods out.

C. At 1% power, in a normal startup lineup, Main Steam pressure transmitter, PT-507 fails high. (No operator action)

D. At 100% power, with control systems in AUTO, Turbine Impulse pressure transmitter, PT-505 fails low. (No operator action)

Proposed Answer:

C. At 1% power, in a normal startup lineup, Main Steam pressure transmitter, PT-507 fails high. (No operator action)

Explanation:

A incorrect, at 100% power, Tave is 572ºF. Over all, Tave changes 25ºF, or .25ºF/%.

Therefore a 10% change will cause Tave to decrease 2.5ºF.

B incorrect, power will increase approximately 2.5%. Tave will decrease less than 4ºF C correct, PT-507 failing high will cause steam dumps (in steam pressure mode) to fail open. They will close at P-12. Tave will decrease from 547 to 543ºF, or 4ºF.

D incorrect, PT-505 failing low will cause rods to drive in. Tave will drop but without operator action, will decrease much more than 4ºF.

Technical Reference(s): A1 - Reactor Coolant System C2B - Steam Dump System Proposed references to be provided to applicants during examination: none ro tier 2 group 2_58.doc

Learning Objective: 10546, 10549, 10551 - Calculate the following parameters associated with the RCS for various power levels - TH, - TC, - DT, -

TAVG, - Pzr Level 8004 - Analyze Steam Dump System control logic.

Question Source: New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.5 55.43 _____

Comments:

K/A: 016 K3.01 - Knowledge of the effect that a loss or malfunction of the NNIS will have on the following: RCS ro tier 2 group 2_58.doc

Calculating RCS Parameters, Continued Variations with The variation with power level for key parameters is shown below.

610 power 600 604 590 T

Hot Leg 580 Temperature 572

°F T 570 Average 560 550 T

Cold Leg 540 540 T

STM 530 520 520 0 10 20 30 40 50 60 70 80 90 100

% Power RCS-15 Temperature Any temperature can be calculated as follows:

calculations Obj 45 T = P(TFP - TZP) + TZP Where: P = present power level fraction TFP = full power value of the temperature, °F TZP = zero power value of the temperature, °F or, T = TH - TC TAVG = (TH + TC)/2 Continued on next page A1.DOC 5-2 REV. 15

Abnormal Operations, Continued Unusual control The table below lists some unusual Steam Dump control system responses response due to system failures.

Refer to OIM figure C-2-8 If When Then Alternate alignments PT-507 Steam Press mode Steam pressure will indicate below Steam Pressure fails low (controller in setpoint and group 1&2 valves will controller in manual automatic) close (if open). allows direct control of valves.

PT 507 Steam Press mode Steam pressure will indicate above Steam Pressure fails high (controller in setpoint and group 1&2 valves will controller in manual automatic) open. allows direct control of

At P-12 setpoint, Tavg = 543°F, valves.

the group 1 & 2 valves will close.

Group 1 valves will not close if Selecting Off Reset will interlock is bypassed. close all valves PT-505 Tavg Mode (if Tref will drop to its minimum value Steam Press mode set at fails low valves armed by a (547°F) and armed valves will pressure for current subsequent load open. power.

rejection).

Load rejection controller will attempt to maintain Tavg = 547°F +

the offset value for the unit (4°F for Unit 1 and 3°F for Unit 2).

Continued on next page C2B.DOC 3 - 12 REV. 11

RO QUESTION 59 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 2 _____

K/A # 028 K2.01 Importance Rating 2.5* 2.8*

Proposed Question:

Which of the following conditions will cause the WHITE Power In Available light to be lit on Hydrogen Recombiner 1-2?

A. Either the normal or redundant breaker closed at 480V Vital Bus G.

B. Either the normal or redundant breaker closed at 480V Vital Bus H.

C. Both the normal and redundant breakers closed at 480V Vital Bus G.

D. Both the normal and redundant breakers closed at 480V Vital Bus H.

Proposed Answer:

D. Both the normal and redundant breakers closed at 480V Vital Bus H.

Explanation:

A incorrect, Bus G does not power recombiner 12.

B incorrect, correct power supply, but both must be closed.

C incorrect, Bus G does not supply recombiner 12 D correct, both supply breakers must be closed.

Technical Reference(s): OP H9, Inside Containment H2 Recombination System Proposed references to be provided to applicants during examination: None Learning Objective: 3650 - Identify the power supply for the Containment Hydrogen Recombiners Question Source: New X Question History: Last NRC Exam: N/A Question Cognitive Level: Memory or Fundamental Knowledge X 10 CFR Part 55 Content: 55.41 41.7 55.43 _____

ro tier 2 group 2_59 rev1.doc

Comments: K/A: 028 K2.01 - Knowledge of bus power supplies to the Hydrogen Recombiners ro tier 2 group 2_59 rev1.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP H-9 DIABLO CANYON POWER PLANT REVISION 9 PAGE 3 OF 6 TITLE: Inside Containment H2 Recombination System UNIT 1 INSTRUCTIONS Record the completion of the steps required on Attachment 9.3.

6.1 Recombiner Operation 6.1.1 Select an OPERABLE recombiner unit and close its associated breaker, verify redundant breaker closed.

NORMAL REDUNDANT BKR*

Recombiner unit 1-1 52-1G-67 52-1G-67R Recombiner unit 1-2 52-1H-35 52-1H-35R

Redundant breakers installed for overcurrent protection of containment electrical penetrations. These breakers should remain closed at all times and should not be used as clearance points.

6.1.2 On the recombiner unit control panel, verify that the white lamp labeled "POWER IN AVAILABLE" is lit. This lamp indicates that the main power breaker to the unit is closed and that power is available to the control and power supply panel.

6.1.3 Verify that the potentiometer labeled "POWER ADJUST" is set at zero.

6.1.4 Turn the switch labeled "POWER OUT SWITCH" to the ON position. Verify that the red lamp on the switchplate is lit.

6.1.5 Measure and record (on the data sheet) the present containment pressure reading.

6.1.6 Determine and record the PRE-LOCA containment temperature.

6.1.7 Using Figure 1, Attachment 9.1, determine and record the power correction factor, Cp.

6.1.8 Record the Vol. 9 Reference Power on the data sheet. Multiply the Reference Power for the unit being used by the Cp to determine the recombiner power setting. Record this value on the data sheet.

6.1.9 Turn the potentiometer clockwise until 5KW is obtained on the meter labeled "POWER OUT." Hold for 10 minutes, then advance to 10KW and hold for 10 more minutes, then advance to 20KW for 5 minutes, then advance to the power setting obtained in step 6.1.8.

6.1.10 Adjust the potentiometer as required to maintain power setting in step 6.1.9 above.

6.1.11 Read and record the digital temperature indicator (all three thermocouples) and power output every 15 minutes on the data sheet until the average temperature stabilizes above the recombination temperature of 1225°F. Record the temperatures every four hours thereafter.

6.1.12 If there is any indication that the recombiner is not operating properly, turn it off and place the standby unit in operation.

6.2 00340709.DOC 02 1129.0747

RO QUESTION 60 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 2 _____

K/A # 029 A1.03 Importance 3.0* 3.3*

Proposed Question:

An alternate containment purge is being performed on unit 2 in accordance with OP H-4:II, Alternate Method For Purging Containment to reduce radionuclide concentration prior to personnel entry.

The purge should be discontinued when containment pressure reaches which of the following?

A. 0.9 psig B. 0.0 psig C. -0.5 psig D. -0.9 psig Proposed Answer:

B. 0.0 psig Explanation:

A incorrect, this is just below the TS limit pressure.

B correct, purge should be stopped at approximately 0.0 psig.

C incorrect, operator is directed not to allow pressure to decrease below -0.3 psig.

D incorrect, this is close to the TS value.

Technical Reference(s):

OP H-4:II TS 3.6.4 Proposed references to be provided to applicants during examination: none Learning Objective: 5129 - State the limits for Containment Purge System ro tier 2 group 2_60.doc

Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 41.10 55.43 _____

Comments:

K/A: 029 A1.03 - Ability to predict and/or monitor changes in parameters to prevent exceeding design limits) associated with operating the Containment Purge System controls including: Containment pressure, temperature, and humidity ro tier 2 group 2_60.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP H-4:II NUCLEAR POWER GENERATION REVISION 3A DIABLO CANYON POWER PLANT PAGE 1 OF 3 OPERATING PROCEDURE UNIT TITLE: Alternate Method for Purging Containment 1 06/22/04 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. SCOPE 1.1 This procedure provides an alternate means to improve containment air quality or reduce radionuclide concentration prior to personnel entry.

1.2 It is normally performed prior to a unit refueling outage, or upon request of radiation protection.

2. DISCUSSION 2.1 This procedure describes an alternate method for purging containment utilizing the service air system.

2.2 Performance and Verification of valve seal removal and installation for AIR-S-1-200 is documented in this procedure in accordance with OP1.DC20.

3. RESPONSIBILITIES 3.1 Shift foreman (SFM) for operation of plant equipment as required by this procedure.

3.2 Radiation protection engineer for analysis of purge permit results and to provide the air change requirements to the SFM prior to starting this procedure.

3.3 Radiation protection personnel for coordinating with chemistry personnel in taking the required samples.

3.4 Chemistry personnel for taking and analyzing all purge permit samples.

4. PREREQUISITES 4.1 The Service Air System is inservice and the Instrument Air System is isolated from the Service Air System (AIR-0-83 closed) during the performance of this procedure. This requirement will preclude any affect on the plant Instrument Air System during this evolution.

4.2 The Service Air System is inservice and aligned to support the large air flow rate required to perform this procedure (up to 2550 CFM).

4.3 Obtain purge permit from Chemistry in accordance with CAP A-6.

4.4 Obtain the most current Containment Air Sample results just prior to the start of the test.

4.5 A RWP/SWP is established and in effect for this test.

4.6 Check that Containment pressure is less than 0.9 psig.

4.7 Contact the Radiation Protection Engineer to determine the volume of air or air changes required to adequately purge containment and return the air quality to acceptable levels.

01024903.DOC 02 0622.0720

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP H-4:II DIABLO CANYON POWER PLANT REVISION 3A PAGE 2 OF 3 TITLE: Alternate Method for Purging Containment UNIT 1

5. PRECAUTIONS AND LIMITATIONS 5.1 Do not exceed 0.9 psig containment pressure.

5.2 Continue purge until containment pressure drops to approximately 0.0 psig. Do not allow containment pressure to drop below -0.3 psig.

5.3 Operator must standby continuously at Penetration 56 and maintain communications with the Control Room while valve AIR-S-1-200 is open, per Tech Spec 3.6.3 (ITS 3.6.3).

5.4 The requirements and precautions established in the RWP/SWP must be adhered to at all times. Due to personnel contamination risk, do not open the Service Air header drain valve (AIR-S-1-116) located under the fuel transfer canal, unless explicitly permitted by the RWP/SWP.

5.5 Monitor Service Air header pressure as required, at PI-1701 U2 140' near RCA Access.

Do not allow Service Air header pressure to drop below 90 psig. PK13-17 will alarm when service air header pressure reaches 93 psig.

5.6 Service Air manual isolation AIR-S-0-83 shall be closed whenever Service Air System is in service, except as required by OP AP-9.

5.7 During use of this procedure, if Instrument Air requires backfeed from Service Air, per OP AP-9, immediately isolate service air to Containment by CLOSING AIR S-1-200.

6. INSTRUCTIONS 6.1 Review all Prerequisites, Precautions and Limitations.

6.2 Open up to 6 service air taps at the 91' El. level of containment and circle below which valves were opened. (Pipe wrench may be needed for caps.)

Unit 1 AZIMUTH AIR-S-1-157 292° AIR-S-1-160 (header drain) 300° AIR-S-1-161 340° AIR-S-1-164 24° AIR-S-1-171 110° AIR-S-1-182 153° AIR-S-1-151 195° AIR-S-1-154 227° 6.3 Station an operator at valve AIR-S-1-200 (Penetration 56) and establish communications with Control Room.

01024903.DOC 02 0622.0720

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP H-4:II DIABLO CANYON POWER PLANT REVISION 3A PAGE 3 OF 3 TITLE: Alternate Method for Purging Containment UNIT 1 CAUTION: Closely monitor service air header pressure PI-1701, 140' U2 @ Col. G/22. Throttle the air flow into containment as required to maintain Service Air header pressure above 90 psig. PK13-17 will alarm when Service Air header pressure reaches 93 psig.

6.4 Break the seal and crack open valve AIR-S-1-200 at Penetration 56. Log seal change on Attachment 9.1.

6.5 Operate additional CFCUs as desired to enhance mixing of containment atmosphere.

6.6 Monitor containment pressure on VB1 or PPC. Upon reaching approximately 0.9 psig, initiate purge/vent in accordance with OP H-4:I.

NOTE: The following step may be performed at the discretion of the SFM to allow securing the watch at AIR-S-1-200 while venting the containment.

6.7 If it is desired to isolate air while venting the containment, close and seal AIR-S-1-200 and secure the watch. Log seal change on Attachment 9.1.

6.8 Discontinue purge/vent when containment pressure drops to approximately 0.0 psig.

6.9 Request Radiation Protection to take containment air sample (as appropriate).

6.10 Repeat steps 6.3 thru 6.9 as required until the containment air quality is determined acceptable by the radiation protection engineer.

6.11 Close and seal valve AIR-S-1-200 at Penetration 56 and complete seal change data on Attachment 9.1. (This step will be N/A if valve was closed in step 6.7.)

6.12 Close (and replace cap, if so equipped) the service air taps in containment that were opened in step 6.2.

6.13 Align the Service Air System as required by the shift foreman.

7. REFERENCES 7.1 OVID Dwg. 106725, Sheet 58.

7.2 OP1.DC20, "Sealed Components."

7.3 OP H-4:I, "Containment Ventilation Make Available and Place In Service."

8. RECORDS 8.1 File completed Attachment 9.1 in the completed Sealed Valve Change Form binder.

9. ATTACHMENTS 9.1 "AIR-S-1-200 Seal Removal and Installation Log," 04/21/98 01024903.DOC 02 0622.0720

Containment Pressure 3.6.4 3.6 CONTAINMENT SYSTEMS 3.6.4 Containment Pressure LCO 3.6.4 Containment pressure shall be > -1.0 psig and < +1.2 psig.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Containment pressure not A.1 Restore containment 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months within limits. pressure to within limits.

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion AND Time not met.

B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.1 Verify containment pressure is within limits. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

RO QUESTION 61 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 2 _____

K/A # 034 G2.4.12 Importance 3.4 3.9 Proposed Question:

PLANT CONDITIONS

Core off load is in progress

The FHB Bridge Crane is positioned over the intended fuel rack and the crew is about to commence lowering the fuel assembly RE-58, Spent Fuel Pool Area Rad Mon goes into high alarm in the FHB Which of the following actions should the FHB crane operator immediately take?

A. Place the fuel assembly in the upender and lower the upender then exit the FHB.

B. Lower the assembly to the bottom of the spent fuel rack, then exit the FHB.

C. Verify Fuel Handling Ventilation transferred to Iodine Removal Mode and exit the FHB.

D. Exit the FHB and notify the control room for instructions.

Proposed Answer:

B. Lower the assembly to the bottom of the spent fuel rack, then exit the FHB.

Explanation:

A incorrect, should be placed in the closest safe location B correct per AR PK11-10, Fuel Handling Building Worker Actions 5.2.1 Place all fuel bundles in a safe storage location.

a. Spent Fuel Storage rack

b. New Fuel elevator (new fuel only)

c. Fuel Transfer conveyer upender

d. New Fuel Storage Rack (new fuel only) 5.2.2 Perform an orderly evacuation of all persons to Access Control.

C incorrect, this is a control room action D incorrect, the fuel bundle must be placed in a safe location.

ro tier 2 group 2_61 rev1.doc

Technical Reference(s): AR PK 11-10, FHB High Radiation RE-58 AND 59 Proposed references to be provided to applicants during examination: None Learning Objective:

6540 - Explain the actions to take on a fuel handling building evacuation alarm Question Source: Bank # DCPP B-0049 Question History: Last NRC Exam Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis 10 CFR Part 55 Content: 55.41 41.13 55.43 _____

Comments:

K/A: 034 G2.4.12 - Fuel Handling Equipment - Knowledge of general operating crew responsibilities during emergency operations.

ro tier 2 group 2_61 rev1.doc

1 B-0049 Points: 1.00 Multiple Choice The following plant conditions exist:

Core off load is in progress

The FHB Bridge Crane is positioned over the intended fuel rack and the crew is about to commence lowering the fuel assembly

Fuel Handling Building Rad Monitors RE-58 and 59 alarm

Gas bubbles being released from the element is noted Which of the following actions should the FHB crane operator immediately take?

A. Lower the assembly to the bottom of the fuel rack, then exit the FHB.

B. Place the fuel assembly in the upender and lower the upender then exit the FHB.

C. Open the supply breaker to the bridge crane and exit the FHB.

D. Exit the FHB and notify the control room for instructions.

Answer: A ASSOCIATED INFORMATION:

Associated objective(s):

6540 Explain the actions to take on a fuel handling building evacuation alarm Reference Id: B-0049 Must appear: No Status: Active User Text: 6540.110343 User Number 1: 3.60 User Number 2: 4.10 Difficulty: 3.00 Time to complete: 3 Topic: LPA-21 Actions to take on a fuel handling building Cross

Reference:

AP-21 Comment: created for r993c15, jpl1.

Converted to B bank from R-54078 during 00 exam review mtc6 Reviewed for 00 biennial exam 1/17/01 mtc6 Reviewed for 02 biennial exam 1/7/03 mtc6 Reviewed for 04 biennial exam 12/23/04 mtc6

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK11-10 NUCLEAR POWER GENERATION REVISION 11 DIABLO CANYON POWER PLANT PAGE 1 OF 2 ANNUNCIATOR RESPONSE UNIT TITLE: FHB High Radiation RE-58 AND 59 1 04/19/02 EFFECTIVE DATE PRO CED U RE CLA SSIFICA TIO N : Q U A LITY RELA TED

1. LOGIC DIAGRAM RIS 59X ALARM RIS 58X

2. ALARM INPUT DESCRIPTION DEVICE ALARM ANNUNCIATOR TYPEWRITER NUMBER INPUT PRINTOUT SETPOINT RIS 59X 1169 New Fuel Storage Area Rad Mon RE-59, Note 1 Hi Rad RIS 58X 1167 Spent Fuel Pool Area Rad Mon RE-58, Hi Note 1 Rad NOTE 1: Refer to I&C Rad Monitors Data Book in the Control Room.

3. PROBABLE CAUSE 3.1 True high radiation level at the detector.

3.2 Surveillance test in progress on monitor.

3.3 Moving operation selector switch to source check.

4. AUTOMATIC ACTIONS 4.1 Fuel Handling Building evacuation alarm sounds.

4.2 Fuel Handling Building ventilation changes to "Iodine Removal" mode of operation.

5. OPERATOR ACTIONS 5.1 Control Room Operator Actions, RM-58 and RM-59 in service.

5.1.1 Verify FHB alarm is initiated (use intercom).

5.1.2 Check Radiation Level on RM-58 and RM-59 at PAM 2 panel.

5.1.3 Verify that the Fuel Handling Ventilation transferred to Iodine Removal Mode.

101771011.D O C 16 0119.0533

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK11-10 DIABLO CANYON POWER PLANT REVISION 11 PAGE 2 OF 2 TITLE: FHB High Radiation RE-58 AND 59 UNIT 1 5.1.4 Make a PA announcement to evacuate the Fuel Handling Building.

5.1.5 Refer to the following procedures as necessary:

a. EP G-1, "Emergency Classification and Emergency Plan Activation"

b. OP AP-21, "Irradiated Fuel Damage"

c. OP AP-22, "SFP Low Level/Hi Temp/Hi Rad" 5.2 Fuel Handling Building Worker Actions 5.2.1 Place all fuel bundles in a safe storage location.

a. Spent Fuel Storage rack

b. New Fuel elevator (new fuel only)

c. Fuel Transfer conveyer upender

d. New Fuel Storage Rack (new fuel only) 5.2.2 Perform an orderly evacuation of all persons to Access Control.

5.3 Control Room Operator Actions, RM-58 or 59 out of service (Tech Spec 3.3.8).

5.3.1 If the Fuel Handling Building Radiation alarm initiates by the in-service monitor, follow Section 5.2 of this response.

5.3.2 If the portable continuous monitor installed to satisfy action A.1.2.1 of Tech Spec 3.3.8 alarms:

a. Fuel Handling Personnel should notify the Control Room immediately of the alarm.

b. Control Room Personnel shall initiate the Fuel Handling Building Radiation Alarm by performing a source check on the in-service Fuel Handling Building Radiation Monitor. If both monitors are out of service or the alarm fails to sound, a P.A. announcement shall be made informing personnel of the condition.

c. Control Room Operators shall follow Step 5.1.3 through Step 5.1.5.

d. Fuel Handling Building workers shall follow all steps in Section 5.2.

5.4 If RE-58 or RE-59 has failed or is out of service for a surveillance test, notify the Shift Chem Tech per OP O-3.

101771011.D O C 16 0119.0533

RO QUESTION 62 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 2 _____

K/A # 041 A2.02 Importance 3.6 3.9 Proposed Question:

PLANT CONDITIONS

Unit 1 trips from 100% power due to an error while performing a surveillance.

The crew has entered E-0.1, Reactor Trip Response.

The CO notes that RCS temperature is 545ºF and decreasing and two Group 2 steam dump valves indicate partially open. All others indicate fully closed.

Which of the following actions would be appropriate for the current plant conditions?

A. Shut the MSIVs and bypass valves.

B. Implement AP-6, Emergency Boration.

C. Place the Steam Dump Bypass switches, 43/SDA and 43/SDB in OFF.

D. Take Steam Dump controller, HC-507 to Manual and press the DECREASE pushbutton.

Proposed Answer:

A. Shut the MSIVs and bypass valves.

Explanation:

A correct, all valves should be closed at this time. Per E-0.1, the MSIVs are closed.

B incorrect, this would be the action if the cooldown continued after shutting the MSIVs.

C incorrect, placing the Bypass switches in OFF removes the arming signal, but would have no effect if the valves are not being controlled by HC-507.

D incorrect, all valves should be closed at this time. E-0.1 states to verify all Steam Dump valves closed, which this would do if there was a demand for them to be open.

Technical Reference(s):

ro tier 2 group 2_62 rev2.doc

C-2B, Steam Dump System E-0.1, Reactor Trip Response Proposed references to be provided to applicants during examination: none Learning Objective: 9993 - Explain the operation of the Steam Dump System.

Question Source:

New Question History: Last NRC Exam Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis 10 CFR Part 55 Content: 55.41 41.5 55.43 Comments: K/A: 041 A2.02 - Ability to (a) predict the impacts of the following malfunctions or operations on the SDS; and (b) based on those predictions or mitigate the consequences of those malfunctions or operations: Steam valve stuck open ro tier 2 group 2_62 rev2.doc

Control System Control System Overview, Continued Physical description (continued)

Part Function Mode selector These switches establish the operating mode of the switch Steam Dump system.

Bypass switches Load Rejection This controller modulates the Steam Dump valves on a Controller load rejection.

It attempts to maintain Tavg at a Tref value (derived from PT-505 as above) plus a defined offset (4°F Unit 1 and 3°F Unit 2).

Reactor Trip This controller modulates the Group 1 and 2 Steam Controller Dump valves on a reactor trip.

It attempt to maintain Tavg at Tnoload (nl) (normally set at 547°F).

Steam Pressure This controller modulates the Group 1 and 2 Steam Controller Dump valves when steam pressure mode is selected on the Mode Selector switch.

It attempts to maintain steam header pressure at the value set at the controller.

The steam pressure controller is normally set at 1005 psig.

This value is varied when performing heatups or cooldowns.

UI-500 This meter indicates the output from all Steam Dump controllers (excluding the individual pressure controllers).

Continued on next page C2B.DOC 2.2 - 3 REV. 11

Control System Bypass Switches (43/SDA, 43/SDB)

Purpose The purpose of 43/SDA and 43/SDB is to allow the P-12 interlock to be Obj. 11, 16 bypassed so the group 1 Steam Dump valves may be used to cooldown below P-12 (Tavg = 543°F).

The switches may also be used to select whether or not the Steam Dump valves can be armed.

Location 43/SDA and 43/SDB are located on the CC-2 benchboard.

Control The following control positions are available for the 43/SDA and 43/SDB Obj. 12 switches.

STEAM DUMP CONTROL BYPASS SELECT 43/SDA 43/SDB TRAIN A TRAIN B ON ON OFF OFF RESET BYPASS RESET BYPASS INTLK INTLK SDS-09 Switch position Purpose OFF RESET Defeats all Train A / Train B Steam Dump valve (maintained contact) arming signals, resets bypass.

ON Steam Dump arming is aligned for normal operation.

(maintained contact)

BYPASS INTLK P-12 will normally prevent arming of all Steam Dump (spring return to valves. This switch position will bypass P-12 for ON) group 1 Steam Dump valves only (after bypass interlock is selected, switch must be positioned to OFF RESET to remove the bypass).

Continued on next page C2B.DOC 2.2 - 5 REV. 11

PACIFIC GAS AND ELECTRIC COMPANY NUMBER EOP E-0.1 DIABLO CANYON POWER PLANT REVISION 28 PAGE 2 OF 25 TITLE: Reactor Trip Response UNIT 1 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. CHECK RCS Temperature - Perform the following:

STABLE OR TRENDING TO 547°F

a. IF RCS Temperature is o Average Temperature if any RCP is LESS THAN 547°F and running decreasing, THEN OR

1) Verify ALL Steam Dump o Cold Leg Temperature if NO RCP is Valves closed.

running

2) Verify S/G Blowdown Isol Vlvs OC - CLOSED

3) Press Reset on MSR Cont Panel.

4) Control Total Feed Flow.

Maintain total feed flow GREATER THAN 435 GPM until NR level is GREATER THAN 6% [16%]

in at least one S/G.

5) IF Cooldown continues, THEN (a) Close MSIVs and MSIV Bypass Vlvs.

(b) Adjust 10% steam dump controllers as needed to maintain S/G pressure LESS THAN OR EQUAL TO 1005 PSIG (8.38 turns).

6) IF Cooldown continues AND is UNCONTROLLED, THEN IMPLEMENT OP AP-6 EMERGENCY BORATION.

7) GO TO Step 2 (Page 4).

THIS STEP CONTINUED ON NEXT PAGE AJ0A62228.DOC

RO QUESTION 63 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 2 _____

K/A # 068 K4.01 Importance 3.4 4.1 Proposed Question:

How would the liquid radwaste system respond if RE-18, Liquid Radwaste Rad Monitor, alarmed during a discharge of a Floor Drain Receiver?

The following component names apply to this question:

FCV-647, Filter 0-4 to ASW Overboard or EDRs

RCV-18, Liquid Waste to Overboard

FCV-477, Filters 04 and 05 outlet to EDRs

FCV-720, FDR recirc valve A. RCV-18 closes. The running Floor Drain Receiver pump will receive a trip signal.

B. FCV-720 opens and RCV-18 closes. The tank that is on discharge will swap to recirculation.

C. FCV-720 opens and FCV-647 closes. The tank that is on discharge will swap to recirculation.

D. RCV-18 closes and FCV-477 opens. Flow is directed to the Equipment Drain Receiver that is on fill.

Proposed Answer:

D. RCV-18 closes and FCV-477 opens. Flow is directed to the Equipment Drain Receiver that is on fill.

Explanation:

A incorrect, RCV-18 closes, but the pump does not trip.

B incorrect, FCV-720 is not affected by RE-18.

C incorrect, neither action occurs.

D correct, the discharge terminates (RCV-18 closes) and it is directed to the EDR inlet header (FCV-477)

Technical Reference(s): G1 - Liquid Radwaste System ro tier 2 group 2_63.doc

Proposed references to be provided to applicants during examination: none Learning Objective: 8442 Explain automatic actions associated with Liquid Rad Waste system valve Question Source: Bank # DCPP A-0542 Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 41.13 55.43 _____

Comments:

K/A: 068 K4.01 Knowledge of design feature(s) and/or interlock(s) which provide for the following: Safety and environmental precautions for handling hot, acidic, and radioactive liquids ro tier 2 group 2_63.doc

1 A-0542 Points: 1.00 Multiple Choice How would the liquid radwaste system respond if RE-18, Liquid Radwaste Rad Monitor, were to come in alarm during a discharge of a Floor Drain Receiver?

A. RCV-18 closes and FCV-477 opens. Flow is directed to the Equipment Drain Receiver that is on fill.

B. RCV-18 closes and FCV-477 opens. Flow is directed to the Floor Drain Receiver that is on fill.

C. RCV-18 opens and FCV-477 closes. The tank that is on discharge will swap to recirculation.

D. RCV-18 closes. The running Floor Drain Receiver pump will receive a trip signal.

Answer: A ASSOCIATED INFORMATION:

Associated objective(s):

8442 Explain automatic actions associated with Liquid Rad Waste system valves 69251 Explain the autom atic actions associated w ith the Liquid Radw aste system .

Reference Id: A-0542 Must appear: No Status: Active User Text: 8442.130494 User Number 1: 2.90 User Number 2: 3.40 Difficulty: 3.00 Time to complete: 3 Topic: RMS - Hi rad effect on a liquid radwaste discharge.

Cross

Reference:

49 Comment: Copied question S-1178. Modified stem, the answer, and distractors. Should validate. 11/12/96 MAP Validated IAW TQ2.ID3. Taken to Review. 01/23/97 jpsj Taken to Active after review. 01/24/97 jmh1 Checked as part of question review for biennial exam 12/22/98 MTC6 Reviewed for 00 biennial exam 1/17/01 mtc6 Reviewed for 02 biennial exam 1/7/03 mtc6 Reviewed for 04 biennial exam 12/21/04 mtc6 Reviewed for L031 NRC Practice Exam 12/22/04 CNH4

Reference:

STG G-1 Page 2.5-21

Liquid Radwaste Monitor, RE-18 Purpose The purpose of Liquid Radwaste Monitor, RE-18, is to monitor liquid Obj 7 radwaste discharges for radioactivity.

Location RE-18 is located on the 54 elevation in the Auxiliary Building.

Obj 6 Diagram The following diagram shows RE-18 in the discharge flowpath.

Obj 24 Waste Processing System EDR Inlet LRW HDR Filter 0-4 FCV PT FT 2-2 1044 477 243 2-1 RE FE ASW 18 243 Overboard FCV RCV 647 18 1-2 55' Elevation 1-1 Auxiliary Building 85' Elevation Turbine Building LRS-18 Automatic Two automatic actions occur when RE-18 has detected high radiation.

actions

Liquid Waste to Aux Saltwater System Overboard isolation valve (RCV-18) will close shutting off flow to the Auxiliary Salt Water System.

Filters 0-4 Outlet to the Equipment Drain Receivers valve (FCV-477) will open to recycle flow back to the EDRs.

Continued on next page G1.DOC 2.5 - 21 REV. 11

RO QUESTION 64 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 2 _____

K/A # 072 K5.02 Importance 2.5 3.2 Proposed Question:

Health Physics is about to transfer a small spherical radioactive source through the Auxiliary Building. The source measures 1000 mrem/hr gamma at 6 inches. The transport route of the source will take it 5 feet away from an Area Radiation Monitoring System (ARMS) detector.

Which of the following describes the maximum radiation (due to the source) shown on the ARMS indicator?

A. 1.0 mrem/hr.

B. 10.0 mrem/hr.

C. 100.0 mrem/hr.

D. 200.0 mrem/hr.

Proposed Answer:

B. 10.0 mrem/hr.

Explanation:

B correct, Dose = DR x (d1/d2)2 Dose = 1000 mr/hr (.5/5)2 Dose = 10.0 mrem A incorrect, math error, using either 100 mrem or .05 C incorrect, if the result of (0.5/5) is not squared.

D incorrect, if 1000/5.

Technical Reference(s): NM-10, RP for Non-Licensed Operators Proposed references to be provided to applicants during examination: none ro tier 2 group 2_64 rev1.doc

Learning Objective: 72414 - Given a dose rate from a point source at a given distance, estimate the dose rate at multiples of fractions of that distance time (within one order of magnitude)

Question Source: Modified Bank # INPO 22492 Question History: Last NRC Exam DCPP 10/2002 Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.5 55.43 _____

Comments: K/A: 072 K5.02 - Knowledge of the operational implications of the following concepts as they apply to the ARM system: Radiation intensity changes with source distance ro tier 2 group 2_64 rev1.doc

INPO Licensed Operator Exam Bank - PWR Questions ID: 22492 Health Physics is about to transfer a small spherical radioactive source through the Auxiliary Building. The source measures 100 mrem/hr gamma at 1 foot distance. The transport route of the source will take it 5 feet away from an Area Radiation Monitoring System (ARMS) detector.

Which one of the following describes the correct maximum radiation (due to the source) shown on the ARMS indicator?

Ans 4 mrem/hr.

D1 1 mrem/hr.

D2 10 mrem/hr.

D3 20 mrem/hr.

AbbrevLocName ExamDate Vendor Type ExamType Cog Level ExamLevel RefMaterial ParentId Diablo Canyon 1 10/1/2002 WEC PWR ILO 2 R QuestionComment Distract1Comment Distract2Comment Distract3Comment KaNumber KaSegment1 KaSegment2 KaSegment3 KaSegment4 KaSegment5 KaRevision

..072.K5.02 072 K5 02 Tuesday, September 21, 2004 Page 8439 of 9479

LESSON: RP FOR NON-LICENSED OPERATORS LESSON NO.: NM-10 Distance Objective 7 Given a dose rate from a point source at a given distance, estimate the dose rate at multiples or fractions of that distance time (within one order of magnitude).

Introduction Distance is oft times the easiest and best of the ALARA tools. When an RP tech insists that you move away from a hot spot or use long handled tools, they are not doing it to harass you.

Main Idea I moved = I known X (distance known/distance moved)2 Example A hot particle reads 20 mR/h at 2 feet, what is its dose rate at 6 inches? What is it at 4 ft?

I moved = 20 mR/h X (2 ft known/0.5 ft moved)2 = 320 mR/h at 6 inches I moved = 20 mR/h X (2 ft known/4 ft moved)2 = 5 mR/h at 4 ft.

Practice / A one inch valve reads 14 mR/h at 4 ft. what will it probably read at 1 Feedback ft? Ans.: 224 mR/h NM10.DOC PAGE 11 OF 14 REV 0

RO QUESTION 65 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 _____

Group # 2 _____

K/A # 075 K1.08 Importance 3.2* 3.2*

Proposed Question:

When would it be appropriate to cross-tie the ASW and Circ Water bays?

A. If one unit loses its ASW pumps and the other units ASW pumps are not available.

B. If the Circ Water screens are severely clogged and the ASW screens are not.

C. If Chlorine injection into the ASW system is necessary.

D. If the ASW pumps are losing suction.

Proposed Answer:

D. If the ASW pumps are losing suction.

Explanation:

A incorrect, the correct action would be to trip the reactor.

B incorrect, .this is the opposite of when the systems would be tied.

C incorrect, Chlorination is to both the Circ Water and ASW bays.

D correct, if the bay level is low and the pumps are losing suction (or cavitating), cross-tying maybe appropriate if the Circ Water screens are less affected.

Technical Reference(s):

AR PK01-03, Aux Saltwater Pumps (rev 13)

AP-10 pages 2, 3 (rev 8)

Proposed references to be provided to applicants during examination: none Learning Objective: 3547 - Describe the actions to be taken in the event the ASW screens cannot be unclogged Question Source:

ro tier 2 group 2_65.doc

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 41.4 55.43 _____

Comments:

K/A: 075 K1.08 - Knowledge of the physical connections and/or causeeffect relationships between the circulating water system and the following systems: Emergency/essential SWS ro tier 2 group 2_65.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP AP-10 NUCLEAR POWER GENERATION REVISION 8 DIABLO CANYON POWER PLANT PAGE 1 OF 6 ABNORMAL OPERATING PROCEDURE UNITS TITLE: Loss of Auxiliary Salt Water 1 2 AND 08/30/02 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. SCOPE 1.1 This procedure provides guidance in restoring auxiliary saltwater (ASW) flow to a CCW heat exchanger in the event flow is lost due to:

1.1.1 Failure of both ASW pumps on the same unit.

1.1.2 Loss of suction to the pump in service.

1.1.3 A rupture in the system piping or fouling of a CCW heat exchanger.

1.1.4 Extensive equipment damage at the intake due to tsunami or other causes.

1.2 This procedure should be used in Modes 1-4. If in Modes 5 and 6, OP AP SD-3, "Loss of Auxiliary Saltwater," should be used.

2. SYMPTOMS 2.1 Possible Main Annunciator Alarms:

2.1.1 AUXILIARY SALT WATER SYSTEM (PK01-01)

a. CCW HX ____ Aux Salt Wtr Diff Press Hi-Lo

b. Aux Salt Wtr Hdr ____ Press Lo 2.1.2 AUX SALT WATER PUMPS (PK01-03)

a. Aux Salt Wtr Pps OC Trip

b. Aux Salt Wtr Pp ____ Bay Lvl Lo

c. Aux Salt Wtr Pp ____ Auto Start 2.1.3 CCW VITAL HDR A/B (PK01-06)

CCW HX ____ Outlet Temp 2.1.4 BAR RACKS SCREENS (PK13-01)

Screen Diff Hi 000660008.D O C 02 0119.0614

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP AP-10 DIABLO CANYON POWER PLANT REVISION 8 PAGE 2 OF 6 TITLE: Loss of Auxiliary Salt Water UNITS 1 AND 2 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. VERIFY an ASW Pump Running

ASW Pp 1 a. If ASW Pumps are available on the opposite unit, then on the opposite

ASW Pp 2 unit:

1) Start standby pump, if available.

a) IF Standby is Pump No. 1, THEN Close FCV-495 AND open FCV-496

-OR-IF Standby is Pump No. 2, THEN Close FCV-496 AND open FCV-495.

b) Open Unit 1 and 2 ASW cross-tie valve, FCV-601.

2) IF Only one pump is available, THEN Open Unit 1 and 2 ASW cross-tie valve, FCV-601 to supply both units with one pump.

b. Comply with action statement of Tech Spec 3.7.8 for both units OR Tech Spec 3.0.3 as applicable.

c. Stop any radwaste discharge in progress.

d. If ASW Pumps are not available on the opposite unit and it is determined that pumps are not capable of being placed in service, then GO TO OP AP-11, Section A.

e. GO TO Step 4.

2. VERIFY ASW Pump Has Not Lost Suction:

Running pump amps - STEADY a. Start standby pump.

b. Secure cavitating pump.

c. Determine cause of cavitation.

1) Verify both ASW Inlet Gates 8 and 9 OPEN.

000660008.D O C 02 0119.0614

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP AP-10 DIABLO CANYON POWER PLANT REVISION 8 PAGE 3 OF 6 TITLE: Loss of Auxiliary Salt Water UNITS 1 AND 2 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

2. VERIFY ASW Pump Has Not Lost Suction: (Continued)

NOTE: The ASW pumps have been successfully tested to run, without cavitation, at sea level of -20 feet. Alarm setpoint is at -6 feet.

2) CHECK PK01-03 NOT in alarm due to ASW Bay Level Low. If in alarm:

VERIFY no Screen Wash Pump Running in affected bay

Screen differential pressure not high (PK13-01 NOT lit) - If high, ensure screens AND screen wash pumps in operation.

Crosstie ASW and Circ Water Bays by:

1) OPEN FCV-432 (ASW Pp 1 Bay) OR FCV-433 (ASP Pp2) Bay.

2) Locally OPEN FCV-604 OR 605 IF Both ASW pumps cavitating AND the cause of the cavitation cannot be corrected.

THEN 1) Secure both ASW pumps

2) RETURN TO Step 1 000660008.D O C 02 0119.0614

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK01-03 NUCLEAR POWER GENERATION REVISION 13 DIABLO CANYON POWER PLANT PAGE 1 OF 4 ANNUNCIATOR RESPONSE UNIT TITLE: AUX SALTWATER PUMPS 103/04/04 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. LOGIC DIAGRAM 43-HF-8 52-HF-8 T4004-C LS163 51X-HF-8 ALARM 51X-HG-6 LS164 43-HG-6 52-HG-6

2. ALARM INPUT DESCRIPTION DEVICE ALARM ANNUNCIATOR TYPEWRITER NUMBER INPUT PRINTOUT PPC ADDRESS T4004C 426 Aux Salt Wtr Pps Temp PPC The inputs to device T4004C are:

1. ASW Pp 1-1 motor top bearing T2435A

2. ASW Pp 1-1 motor bottom bearing T2436A

3. ASW Pp 1-1 stator temp T2437A

4. ASW Pp 1-2 motor top bearing T2439A

5. ASW Pp 1-2 motor bottom bearing T2440A

6. ASW Pp 1-2 stator temp T2441A 03261513.DOC 16 0304.1020

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK01-03 DIABLO CANYON POWER PLANT REVISION 13 PAGE 2 OF 4 TITLE: AUX SALTWATER PUMPS UNIT 1 DEVICE ALARM ANNUNCIATOR TYPEWRITER NUMBER INPUT PRINTOUT SETPOINT 51X-HF-8 427 Aux Salt Wtr Pps OC Trip Min. 75 amps Inst 645 amps 51X-HG-6 427 Aux Salt Wtr Pps OC Trip Min. 75 amps Inst 645 amps LS 163 1013 Aux Salt Wtr Pp 1-1 Bay Lvl Lo -6 feet LS 164 1014 Aux Salt Wtr Pp 1-2 Bay Lvl Lo -6 feet 43-HF-8 61 Aux Salt Wtr Pp 1-1 Auto Start Cont. Switch in AUTO 52-HF-8 Bkr Closed 43-HG-6 74 Aux Salt Wtr Pp 1-2 Auto Start Cont. Switch in AUTO 52-HG-6 Bkr Closed

3. PROBABLE CAUSE 3.1 Motor problems 3.1.1 Loss of ventilation 3.1.2 Motor overloaded 3.1.3 Excessive flow 3.1.4 Failed bearing 3.1.5 Excessive vibration 3.2 Suction pit low level 3.2.1 Pump running with suction pit inlet gate closed.

3.2.2 Traveling screen clogged.

3.3 Auto start 3.3.1 Low discharge header pressure on running pump.

3.3.2 U.V. on 4KV Vital Bus of running pump.

3.3.3 Safety Injection 3.3.4 Transfer to DSL with no S.I.

3.3.5 Auto Transfer to Startup Power.

4. AUTOMATIC ACTIONS 4.1 Possible trip of running pump.

4.2 Possible auto start of standby pump.

03261513.DOC 16 0304.1020

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK01-03 DIABLO CANYON POWER PLANT REVISION 13 PAGE 3 OF 4 TITLE: AUX SALTWATER PUMPS UNIT 1

5. OPERATOR ACTIONS 5.1 Running ASW pump tripped or secured. Alarm Input 427 5.1.1 Verify standby ASW pump running with normal current. If all ASW flow is lost, GO TO OP AP-10/AP SD-3, and implement step 5.3 of this procedure.

5.1.2 Verify normal parameters on CCW-ASW HX, ASW flow and ASW discharge pressure.

5.1.3 Verify continuous chlorination secured to idle ASW pump bay. Refer to OP E-3:VI.

5.1.4 Refer to TS 3.7.8 and ECG 17.2.

5.2 Motor problems. Alarm Input 426 5.2.1 If a pump tripped on overcurrent, perform Step 5.1, AND:

a. Dispatch an Operator to inspect the switchgear. Refer to Operations Policy B-2.

b. Notify Maintenance Services of O.C. trip.

5.2.2 If an ASW pump motor stator or bearing temperature is in alarm then:

a. Check the room ventilation fan running.

b. Check the motor oil levels.

c. Swap to an alternate pump if available.

d. If the pump must be left running then follow Step 5.2.3.

5.2.3 An ASW pump can be run up to the following temperatures without affecting the lifetime of the component. If any of these limits are reached or exceeded then record how long and by how far the limits are exceeded and initiate an Action Request.

a. ASW pump motor stator - 248°F

b. ASW pump motor top bearing - 210°F

c. ASW pump motor bottom bearing - 210°F 03261513.DOC 16 0304.1020

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK01-03 DIABLO CANYON POWER PLANT REVISION 13 PAGE 4 OF 4 TITLE: AUX SALTWATER PUMPS UNIT 1 5.3 Suction pit low level. Alarm Inputs 1013, 1014 5.3.1 Transfer pumps.

NOTE: The ASW pumps have been successfully tested to run, without cavitation, at sea level of -20 feet. Alarm setpoint is at -6 feet sea level. Therefore, if it must be done, the pump can handle it down to -20 feet.

5.3.2 Shutdown the pumps with the low level.

a. Implement step 5.1 of this procedure.

5.3.3 Check the inlet gate open, if inlet gate is closed open it after bay level is reestablished.

5.3.4 If the traveling screen is plugged due to excessive debris, refer to OP AP-10/OP SD-3 and OP AP-11/OP SD-4.

5.3.5 Consider opening any combination of demusseling valves (FCVs 432, 433, 604 and 605) if CWP screens are less impacted than the ASW screen.

5.3.6 Consider having Maintenance manually rolling the ASW screens to expose clear screens into the flow path by turning the motor coupling either by hand or with a drill motor drive.

5.3.7 Refer to TS 3.7.8.

5.4 Auto start. Alarm Input 74 5.4.1 Check normal current on the running pump.

5.4.2 Verify normal parameters on CCW-ASW HX, ASW flow and ASW discharge pressure.

03261513.DOC 16 0304.1020

RO QUESTION 66 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 3 _____

Group # 1 _____

K/A # G2.1.10 Importance 2.7 3.9 Proposed Question:

Which of the following conditions, by itself, would be a violation of the Facility Operating License for Unit 1?

A. 101% indicated NI power.

B. Calculated power of 3415 MWth.

C. Changing load in excess of 5 megawatts per minute.

D. Performing a power ascension at greater than 5%/hour.

Proposed Answer:

B. Calculated power of 3415 MWth.

Explanation:

A incorrect, 101% NI does not necessarily correlate to power in excess of RTP.

B correct, as a condition of the operating license, PG&E can operate the unit not in excess of 3411MWth.

C incorrect, this exceeds the limit set to minimize the effects of xenon oscillations on axial offset.

D incorrect, this would violate fuel conditioning guidelines but not the Facility License.

Technical Reference(s):

Facility Operating License, Units 1 and 2.

Proposed references to be provided to applicants during examination: none Learning Objective: 9666 - Identify the operating license contents.

Question Source:

New X Question History: Last NRC Exam ____________

ro tier 3 group 1_66.doc

Question Cognitive Level:

Memory or Fundamental Knowledge Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.10 55.43 Comments:

K/A: G2.1.10 - Knowledge of conditions and limitations in the facility license.

ro tier 3 group 1_66.doc

C. This License shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1) Maximum Power Level The Pacific Gas and Electric Company is authorized to operate the facility at reactor core power levels not in excess of 3411 megawatts thermal (100% rated power) in accordance with the conditions specified herein.

(2) Technical Specifications The Technical Specifications contained in Appendix A and the Environmental Protection Plan contained in Appendix B, as revised through Amendment No. 178, are hereby incorporated in the license.

Pacific Gas and Electric Company shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan, except where otherwise stated in specific license conditions.

(3) Initial Test Program The Pacific Gas and Electric Company shall conduct the post-fuel-loading initial test program (set forth in Section 14 of Pacific Gas and Electric Company's Final Safety Analysis Report, as amended), without making any major modifications of this program unless modifications have been identified and have received prior NRC approval. Major modifications are defined as:

a. Elimination of any test identified in Section 14 of PG&E's Final Safety Analysis Report as amended as being essential;

b. Modification of test objectives, methods, or acceptance criteria for any test identified in section 14 of PG&E's Final Safety Analysis Report, as amended, as being essential;

c. Performance of any test at a power level different from that described in the program; and

d. Failure to complete any test included in the described program (planned or scheduled for power levels up to the authorized power level).

8S9IDB19.DOC R19 Page 5 of 11 License No. DPR-80

RO QUESTION 67 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 3 _____

Group # 1 _____

K/A # G2.1.21 Importance 3.1 3.2 Proposed Question:

You have been given a procedure to perform work.

You notice that the procedure was "issued for use" 4 days ago. The work has not been started.

Which one of the following actions, if any, is necessary prior to beginning the work?

A. Revalidate the procedure using the Procedure Navigator.

B. The current procedure cannot be used, get the procedure reissued.

C. Check the copy you have has a signature on the front page and the number of pages and attachments match with another copy of the procedure.

D. Once the procedure has been issued for use, no action is necessary prior to beginning the work.

Proposed Answer:

A. Revalidate the procedure using the Procedure Navigator.

Explanation:

A correct, Immediately prior to initially starting a job (i.e., within the shift), issue the procedure for use (see below instructions) or revalidate it if already issued for use. To revalidate procedures, use the Procedure Navigator procedure properties or list of recently revised procedures.

B incorrect, reissuing is not necessary.

C incorrect, This is part of issuing the procedure for use.

D incorrect, validation is required each shift.

ro tier 3 group 1_67.doc

Technical Reference(s):

AD1.ID1 R13, Procedure Use and Adherence Proposed references to be provided to applicants during examination: none Learning Objective: 9798 - State requirements for procedure deviation.

Question Source: Bank #

Modified Bank # DCPP N-72598 New ______

Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 41.10 55.43 _____

Comments:

K/A: G2.1.21 - Ability to obtain and verify controlled procedure copy.

ro tier 3 group 1_67.doc

Procedure Use And Adherence AD2.ID1 R13 Page 5 of 15 4.3 ISSUING PROCEDURES FOR USE

1) Procedures copied from controlled manuals or printed from the Procedure Navigator shall be "issued for use" in accordance with the below instructions prior to performing physical work. The intent of issuing a procedure for use is to ensure the performer has the latest revision when initially starting a job.

a) Immediately prior to initially starting a job (i.e., within the shift), issue the procedure for use (see below instructions) or revalidate it if already issued for use. To revalidate procedures, use the Procedure Navigator procedure properties or list of recently revised procedures.

b) Once issued for use, chemistry and radiation protection procedures (other than surveillance tests) that are implemented for recurring, repetitive tasks do not require revalidation prior to the start of each task for the duration of the issued for use period.

2) To issue a procedure for use:

a) Obtain a copy of the procedure. Include any OTSCs outstanding against the procedure. Do not use copies of procedures that have an "uncontrolled procedure" banner.

b) Verify that the procedure is the current version (revision level and OTSCs) by comparison against the Procedure Navigator procedure properties. Priority 1 controlled manuals may also be used for this purpose. If the Procedure Navigator is unavailable, the shift manager may authorize that both control copy #5 (plant library) AND the EC/OTSC drop box (site procedure group area) be checked to determine the current version.

c) If not already available, enter the following information (or similar) on the first page or cover sheet:

ISSUED FOR USE By: _________ Date: _________ Expires: _________

d) Sign, date, and enter an expiration date in the Issued for Use block. The issued for use period may be up to 31 days.

e) Ensure the level of use classification is indicated on the procedure or cover sheet.

f) Only the pages needed for work need be issued for use.

Identify all pages issued on the first page of the procedure or cover sheet.

Ensure all precautions and prerequisites applicable to the task are included.

3) Procedures in use longer than the issued for use period shall be re-validated and re-issued for use.

4) Procedure Forms and Attachments a) Continuous, Periodic, or Multiple Use Procedures - These forms and attachments are part of a procedure that is issued for use.

b) Reference Use Procedures - These forms and attachments do not need to be issued for use. However, the user shall ensure that current forms and attachments are used.

RO QUESTION 68 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 3 _____

Group # 1 _____

K/A # G2.1.29 Importance 3.4 3.3 Proposed Question:

Which of the following is the proper method for independently verifying the position of a normally SEALED CLOSED manual valve?

A. Visually check the position of the valve stem to verify the valve position.

B. Remove the seal and attempt to move the valve in the open direction without using excessive force, then close and reseal.

C. Check the sealed component checklist binder to determine if the valve has been opened.

D. Remove the seal, attempt to move the valve in the closed direction without using excessive force then reseal.

Proposed Answer:

D. Remove the seal, attempt to move the valve in the closed direction without using excessive force then reseal.

Explanation:

A incorrect, visual verification may be made on a throttle valve if other indications are unavailable B incorrect, valve is not moved in the closed direction.

C incorrect, seal must be removed and position verified.

D correct, to verify the valve open:

1. Compare the component tag number with the implementing document.

2. Physically verify the valve position by checking the valve open.

Move the valve in closed direction without using excessive force.

Sealed or locked valves shall be verified with the sealing or locking devices removed.

Technical Reference(s): OP1.DC2 page 6 of 9 Proposed references to be provided to applicants during examination: none ro tier 3 group 1_68.doc

Learning Objective: 7912 - Explain actions to take when performing an alignment on valves based on their position Question Source: Bank # DCPP P-1544 Question History: Last NRC Exam STP 11/94 Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 41.10 55.43 _____

Comments:

K/A: G2.1.29 - Knowledge of how to conduct and verify valve lineups.

ro tier 3 group 1_68.doc

Verifications OP1.DC2 R13 Page 6 of 9 4.3.2 How to Perform Peer Checking

1) Before another individual performs a task, a) The peer establishes visual and verbal communication with the performer.

b) The performer informs the peer of his intended actions, the purpose of those actions, and establishes hand contact with the component to be manipulated.

c) The peer will concur with the component selected and the intended manipulation.

(1) The peer should have a clear view of the performer's actions. This includes being on the same side of a control console as a performer when the action is performed on the control console.

(2) The peer should check integrator and potentiometer settings made by the performer.

d) The performer then manipulates the component.

4.4 DOCUMENTATION REQUIREMENTS All plant procedures that have been evaluated to require independent verification shall include provisions for documenting independent verification.

1) The procedure or data sheet shall provide spaces for both the performer and the independent verifier to initial each step where components are manipulated.

2) The procedure, data sheet, work package, or combination thereof shall provide spaces for the initials and names of both performer and the independent verifier.

4.5 EQUIPMENT VERIFICATION TECHNIQUES The following table the verification techniques that should be used when verifying the position of various components.

Table 1: Verification Techniques Device & Position Verification Technique

1. Compare the component tag number with the implementing document.

2. Physically verify the valve position by checking the valve closed.

Manual Valves

Attempt to move the valve in the CLOSED direction without using CLOSED excessive force.

Sealed or locked valves shall be verified with the sealing or locking devices removed.

1. Compare the component tag number with the implementing document.

2. Physically verify the valve position by checking the valve open.

Manual Valves

Move the valve in closed direction enough to verify stem OPEN movement.

Return the valve to the full open position.

Table continues on next page.

1 P-1544 Points: 1.00 Multiple Choice WHICH ONE (1) of the following is the proper method for independently verifying the position of a normally SEALED OPEN valve?>>

A. Remove the seal, move the valve in the closed direction enough to verify stem movement, return valve to original position and seal.

B. Visually check the position of the valve stem to verify the valve position.

C. Remove the seal and attempt to move the operator in the open direction, and reseal.

D. Check the sealed component checklist binder to determine if the valve has been closed.

Answer: A ASSOCIATED INFORMATION:

Associated objective(s):

3598 Explain the characteristics of the sealed valve program Reference Id: P-1544 Must appear: No Status: Active User Text: 3598.13ALLN User Number 1: 3.90 User Number 2: 4.10 Difficulty: 1.00 Time to complete: 3 Topic: Verification of sealed valve position Cross

Reference:

OP1.DC2, LADM-9, NADM1 Comment: SOUTH TEXAS RO EXAM 11/01/94 OP1.DC2

RO QUESTION 69 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 3 _____

Group # 2 _____

K/A # G2.2.28 Importance 2.6 3.5 Proposed Question:

OP B-8H, Non-Refueling Fuel Handling Instructions, states that the new fuel elevator is normally used only for lowering new fuel assemblies into the SFP.

An exception is to raise a new fuel assembly out of the spent fuel pool.

Whose approval is necessary to perform this exception?

A. Shift Manager B. Fuel Handling Supervisor C. Station Director or his delegate D. Vice President and General Manager or his delegate Proposed Answer:

C. Station Director or his delegate Explanation:

A incorrect, SFM responsible operation of the plant and plant equipment needed to support the fuel movements and the proper logging of the movements in the Operations Shift Log.

B incorrect, FHS responsible for supervision of fuel or load handling operations, response to high radiation or other emergency conditions and communications with the Control Room.

C correct, per caution in procedure, The new fuel elevator is normally used only for lowering new fuel assemblies into the SFP. The exceptions to this are for movement of the dummy fuel assembly, raising a new fuel assembly out of the SFP or for fuel repair.

These exceptions require prior permission of the Station Director or his delegate.

D incorrect, VP level is not necessary.

Technical Reference(s): OP B-8H page 3 of 8 ro tier 3 group 2_69 rev1.doc

Proposed references to be provided to applicants during examination: none Learning Objective: 4501 - Explain the operation of NEW FUEL ELEVATOR Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 41.13 55.43 Comments: K/A: G2.2.28 - Knowledge of new and spent fuel movement procedures.

ro tier 3 group 2_69 rev1.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP B-8H DIABLO CANYON POWER PLANT REVISION 18 PAGE 3 OF 8 TITLE: Non-Refueling Fuel Handling Instructions UNITS 1 AND 2 4.8 If irradiated fuel assemblies are to be raised in the New Fuel Elevator, the elevator shall be configured for such use in accordance with PEP M-42.01.

4.9 The Spent Fuel Bridge Crane has been visually inspected in accordance with MP M-50.3 within one day of use and re-performed prior to use on subsequent days.

4.10 The Spent Fuel Bridge Crane and associated interlocks have been functionally tested per STP M-27A within seven days prior to the start of fuel handling operations.

4.11 The Fuel Handling Building overhead crane prior to use has been:

4.11.1 Visually inspected in accordance with M-50.3, and 4.11.2 The interlocks verified per STP M-43.

4.12 The SFP Bridge Crane Auxiliary Hoist load cells shall be in calibration to assist in determining drag limits described in step 5.5. Calibration is needed only during fuel movement.

4.13 The FHB Overhead Crane operator shall be qualified per maintenance services intranet site, qual. number MG0851Q.

4.14 The NFSV and SFP Radiation Monitors (RE-58 and 59) and a Gaseous Activity FHB Ventilation Change Radiation Monitor is OPERABLE per TS 3.3.8.

4.15 Housekeeping Zones have been established per AD4.

4.16 Perform a tailboard with involved personnel regarding the overall plan and the applicable portions of sections 5 and 6 of this procedure. For fuel or component movements an ICA map showing the approved moves will normally accompany the Movement Authorizations. In addition, a daily tailboard is required for personnel addressing responses to high radiation alarms and evacuations per step 6.1.

4.17 Prior to movement of the SFP bridge crane ensure the skimmer suction T-handles are lowered below the crane rail.

5. PRECAUTIONS AND LIMITATIONS CAUTION: The new fuel elevator is normally used only for lowering new fuel assemblies into the SFP.

The exceptions to this are for movement of the dummy fuel assembly, raising a new fuel assembly out of the SFP or for fuel repair. These exceptions require prior permission of the Station Director or his delegate.

NOTE: The breaker for the new fuel elevator has a lock controlled by the shift foreman to preclude inadvertent use.

5.1 Because of criticality considerations, placement of fuel in the SFP shall be per TS 3.7.17.

Observe "cells not to be used for fuel" on spent fuel rack maps.

5.2 Personnel should observe all crane safety rules in addition to the special fuel handling requirements. This includes no mounting or dismounting of a moving crane.

00989018.DOC 02 1130.1020

RO QUESTION 70 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 3 _____

Group # 2 _____

K/A # G2.2.33 Importance 2.5 2.9 Proposed Question:

Unit 2 is performing a plant shutdown and driving in the control banks.

As the rods are inserted, at what point will the Control Bank A rods begin to insert?

Note: Overlap thumbwheels are set for 100 steps.

A. When the 4 Control Bank B rods reach 100 steps.

B. When the 4 Control Bank B rods reach 128 steps.

C. When the 8 Control Bank B rods reach 100 steps.

D. When the 8 Control Bank B rods reach 128 steps.

Proposed Answer:

C. When the 8 Control Bank B rods reach 100 steps.

Explanation:

A incorrect, there are 8 CBB rods for Unit 2, 4 for Unit 1.

B incorrect, there is 100 steps of overlap for CBB and CBA, therefore, CBA will begin moving at CBB at 100.

C correct, there are 8 CBB rods for Unit 2, 4 for Unit 1 and there is 100 steps of overlap for CBB and CBA, therefore, CBA will begin moving at CBB at 100.

D incorrect, there is 100 steps of overlap for CBB and CBA, therefore, CBA will begin moving at CBB at 100.

Technical Reference(s):

STP R-1A, attachment 9.1 and 9.2 OIM A-3-4 Proposed references to be provided to applicants during examination: none ro tier 3 group 2_70.doc

Learning Objective: 5038 - Explain the unit differences for the Rod Control system.

5048 - Explain the operation of the Bank Overlap Unit.

Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.6 55.43 Comments: Unit difference.

K/A: G2.2.33 - Knowledge of control rod programming.

ro tier 3 group 2_70.doc

05/28/03 Page 1 of 2 DIABLO CANYON POWER PLANT TITLE:

STP R-1A ATTACHMENT 9.1 Table 1 - Exercising Unit 1 Rod Cluster Control Assemblies 1

DATE _______________ TIME ___________

ROD BANK SELECTOR SWITCH POSITION ____________ POWER LEVEL INITIAL POSITION EXERCISED FINAL POSITION POSITION ROD ROD STEP DRPI* STEP COUN DRPI* STEP COUN DRPI BAN GROUP ROD COUNTER TER TER

K D4 1 D12 M12 SA M4 G5 2 E9 J11 L7 G3 1 C9 J13 SB N7 C7 2 G13 N9 J3 H2 SC B8 H14 P8 F6 SD F10 K10 K6 E3 1 C11 L13 CA N5 C5 2 E13 N11 L3

Arrows may be used when data are the same.

05/28/03 Page 2 of 2 STP R-1A (UNIT 1)

ATTACHMENT 9.1 TITLE: Table 1 - Exercising Unit 1 Rod Cluster Control Assemblies INITIAL POSITION EXERCISED FINAL POSITION POSITION ROD ROD STEP DRPI* STEP COUN DRPI* STEP COUN DRPI BAN GROUP ROD COUNTER TER TER

K 1 D8 CB M8 2 H4 H12 C3 1 C13 N13 CC N3 H6 2 F8 H10 K8 F2 1 B10 K14 CD P6 B6 2 F14 P10 K2 H8

Arrows may be used when data are the same.

REMARKS:

Performed by: ______________________________________________ Date ______________

05/28/03 Page 1 of 2 DIABLO CANYON POWER PLANT TITLE:

STP R-1A ATTACHMENT 9.2 Table 2 - Exercising Unit 2 Rod Cluster Control Assemblies 2

DATE _______________ TIME ___________

ROD BANK SELECTOR SWITCH POSITION ____________ POWER LEVEL INITIAL POSITION EXERCISED FINAL POSITION POSITION ROD ROD STEP DRPI* STEP COUN DRPI* STEP COUN DRPI BAN GROUP ROD COUNTER TER TER

K D2 1 B12 M14 SA P4 B4 2 D14 P12 M2 G3 1 C9 J13 SB N7 C7 2 G13 N9 J3 E3 SC C11 L13 N5 C5 SD E13 N11 L3 H6 CA 1 H10 F8 2 K8

Arrows may be used when data are the same.

05/28/03 Page 2 of 2 STP R-1A (UNIT 2)

ATTACHMENT 9.2 TITLE: Table 2 - Exercising Unit 2 Rod Cluster Control Assemblies INITIAL POSITION EXERCISED FINAL POSITION POSITION ROD ROD STEP DRPI* STEP COUN DRPI* STEP COUN DRPI*

BAN GROUP ROD COUNTER TER TER K

F2 1 B10 K14 CB P6 B6 2 F14 P10 K2 H2 1 B8 H14 CC P8 F6 2 F10 K10-K6 D4 1 D12 M12 CD M4 H4 2 D8 H12 M8 H8

Arrows may be used when data are the same.

REMARKS:

Performed by: ______________________________________________ Date ______________

RO QUESTION 71 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 3 _____

Group # 3 _____

K/A # G2.3.1 Importance 2.6 3.0 Proposed Question:

Which of the following identifies the person who must approve the issuing of a Very High Radiation Area (VHRA) key?

A. RP Foreman B. RP Manager or his designee C. Shift Manager D. Operations Manager or his designee Proposed Answer:

B. RP Manager Explanation:

A incorrect, the foreman approves transfer of issued keys to others B correct, per RCP D-222, Radiation Protection Lock and Key Control, the RP Manger (or his designee) must approve issuing key to VHRA C incorrect, SM approval not required for key issue.

D incorrect, Ops Manager approval not required.

Technical Reference(s): RCP D-222, Radiation Protection Lock and Key Control Proposed references to be provided to applicants during examination: none Learning Objective: 71145 - STATE the 10CFR20 radiation dose limits for TEDE, skin, extremeties, lense of the eye, individual organs, the embroyo/fetus and a member of the public Question Source: Bank # INPO 23099 Question History: Last NRC Exam Salem 2002 ro tier 3 group 3_71 rev1.doc

Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 41.12 55.43 43.4 Comments:

K/A: G2.3.1 - Knowledge of 10 CFR: 20 and related facility radiation control requirements.

ro tier 3 group 3_71 rev1.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER RCP D-222 DIABLO CANYON POWER PLANT REVISION 3 PAGE 4 OF 9 TITLE: Radiation Protection Lock and Key Control UNITS 1 AND 2 7.2 Key Controls{tc "Key Controls" \f C \l 2}

7.2.1 LHRA and VHRA keys may be issued to qualified individuals, as specified in 5.1 and 5.3 of this procedure, provided access to the area (s) of interest has been authorized in accordance with RCP D-220.

CAUTION: Prior to issuing a VHRA key, approval from the radiation protection manager or designee is required.

7.2.2 LHRA and VHRA keys issued from the key box shall be logged in the key issue log, or electronic equivalent, regardless of the length of time that the key is out.

7.2.3 Issued keys may be transferred in the field to other qualified individuals provided that:

a. A foreman grants prior approval.

b. The key issue log or electronic equivalent is updated to show that the key has been checked in then checked out to the new recipient.

7.2.4 Each key should be marked with a unique identification number.

7.2.5 Each key stored in key boxes described in 7.1 should be attached to a numbered tag (typically brass), corresponding to the storage location in the box.

7.2.6 A color-coded second tag shall be attached to each LHRA, and VHRA key.

The following colors shall be used:

a. LHRA= yellow tag

b. VHRA=red tag 7.2.7 A key issue log (see attachment 10.1) or electronic equivalent shall be kept for all keys controlled by this procedure.

7.2.8 A key inventory shall be performed at least once per shift and should contain the following information:

a. Key tag number

b. Status (e.g., logged out, downgraded, or missing).

c. Key control (non-rad, LHRA, VHRA).

d. Date and time inventory completed.

e. Name of person performing inventory.

5SDX0K03.DOC 07 0613.0741

INPO Licensed Operator Exam Bank - PWR Questions ID: 23099 Which one of the choices correctly identifies the position title of the person or persons who must be notified prior to issuance of Very High Radiation Area key?

Ans Operations Superintendent and Radiation Protection Manager D1 Operations Manager and Radiation Protection Manager D2 Radiation Protection Manager Only D3 Operations Superintendent Only AbbrevLocName ExamDate Vendor Type ExamType Cog Level ExamLevel RefMaterial ParentId Salem Unit 1 11/4/2002 WEC PWR ILO 1 R QuestionComment Distract1Comment Distract2Comment Distract3Comment KaNumber KaSegment1 KaSegment2 KaSegment3 KaSegment4 KaSegment5 KaRevision

..G2.3.1 G2 3 1 Tuesday, September 21, 2004 Page 8787 of 9479

RO QUESTION 72 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 3 _____

Group # 3 _____

K/A # G2.3.2 Importance 2.5 2.9 Proposed Question:

The Total Effective Dose Equivalent (TEDE) is defined as:

A. The sum of the Total Organ Dose Equivalent (TODE) and the Shallow Dose Equivalent (SDE)

B. The sum of the Deep Dose Equivalent (DDE) and the Committed Dose Equivalent (CDE)

C. The sum of the Deep Dose Equivalent (DDE) and the Committed Effective Dose Equivalent (CEDE)

D. The sum of the Total Organ Dose Equivalent (TODE) and the Committed Effective Dose Equivalent (CEDE)

Proposed Answer:

C. The sum of the Deep Dose Equivalent (DDE) and the Committed Effective Dose Equivalent (CEDE)

Explanation:

A incorrect, does not use TODE or SDE B incorrect, TODE = The summed total of the DDE (external whole body exposure) and the CDE (internal dose to the organs or tissues from internal exposure from non-stochastic ALI), when CDE is not zero.

C correct, TEDE = The sum of the DDE (for external exposures) and the CEDE (for internal exposures).

D incorrect, does not use TODE Technical Reference(s): LEP3, EP RB PROCEDURES Proposed references to be provided to applicants during examination: none ro tier 3 group 3_72.doc

Learning Objective:

71144 - DEFINE the following:

a. CDE

b. CEDE

c. DDE

d. LDE

e. SDE

f. TEDE

g. Total Organ Dose Equivalent

h. Declared Pregnant Female

i. Restricted Area Question Source: Bank # P-69970 Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 41.12 55.43 43.4 Comments: K/A: G2.3.2 - Knowledge of facility ALARA program.

ro tier 3 group 3_72.doc

1 P-69970 Points: 1.00 Multiple Choice The Total Effective Dose Equivalent (TEDE) is defined as:

A. The sum of the Deep Dose Equivalent (DDE) and the Committed Effective Dose Equivalent (CEDE)

B. The sum of the Deep Dose Equivalent (DDE) and the Shallow Dose Equivalent (SDE)

C. The sum of the Deep Dose Equivalent (DDE) and the Committed Dose Equivalent (CDE)

D. The sum of the Total Organ Dose Equivalent (TODE) and the Committed Effective Dose Equivalent (CEDE)

Answer: A ASSOCIATED INFORMATION:

Associated objective(s):

71144 DEFINE the following:

a. CDE

b. CEDE

c. DDE

d. LDE

e. SDE

f. TEDE

g. Total Organ Dose Equivalent

h. Declared Pregnant Female

i. Restricted Area Reference Id: P-69970 Must appear: No Status: Active User Text:

User Number 1: 0.00 User Number 2: 0.00 Difficulty: 1.00 Time to complete: 2 Topic: LEP3 - Define TEDE Cross

Reference:

LEP3 Obj 1 Comment: 71144

PERSONNEL EXPOSURE TERMS AND DEFINITIONS Obj 1[RLF118] The following terms and definitions are used to track personnel exposure to prevent violation of Legal Exposure Limits.

Acronym Term Definition CDE Committed Dose Equivalent The dose equivalent to an organ that will be received from an intake by an individual during the 50 year period following the intake.

CEDE Committed Effective Dose The product of the Committed Dose Equivalent Equivalent and a weighting factor to equate dose to the organ to the equivalent dose (risk) from uniform irradiation of the whole body.

DDE Deep Dose Equivalent Dose associated with external exposure of the whole body (depth 1 cm).

LDE Lens Dose Equivalent External exposure to the lens of the eye (depth of 0.3 cm).

SDE Shallow Dose Equivalent The dose that applies to the external exposure of the skin or any extremity (depth of 0.007 cm).

TEDE Total Effective Dose Equivalent The sum of the DDE (for external exposures) and the CEDE (for internal exposures).

TODE Total Organ Dose Equivalent The summed total of the DDE (external whole body exposure) and the CDE (internal dose to the organs or tissues from internal exposure from non-stochastic ALI), when CDE is not zero.

DPW Declared Pregnant Woman A woman who has voluntarily informed DCPP, in writing, of her pregnancy and the estimated date of conception.

RESTRICTED AREA The Protected Area of the plant associated within the power block.

The Restricted Area does not include Intake Area.

PAGE 7 OF 25

RO QUESTION 73 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 3 _____

Group # 3 _____

K/A # G2.3.4 Importance 2.5 3.1 Proposed Question:

An operator has a Total Effective Dose Equivalent (TEDE) of 4 REM for the current year.

He has been approved to exceed the Administrative Guideline.

Which of the following is the longest the operator can stay in a 100 mR/hr radiation area without exceeding the DCPP Administrative Exposure Limit for the year?

A. None, the Admistrative Guideline limit and Administrative Exposure Limit for a year are the same.

B. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months C. 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months D. 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months Proposed Answer:

C. 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months Explanation:

DCPP limit is 10% below federal limit - 4.5 rem. Max stay time is 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months .

A incorrect, maximum permissible is 4.5 rem.

B incorrect, this would still be under to the limit.

C correct, exposure would be 4.5 rem - the DCPP exposure limit.

D incorrect, this would be 5.0 rem.

Technical Reference(s):

Student handout for Radiation Worker Training - page 45 (rev 1/02)

Proposed references to be provided to applicants during examination: none ro tier 3 group 3_73.doc

Learning Objective: State the DCPP exposure limits and guidelines (including declared pregnant female).

Question Source:

Modified Bank # INPO 22396 Question History: Last NRC Exam DCPP 10/02 Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.12 55.43 Comments:

K/A: G2.3.4 - Knowledge of radiation exposure limits and contamination control, including permissible levels in excess of those authorized.

ro tier 3 group 3_73.doc

INPO Licensed Operator Exam Bank - PWR Questions ID: 22396 An operator has a Total Effective Dose Equivalent (TEDE) of 4 REM for the current year.

He has been approved to exceed the Administrative Guideline of 2 REM for the year.

How long can the operator stay in a 50 mR/hr radiation area without exceeding the DCPP Administrative Exposure Limit for the year?

Ans 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months D1 0 hours0 days 0 hours 0 weeks 0 months D2 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months D3 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months AbbrevLocName ExamDate Vendor Type ExamType Cog Level ExamLevel RefMaterial ParentId Diablo Canyon 1 10/1/2002 WEC PWR ILO 2 R QuestionComment Distract1Comment Distract2Comment Distract3Comment KaNumber KaSegment1 KaSegment2 KaSegment3 KaSegment4 KaSegment5 KaRevision

..2.3.4 2 3 4 Tuesday, September 21, 2004 Page 8343 of 9479

RO QUESTION 74 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 3 _____

Group # 4 _____

K/A # G2.4.12 Importance 3.4 3.9 Proposed Question:

A LOCA has occurred on Unit 2.

The crew is reviewing the foldout page as part of a procedure transition tailboard.

As a minimum, what amount of repeat back is required by an operator who is assigned a foldout page item to monitor?

A. The high level action.

B. Simple acknowledgement of the assignment.

C. A brief summary of the action and the parameters to monitor.

D. The high level action and the specific parameters and values to monitor.

Proposed Answer:

A. The high level action.

Explanation:

A correct, per OP1.DC11 page 10 (rev 24). foldout page should be reviewed with the crew as a part of the procedure transition tailboard. Specific assignments should be made to appropriate control room operators by assigning the foldout page number and the operator repeating back the high level action. Specific parameters and values are not required to be repeated back. A copy of the foldout page should be given to any operator with an assignment.

B incorrect, repeat high level action.

C incorrect, repeat back the high level action.

D incorrect, specific parameters etc not required.

Technical Reference(s): OP1.DC11 - Conduct of Operations - Abnormal Plant Conditions ro tier 4 group 1_74.doc

Proposed references to be provided to applicants during examination: none Learning Objective: 7922 - Discuss the characteristics of a tailboard Question Source:

New X_

Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 41.10 55.43 _____

Comments:

K/A: G2.4.12 - Knowledge of general operating crew responsibilities during emergency operations.

ro tier 4 group 1_74.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP1.DC11 DIABLO CANYON POWER PLANT REVISION 25 PAGE 11 OF 14 TITLE: Conduct of Operations-Abnormal Plant Conditions 5.5.11 Procedure steps flagged as "continuous action" items should be assigned to the appropriate control room individual to ensure that the requirements are met if conditions change later in the procedure.

5.5.12 EOP foldout page information should be handled in the following manner:

a. For procedures which have no procedure transition tailboard, the shift foreman and the WCSFM should monitor the foldout page items and notify the control room crew of any actions necessary from the foldout page.

b. For other EOPs, the foldout page should be reviewed with the crew as a part of the procedure transition tailboard. Specific assignments should be made to appropriate control room operators by assigning the foldout page number and the operator repeating back the high level action. Specific parameters and values are not required to be repeated back. A copy of the foldout page should be given to any operator with an assignment.

5.5.13 The critical safety function (CSFs) status trees shall be monitored at the periodicity required by the EOP rules of usage (Attachment 7.1).

a. When the SPDS is in service, PERIODIC (once every 10 to 20 minutes) monitoring of the CSF status trees is performed to verify that no red or magenta paths exist. This should be accomplished by selecting one of the CSF screens and using the displayed CSF numbers to check colors.

b. When the SPDS is in service, CONTINUOUS monitoring of the CSF status trees is performed when a red or magenta path exists (exceptions to this are discussed in Attachment 7.1). This should be accomplished by selecting one of the CSF status trees. The person responsible for CSF monitoring remains in the direct area of the SPDS panels allowing immediate detection of a CSF status change.

c. When the SPDS is out of service, the CSF monitoring function is satisfied by using the sheets provided in EOP F-0. In this case, the monitor should review all the sheets in sequence, and should repeat the review periodically or continuously based upon the CSF status per EOP F-0.

d. When a red or magenta path exists, the redundant instrumentation should be verified prior to transitioning to an FR procedure. The intent of this check is to ensure an FR is not implemented based on inaccurate SPDS indication.

01165525.DOC 01B 1112.0815

RO QUESTION 75 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 3 _____

Group # 4 _____

K/A # G2.4.45 Importance 3.3 3.6 Proposed Question:

The crew has entered E-0, Reactor Trip or Safety Injection. SI has actuated. Immediate actions are complete.

Which of the following alarms should be brought to the attention of the SFM as soon as it is received and reviewed by the operator?

A. AR PK09-11, Feedwater Isolation B. AR PK09-12, Main Feedwater Pump Trip (RED)

C. AR PK09-18, Turbine Driven Aux FW Pp D. AR PK12-13, AMSAC Tripped Proposed Answer:

C. AR PK09-18, Turbine Driven Aux FW Pp Explanation:

OP1.DC11 states: All alarms received in the control room shall be reviewed for significance. Significant alarms received during the use of AOPs and EOPs shall be brought to the attention of the SFM by the person acknowledging the alarm.

A incorrect, expected alarm.

B incorrect, expected alarm.

C correct, alarm signals trouble with a running AFW pump.

D incorrect, expected alarm.

Proposed references to be provided to applicants during examination: none ro tier 4 group 1_75.doc

Learning Objective: 7951 - Explain the duties on a reactor trip Technical Reference(s):

OP1.DC11 - Conduct of Operations - Abnormal Plant Conditions AR PK12-13 AR PK09-18 AR PK09-12 AR PK09-11 Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.10 55.43 Comments:

K/A: G2.4.45 - Ability to prioritize and interpret the significance of each annunciator or alarm.

ro tier 4 group 1_75.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP1.DC11 DIABLO CANYON POWER PLANT REVISION 25 PAGE 12 OF 14 TITLE: Conduct of Operations-Abnormal Plant Conditions 5.5.14 In many cases, the AOPs, EOPs, or ARPs refer to normal operating procedures to accomplish various tasks necessary to mitigate a plant event. In these cases, certain precautions, limitations, or procedure steps in the normal operating procedures may not be applicable or desirable during the emergency use of that procedure.

a. If, in the judgment of the shift foreman, time is critical or the operator is knowledgeable about the task being referred to, following consultation with the SM and/or WCSFM the SFM may direct the operator to take actions consistent with these normal operating procedures but using different methodologies or without having the procedure in hand (reference: AD2.ID1).

5.5.15 Use of Annunciator Response Procedures (ARPs)

a. It is vital that the crew use diagnostics, teamwork, and communications to get pertinent information to the SFM.

b. The SFM shall use his/her command and control of the situation and the crew's team skills to prioritize the actions that need to be taken.

Depending on plant conditions, these actions may include completion of all or part of the ARP.

c. All alarms received in the control room shall be reviewed for significance. Significant alarms received during the use of AOPs and EOPs shall be brought to the attention of the SFM by the person acknowledging the alarm.

d. The SFM should determine the priority of annunciators and the appropriate response, based on plant conditions or events in progress.

e. The SFM should assign a crewmember the responsibility of monitoring and addressing alarms.

1. The appropriate ARP should be reviewed for each alarm deemed significant. The SFM will determine when this action will occur, based on manpower available and the events in progress.

2. The SFM should be kept updated on any actions performed that could impact the EOP or AOP procedure flowpath.

01165525.DOC 01B 1112.0815

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK12-13 NUCLEAR POWER GENERATION REVISION 10 DIABLO CANYON POWER PLANT PAGE 1 OF 1 ANNUNCIATOR RESPONSE UNIT TITLE: AMSAC TRIPPED 1 02/20/02 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. LOGIC DIAGRAM

2. ALARM INPUT DESCRIPTION DEVICE ALARM ANNUNCIATOR TYPEWRITER NUMBER INPUT PRINTOUT SETPOINT AMSAC 793 AMSAC TRIPPED K101A K101B

3. PROBABLE CAUSE 3.1 Turbine Power >32% within the last 4 minutes with 3/4 S/G's <11% narrow range level for >25 seconds.

3.2 Restoration of power to AMSAC system.

4. AUTOMATIC ACTIONS 4.1 Trip Main Turbine 4.2 Start all AFW pumps 4.3 Blowdown isolation outside containment 4.4 S/G sample valve isolation

5. OPERATOR ACTIONS NOTE: After an AMSAC actuation, the AMSAC generated turbine trip must be manually reset on VB-3 after this alarm clears. This action is required prior to relatching the turbine due to time delays in the circuitry. AFW pumps may be stopped and blowdown isolation valves may be reopened as soon as either actuating signal has cleared.

5.1 If reactor has tripped, go to EOP E-0.

5.2 If plant conditions require a reactor trip, manually trip the reactor and go to EOP E-0.

138750100.DOC 16 0120.0616

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK09-12 NUCLEAR POWER GENERATION REVISION 16 DIABLO CANYON POWER PLANT PAGE 1 OF 3 ANNUNCIATOR RESPONSE UNIT TITLE: MAIN FEEDWATER PUMP TRIP (RED) 108/11/04 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. LOGIC DIAGRAM YS70 YS80 DO/10 LS119 LS125 ALARM 94T11A 94T12A DO/10 POS62 POS76 2.

12930116.DOC 16 0811.0755

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK09-12 DIABLO CANYON POWER PLANT REVISION 16 PAGE 2 OF 3 TITLE: MAIN FEEDWATER PUMP TRIP (RED) UNIT 1 ALARM INPUT DESCRIPTION DEVICE ALARM ANNUNCIATOR TYPEWRITER NUMBER INPUT PRINTOUT SETPOINT YS 70 554 FWP Turb 11 & 12 Thrust Brg Wear Trip 20 Mils (2 of 2 probes YT70A and YT70B)

YS 80 554 FWP Turb 11 & 12 Thrust Brg Wear Trip 20 Mils (2 of 2 probes YT80A and YT80B)

LS 119 555 FWP Turb 1-1 L.O. Lvl Lo-Lo Trip 39" Below Flange LS 125 556 FWP Turb 1-2 L.O. Lvl Lo-Lo Trip 39" Below Flange POS 62 559 FWP Turb 1-1 Lo Vac Trip 10" to 15" Hg Abs POS 76 560 FWP Turb 1-2 Lo Vac Trip 10" to 15" Hg Abs 94 T 11A 557 FWP Turb 1-1 Trip Low Control Oil Pressure:

58.5-61.5 Psig 94 T 12A 558 FWP Turb 1-2 Trip Low Control Oil Pressure:

58.5-61.5 Psig DO/10 699 FWP 1-1 Speed Controls Trip DO/10 743 FWP 1-2 Speed Controls Trip

3. PROBABLE CAUSE 3.1 Main F.W.P. Trip due to:

3.1.1 Thrust Brg Wear 3.1.2 Low-Low Lube Oil Tank Level 3.1.3 Low Vacuum 3.1.4 Overspeed 3.1.5 Manual trip 3.1.6 SIS 3.1.7 P-14 3.1.8 Hi Discharge Pressure 3.1.9 HPU Pressure 100 psig 12930116.DOC 16 0811.0755

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK09-12 DIABLO CANYON POWER PLANT REVISION 16 PAGE 3 OF 3 TITLE: MAIN FEEDWATER PUMP TRIP (RED) UNIT 1

4. AUTOMATIC ACTIONS 4.1 Possible auto start of AFW pumps.

4.2 Possible Reactor Trip.

4.3 Automatic programmed ramp to 650 MW initiated at 225 MW/Min then a ramp to 550 MW at 25 MW/Min.

5. OPERATOR ACTIONS 5.1 Check annunciator printout and control room instrumentation to verify plant conditions.

An overspeed trip can be verified locally, per step 5.4.

5.2 If the reactor trips, go to EOP E-0.

5.3 Go to Abnormal Operating Procedure, OP AP-15.

5.4 An overspeed trip can be verified at the local OPVIEW panel as follows:

5.4.1 At the Woodward control panel on the FWP pedestal, verify the keyswitch is selected to "OPVIEW DISABLED."

5.4.2 Touch the screen to awaken. Verify the message "LOCAL CONTROL Modbus Commands Disabled" appears in the upper left corner of the screen.

This indicates the Control Room has pump control.

5.4.3 The cause of the trip should be shown across the bottom of the screen.

Optionally, if not selected, touch "Main Menu" to select.

5.4.4 Select "Alarm Log."

5.4.5 The cause of the trip will be shown across the bottom of the screen.

5.5 If a programmed ramp has been initiated:

5.5.1 Verify validity of the ramp.

a. Place ramp on HOLD if not valid.

5.5.2 Implement AP-25.

6. REFERENCES 6.1 501128 Main Annunciator Schematic Diagram 6.2 663300-11 Boiler F.P. Turbine Test Data (POS 62, 76) 6.3 Loop Test 20-70 (YS 70) 6.4 Loop Test 20-80 (YS 80) 6.5 Loop Test 20-22FF (LS-119) 6.6 Loop Test 20-23FF (LS-125) 6.7 Loop Test 20-23K (PS-86; 94T11A) 6.8 Loop Test 20-23K (PS-99; 94T12A) 6.9 437567 FWP Turbine Control Schematic Diagram 12930116.DOC 16 0811.0755

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK09-11 NUCLEAR POWER GENERATION REVISION 6 DIABLO CANYON POWER PLANT PAGE 1 OF 1 ANNUNCIATOR RESPONSE UNIT TITLE:

APPROVED:

FEEDWATER ISOLATION 11/07/88 1

11/07/88 DATE EFFECTIVE DATE

1. LOGIC DIAGRAM K 0614 ALARM

2. ALARM INPUT DESCRIPTION DEVICE ALARM ANNUNCIATOR TYPEWRITER NUMBER INPUT PRINTOUT SETPOINT K 0614 47 FW Isol From React Trip & Lo Tavg 2/4 LT 554°F

3. PROBABLE CAUSE 3.1 A reactor trip (P-4) with a low TAVG signal, either train A or B.

NOTE: This alarm will not be initiated by a feedwater isolation as a result of stm.

gen. Hi-Hi level or an S.I. initiation signal.

4. AUTOMATIC ACTIONS 4.1 Closure of all S/G feedwater control and bypass valves.

5. OPERATOR ACTIONS 5.1 Check annun. printout and control room instrumentation to verify plant conditions.

5.2 With Reactor TRIP, GO TO Emergency Procedure EP E-0.

NOTE: If this alarm occurs, feedwater control valve isolation can only be reset via the two feedwater isolation reset pushbuttons on VB-3.

119301ZZZ.DOC 16 1

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK09-18 NUCLEAR POWER GENERATION REVISION 13B DIABLO CANYON POWER PLANT PAGE 1 OF 2 ANNUNCIATOR RESPONSE UNIT TITLE: TURBINE DRIVEN AUX FW PP 109/05/02 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. LOGIC DIAGRAM T4008C POS425 PS420 POS433 ALARM POS426A 49X12-30 27-12-30

2. ALARM INPUT DESCRIPTION DEVICE ALARM ANNUNCIATOR TYPEWRITER PPC NUMBER INPUT PRINTOUT SETPOINT ADDRES S

T4008C 594 Aux FWP 1-1 Temp PPC The inputs to device T4008C are as follows:

1. Aux FWP 1-1 Turb Inbd Brg Temp T2359A

2. Aux FWP 1-1 Turb Outbd Brg Temp T2360A

3. Aux FWP 1-1 Pp Inbd Brg Temp T2363A

4. Aux FWP 1-1 Pp Thr Brg Temp T2365A PS 420 1061 Aux FWP 1-1 Suct Press Lo LT 8.5 psig POS 425(H) 595 Aux FWP Turb 1-1 FCV-37 or FCV-38 Clsd Vlv Clsd POS 433(F) 595 Aux FWP Turb 1-1 FCV-37 or FCV-38 Clsd Vlv Clsd 49X-12-30 1164 Aux FWP Turb 11 FCV-95 OC Trip 189301113.D O C 16 0120.0620

PA CIFIC G A S A N D ELECTRIC CO M PA N Y N U M BER A R PK 09-18 D IA BLO CA N Y O N PO W ER PLA N T REV ISIO N 13B PA G E 2 OF 2 TITLE: TU RBIN E D RIV EN A U X FW PP U N IT 1 DEVICE ALARM ANNUNCIATOR TYPEWRITER PPC NUMBER INPUT PRINTOUT SETPOINT ADDRES S

27-12-30 1165 Aux FWP Turb 11 FCV-95 Cont UV POS 426A 475 Aux Feed Pp Turb 1-1 Stm Inlet FCV-152 Clsd Vlv Clsd

3. PROBABLE CAUSE 3.1 Loss of cooling water.

3.2 Low CST level 3.3 Steam supply valve closed.

3.4 Overcurrent trip of FCV-95.

4. AUTOMATIC ACTIONS None

5. OPERATOR ACTIONS 5.1 If bearing high temperature:

5.1.1 Monitor bearing temperature.

5.1.2 Locally check cooling water supply and adjust as necessary.

5.2 If FCV-152 is closed refer to OP D-1:IV to reset.

5.3 Check the position of FCV-37 or FCV-38.

5.3.1 Closure of FCV-37 or FCV-38 makes the Turbine Driven Auxiliary Feedwater Pump inoperable.

5.4 If low suction pressure:

5.4.1 Check CST level and local valve lineup.

5.4.2 Refer to OP D-1:V for alternate AFW supplies.

5.5 Check power supply for FCV-95.

5.6 Refer to T.S. 3.7.1.2 (ITS 3.7.5).

189301113.D O C 16 0120.0620

SRO QUESTION 76 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 1 Group # _____ 1 K/A # EPE 011 G2.2.25 Importance 3.7 Proposed Question:

Technical Specification 3.5.1, Accumulators, applies until the plant is in MODE 3, less than 1000 psig.

Why are the Accumulators allowed to be removed from service below 1000 psig?

A. Nitrogen injection is a larger risk.

B. The probability of a large LOCA with a blowdown phase is sufficiently low.

C. ECCS injection is sufficient to ensure peak clad temperature remains below 2200ºF.

D. Accumulator boron concentration is typically less than required shutdown boron concentration.

Proposed Answer:

C. ECCS injection is sufficient to ensure peak clad temperature remains below 2200ºF.

Explanation:

A incorrect, this is why Accumulators are isolated in many EOPs.

B incorrect, a large LOCA will still have a blowdown phase.

C correct, below 1000 psig, ECCS injection is sufficient to maintain core cooling.

D incorrect, Required boron concentration in an accumulator is higher than any required shutdown boron concentration.

Technical Reference(s):

B 3.5.1 - Accumulators Bases TS 3.5.1 - Accumulators Proposed references to be provided to applicants during examination: none Learning Objective: 9694E - Discuss Technical Specification Bases.

Question Source:

sro tier 1 group 1_76 rev1.doc

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis 10 CFR Part 55 Content: 55.41 _____

55.43 43.2 Comments:

K/A: EPE 01 1 G2.2.25 - Large Break LOCA, Knowledge of bases in technical specifications for limiting conditions for operations and safety limits.

sro tier 1 group 1_76 rev1.doc

Seal Injection Flow 3.5.5 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.1 Accumulators LCO 3.5.1 Four ECCS accumulators shall be OPERABLE.

APPLICABILITY: MODES 1 and 2, MODE 3 with RCS pressure > 1000 psig.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One accumulator A.1 Restore boron 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months inoperable due to boron concentration to within concentration not within limits.

limits.

B. One accumulator B.1 Restore accumulator to 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months inoperable for reasons OPERABLE status.

other than Condition A.

C. Required Action and C.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A or B AND not met.

C.2 Reduce RCS pressure to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

< 1000 psig.

D. Two or more accumulators D.1 Enter LCO 3.0.3. Immediately inoperable.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.1.1 Verify each accumulator isolation valve is fully open. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.5.1.2 Verify borated water volume in each accumulator is 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

> 814 ft3 and < 886 ft3.

SR 3.5.1.3 Verify nitrogen cover pressure in each accumulator is 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

> 579 psig and < 664 psig.

(continued)

Seal Injection Flow 3.5.5 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.5.1.4 Verify boron concentration in each accumulator is 31 days

> 2200 ppm and < 2500 ppm.

AND

NOTE-------

Only required to be performed for affected accumulators.

Once within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after each solution volume increase of > 5.6%

of narrow range indicated level that is not the result of addition from the refueling water storage tank.

SR 3.5.1.5 Verify power is removed from each accumulator 31 days isolation valve operator when RCS pressure is > 1000 psig.

Accumulators B 3.5.1 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

B 3.5.1 Accumulators BASES BACKGROUND The functions of the ECCS accumulators are to supply borated water to replace inventory in the reactor vessel during the latter phase of blowdown to the beginning phase of reflood of a loss of coolant accident (LOCA). The ECCS injection mode following a large break LOCA consists of three phases: 1) blowdown, 2) refill, and 3) reflood.

The blowdown phase of a large break LOCA is the initial period of the transient during which the RCS departs from equilibrium conditions, and heat from fission product decay, hot internals, and the vessel continues to be transferred to the reactor coolant. The blowdown phase of the transient ends when the RCS pressure falls to a value approaching that of the containment atmosphere.

In the refill phase of a LOCA, which immediately follows the blowdown phase, reactor coolant inventory has vacated the core through steam flashing and spill out through the break. The core is essentially in adiabatic heatup. The balance of accumulator inventory is then available to help fill voids in the lower plenum and reactor vessel downcomer so as to establish a recovery level at the bottom of the core and ongoing reflood of the core with the addition of ECCS water.

The refill phase is complete when the injection of ECCS water has filled the reactor vessel downcomer and the lower plenum of the reactor vessel, which is bounded by the bottom of the fuel rods.

The reflood phase follows the refill phase and continues until the reactor vessel has been filled to the extent that core temperature rise has been terminated.

The accumulators function in the later stage of blowdown to the beginning of reflood to fill the downcomer and lower plenum. The injection of the ECCS pumps aid during refill. Reflood and the following long term heat removal is accomplished by water pumped into the core by the ECCS pumps.

The accumulators are pressure vessels partially filled with borated water and pressurized with nitrogen gas. The accumulators are passive components, since no operator or control actions are required in order for them to perform their function. Internal accumulator tank pressure is sufficient to discharge the accumulator contents to the RCS, if RCS pressure decreases below the accumulator pressure.

Each accumulator is piped into an RCS cold leg via an accumulator line and is isolated from the RCS by an open motor operated isolation valve (continued)

DIABLO CANYON - UNITS 1 & 2 Revision 2 8S9IDX02.DOC - R2B 1

Accumulators B 3.

5.1 BACKGROUND

(8808A, B, C, and D) and by two check valves in series. The (continued) accumulator size, water volume, and nitrogen cover pressure are selected so that three of the four accumulators are sufficient to partially cover the core before significant clad melting or zirconium water reaction can occur following a LOCA. The need to ensure that three accumulators are adequate for this function is consistent with the LOCA assumption that the entire contents of one accumulator will be lost via the RCS pipe break during the blowdown phase of the LOCA.

APPLICABLE The accumulators are assumed OPERABLE in both the large and small SAFETY break LOCA analyses at full power (Ref. 1 and 3). These are the ANALYSES Design Basis Accidents (DBAs) that establish the acceptance limits for the accumulators. Reference to the analyses for these DBAs is used to assess changes in the accumulators as they relate to the acceptance limits.

In performing the LOCA calculations, conservative assumptions are made concerning the availability of ECCS flow with no credit taken for ECCS pump flow until an effective delay has elapsed. In the early stages of a LOCA, with or without a loss of offsite power, the accumulators provide the sole source of makeup water to the RCS.

The assumption of loss of offsite power is required by regulations and conservatively imposes a delay wherein the ECCS pumps cannot deliver flow until the emergency diesel generators start, come to rated speed, and go through their timed loading sequence. The delay time is conservatively set with an additional 2 seconds to account for SI signal generation. In cold leg break scenarios, the entire contents of one accumulator are assumed to be lost through the break. No operator action is assumed during the blowdown stage of a large break LOCA.

The limiting large break LOCA is a double ended guillotine break in the RCS piping. During this event, the accumulators discharge to the RCS as soon as RCS pressure decreases to below accumulator pressure.

The worst case small break LOCA analyses also assume a time delay before pumped flow reaches the core. For the larger range of small breaks, the SI pumps begin RCS injection, however, the increase in fuel clad temperature is terminated primarily by the accumulators, with pumped flow then providing continued cooling. As break size decreases, the accumulators and the ECCS centrifugal charging and SI pumps play a part in terminating the rise in clad temperature. As break size continues to decrease, the role of the accumulators continues to decrease.

(continued)

DIABLO CANYON - UNITS 1 & 2 Revision 2 8S9IDX02.DOC - R2B 2

Accumulators B 3.5.1 BASES APPLICABLE The accumulators do not discharge above the pressure of their nitrogen SAFETY cover gas (579 to 664 psig.) At higher pressures the ECCS centrifugal ANALYSES charging pumps and SI pumps injection becomes solely responsible for (continued) terminating the temperature increase.

This LCO helps to ensure that the following acceptance criteria established for the ECCS by 10 CFR 50.46 (Ref. 2) that are applicable for the accumulators will be met following a LOCA:

a. Maximum fuel element cladding temperature is < 2200°F;

b. Maximum cladding oxidation is < 0.17 times the total cladding thickness before oxidation;

c. Maximum hydrogen generation from a zirconium-water reaction is

< 0.01 times the hypothetical amount that would be generated if all of the metal in the cladding cylinders surrounding the fuel, excluding cladding surrounding the plenum volume, were to react; and

d. Core is maintained in a coolable geometry.

Since the accumulators discharge during the blowdown and reflood phase of a LOCA, they do not contribute to the long term cooling requirements of 10 CFR 50.46, though their water volume is credited as part of the long term cooling inventory.

For both the large and small break LOCA analyses, a nominal contained accumulator water volume (814 cubic feet to 886 cubic feet) is used. The contained water volume is the same as the deliverable volume for the accumulators, since the accumulators are emptied, once discharged. For small breaks, an increase in water volume is a peak clad temperature penalty. Depending on the NRC-approved methodology used to analyze large breaks, an increase in water volume may result in either a peak clad temperature penalty or benefit, depending on downcomer filling and subsequent spill through the break during the core reflooding portion of the transient. The analysis makes a conservative assumption with respect to ignoring or taking credit for line water volume from the accumulator to the check valve. The safety analysis assumes values of >814 cubic feet and <886 cubic feet. The implementation of these values is performed accounting for instrument uncertainty.

The minimum boron concentration setpoint is used in the post LOCA boron concentration calculation. The calculation is performed to assure reactor subcriticality in a post LOCA environment. Of particular interest is the large break LOCA, since no credit is taken for control rod assembly insertion.

(continued)

DIABLO CANYON - UNITS 1 & 2 Revision 2 8S9IDX02.DOC - R2B 3

Accumulators B 3.5.1 BASES APPLICABLE A reduction below the accumulator LCO minimum boron concentration SAFETY would produce a subsequent reduction in the available containment ANALYSES recirculation sump boron concentration for post LOCA shutdown and (continued) an increase in the sump pH. The maximum boron concentration is used in determining the cold leg to hot leg recirculation injection switchover time and minimum sump pH.

The large and small break LOCA analyses are performed at the minimum nitrogen cover pressure (579 psig), since sensitivity analyses have demonstrated that higher nitrogen cover pressure results in a computed peak clad temperature benefit. The maximum nitrogen cover pressure limit (664 psig) provides margin to assure inadvertent relief valve actuation does not occur.

These analysis-assumed pressures are specified in the SRs. Volumes are shown on the control board indicators as % readings on accumulator narrow range level instruments. Adjustments to the analysis parameters for instrument inaccuracies or other reasons are applied to determine the acceptance criteria used in the plant surveillance procedures. These adjustments assure the assumed analyses parameters are maintained.

The effects on containment mass and energy releases from the accumulators are accounted for in the appropriate analyses (Refs. 1 and 3).

The accumulators satisfy Criterion 2 and Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO The LCO establishes the minimum conditions required to ensure that the accumulators are available to accomplish their core cooling safety function following a LOCA. Four accumulators are required to ensure that 100% of the contents of three of the accumulators will reach the core during a LOCA. This is consistent with the assumption that the contents of one accumulator spill through the break. If less than three accumulators are injected during the blowdown phase of a LOCA, the ECCS acceptance criteria of 10 CFR 50.46 (Ref. 2) could be violated.

For an accumulator to be considered OPERABLE, the isolation valve must be fully open, power removed above a nominal pressure of 1000 psig, and the limits established in the SRs for contained volume, boron concentration, and nitrogen cover pressure must be met.

(continued)

DIABLO CANYON - UNITS 1 & 2 Revision 2 8S9IDX02.DOC - R2B 4

Accumulators B 3.5.1 BASES (continued)

APPLICABILITY In MODES 1 and 2, and in MODE 3 with RCS pressure > 1000 psig, the accumulator OPERABILITY requirements are based on full power operation. Although cooling requirements decrease as power decreases, the accumulators are still required to provide core cooling as long as elevated RCS pressures and temperatures exist.

This LCO is only applicable at RCS pressures > 1000 psig. At pressures < 1000 psig, the rate of RCS blowdown is such that the ECCS pumps can provide adequate injection to ensure that peak clad temperature remains below the 10 CFR 50.46 (Ref. 2) limit of 2200°F.

In MODE 3, with RCS pressure < 1000 psig, and in MODES 4, 5, and 6, the accumulator motor operated isolation valves are normally closed to isolate the accumulators from the RCS. This allows RCS cooldown and depressurization without discharging the accumulators into the RCS or requiring depressurization of the accumulators.

Accumulator may be unisolated when accumulator pressure is less than the maximum RCS pressure for the existing RCS cold leg temperature allowed by the P/T limit curves provided in the PTLR. This condition is in agreement with the TS 3.4.12 LCO requirement.

ACTIONS A.1 If the boron concentration of one accumulator is not within limits, it must be returned to within the limits within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . In this Condition, the ability to maintain subcriticality or minimum boron precipitation time may be reduced. The boron in the accumulators contributes to the assumption that the combined ECCS water in the partially recovered core during the early reflooding phase of a large break LOCA is sufficient to keep that portion of the core subcritical. One accumulator below the minimum boron concentration limit, however, will have no effect on available ECCS water and an insignificant effect on core subcriticality during reflood. Boiling of ECCS water in the core during reflood concentrates boron in the saturated liquid that remains in the core. In addition, current analyses demonstrate that the accumulators will discharge following a large main steam line break. The impact of their discharge is minor and not a design limiting event. Thus, 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is allowed to return the boron concentration to within limits.

B.1 If one accumulator is inoperable for a reason other than boron concentration, the accumulator must be returned to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . In this Condition, the required contents of three accumulators cannot be assumed to reach the core during a LOCA.

Due to the severity of the consequences should a LOCA occur in these conditions, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time to open the valve, remove (continued)

DIABLO CANYON - UNITS 1 & 2 Revision 2 8S9IDX02.DOC - R2B 5

SRO QUESTION 77 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 1 Group # _____ 1 K/A # APE 022 G2.1.33 Importance 4.0 Proposed Question:

PLANT CONDITIONS:

Unit 1 is in MODE 6.

The crew is preparing to fill the refueling cavity - it is estimated it will require 360,000 gallons.

Both Boric Acid Storage Tanks are inoperable As a minimum, for the current plant conditions, what must the level in the RWST (in whole %) be to allow the filling of the refueling cavity?

A. 73%

B. 77%

C. 84%

D. 90%

Proposed Answer:

C. 84%

Explanation:

A incorrect, this is what would be required to do the fill, but neglecting the necessary 50,000.

B incorrect, ECG 8.8 bases states the volume is 50,000 gallons but that includes unuable volume and 17,865 gallons is required. 17,864 + 360K = 378 or 77%.

C correct, required volume is 360,0009 gallons (74%) plus 50,000 gallons to have the RWST operable for ECG 8.8. This brings the required volume to 410,000 gallons (84% -

411,381 gallons).

D incorrect, this would be 50K added to the minumum volume at 0%, then added to 360,000K.

sro tier 1 group 1_77 rev1.doc

Technical Reference(s):

ECG 8.8, Reactivity Control Systems - Borated Water Source - Shutdown Refueling Water Storage Tank Percent Indicated Vs. Volume, Page IE-9.2b Proposed references to be provided to applicants during examination:

ECG 8.8, Reactivity Control Systems - Borated Water Source - Shutdown Refueling Water Storage Tank Percent Indicated Vs. Volume, Page IE-9.2b Learning Objective: 66041 - Discuss the requirements of System 8 ECGs Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 _____

55.43 43.2/43.3 Comments:

K/A: APE 022 G2.1.33 - Loss of Reactor Coolant Makeup - Ability to recognize indications for system operating parameters which are entry-level conditions for technical specifications.

sro tier 1 group 1_77 rev1.doc

Reactivity Control Systems - Borated Water Source - Shutdown 8.8 8.0 CHEMICAL AND VOLUME CONTROL SYSTEM 8.8 Reactivity Control Systems - Borated Water Source - Shutdown ECG 8.8 A minimum of one borated water source shall be OPERABLE.

APPLICABILITY: MODES 5 and 6.

ACTIONS

NOTE------------------------------------------------------------

Prior to exceeding the Completion Time of any Required Action, a 10 CFR 50.59 evaluation must be approved by the PSRC justifying the acceptability of exceeding the Completion Time.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. No borated water source A.1 Suspend all operations Immediately OPERABLE. involving CORE ALTERATIONS or positive reactivity changes.

SURVEILLANCE REQUIREMENTS

NOTE------------------------------------------------------------

SR 8.8.1 through SR 8.8.4 shall be current for at least the credited OPERABLE borated water source.

SURVEILLANCE FREQUENCY SR 8.8.1 Verify the RWST temperature is within limit when it is the source 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of borated water and the outside ambient air temperature is less than 35°F.

SR 8.8.2 Verify the boron concentration of the water is within limits. 7 days SR 8.8.3 Verify the contained borated water volume is within limits. 7 days SR 8.8.4 Verify the boric acid storage tank solution temperature is within 7 days limit when it is the source of borated water.

Diablo Canyon Units 1 & 2 Rev. 0 1GZOW300.DOC 1

Reactivity Control Systems - Borated Water Source - Shutdown 8.8 SURVEILLANCE FREQUENCY BASES BACKGROUND ECG 8.8 was developed to relocate the requirements from current TS (CTS) 3/4.1.2.5 to the ECGs as approved by Reference 1.

The boration subsystem of the chemical and volume control system (CVCS) provides the means to meet one of the functional requirements of the CVCS, i.e. to control the chemical neutron absorber (boron) concentration in the reactor coolant system (RCS) and to help control the boron concentration to maintain shutdown margin (SDM). To accomplish this functional requirement, the boration systems require a source of borated water, one or more flow paths to inject this borated water into the RCS, and appropriate charging pumps to provide the necessary charging head.

The boron injection system ensures that negative reactivity control is available during each mode of facility operation. The components required to perform this function include: (1) borated water sources, (2) charging pumps, (3) separate flow paths, (4) boric acid transfer pumps, and (5) an emergency power supply from an OPERABLE diesel generator.

Final Safety Analysis Report (FSAR) Section 9.3.4.2.2.4, Chemical Shim APPLICABLE and Reactor Coolant Makeup, describes the design bases of the CVCS SAFETY chemical shim (boric acid) and reactor coolant makeup system. FSAR ANALYSES Section 15.2.4, Uncontrolled Boron Dilution, provides an analysis of the uncontrolled boron dilution accident.

FSAR Section 9.3.4, Chemical And Volume Control System (CVCS),

states that the boron injection system, for cold shutdown conditions, is designed to increase the RCS boron concentration to the cold shutdown concentration. It is capable of borating the RCS through either one of two flowpaths and from either one of two boric acid sources. The amount of boric acid stored in the CVCS always exceeds that amount required to borate the RCS to cold shutdown concentration assuming that the control assembly with the highest reactivity worth is stuck in its fully withdrawn position.

(continued)

Diablo Canyon Units 1 & 2 Rev. 0 1GZOW300.DOC 2

Reactivity Control Systems - Borated Water Source - Shutdown 8.8 SURVEILLANCE FREQUENCY BASES APPLICABLE Reference 2 states that the boration subsystem is not assumed to operate SAFETY to mitigate the consequences of a design basis accident or transient. In ANALYSES the case of a malfunction of the CVCS, which causes a boron dilution (continued) event, the response required by the operator is to close the appropriate valves in the reactor makeup system before the SDM is lost. Operation of the boration subsystem is not assumed to mitigate this event.

Furthermore, Reference 3 notes that the normal capability to control reactivity with boron is not credited in the accident analysis.

Reference 4 states with the RCS temperature below 200°F, one boron injection system is acceptable without single failure consideration on the basis of the stable reactivity condition of the reactor and the additional restrictions prohibiting CORE ALTERATIONS and positive reactivity changes in the event the single injection system becomes inoperable.

The boron capability required below 200°F is sufficient to provide an SDM of 1% k/k after xenon decay and cooldown from 200°F to 140°F. This condition requires either 2,499 gallons of 7,000 ppm borated water from the boric acid storage tanks or 17,865 gallons of 2,300 ppm borated water from the RWST.

LCO The LCO requires at least one of two sources of borated water to be OPERABLE. The acceptable sources and limits are:

a. A Boric Acid Storage System with:

1) A minimum contained borated water volume of 2,499 gallons,

2) A boron concentration between 7,000 and 7,700 ppm, and

3) A minimum solution temperature of 65°F.

b. The Refueling Water Storage Tank (RWST) with;

1) A minimum contained borated water volume of 50,000 gallons,

2) A minimum boron concentration of 2300 ppm, and

3) A minimum solution temperature of 35°F.

The contained water volume limits for each source include allowance for water not available because of discharge line location and other physical characteristics (Reference 4).

(continued)

Diablo Canyon Units 1 & 2 Rev. 0 1GZOW300.DOC 3

Reactivity Control Systems - Borated Water Source - Shutdown 8.8 BASES APPLICABILITY ECG 8.8 is only applicable in MODES 5 and 6 (RCS temperature 200°F). When RCS temperature is below 200°F, only one boron injection flow path is required, without single failure consideration, as discussed in the safety analyses section above. For operation in MODES 1 - 4, refer to ECG 8.4, which requires a minimum of two boron injection flow paths to be OPERABLE to ensure functional capability in the event an assumed failure renders one of the flow paths inoperable (Reference 4).

ACTIONS A.1 Condition A applies when none of the borated water sources are OPERABLE. With this condition, Action A.1 requires that all operations involving CORE ALTERATIONS or positive reactivity changes be suspended immediately. This will preclude any positive reactivity changes. With no source for injection of borated water, core protection is severely reduced and any actions that add positive reactivity to the core must be suspended immediately.

SURVEILLANCE SR 8.8.1 through SR 8.8.4 are required to be current for at least the REQUIREMENTS credited OPERABLE borated water source.

SR 8.8.1 This surveillance verifies that the RWST solution temperature is not less than 35°F when it is the source of borated water and the outside ambient air temperature is less than 35°F. This assures that the boric acid solution remains soluble. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months frequency is appropriate based on the large volume of solution that has to undergo the temperature change and on engineering judgment.

SR 8.8.2 through 8.8.4 These surveillances verify that the boron concentration, borated water volume, and temperature of the boric acid storage tank, when it is the source of borated water, are within limits specified by the LCO Bases.

The 7 day Frequency has been shown to be acceptable through operating experience.

(continued)

Diablo Canyon Units 1 & 2 Rev. 0 1GZOW300.DOC 4

Reactivity Control Systems - Borated Water Source - Shutdown 8.8 BASES REFERENCES 1. License Amendments 135 (Unit 1) and 135 (Unit 2) dated May 28, 1999.

2. License Amendment Request 97-09, Attachment 21, page 7 (PG&E Letter DCL-97-106 dated June 2, 1997)

3. J. D. Andrachek, et. Al., Methodically Engineered, Restructured, and Improved Technical Specifications, (MERITS) Program - Phase II Task 5, Criteria Application, WCAP-11618, dated November 1987.

4. CTS Bases 3/4.1.2 (relocated to ECG 8.8 Bases).

6/27/2000 Effective Date Diablo Canyon Units 1 & 2 Rev. 0 1GZOW300.DOC 5

SRO QUESTION 78 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 1 Group # _____ 1 K/A # APE 025 AA2.02 Importance 3.8 Proposed Question:

PLANT CONDITIONS:

Unit 1 is in MODE 5.

RHR pump 1-1 is in service.

PK11-21, High Radiation alarms. A few minutes later, PK02-16, RHR System and PK02-17 RHR Pumps also go into alarm.

Which of the following procedures should the SFM utilize to address the current plant conditions?

A. AP-1, Excessive Reactor Coolant System Leakage.

B. AP-16, Malfunction of the RHR System.

C. AP-24, Shutdown LOCA.

D. AP SD-2, Loss of RCS Inventory.

Proposed Answer:

D. AP SD-2, Loss of RCS Inventory.

Explanation:

A incorrect, not appropriate in MODE 5 (applies in MODEs 1 - 4).

B incorrect, not applicable in MODE 5 or appropriate if there is a loss of RCS inventory.

C incorrect, not applicable in MODE 5.

D correct, this is the procedure to use for loss of RCS inventory in MODE 5.

Technical Reference(s):

PK02-16, PK02-17, PK11-21 OP AP-24, OP AP SD-2, OP AP -1, OP AP-16 Proposed references to be provided to applicants during examination: none sro tier 1 group 1_78.doc

Learning Objective: 3478 - State the entry conditions for abnormal operating procedures Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 _____

55.43 43.5 Comments:

K/A: APE 025 AA2.02 - Ability to determine and interpret the following as they apply to the Loss of Residual Heat Removal System: Leakage of reactor coolant from RHR into closed cooling water system or into reactor building atmosphere sro tier 1 group 1_78.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP AP 16 NUCLEAR POWER GENERATION REVISION 13 DIABLO CANYON POWER PLANT PAGE 1 OF 10 ABNORMAL OPERATING PROCEDURE UNITS TITLE: Malfunction of the RHR System 1 2 AND 09/04/02 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. SCOPE 1.1 This procedure covers the steps to be taken following malfunction of the Residual Heat Removal system due to a loss of flow or leakage while in Mode 4.

1.2 OP AP-24, "Shutdown LOCA," provides the action necessary for maintaining core cooling and protecting the reactor core in the event of an RCS leak while on Residual Heat Removal. This procedure may be implemented from OP AP-24 to provide diagnosis for and corrective actions for leaks occurring in systems other than the RCS that cause a loss of RCS inventory.

2. SYMPTOMS 2.1 Abnormal fluctuations in RHR flow on FI-970A & B and/or FI-971A & B.

2.2 Increasing level indication in the PRT.

2.3 Increasing level indication in CCW Surge Tank.

2.4 Possible Annunciator Alarms 2.4.1 CCW SYS SURGE TK LVL/MK-UP (PK01-07)

1) CCW Surge Tk Level Hi/Lo 2.4.2 RHR SYSTEM (PK02-16)

1) RHR Suction Valve Open

2) RHR Pp _____ Room Sump Lvl Hi

3) RHR Pp _____ Disch Press Hi

4) RHR Pp 2-1 and 2-2 Disch Flow Low 2.4.3 RHR PUMPS (PK02-17)

1) RHR Pps OC Trip

2) RHR Pp _____ Room Sump Pps run 2.4.4 HIGH RADIATION (PK11-21)

1) Contmt Area Mon High Rad RE-2

2) Process Mon Hi-Rad (RE-17A & B) 001193113.D O C 02 0120.0655

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP AP-1 NUCLEAR POWER GENERATION REVISION 14 DIABLO CANYON POWER PLANT PAGE 1 OF 10 ABNORMAL OPERATING PROCEDURE UNITS TITLE: Excessive Reactor Coolant System Leakage 1 2 AND 08/08/01 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. SCOPE 1.1 This procedure covers RCS leakage conditions where the charging system is capable of maintaining normal PZR level while the PZR heaters maintain normal system pressure. The goal is to limit the release of radioactive material by isolating defective component or reduce the magnitude of the leakage to within Tech Spec limits. ITS 3.4.13, "RCS Operational Leakage,"

applies in Modes 1-4.

2. SYMPTOMS 2.1 Irregular RCP seal flow (FR-157 or 159, VB2).

2.2 Charging/letdown flow mismatch (FI-134A, VB2; FI-128A, CC2).

2.3 Decreasing VCT level (LI-112, VB2).

2.4 Abnormal seal injection flow (FI-144, 143, 115, 116; VB2).

2.5 Abnormal letdown flow (FI-134A, VB2).

2.6 PRT high level LI-470, high press PI-472, or high temp TI-471 (VB2).

2.7 High RCDT level (LI-188, Aux Board), or increased pumpdown frequency.

2.8 PZR safety valve or PORV discharge line high temp (TI-465, 467, 469, or 463; VB2).

2.9 Rx vessel flange leakoff temp high (TI-401, VB-2).

2.10 High Containment Sump or Rx Cavity Sump levels (LR-60, 61, 62; PAM1).

2.11 High Containment air temp or pressure (TR-26, PR-933; VB1).

2.12 Increased Containment radiation (RM-11 or 12, RMS CAB II).

2.13 Increasing rad levels (RE-17A/B) with possible autoclosure of RCV-16 (VB1).

2.14 Increasing CCW surge tank level (VB1).

2.15 Possible autoclosure of FCV-357 (VB1).

2.16 Increasing CCW header "C" flow (FI-46, VB1).

2.17 Increasing letdown temp (TI-130, VB2).

2.18 TCV-130, CCW to Letdown HX, goes full open (VB2).

2.19 Possible flashing in letdown line (PI-135, VB2).

00072514.DOC 02 0808.0853

1 &2 D IABLO C ANYON P OWER P LANT OP AP SD-2 ABNORMAL OPERATING PROCEDURE REV. 15 UNITS PAGE 1 OF 14 Loss of RCS Inventory 11/26/04 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. SCOPE 1.1 This procedure provides guidance for locating and isolating an RCS leak in Modes 5 and 6.

1.1.1 Steps 1 thru 22 are to be used if RCS level is less than 108' or if level is less than 111' and dropping rapidly such that loss of RHR is imminent.

a. Step 2 checks for cavitation, or possible cavitation, of the RHR pumps and reduces flow or stops the pumps to stop the cavitation.

b. Step 6 checks for a LOCA from an RHR relief valve.

c. Steps 7 thru 10 add water from the RWST and restart the RHR pumps in the injection mode.

d. Steps 11 thru 13 are used to vent the RHR System.

e. Steps 14 thru 22 are plant stabilization actions.

1.1.2 If RCS level is greater than 108' and inventory loss is manageable, the inventory loss reduction, isolation and recovery actions begin at step 24.

a. Steps 24 thru 27 shut down the RCPs, if running, and reduce RCS pressure to reduce the inventory loss.

b. Step 28 restores inventory.

c. Steps 29 thru 33 check for the location of the leak by monitoring tank levels, doing local checks and by isolating RHR or the charging and letdown lines.

d. If the leak has not been found by this time the leak is assumed to be on an RHR train, steps 34 thru 36 are used to isolate a leaking RHR train.

1.2 This procedure also provides guidance to restore RCS inventory.

1.3 This procedure covers the steps required to regain RHR cooling after a loss of inventory and subsequent loss of RHR pumps while at reduced RCS inventory conditions (Reactor Vessel level less than 111').

2.

02 01069415.DOC 1126.0753 Page 1 of 15

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP AP-24 NUCLEAR POWER GENERATION REVISION 5 DIABLO CANYON POWER PLANT PAGE 1 OF 29 ABNORMAL OPERATING PROCEDURE UNITS TITLE: SHUTDOWN LOCA 1 2 AND 10/02/97 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. SCOPE This procedure provides actions for protecting the reactor core in the event of a Loss of Coolant Accident (LOCA) that occurs during either Mode 3 after the accumulators are isolated or Mode 4.

2. SYMPTOMS 2.1 The following symptoms are indicative of a Loss of Coolant Accident (LOCA) during Modes 3 and 4:

2.1.1 Uncontrolled decrease in PZR level 2.1.2 Uncontrolled decrease in RCS subcooling 011231005.DOC 02 1

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK11-21 NUCLEAR POWER GENERATION REVISION 25 DIABLO CANYON POWER PLANT PAGE 1 OF 3 ANNUNCIATOR RESPONSE UNIT TITLE: HIGH RADIATION 110/08/03 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. LOGIC DIAGRAM RC1X RC2X RC4X RC6X ALARM RC7X RC10X 74HRA

2. ALARM INPUT DESCRIPTION DEVICE ALARM ANNUNCIATOR TYPEWRITER NUMBER INPUT PRINTOUT SETPOINT RC 1X 662 Control Room Area Mon High Rad RE-1 NOTE RC 2X 663 Contmt Area Mon High Rad RE-2 NOTE RC 4X 664 Charging PP Area Mon High Rad RE-4 NOTE RC 10X 665 Aux Bldg Cont Bd Area Mon Hi Rad RE-10 NOTE RC 6X 668 Pri Sampling Rm Area Mon Hi Rad RE-6 NOTE RC 7X 669 In-Core Seal Table Area Mon Hi Rad RE-7 50 mR/HR 74 HRA 1066 Process Monitor Hi-Rad (See Step 5.3.1 for listing of monitors)

NOTE: Refer to Volume 9 in the Control Room for set points.

21177125.DOC 16 1008.1037

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK11-21 DIABLO CANYON POWER PLANT REVISION 25 PAGE 2 OF 3 TITLE: HIGH RADIATION UNIT 1

3. PROBABLE CAUSE 3.1 High radiation sensed by the detector.

3.2 Surveillance test in progress.

3.3 Instrument failed high.

4. AUTOMATIC ACTIONS 4.1 RE-1, 2, 3, 4, 6, 7, 10, 11, 12 and 13 - none.

4.2 RE-44A and 44B - containment ventilation isolation.

NOTE: If CVI bypass switch is selected to BYPASS, CVI actuation is disabled for that RM.

4.3 RE-17A and 17B - isolate CCW surge tank vent.

4.4 RE isolates discharge to outfall and opens recirc to EDR.

4.5 RE isolates gas decay tank discharge to plant vent.

5. OPERATOR ACTIONS 5.1 Check annunciator printout.

5.2 For all high radiation alarms, investigate the cause of the alarm.

5.2.1 If alarm is expected or spurious then Reset by performing the following:

a. Notify CO of expected alarm during reset, PK11-23 input 1068.

b. Check RE reading below high alarm setpoint.

c. Place the RE Operation Selector switch to Reset.

d. Place the RE Operational Selector switch to Operate.

e. Check the high alarm is reset on the radiation monitor and PK.

5.3 If a process monitor high rad alarm. Alarm Input 1066 5.3.1 Check process monitors RE-3, 11, 12, 13, 17A, 17B, 18, 22, 44A and 44B.

NOTE: If the digital display of a digital radiation monitor is overranged the LED's will display "E.EEE+E."

5.3.2 If RM-13, RM-44A, and/or RM-44B is valid, and is NOT due to Sampling or pre-planned evolution by Radiation Protection/Engineering:

a. At the POV-1 and POV-2 panels place the "S" Signal Test switch to the "S" Signal Test position.

b. At VB-4 place the Aux Bldg Vent Char Fltr Prehtr Control switch to ON.

5.3.3 If the process monitor high rad alarm was already in, check the high rad reflash module to see which new alarm came in or check rad monitor panels for alarms.

5.3.4 If automatic actions are required for the rad monitor, verify appropriate actions have taken place.

21177125.DOC 16 1008.1037

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK11-21 DIABLO CANYON POWER PLANT REVISION 25 PAGE 3 OF 3 TITLE: HIGH RADIATION UNIT 1 5.4 If RE-17A or 17B is in alarm, check CCW surge tank level (LI-139 and LI-140). If leakage into the CCW System is suspected, GO TO OP AP-11, "CCW System Inleakage," section.

5.5 If the RM-44A or B detector is overranged:

5.5.1 The following actions will occur:

a. The digital display will fail to "E.EEE+E."

b. At the Control Room panel the ALERT, HIGH, and FAIL/ACK lights will be lit.

c. Containment Ventilation Isolation will occur.

d. At the local panel the HIGH VOLTAGE DISABLE light will be lit.

e. The anti-jam circuit fuse opens disabling the detector.

5.5.2 Notify MS 5.6 If RM-12 is out of service or a CVI occurs, refer to PK01-17 for placing the CFCU collection system in service.

5.7 To restart RE 11 or 13 pump perform the following:

5.7.1 Verify Sample Selector position: RE 11 normally selected to Main Sample.

RE 13 normally selected to Ducts 1 & 2.

5.7.2 Verify High Pressure alarm reset, red alarm light off. To reset high alarm Place High Pressure switch to Reset and then return to Operate.

5.7.3 Verify Paper Drive Selector to Operate.

5.7.4 Place Pump Power Selector to Start and hold until low flow alarm clears.

Allow switch to spring return to Local (normal setting).

5.7.5 Check associated alarms and AR PKs clear.

5.8 If RM-7 is in alarm, Alarm Input 669, and an incore flux map is not in progress, then perform the following:

5.8.1 Check the MIDS power distribution panel for a seal table leakage alarm. Refer to OP O-21.

5.8.2 Contact the Chemistry Foreman, Radiation Protection Foreman, and the Reactor Engineering Section to inform them of a potential seal table leak.

5.8.3 Upon notification from the Reactor Engineer, increase monitoring of RM-7 for approximately 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for any continued alarm after storage of the neutron detectors.

5.9 If a tank rupture is suspected GO to OP AP-14. Alarm Inputs 664, 665 & 668 5.10 Inform Chemistry and Rad Protection Foremen of any unusual condition.

5.11 Refer to R-2 if high airborne is suspected.

5.12 Refer to EP G-1 and/or XI1.ID2 for reportability requirements.

21177125.DOC 16 1008.1037

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK02-17 NUCLEAR POWER GENERATION REVISION 11D DIABLO CANYON POWER PLANT PAGE 1 OF 4 ANNUNCIATOR RESPONSE UNIT TITLE: RHR PUMPS 106/12/02 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. LOGIC DIAGRAM 172568111.D O C 16 0120.0706

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK02-17 DIABLO CANYON POWER PLANT REVISION 11D PAGE 2 OF 4 TITLE: RHR PUMPS UNIT 1

2. ALARM INPUT DESCRIPTION DEVICE ALARM ANNUNCIATOR TYPEWRITER NUMBER INPUT PRINTOUT SETPOINT 51X-HG-8 455 RHR PPS OC Trip Min 67.5 AMPS Inst 645 AMPS 51X-HH-11 455 RHR PPS OC Trip Inst 645 AMPS TIS 170 1089 RHR PP 1-1 Mtr Brg Temp Hi GT 180°F TIS 171 1089 RHR PP 1-1 Mtr Brg Temp Hi GT 185°F TIS 172 1090 RHR PP 1-2 Mtr Brg Temp Hi GT l85°F TIS 173 1090 RHR PP 1-2 Mtr Brg Temp Hi GT l85°F 42-1F-6 457 RHR PP 1-1 Room Sump PPS run Contactor Clsd 42-1G-6 457 RHR PP 1-1 Room Sump PPS run Contactor Clsd 42-1F-15 458 RHR PP 1-2 Room Sump PPS run Contactor Clsd 42-1G-18 458 RHR PP 1-2 Room Sump PPS run Contactor Clsd T4500C 454 RHR PPS Temp PPC PPC ADDRESS The inputs to device T4500C are:

1. RHR PP 1-1 STATOR TEMP TO659A

2. RHR PP 1-2 STATOR TEMP T0665A

3. PROBABLE CAUSE 3.1 RHR pump OC trip.

3.2 RHR pump Hi motor bearing temp.

3.3 RHR pump Hi stator temp.

3.4 RHR pump room sump pump start.

4. AUTOMATIC ACTIONS 4.1 Possible RHR pump trip.

172568111.D O C 16 0120.0706

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK02-17 DIABLO CANYON POWER PLANT REVISION 11D PAGE 3 OF 4 TITLE: RHR PUMPS UNIT 1

5. OPERATOR ACTIONS 5.1 Check main annunciator printout.

5.2 Check stability of operating RHR pumps (presence of OC lights, pump pressures, and flows).

5.3 If alarm is due to a pump trip:

5.3.1 Monitor operation of remaining pump closely if running and refer to OP AP-16, AP SD-2 or AP SD-5.

5.3.2 Send an operator to check physical condition of pump and motor if conditions permit.

5.3.3 Except in an emergency, do not attempt a restart of the pump until it has been check electrically.

5.3.4 Refer to Step 5.7.1 for Technical Specification (Tech Spec) limitations.

5.4 If alarm is due to high motor bearing temperature.

5.4.1 Send an operator to check motor bearing temperatures (panel BTK-109 in outer hallway) and bearing oil conditions locally if conditions permit.

5.4.2 Check for proper pump area ventilation.

5.4.3 An RHR pump can be run with bearing temperatures up to 180°F without affecting the lifetime of the component. If this temperature is reached or exceeded then record how long and by how far the limit was exceeded and initiate an Action Request.

5.4.4 If pump operation should not continue, refer to Step 5.7.1 for Tech Spec limitations and refer to OP AP-16, AP SD-2 or AP SD-5.

5.5 If alarm is due to high stator temp.:

5.5.1 Check stator temperature indication on PPC.

5.5.2 Check for excessive motor current.

5.5.3 Check for proper pump area ventilation.

5.5.4 An RHR pump can be run with its stator temperature up to 248°F without affecting the lifetime of the component. If this temperature is reached or exceeded then record how long and by how far the limit was exceeded and initiate an Action Request.

5.5.5 Refer to Step 5.7.1 for Tech Spec limitations.

172568111.D O C 16 0120.0706

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK02-17 DIABLO CANYON POWER PLANT REVISION 11D PAGE 4 OF 4 TITLE: RHR PUMPS UNIT 1 5.6 If alarm is due to RHR room sump pump operation:

5.6.1 Have an operator check sump pump operation.

5.6.2 Send an operator to check RHR pump room for source of water if conditions permit.

5.6.3 If sump pump operation is due to RHR pump seal failure, determine if pump should be cleared. If so, refer to Step 5.7 below.

5.7 If an RHR pump must be cleared:

5.7.1 Refer to Tech Spec:

a. In Modes 1, 2 and 3, refer to Tech Spec 3.5.2 (ITS 3.5.2).

b. In Mode 4 refer to Tech Spec 3.5.3 (ITS 3.5.3) and 3.4.1.3 (ITS 3.4.6).

c. In Mode 5 refer to Tech Spec 3.4.1.4.1 (ITS 3.4.7) and 3.4.1.4.2 (ITS 3.4.8).

d. In Mode 6 refer to Tech Spec 3.9.8.1 (ITS 3.9.5) and 3.9.8.2 (ITS 3.9.6).

5.7.2 Refer to OP B-2:III to clear an RHR pump.

172568111.D O C 16 0120.0706

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK02-16 NUCLEAR POWER GENERATION REVISION 22 DIABLO CANYON POWER PLANT PAGE 1 OF 5 ANNUNCIATOR RESPONSE UNIT TITLE: RHR SYSTEM 103/07/03 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. LOGIC DIAGRAM

2. ALARM INPUT DESCRIPTION DEVICE ALARM ANNUNCIATOR TYPEWRITER NUMBER INPUT PRINTOUT SETPOINT PC 405BX 57 RHR Suction Valve Open 435 PSIG POS 674X PC 403BX 57 RHR Suction Valve Open 435 PSIG POS 669X LS 426 246 RHR PP 1-1 Room Sump Lvl Hi GT 21" H2O LS 430 l72 RHR PP 1-2 Room Sump Lvl Hi GT 21" H2O PC 647 362 RHR PP 1-2 Disch Press Hi GT 600 PSIG PC 635 1412 RHR PP 1-1 Disch Press Hi GT 600 PSIG FIS 641AX 1078 RHR PP 1-1 and 1-2 Disch Flow Low LT 475 GPM FIS 641BX and GT 20 SEC 16256822.DOC 16 0307.0248

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK02-16 DIABLO CANYON POWER PLANT REVISION 22 PAGE 3 OF 5 TITLE: RHR SYSTEM UNIT 1 PROBABLE CAUSE 3.1 RHR Pump Room Hi sump level.

3.2 RHR Pump Hi discharge pressure.

3.2.1 RHR flow less than 3000 gpm per train.

3.3 RHR Pump discharge flow low.

3.3.1 Failure of flow sensor, or valve closed.

3.3.2 Closure of valves 8701/8702.

3.3.3 Low RCS level during refueling.

3.3.4 Low frequency on vital 4KV Bus G or H.

3.4 8701 or 8702 not fully closed during RCS pressurization.

3.5 RCS check valve backleakage.

4. AUTOMATIC ACTIONS 4.1 A Hi sump level will start one or more RHR Pump Room sump pumps and bring in PK02-17.

4.2 Possible lifting of RHR System relief valves.

5. OPERATOR ACTIONS CAUTION 1: IF RHR discharge pressure is high, pressure should be reduced below 600 psig within 20 minutes to avoid damage to the pump seals.

CAUTION 2: RHR and CCW System piping and heat exchangers are susceptible to waterhammer. Care should be taken to avoid situations which could lead to waterhammer and a subsequent loss of system integrity. These situations include:

The formation of steam voids due to insufficient CCW flow through the RHR heat exchanger when the RHR System temperature is high,

The formation of steam voids due to rapid depressurization of a large volume of water at a high temperature,

Subsequent collapse of steam voids when cold water is introduced to the system,

Subsequent collapse of steam voids when the system is rapidly repressurized.

NOTE: Refer to OP AP-16 for RHR malfunctions while in MODE 4.

5.1 Check main annunciator printout to determine which condition initiated alarm.

16256822.DOC 16 0307.0248

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK02-16 DIABLO CANYON POWER PLANT REVISION 22 PAGE 4 OF 5 TITLE: RHR SYSTEM UNIT 1 5.2 High RHR discharge pressure with RCS Solid: Alarm Input 362, 1412 5.2.1 Verify greater than 3000 gpm flow for each RHR train in service. Increase flow as necessary.

5.2.2 Verify OPEN or fully OPEN HCV-133.

5.2.3 Take Manual Control of PCV-135 and OPEN to reduce RHR/RCS pressure, if necessary.

5.2.4 Verify RCS low pressure protection is "CUT-IN" on Pressurizer PORVs, PCV-455C and PCV-456.

5.2.5 OPEN Pressurizer PORVs as necessary to reduce RHR/RCS pressure to desired operating band.

5.2.6 If RHR System relief valves have lifted, verify they reclosed when system pressure returns to normal.

5.2.7 Go to Step 5.4.

5.3 High RHR discharge pressure with a bubble in the Pressurizer: Alarm Input 362, 1412 5.3.1 Shutdown the RHR Pump in service.

5.3.2 Reduce RHR/RCS pressure to desired operating band with PZR auxiliary spray or PZR PORVs, as necessary.

5.3.3 If RHR System pressure is increasing while performing RCS pressurization, then,

a. Stop RCS pressurization.

b. Decrease RCS pressure as necessary to reduce RHR pressure below 600 psig.

c. Contact the Engineering Section to determine if check valve backleakage is occurring.

d. Contact Plant Management for further guidance to seat the check valve.

5.3.4 If RHR System pressure increases after the RCS is at normal operating pressure, contact Plant Management for further guidance to depressurize the RHR System.

5.3.5 If RHR System relief valves have lifted, verify they reclosed when system pressure returns to normal.

16256822.DOC 16 0307.0248

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK02-16 DIABLO CANYON POWER PLANT REVISION 22 PAGE 5 OF 5 TITLE: RHR SYSTEM UNIT 1 5.4 If RHR System pressure exceeded 600 psig, perform a system inspection to verify RHR System integrity. Alarm Input 363, 1412 5.4.1 Write an AR for an engineering evaluation of system operability.

5.5 If alarm is due to a Hi sump level, Alarm Input 172, 246 5.5.1 Have an operator check sump pump operation.

5.5.2 Check RHR Pump Room for level and source of water.

5.5.3 If an RHR Pump seal has failed, refer to OP B-2 to clear RHR Pump.

5.5.4 If an RHR Pump must be cleared, refer to Technical Specifications (Tech Specs) for limitations on plant operation.

a. In Modes 1, 2 and 3 refer to Tech Spec 3.5.2.

b. In Mode 4 refer to Tech Spec 3.5.3 and 3.4.6.

c. In Mode 5 refer to Tech Spec 3.4.7 or 3.4.8 as appropriate.

d. In Mode 6 refer to Tech Spec 3.9.5 or 3.9.6 as appropriate.

5.6 If the RHR low flow alarm is received; Alarm Input 1078 5.6.1 Check for low frequency on vital 4KV Bus G or H.

5.6.2 Verify the running RHR pump's recirc valve (FCV-641A or B) is in AUTO or OPEN.

5.6.3 GO TO OP AP SD-2 or SD-5.

5.7 If the RHR suction valve open alarm is received, Alarm Input 57 5.7.1 If the RHR System is in service, stop the RCS pressurization.

5.7.2 If the RHR System is not in service, shut 8701 and 8702.

16256822.DOC 16 0307.0248

SRO QUESTION 79 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 3 Group # _____ 1 K/A # APE 026 AA2.06 Importance 3.1 Proposed Question:

Unit 1 is at full power when the running ASW pumps trip and no other ASW pumps can be started. CCW heat exchanger outlet temperature is 95ºF.

Which of the following describes the approximate time limit for establishing backup cooling to one CCP and the concern if it is not established in time?

A. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months - loss of integrity to RCP seals.

B. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months - damage to the seals of the CCPs.

C. 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months - loss of integrity to RCP seals.

D. 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months - damage to the seals of the CCPs.

Proposed Answer:

A. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months - loss of integrity to RCP seals.

Explanation:

A total loss of ASW will send the operator from AP-10, LOSS OF AUXILIARY SALTWATER, which will send the crew to AP-11 when no ASW pumps are available A correct, per Appendix C of AP-11, Without either seal injection or thermal barrier cooling the integrity of the RCP seals will be lost in approximately one hour.

B incorrect, the concern is the RCP seal package.

C incorrect, the time is one hour.

D incorrect, the concern is the RCP seal package.

Technical Reference(s): AP-11, appendix C`

Proposed references to be provided to applicants during examination: none Learning Objective:

3502, 3495, 5664 - Explain the alternate cooling lineup for the CCP using fire water and how it affects the CCP cooling operations.

sro tier 1 group 1_79.doc

Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 _____

55.43 43.5 Comments:

K/A: APE 026 AA2.06 - Ability to determine and interpret the following as they apply to the Loss of Component Cooling Water: The length of time after the loss of CCW flow to a component before that component may be damaged sro tier 1 group 1_79.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP AP-11 DIABLO CANYON POWER PLANT REVISION 21 PAGE 31 OF 37 TITLE: Malfunction of Component Cooling Water System UNITS 1 AND 2 APPENDIX C BACKUP COOLING TO A CENTRIFUGAL CHARGING PUMP

1. SCOPE 1.1 The purpose of this appendix is to make available a cooling water supply to one centrifugal charging pump (lube oil and gear oil coolers) when CCW cooling has been lost. Without either seal injection or thermal barrier cooling the integrity of the RCP seals will be lost in approximately one hour.

2. DISCUSSION 2.1 The backup cooling system can be connected to either centrifugal charging pump, however, this system can only be used to supply cooling for one charging pump at a time.

The cooling water will come from a fire sprinkler drain with a quick disconnect fitting.

The hoses to be used have quick disconnect fittings. The backup cooling hoses are stored near the #3 CCW pump. Each hose is labeled with a letter designation corresponding to the specified hose in the following instructions.

3. INSTRUCTIONS NOTE 1: Unit 2 valve numbers are in parentheses.

NOTE 2: If difficulty is encountered connecting quick disconnect fittings it may be due to pressure buildup behind the quick disconnect. To relieve the pressure, tap the internal center pin of the quick disconnect fitting using the "quick disconnect adjuster" (rod and hammer) stored with the hoses.

3.1 Connect one end of the 2"x34' hose (Hose 'A') at FP-1-347 (FP-2-350) (sprinkler test valve near the #3 CCW pump room entrance) and connect other end to connection on fire door B21 (B39-2) (outside entry to CCP room).

3.2 Connect one end of the 2"x51' hose (Hose 'B') at fire door B21 (B39-2) (inside entry of CCP room), and connect other end at FP-1(2)-1295 (manifold on wall of CCP room).

3.3 Connect the 1"x12' hose from the manifold outlet to the CCP oil coolers:

NOTE: The hose can only be connected to one CCP.

CCP 1-1 CCP 1-2 CCP 2-1 CCP 2-2 oil coolers FP-1-1303 to FP-1-1303 to FP-2-1303 to FP-2-1303 to (Hose 'C') CCW-1-700 CCW-1-199 CCW-2-700 CCW-2-199 3.4 Connect the 1"x12' hose from the CCP oil coolers to the floor drain:

NOTE 1: This hose has a quick disconnect fitting at one end.

NOTE 2: The CCP 1-1 pump oil cooler drain hose is 1"x27'.

CCP 1-1 CCP 1-2 CCP 2-1 CCP 2-2 oil coolers CVCS-1-488A CCW-1-195 CCW-2-582 CCW-2-195 (Hose 'D') to drain to drain to drain to drain 000798221.DOC 02 0120.0721

SRO QUESTION 80 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 3 Group # _____ 1 K/A # APE 054 AA2.01 Importance 4.4 Proposed Question:

While at 45% power, a main feed reg valve failure causes level in one steam generator to rise to 80%.

Which of the following actions should be implemented by the SFM?

A. Direct the operator to trip the reactor and enter E-0, Reactor Trip or Safety Injection.

B. Enter AP-25, Rapid Load Reduction.

C. Enter AP-29, Main Turbine Malfunction.

D. Enter AP-2, Full Load Rejection.

Proposed Answer:

A. Direct the operator to trip the reactor and enter E-0, Reactor Trip or Safety Injection.

Explanation:

A correct, exceeding P-14, causes a turbine trip, the running MFP to trip and FWI. The loss of feed will cause levels in the other steam generators to drop, the reactor will have to be tripped.

B incorrect, cannot reduce load, must trip the reactor.

C incorrect, the turbine will trip but the reactor must be tripped.

D incorrect, the turbine trip will cause a loss of load, but the reactor must be tripped.

Technical Reference(s): B-6A, Reactor Protection Proposed references to be provided to applicants during examination: none Learning Objective: 7373, 8181, 8182, 3308, 3302, 3301 - State the setpoints for all Reactor Trips, control and protection interlocks and ESFAS actuation signals.

sro tier 1 group 1_80.doc

Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 _____

55.43 43.5 Comments:

K/A: APE 054 AA2.01 - Ability to determine and interpret the following as they apply to the Loss of Main Feedwater (MFW): Occurrence of reactor and/or turbine trip sro tier 1 group 1_80.doc

Turbine Trip Purpose The purpose of the Turbine Trip/Reactor Trip is to sense a mismatch between Obj 11, 12 turbine load and reactor power to minimize the resultant thermal transient if the reactor was not tripped.

Description, A turbine trip is sensed by a decrease in turbine auto stop oil pressure or by a setpoint limit switch on the full closure of the turbine stop valves. A [two out of three Obj 13 pressure switches sensing low auto stop oil pressure], 50 psig, or [four of four turbine stop valves full closed] is required to trip the reactor.

This trip is blocked below 50% reactor power.

Logic The following logic applies to the Turbine Trip/Reactor Trip.

IF AND THEN a Turbine Trip/Reactor Trip signal is generated to low auto stop oil power is above P-9, 50% trip the reactor.

pressure is reactor power

Any switch reading low sensed on 2 of 3 pressure will activate an pressure switches alarm to indicate a switch is tripped.

power is below P-9 the reactor will not trip.

a Turbine Trip/Reactor Trip signal is generated to full closed is power is above P-9, 50% trip the reactor.

sensed on all four reactor power

Any valve position turbine stop switch reading full closed valves will activate an alarm to indicate a switch is tripped.

power is below P-9 the reactor will not trip.

Continued on next page B6A.DOC 4-1 REV. 13

Integrated Operations Feedwater Isolation Actuation Purpose The purpose of the Feedwater Isolation (FWI) Actuation signal is to provide Obj 25 isolation of feedwater within 7 seconds to the S/Gs to prevent:[GRH1]

S/G overfeeding.

excessive RCS cooldown and positive reactivity addition.

feeding a high energy line break inside the containment.

Description, FWI Actuation signal is generated by:

setpoint

P-14, S/G High-High level of [ 75%] sensed by two of three level Obj 13 detectors in any one S/G.

any SI signal.

P-4, Reactor Trip with Tavg [ 554°F] sensed in two of four loops.

Controls The following controls are available for the FWI Actuation signal.

Obj 32, 33, 34 In the Control Room on VB-3:

Control Operation RESET FWI Train A pushbutton RESET FWI Train B Logic The following logic applies to the FWI Actuation signal.

Obj 27, 29, 36 IF Then

the Main Turbine is tripped.

both Main FW Pump Turbines are tripped.

activated by SSPS Train B only.

P-14 OR any SI

all Feedwater Isolation valves are closed.

signal is activated by SSPS Train A only.

generated

all Feedwater Regulating valves are closed.

all Feedwater Bypass valves are closed.

PK09-11, Feedwater Isolation will alarm.

Red light for above Monitor Light Box C for FWI and S/G come on.[GRH2]

Continued on next page B6A.DOC 2.2 -36 REV. 13

SRO QUESTION 81 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 1 Group # _____ 1 K/A # APE 057 AA2.14 Importance 3.6 Proposed Question:

Unit 1 is at full power.

AR PK19-19, UPS Failure alarms. The CO reports inputs 1503 and 1505 are in.

Which of the following describes the status of inverter 1-4 and the vital AC instrument bus 14?

A. Both the inverter and the vital AC instrument bus are OPERABLE.

B. The inverter is OPERABLE; the vital AC instrument bus is inoperable.

C. The inverter is inoperable; the vital AC instrument bus is OPERABLE.

D. Both the inverter and vital AC instrument bus are inoperable. The vital AC instrument bus will be OPERABLE if the inverter can be transferred to its backup.

Proposed Answer:

C. The inverter is inoperable; the vital AC instrument bus is OPERABLE.

Explanation:

A incorrect, for the inverter to be OPERABLE, it must be powered from its normal source or from the DC source.

B incorrect, the inverter has transferred to its backup supply (input 1505), therefore the vital AC instrument bus is OPERABLE.

C correct, the vital instrument bus is powered from a class 1E CVT (backup supply) and OPERABLE, the inverter is inoperable.

D incorrect, the vital AC bus is currently energized.

Technical Reference(s):

Tech Spec 3.8.7 Tech Spec Bases B3.8.7 AR PK19-19 sro tier 1 group 1_81.doc

Proposed references to be provided to applicants during examination:

Tech Spec 3.8.7 Tech Spec Bases B3.8.7 AR PK19-19 Learning Objective: 9697 - Identify Technical Specification LCOs Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 _____

55.43 43.2 Comments:

K/A: APE 057 AA2.14 - Ability to determine and interpret the following as they apply to Loss of Vital AC Instrument Bus: That substitute power sources have come on line on a loss of initial ac sro tier 1 group 1_81.doc

Distribution Systems-Operating 3.8.7 3.8 ELECTRICAL POWER SYSTEMS 3.8.7 Inverters-Operating LCO 3.8.7 Four Class 1E Vital 120 V UPS inverters shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One required inverter A.1 -----------NOTE---------------

inoperable. Enter applicable Conditions and Required Actions of LCO 3.8.9, "Distribution Systems -

Operating" with any vital 120 V AC bus de-energized.

Restore inverter to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE status.

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.7.1 Verify correct inverter voltage and alignment to 7 days required AC vital buses.

Inverters - Operating B 3.8.7 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.7 Inverters - Operating BASES BACKGROUND The Class 1E UPS inverters are the preferred source of power for the AC vital buses because of the stability and reliability they achieve. The function of the inverter is to provide AC electrical power to the vital buses. The inverters can be powered from an internal AC source/rectifier or from the station battery. The station battery provides an uninterruptible power source for the instrumentation and controls for the Reactor Protective System (RPS) and the Engineered Safety Feature Actuation System (ESFAS). Specific details on inverters and their operating characteristics are found in the FSAR, Chapter 7 (Ref. 1).

APPLICABLE The initial conditions of Design Basis Accident (DBA) and transient SAFETY analyses in the FSAR, Chapter 6 (Ref. 2) and Chapter 15 (Ref. 3),

ANALYSES assume Engineered Safety Feature systems are OPERABLE. The inverters are designed to provide the required capacity, capability, redundancy, and reliability to ensure the availability of necessary power to the RPS and ESFAS instrumentation and controls so that the fuel, Reactor Coolant System, and containment design limits are not exceeded. These limits are discussed in more detail in the Bases for Section 3.2, Power Distribution Limits; Section 3.4, Reactor Coolant System (RCS); and Section 3.6, Containment Systems.

The OPERABILITY of the inverters is consistent with the initial assumptions of the accident analyses and is based on meeting the design basis of the unit. This includes maintaining required AC vital buses OPERABLE during accident conditions in the event of:

a. An assumed loss of all offsite AC electrical power or all onsite AC electrical power; and

b. A worst case single failure.

Inverters are a part of the distribution system and, as such, satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO The Class 1E UPS inverters ensure the availability of AC electrical power for the systems instrumentation required to shut down the reactor and maintain it in a safe condition after an anticipated operational occurrence (AOO) or a postulated DBA.

(continued)

Inverters - Operating B 3.8.7 BASES LCO Maintaining the required inverters OPERABLE ensures that the (continued) redundancy incorporated into the design of the RPS and ESFAS instrumentation and controls is maintained. The four inverters ensure an uninterruptible supply of AC electrical power to the 120 VAC vital buses even if the 4.16 kV safety buses are de-energized.

Operable inverters require the associated 120 VAC vital bus to be powered by the inverter with output voltage within tolerances, and power input to the inverter from a 125 VDC station battery. Alternatively, power supply may be from an internal AC source via rectifier as long as the station battery is available as the uninterruptible power supply.

APPLICABILITY The inverters are required to be OPERABLE in MODES 1, 2, 3, and 4 to ensure that:

a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AOOs or abnormal transients; and

b. Adequate core cooling is provided, and containment OPERABILITY and other vital functions are maintained in the event of a postulated DBA.

Inverter requirements for MODES 5 and 6 are covered in the Bases for LCO 3.8.8, "Inverters - Shutdown."

ACTIONS A.1 With a required inverter inoperable, its associated 120 VAC vital bus becomes inoperable until it is re-energized from its Class 1E constant voltage source transformer.

For this reason a Note has been included in Condition A requiring the entry into the Conditions and Required Actions of LCO 3.8.9, "Distribution Systems - Operating." This ensures that the 120 VAC bus is re-energized within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

Required Action A.1 allows 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to fix the inoperable inverter and return it to service. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months limit is based upon engineering judgment, taking into consideration the time required to repair an inverter and the additional risk to which the unit is exposed because of the inverter inoperability. This has to be balanced against the risk of an immediate shutdown, along with the potential challenges to safety systems such a shutdown might entail. When the 120 VAC vital bus is powered from its constant voltage source, it is relying upon interruptible (continued)

Inverters - Operating B 3.8.7 BASES ACTIONS A.1 (continued)

AC electrical power sources (offsite and onsite). The uninterruptible inverter source to the 120 VAC vital buses is the preferred source for powering instrumentation trip setpoint devices.

B.1 and B.2 If the inoperable devices or components cannot be restored to OPERABLE status within the required Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.8.7.1 REQUIREMENTS This Surveillance verifies that the inverters are functioning properly with all required circuit breakers closed and 120 VAC vital buses energized from the inverter. The verification of proper voltage output ensures that the required power is readily available for the instrumentation of the RPS and ESFAS connected to the AC vital buses. The 7 day Frequency takes into account the redundant capability of the inverters and other indications available in the control room that alert the operator to inverter malfunctions.

REFERENCES 1. FSAR, Chapter 7.

2. FSAR, Chapter 6.

3. FSAR, Chapter 15.

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK19-19 NUCLEAR POWER GENERATION REVISION 4A DIABLO CANYON POWER PLANT PAGE 1 OF 4 ANNUNCIATOR RESPONSE UNIT TITLE: VITAL UPS FAILURE 102/04/00 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. LOGIC DIAGRAM X9-11 X15-11 X204-11 27-PY11 27-PY11A X16-11 X17-11 X10-11 X9-12 X15-12 X204-12 27-PY12 X16-12 X17-12 X10-12 ALARM X9-13 X15-13 X204-13 27-PY13 27-PY13A X16-13 X17-13 X10-13 X9-14 X15-14 X204-14 27-PY14 X16-14 X17-14 X10-14 192229004.DOC 16 1

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK19-19 DIABLO CANYON POWER PLANT REVISION 4A PAGE 2 OF 4 TITLE: VITAL UPS FAILURE UNIT 1

2. ALARM INPUT DESCRIPTION DEVICE ALARM ANNUNCIATOR TYPEWRITER NUMBER INPUT PRINTOUT SETPOINT 27PY11 1482 Instr AC Dist Panel 1-1 Undervoltage 27PG11A 1483 Instr AC Dist Panel 1-1A Undervoltage X10-11 1484 Instr AC UPS 1-1 Inverter Failure X15-11 1485 Instr AC UPS 1-1 Loss of AC Output X16-11 1486 Instr AC UPS 1-1 on Bypass X9-11 1487 Instr AC UPS 1-1 Loss of Battery Source 27PY12 1489 Instr AC Dist Panel 1-2 Undervoltage X10-12 1490 Instr AC UPS 1-2 Inverter Failure X15-12 1491 Instr AC UPS 1-2 Loss of AC Output X16-12 1492 Instr AC UPS 1-2 on Bypass X9-12 1493 Instr AC UPS 1-2 Loss of Battery Source 27PY13 1495 Instr AC Dist Panel 1-3 Undervoltage 27PY13A 1496 Instr AC Dist Panel 1-3A Undervoltage X10-13 1497 Instr AC UPS 1-3 Inverter Failure X15-13 1498 Instr AC UPS 1-3 Loss of AC Output X16-13 1499 Instr AC UPS 1-3 on Bypass X9-13 1500 Instr AC UPS 1-3 Loss of Battery Source 27PY14 1502 Instr AC Dist Panel 1-4 Undervoltage X10-14 1503 Instr AC UPS 1-4 Inverter Failure X15-14 1504 Instr AC UPS 1-4 Loss of AC Output X16-14 1505 Instr AC UPS 1-4 on Bypass X(-14 1506 Instr AC UPS 1-4 Loss of Battery Source 192229004.DOC 16 2

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK19-19 DIABLO CANYON POWER PLANT REVISION 4A PAGE 3 OF 4 TITLE: VITAL UPS FAILURE UNIT 1

3. PROBABLE CAUSE 3.1 PY panel de-energized.

3.2 PY panel energized from the Backup Regulating Transformer.

3.3 Loss of output voltage from a UPS.

3.4 Loss of DC input to an inverter.

3.5 Inverter failure.

4. AUTOMATIC ACTIONS 4.1 Power supply to PY panel transferred to Backup Regulating Transformer.

5. OPERATOR ACTIONS 5.1 INSTRUMENT AC DIST PANEL UNDERVOLTAGE 5.1.1 If reactor trips, go to EOP E-0.

5.1.2 If loss of instrument AC System, go to OP AP-4.

5.1.3 Refer to Tech Spec. 3.8.2.1 and 3.8.2.2 (ITS 3.8.9 and 3.8.10).

5.2 INSTRUMENT AC UPS LOSS OF AC OUTPUT 5.2.1 If reactor trips, go to EOP E-0.

5.2.2 If loss of instrument AC System, go to OP AP-4.

5.2.3 Refer to Tech Spec. 3.8.2.1 and 3.8.2.2 (ITS 3.8.7 and 3.8.8).

5.3 INSTRUMENT AC UPS ON BYPASS NOTE: The UPS output will transfer to Bypass supply if a fault is sensed on the UPS output. The UPS output should then transfer back to the UPS output. The red light P202 BYPASS SOURCE SUPPLYING LOAD light will clear when the UPS output transfers back the inverter, but the control room alarm will stay latched in until alarm reset button S2 is pressed.

5.3.1 Determine why UPS output is on Bypass supply.

5.3.2 Re-energize the UPS output from the Inverter supply when problem is corrected.

5.3.3 Refer to Tech Spec 3.8.2.1 and 3.8.2.2 (ITS 3.8.7 and 3.8.8).

192229004.DOC 16 3

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK19-19 DIABLO CANYON POWER PLANT REVISION 4A PAGE 4 OF 4 TITLE: VITAL UPS FAILURE UNIT 1 5.4 INSTRUMENT AC UPS LOSS OF BATTERY SOURCE 5.4.1 Determine why the UPS lost its DC input.

5.4.2 Restore the DC input.

NOTE: To prevent damage to the inverter, the inverter should not be operated without its DC input.

5.4.3 If the DC Input cannot be restored, then transfer the UPS output to the Bypass supply per OP J-10:IV.

5.4.4 Refer to Tech Spec 3.8.2.1 and 3.8.2.2 (ITS 3.8.7 and 3.8.8).

5.5 INSTRUMENT AC UPS INVERTER FAILURE 5.5.1 Verify UPS output transferred to Bypass Supply. If the UPS output did not transfer, then go to OP AP-4.

5.5.2 Notify Maintenance Services to troubleshoot and correct the problem with the inverter.

5.5.3 Refer to Tech Spec 3.8.2.1 and 3.8.2.2 (ITS 3.8.7 and 3.8.8).

5.5.4 Re-energize the UPS output from the inverter when the inverter is repaired.

192229004.DOC 16 4

SRO QUESTION 82 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 1 Group # _____ 2 K/A # APE 061 AA2.05 Importance 4.2 Proposed Question:

Unit 2 is performing a core offload.

AR PK11-21 alarms. The SFM is determining if the alarm is valid to determine if containment should be evacuated per AP-21, Irradiated Fuel Damage.

Which of the following describes why the SFM should order containment evacuation?

Assume all readings are valid.

A. Containment Area monitor RE-2 reads 30 mR/hr.

B. Containment Air Radiogas monitor RE-12 reads 5.2 x103 cpm.

C. Containment Ventilation Exhaust monitor RE-44A reads 7.6 x10-5 µCi/cc.

D. Containment Ventilation Exhaust monitor RE-44B reads 1.7 x10-4 µCi/cc.

Proposed Answer:

B. Containment Air Radiogas monitor RE-12 reads 5.2 x103 cpm.

Explanation:

A incorrect, this is above the modes 2-5 setpoint but less than the mode 6 setpoint.

B correct, unit 2 high alarm setpoint is 5.1 x103 cpm.

C incorrect, above alert but below high alarm setpoint.

D incorrect, above alert but below high alarm setpoint.

sro tier 1 group 2_82 rev1.doc

Technical Reference(s):

OP AP-21, Irradiated Fuel Damage Vol. 9B tables:

T-IIC-2 (page II-5-53)

T-IIC-2 (page II-5-58)

T-IIC-2 (page II-5-85a)

T-IIC-2 (page II-5-86b)

Proposed references to be provided to applicants during examination:

T-IIC-2 (page II-5-53)

T-IIC-2 (page II-5-58)

T-IIC-2 (page II-5-85a)

T-IIC-2 (page II-5-86b)

Learning Objective: 6543 - Explain the actions for a containment evacuation alarm Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 _____

55.43 43.5 Comments: unit difference K/A: APE 061 AA2.05 - Ability to determine and interpret the following as they apply to the Area Radiation Monitoring (ARM) System Alarms: Need for area evacuation; check against existing limits sro tier 1 group 2_82 rev1.doc

SRO QUESTION 83 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 1 Group # _____ 2 K/A # W/E02 EA2.1 Importance 4.2 Proposed Question:

A steam break occurs inside containment on Steam Generator 2-2. The crew is performing the steps of E-0, Reactor Trip or Safety Injection.

Current plant conditions:

Containment pressure - 14 psig (peak at 25 psig)

Steam Generator 2-2 early isolation performed

Total AFW throttled to 500 gpm

RCS pressure - 1850 and increasing

Steam Generator pressures:

o 2 900 psig, stable o 2 0 psig, stable o 2-3 and 2 1000 psig, stable

Pressurizer Level - 35%, increasing

RCS Subcooling 50ºF The procedural flowpath should be E-0 to .

A. E-1.1 B. E-2 to E-1.1 C. FR-Z.1 to E-1.1 D. FR-Z.1 to E-2 to E-1.1 Proposed Answer:

B. E-2 to E-1.1 sro tier 1 group 2_83.doc

Explanation:

A incorrect, at step 11 of E-0, (No Steam Generator completely depressurized), the crew will be directed to E-2.

B correct, crew will go to E-2, confirm/complete the S/G isolation then go to E-1.1 C incorrect, the condition for transitioning to Z.1 no longer exists.

D incorrect, the condition for transitioning to Z.1 no longer exists.

Technical Reference(s):

E-0, F-0 Proposed references to be provided to applicants during examination: none Learning Objective: 3552 - Identify entry conditions for the EOPs Question Source: Bank #

Modified Bank # DCPP P-51520 New ______

Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 _____

55.43 43.5 Comments:

K/A: W/E02 EA2.1 - Ability to determine and interpret the following as they apply to SI Termination: Facility conditions and selection of appropriate procedures during abnormal and emergency operations.

sro tier 1 group 2_83.doc

1 P-51520 Points: 1.00 Multiple Choice A main steamline break, upstream of the MSIV and outside containment, occurs on S/G 1-2. The expected procedural flowpath is:

A. E-0, E-2, E-1, E-1.1 B. E-0, E-1, E-2, E-1.2 C. E-0, E-2, E-1, E-1.2 D. E-0, E-1, E-2, E-1.1 Answer: A ASSOCIATED INFORMATION:

Associated objective(s):

3552 Identify entry conditions for the EOPs Reference Id: P-51520 Must appear: No Status: Active User Text:

User Number 1: 0.00 User Number 2: 0.00 Difficulty: 2.00 Time to complete: 2 Topic: LPE1A EOP flowpath for MSLB Cross

Reference:

LPE-1A OBJ 2, 3 Comment:

F-0.5 CONTAINMENT GO TO FR-Z.1 GO TO CONTMT NO FR-Z.1 PRESS < 47 PSIG YES GO TO CONTMT NO FR-Z.2 PRESS < 22 PSIG YES CONTAINMENT WR NO SUMP LVL < 94 FT- EL LR-942A/943A (PAM 1) YES GO TO FR-Z.3 CONTMT RAD < 6 R/HR NO RM-30 OR RM-31 (SPDS OR PAM 2) YES CSF SAT

PACIFIC GAS AND ELECTRIC COMPANY NUMBER EOP E-0 DIABLO CANYON POWER PLANT REVISION 28 PAGE 9 OF 33 TITLE: Reactor Trip or Safety Injection UNIT 1 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

11. CHECK S/Gs - NOT FAULTED GO TO EOP E-2, FAULTED STEAM GENERATOR o NO S/G Pressure decreasing in an ISOLATION uncontrolled manner o NO S/G Completely depressurized -----------------------------

12. Check S/Gs - NOT RUPTURED

a. Secondary Radiation Monitors - a. IF A valid alarm exists NORMAL THEN GO TO EOP E-3, o PK11-06, SJAE HI RAD - OFF STEAM GENERATOR TUBE RUPTURE o PK11-17, S/G BLOWDOWN HI RAD - OFF o PK11-18, MAIN STM LINE HI RAD - OFF -----------------------------

b. Secondary Radiation Recorders b. IF A valid upward trend or (VB2) - NO UPWARD TREND spike exists, OR SPIKE THEN GO TO EOP E-3, o RM-15/15R, SJAE Monitors STEAM GENERATOR TUBE RUPTURE o RM-19, Blowdown Monitor o RM-71, 72, 73 or 74, Main Steam Line Monitors -----------------------------

c. Steam Generator Level - NO S/G c. GO TO EOP E-3, STEAM GENERATOR LEVEL INCREASING IN AN TUBE RUPTURE UNEXPECTED MANNER (WR/NR) 8S9IAA28.DOC

PACIFIC GAS AND ELECTRIC COMPANY NUMBER EOP E-2 DIABLO CANYON POWER PLANT REVISION 13 PAGE 5 OF 9 TITLE: Faulted Steam Generator Isolation UNIT 1 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

7. Check Secondary System Radiation for S/G Tube Rupture:

a. Steam Line Radiation - NORMAL a. GO TO EOP E-3, STEAM GENERATOR TUBE RUPTURE.

o PPC trend indicates NO upward trend or spike prior to the trip on RM-71, 72, 73, or 74 - Main Steam Line Monitors o NO valid alarm on PK11-18, MAIN STEAM LINE HI RAD

b. SJAE Radiation - NORMAL b. GO TO EOP E-3, STEAM GENERATOR TUBE RUPTURE.

o PPC trend indicates NO upward trend or spike on RM-15 or 15R

- SJAE Monitors o NO valid alarm on PK11-06, SJAE HI RAD

c. S/G Blowdown Radiation - c. GO TO EOP E-3, STEAM GENERATOR NORMAL TUBE RUPTURE.

o PPC trend indicates no upward trend or spike prior to the trip on RM Blowdown Monitor o NO valid alarm on PK11-17, S/G BLOWDOWN HI RAD

d. Contact Chemistry Department to d. IF HIGH S/G ACTIVITY, conduct periodic samples of all THEN GO TO EOP E-3, S/Gs - NORMAL ACTIVITY STEAM GENERATOR TUBE RUPTURE.

PACIFIC GAS AND ELECTRIC COMPANY NUMBER EOP E-2 DIABLO CANYON POWER PLANT REVISION 13 PAGE 6 OF 9 TITLE: Faulted Steam Generator Isolation UNIT 1 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

8. CHECK If ECCS Flow Should Be Reduced:

a. RCS Subcooling GREATER THAN a. GO TO Step 9.

20°F (SCMM or Appendix C)

b. Secondary heat sink satisfied: b. GO TO Step 9.

o Total feed flow to intact S/Gs -

GREATER THAN 435 GPM OR o NR Level in at least one intact S/G - GREATER THAN 6%

[16%]

c. RCS Pressure - STABLE OR c. GO TO Step 9 INCREASING

d. PZR Level - GREATER THAN 12% d. GO TO Step 9

[36%]

e. GO TO EOP E-1.1, SI TERMINATION

9. GO TO EOP E-1, LOSS OF REACTOR OR SECONDARY COOLANT

- END -

SRO QUESTION 84 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 1 Group # _____ 2 K/A # W/E09 EA2.1 Importance 3.8 Proposed Question:

The following plant conditions exist:

A loss of offsite power has occurred.

The crew is performing the actions of E-0.2, Natural Circulation Cooldown.

Low steamline pressure and low PZR pressure SI signals are blocked.

RCS pressure is 1850 psig and trending down slowly.

Pressurizer Level is 55% and increasing slowly

CST level is 35%

RCS temperature is 535ºF

The crew performing a cooldown at 25ºF per hour.

RVLIS is unavailable.

All CRDM fans are running Based on the current plant conditions, which of the following procedures should the crew be in when the plant reaches cold shutdown?

A. E-0.2, Natural Circulation Cooldown B. E-0.3, Natural Circulation Cooldown With Steam Void in the Vessel (With RVLIS)

C. E-0.4, Natural Circulation Cooldown With Steam Void in the Vessel (Without RVLIS)

D. OP L-7, Plant Stabilization Following a Reactor Trip or OP L-5, Plant Cooldown From Minimum Load to Cold Shutdown.

Proposed Answer:

C. E-0.4, Natural Circulation Cooldown With Steam Void in the Vessel (Without RVLIS sro tier 1 group 2_84.doc

Explanation:

A incorrect, based on graph IB-3, insufficient CST level means a faster cooldown is needed than is accomplished in E-0.2 B incorrect, RVLIS is not available.

C correct, based on CST level and no RVLIS, crew should go to E-0.4 D incorrect, these are the procedures used if a RCP can be started.

Technical Reference(s):

E-0.2, Natural Circulation Cooldown Vol 9, Section IF, Figure IB-2, (page IF-2)

Proposed references to be provided to applicants during examination:

Pages IF-1, IF-2, IF-3 Learning Objective: 5433 - Identify exit conditions for the EOPs Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 _____

55.43 43.5 Comments: is E-0.2 necessary to answer the question?

K/A: W/E09 EA2.1 - Ability to determine and interpret the following as they apply to Natural Circulation Operations: Facility conditions and selection of appropriate procedures during abnormal and emergency operations.

sro tier 1 group 2_84.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER EOP E-0.2 DIABLO CANYON POWER PLANT REVISION 18 PAGE 13 OF 25 TITLE: Natural Circulation Cooldown UNIT 1 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

15. INITIATE RCS Depressurization With The RCS Cooldown:

NOTE: Refer to Volume 9, Section "IF", for data to evaluate the required cooldown rate considering CST volume.

a. Maintain 25°F/hr Cooldown Rate

b. Maintain the cooldown rate and b. IF It is determined that the depressurization criteria listed on Cooldown and the Foldout page Depressurization must be performed at a rate that may cause formation of a Steam Void in the Vessel, THEN GO TO EOP E-0.3, NATURAL CIRCULATION COOLDOWN WITH STEAM VOID IN VESSEL (WITH RVLIS)

OR GO TO EOP E-0.4, NATURAL CIRCULATION COOLDOWN WITH STEAM VOID IN VESSEL (WITHOUT RVLIS).

THIS STEP CONTINUED ON NEXT PAGE 8S9IAC18.DOC

SRO QUESTION 85 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 1 Group # _____ 2 K/A # W/E13 G2.4.30 Importance 3.6 Proposed Question:

The following conditions exist on Unit 1:

A spurious closure of all MSIVs occurred while operating at 100% power

The reactor tripped and immediate actions of E-0, Reactor Trip or Safety Injection performed

During the post trip review, it is discovered that an overpressure condition on 13 SG with pressure at 1240 psig existed.

There is no indication that any of the safeties on the 13 steam generator operated

All other steam generators and plant safety systems functioned as designed

During subsequent repairs the unit has been holding in MODE 3 for the past 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months The condition of the 13 steam generator is reportable to the NRC because:

A. The plant exceeded a safety limit.

B. A loss of two fission barriers was imminent.

C. Challenges occurred to the safety valves.

D. The plant is in a condition prohibited by Technical Specifications.

Proposed Answer:

D. The plant is in a condition prohibited by Technical Specifications.

sro tier 1 group 2_85.doc

Explanation:

A incorrect, the safety limits are RCS pressure and Reactor Core (the combination of THERMAL POWER, Reactor Coolant System (RCS) highest loop average temperature, and pressurizer pressure).

B incorrect, no evidence of a loss of a fission barrier.

C incorrect, the challenge of the safety valves is not the reportable event, the loss of the safety valves is the reportable event.

D correct, steam generator safeties are necessary in MODES 1 thru 3. All safeties are inoperable. The unit should have been in MODE 4 in 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

Technical Reference(s):

Technical Specification 2.1 and 3.7.1 XI1.ID2, Regulatory Reporting Requirements and Reporting Process, attachment 8.5 page 4 of 8 Proposed references to be provided to applicants during examination:

Technical Specification 2.1 and 3.7.1 Learning Objective: 9697 - Identify Technical Specification LCOs Question Source: Bank # INPO 21506 Question History: Last NRC Exam Braidwood 7/2002 Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 _____

55.43 43.2 Comments: print TS 3.7.1, 2.1, Eplan G-1 and Reporting Requirements, att. 8.4 K/A: W/E13 G2.4.30 - Steam Generator Overpressure - Knowledge of which events related to system operations/status should be reported to outside agencies.

sro tier 1 group 2_85.doc

SLs 2.0 2.0 SAFETY LIMITS (SLs) 2.1 SLs 2.1.1 Reactor Core SLs In MODES 1 and 2, the combination of THERMAL POWER, Reactor Coolant System (RCS) highest loop average temperature, and pressurizer pressure shall not exceed the SLs specified in Figure 2.1.1-1.

2.1.2 RCS Pressure SL In MODES 1, 2, 3, 4, and 5, the RCS pressure shall be maintained 2735 psig.

2.2 SL Violations 2.2.1 If SL 2.1.1 is violated, restore compliance and be in MODE 3 within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

2.2.2 If SL 2.1.2 is violated:

2.2.2.1 In MODE 1 or 2, restore compliance and be in MODE 3 within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

2.2.2.2 In MODE 3, 4, or 5, restore compliance within 5 minutes.

DIABLO CANYON - UNITS 1 & 2 TAB 2.0 - R2 1

SLs 2.0 UNITS 1 & 2 680 670 UNACCEPTABLE Thermal power limited to OPERATION a maximum of 109% of 660 RTP by power range high neutron flux trip.

650 2250 PSIA 2460 PSIA 640 2000 PSIA 630 Vessel T-avg (F) 620 1860 PSIA 610 600 590 ACCEPTABLE*

OPERATION 580 570 560 0% 20% 40% 60% 80% 100% 120%

Percent of Rated Thermal Power (RTP)

Figure 2.1.1-1 REACTOR CORE SAFETY LIMIT DIABLO CANYON - UNITS 1 & 2 TAB 2.0 - R2 2

MSSVs 3.7.1 3.7 PLANT SYSTEMS 3.7.1 Main Steam Safety Valves (MSSVs)

LCO 3.7.1 Five MSSVs per steam generator shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS

NOTE-------------------------------------------------------------

Separate Condition entry is allowed for each MSSV.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more MSSVs A.1 Reduce the Power Range 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months inoperable. High Neutron Flux trip setpoint per Table 3.7.1-1.

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND OR One or more steam B.2 Be in MODE 4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months generators with less than two MSSVs OPERABLE.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.1.1 -----------------------------NOTE----------------------------

Only required to be performed in MODES 1 and 2.

Verify each required MSSV lift setpoint per In accordance with the Table 3.7.1-2 in accordance with the Inservice Inservice Testing Testing Program. Following testing, lift setting Program.

shall be within +/- 1%.

MSSVs 3.7.1 Table 3.7.1-1 (page 1 of 1)

Maximum Allowable Power Range Neutron Flux High Setpoint With Inoperable MSSVs MINIMUM NUMBER OF MSSVs PER STEAM MAXIMUM ALLOWABLE POWER RANGE GENERATOR REQUIRED OPERABLE NEUTRON FLUX HIGH SETPOINT

%RTP 4 87*

3 47*

2 29*

Unless the reactor trip system breakers are in the open position.

MSSVs 3.7.1 Table 3.7.1-2 (page 1 of 1)

Main Steam Safety Valve Lift Settings VALVE NUMBER LIFT SETTING (psig)

STEAM GENERATOR

1 #2 #3 #4 RV-3 RV-7 RV-11 RV-58 1065 (-2%, +3%)

RV-4 RV-8 RV-12 RV-59 1078 (+/- 3%)

RV-5 RV-9 RV-13 RV-60 1090 (+/- 3%)

RV-6 RV-10 RV-14 RV-61 1103 (+/- 3%)

RV-222 RV-223 RV-224 RV-225 1115 (+/- 3%)

SRO QUESTION 86 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 2 Group # _____ 1 K/A # 003 A2.05 Importance 2.8 Proposed Question:

The crew is making preparations to start a RCP using Attachment B in E-0.2, Natural Circulation Cooldown. The CO reports Seal Leakoff flow is low. All other conditions for starting the RCP are met.

Which of the following actions should the SFM direct the operator to perform?

A. Start the RCP.

B. Increase VCT level.

C. Increase charging flow.

D. Decrease VCT pressure.

Proposed Answer:

D. Decrease VCT pressure.

Explanation:

A incorrect, this is not a procedure in which RCPs are started if normal conditions are not met.

B incorrect, increasing VCT level will increase VCT pressure, which will further decrease seal leakoff flow.

C incorrect, increasing charging will not affect appreciably affect seal leakoff.

D correct, decreasing VCT pressure will decrease the DP and increase seal leakoff flow.

Technical Reference(s):

E-0.2, Natural Circulation Cooldown, attachment B, Restart of Reactor Coolant Pump Proposed references to be provided to applicants during examination: none Learning Objective: 4892 - State the cause/effect relationship between VCT and RCPs sro tier 2 group 1_86.doc

Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.5 55.43 43.5 Comments:

K/A: 003 A2.05 - Reactor Coolant Pump - Ability to (a) predict the impacts of the following malfunctions or operations on the RCPS; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those malfunctions or operations: Effects of VCT pressure on RCP seal leakoff flows sro tier 2 group 1_86.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER EOP E-0.2 DIABLO CANYON POWER PLANT REVISION 18 PAGE 23 OF 25 TITLE: Natural Circulation Cooldown UNIT 1 APPENDIX B RESTART OF REACTOR COOLANT PUMP NOTE: RCP No. 2 (preferred) or RCP No.1 should be given priority for purpose of normal PZR Spray. If RCP 1 is desired for PZR Spray then RCP 3 and 4 should also be started to provide sufficient PZR Spray DELTA-P.

CAUTION: RCP Seals may be damaged if RCP Seal Cooling was lost AND an RCP is started WITHOUT an RCP Seal Status Evaluation.

1. Start oil lift pump and run for 2 minutes.

2. Reset SI, Phase A or Phase B as necessary to provide RCP support systems.

3. Verify the following CCW valves open to RCP thermal barrier and oil coolers:

FCV-355

FCV-356

FCV-749

FCV-363

FCV-750

FCV-357

4. Verify seal DP GREATER THAN 255 PSID, Depressurize VCT as necessary.

5. Verify Seal Injection flow between 8 GPM TO 13 GPM.

6. Verify Seal Leak Off flow WITHIN limits shown on graph.

7. Verify closed PCV-455A and B, Normal PZR Spray Vlvs, AUTO optional.

8. Start RCP. Observe RCP Pump Motor AMPS and FLOW to verify NORMAL operation.

8S9IAC18.DOC

SRO QUESTION 87 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 2 Group # _____ 1 K/A # 005 G2.4.45 Importance 3.6 Proposed Question:

The crew is performing the actions of E-1, Loss of Reactor or Secondary Coolant.

PK01-22, RHR SUCT VLV CHMBR LEVEL HI alarms.

Which of the following describes whether or not action should be taken by the SFM to investigate the alarm?

A. Action should be taken. The alarm indicates seat leakage is occurring which could cause the valve(s) to bind when opened.

B. Action should be taken. The alarm indicates a potential leak, which if left uncorrected could lead to motor damage.

C. No action necessary. The valves are designed to operate in adverse conditions.

D. No action necessary. The alarm is expected as water from the containment sump fills the piping up to the valve.

Proposed Answer:

B. Action should be taken. The alarm indicates a potential leak, which if left uncorrected could lead to motor damage.

Explanation:

A incorrect, this is not an indication of seat leakage.

B correct, If chamber level gets too high, valves 8982A or B may get water into the valve motor and render the valve inoperable.

C incorrect, the valves may not operate in this condition.

D incorrect, if piping is intact, this alarm will not actuate.

Technical Reference(s):

sro tier 2 group 1_87.doc

PK01-22, RHR SUCT VLV CHMBR LEVEL HI Proposed references to be provided to applicants during examination: none Learning Objective: 7036 - State the RHR parameters that produce alarms.

Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 _____

55.43 43.5 Comments:

K/A: 005 G2.4.45 - Residual Heat Removal - Ability to prioritize and interpret the significance of each annunciator or alarm.

sro tier 2 group 1_87.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK01-22 NUCLEAR POWER GENERATION REVISION 8A DIABLO CANYON POWER PLANT PAGE 1 OF 1 ANNUNCIATOR RESPONSE UNIT TITLE: RHR SUCT VLV CHMBR LEVEL HI 112/17/99 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. LOGIC DIAGRAM LS297 ALARM LS296

2. ALARM INPUT DESCRIPTION DEVICE ALARM ANNUNCIATOR TYPEWRITER NUMBER INPUT PRINTOUT SETPOINT LS 297 444 RHR Suction Vlv Chamber 1-1 Lvl High GT 11" From Bottom of Chamber LS 296 445 RHR Suction Vlv Chamber 1-2 Lvl High GT 11" From Bottom of Chamber

3. PROBABLE CAUSE 3.1 Packing leak on RHR suction valves from sump.

3.2 Leak in recirculation sump penetration.

4. AUTOMATIC ACTIONS None

5. OPERATOR ACTIONS CAUTION: If chamber lvl. gets too high, valves 8982A or B may get water into the valve motor and render the valve inoperable.

5.1 Check the recirc. chamber through the view port for visible leakage or water level.

5.2 Drain the chamber to the miscellaneous equipment drain tank.

5.3 File an Action Request so the condition can be repaired as soon as practical.

222615088.D O C 16 1

SRO QUESTION 88 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 2 Group # _____ 1 K/A # 022 A2.04 Importance 3.2 Proposed Question:

High ocean temperature and fouling of CCW heat exchanger 11 has caused the following conditions to occur on Unit 1:

PK01-16, CONTMT ENVIRONMENT - PPC is in alarm

Containment Temperature ;

o 100 ft elevation between crane wall and containment wall 122 °F o 100 ft elevation between S/Gs 115 °F o 140 ft elevation 115 °F o 184 ft elevation 120 °F

CFCUs 11, 12, 13 and 15 are running in FAST

All CRDM fans are running

Amps on CFCUs 11, 12, and 13 are 330

Amps on CFCU 15 is 340

Containment pressure is above the alarm setpoint and is currently 1.0 psig and increasing slowly Based on the current plant conditions, which of the following actions should the SFM direct the operator to perform?

A. Direct a start of CFCU 14, and consider venting containment.

B. Direct a start of CFCU 14 and restore pressure within limits within the next 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or be in MODE 3 in the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

C. Direct a start of start CFCU 14, reduce containment temperature to less than 120ºF within the next 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or be in MODE 3 in the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and consider venting containment.

D. Direct a start of start CFCU 14, restore pressure within limits within the next 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or be in MODE 3 in the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and consider venting containment.

sro tier 2 group 1_88.doc

Proposed Answer:

A. Start CFCU 14, and consider venting containment.

Explanation:

A correct, CFCU 14 should be started. Containment temperature (average) is less than TS 3.6.5 limit of 120ºF. Consideration of venting containment should be considered since amps on CFCU 15 are above 330.

B incorrect, containment pressure is not above the limit (1.2 psig).

C incorrect, Containment temperature (average = 118F) is less than TS 3.6.5 limit of 120ºF.

D incorrect, no guidance to stop CFCU 14.

Technical Reference(s):

PK01-16 Tech Spec 3.6.4 Tech Spec 3.6.5 Proposed references to be provided to applicants during examination:

PK01-16 Tech Spec 3.6.4 Tech Spec 3.6.5 Learning Objective: 9697F - Identify 3.6 Technical Specification LCOs Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 55.43 43.2 Comments:

K/A: 022 A2.04 - Ability to (a) predict the impacts of the following malfunctions or operations on the CCS; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those malfunctions or operations:

Loss of service water sro tier 2 group 1_88.doc

Containment Pressure 3.6.4 3.6 CONTAINMENT SYSTEMS 3.6.4 Containment Pressure LCO 3.6.4 Containment pressure shall be > -1.0 psig and < +1.2 psig.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Containment pressure not A.1 Restore containment 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months within limits. pressure to within limits.

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion AND Time not met.

B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.1 Verify containment pressure is within limits. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

Containment Air Temperature 3.6.5 3.6 CONTAINMENT SYSTEMS 3.6.5 Containment Air Temperature LCO 3.6.5 Containment average air temperature shall be < 120°F.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Containment average air A.1 Restore containment 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months temperature not within limit. average air temperature to within limit.

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion AND Time not met.

B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.5.1 Verify containment average air temperature is 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months within limit.

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK01-16 NUCLEAR POWER GENERATION REVISION 9B DIABLO CANYON POWER PLANT PAGE 1 OF 2 ANNUNCIATOR RESPONSE UNIT TITLE: CONTMT ENVIRONMENT - PPC 109/04/02 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. LOGIC DIAGRAM Y0405C ALARM

2. ALARM INPUT DESCRIPTION DEVICE ALARM ANNUNCIATOR TYPEWRITER PPC NUMBER INPUT PRINTOUT SETPOINT ADDRESS Y0405C 437 Contmt Environment PPC The inputs to device Y0405C are as follows:

1. CONTMT PRESS, PT 937 P1000A

2. CONTMT PRESS, PT 936 P1001A

3. CONTMT PRESS, PT 935 P1002A

4. CONTMT PRESS, PT 934 P1003A

5. VESSEL SE SHIELD WALL TEMP, TT-720 T0720A

6. VESSEL SW SHIELD WALL TEMP, TT-721 T0721A

7. VESSEL NW SHIELD WALL TEMP, TT-722 T0722A

8. VESSEL NE SHIELD WALL TEMP, TT-723 T0723A

9. CONTMT TEMP (SELECTED) Y0701A

3. PROBABLE CAUSE 3.1 High air temperature/pressure due to:

3.1.1 Steam leak 3.1.2 Missing insulation 3.1.3 Fan cooler problems 3.1.4 Instrument air/N2 leakage 3.2 High shield wall temperatures due to:

3.2.1 Inadequate fan cooler flow 3.2.2 High CCW temperature 3.2.3 Inadequate CRDM fan cooler flow pk01_16.doc 16 0120.0828

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK01-16 DIABLO CANYON POWER PLANT REVISION 9B PAGE 2 OF 2 TITLE: CONTMT ENVIRONMENT - PPC UNIT 1

4. AUTOMATIC ACTIONS None

5. OPERATOR ACTIONS 5.1 Call up PK01-16 on the PPC and check for an out of limit conditions.

5.2 Check the CCW system for normal heat exchanger outlet temperature.

5.3 Check the CCW flow normal through each fan cooler unit.

5.4 If necessary place another fan cooler unit in service.

5.5 Verify all in service or start additional CRDM fan cooler.

5.6 If Contmt pressure is in alarm, refer to Technical Specification 3.6.1.4 (ITS 3.6.4) and consider venting containment if Contmt press is 0.8 psig or any CFCU in fast speed indicates greater than 330 amps.

5.7 If Contmt temp GT 120°F, refer to Technical Specification 3.6.1.5 (ITS 3.6.5).

pk01_16.doc 16 0120.0828

SRO QUESTION 89 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 2 Group # _____ 1 K/A # 076 G2.2.22 Importance 4.1 Proposed Question:

Units 1 and 2 are at full power.

Both trains of ASW on Unit 2 are declared inoperable. Cross Tie valve FCV-601 has been opened to provide ASW to Unit 2.

Which of the following describes when, if at all, the units must be in MODE 3?

A. Unit 2 must be in MODE 3 in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . Unit 1 can remain at power indefinitely.

B. Unit 2 must be in MODE 3 in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . Unit 1 must be in MODE 3 in 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months .

C. Unit 2 must be in MODE 3 in 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months . Unit 1 can remain at power indefinitely.

D. Unit 2 must be in MODE 3 in 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months . Unit 1 must be in MODE 3 in 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months .

Proposed Answer:

D. Unit 2 must be in MODE 3 in 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months . Unit 1 must be in MODE 3 in 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months .

Explanation:

Per TS Bases B3.7.8 - In the event of a total loss of ASW in one unit, the capability to cross-tie units ensures the availability of sufficient redundant cooling capacity for the affected unit. If the unit cross-tie capability were used, the unit with no operable ASW train would enter LCO 3.0.3, and the unit from which ASW was being provided would be in a 72-hour action with the cross-tie then declared inoperable.

A incorrect, the time for Unit 1 is 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months , (3.0.3), Unit 2 must shutdown, starting in 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , due to one train inoperable (because it is providing unit 1 ASW)

B incorrect, the time for Unit 1 is 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months , (3.0.3)

C incorrect, Unit 2 must shutdown, starting in 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , due to one train inoperable (because it is providing unit 1 ASW) sro tier 2 group 1_89.doc

D correct, per TS 3.0.3, Unit 1 must be in MODE 3 in 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months . Unit 2 can remain at power for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (TS 3.7.8 ACTION A) but then must be in MODE 3 in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months (ACTION B) - 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months total.

Technical Reference(s):

Tech Spec 3.7.8 Tech Spec Bases B3.7.8 Proposed references to be provided to applicants during examination:

Tech Spec 3.7.8 Tech Spec 3.0.3 Learning Objective: 9697 - Identify Technical Specification LCOs Question Source: Bank # DCPP R-55056 Modified Bank # _______

New ______

Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 _____

55.43 43.2 Comments:

K/A: 076 G2.2.22 - Service Water - Knowledge of limiting conditions for operations and safety limits.

sro tier 2 group 1_89.doc

1 R-55056 Points: 1.00 Multiple Choice Both trains of Unit 1 Auxiliary Saltwater System are INOPERABLE.

The Unit 2 Auxiliary Saltwater System is cross-tied to provide cooling for Unit 1 loads.

How long can each unit operate in this configuration before MODE 3 must be achieved?

A. 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months for Unit 1, and 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months for Unit 2 B. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months for Unit 1, and 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months for Unit 2.

C. 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months for Unit 1, and indefinitely for Unit 2.

D. 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months for both Unit 1 and Unit 2 Answer: A ASSOCIATED INFORMATION:

Associated objective(s):

9697 Identify Technical Specification LCOs Reference Id: R-55056 Must appear: No Status: Active User Text: 9697.13ALLN User Number 1: 3.30 User Number 2: 4.10 Difficulty: 2.00 Time to complete: 3 Topic: Two ASW Trains OOS, xtied to other unit Cross

Reference:

ITS 3.7.8, LCO 3.0.3 Comment: This question generated for R996C10, RLF1,12/07/99

ASW 3.7.8 3.7 PLANT SYSTEMS 3.7.8 Auxiliary Saltwater (ASW) System LCO 3.7.8 Two ASW trains shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One ASW train inoperable. A.1 ------------NOTE--------------

Enter applicable Conditions and Required Actions of LCO 3.4.6, RCS Loops - MODE 4, for residual heat removal loops made inoperable by ASW.

Restore ASW train to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion AND Time of Condition A not met. B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.8.1 Verify each ASW manual and power operated, 31 days valve in the flow path servicing safety related equipment, that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.7.8.2 Verify each ASW power operated valve in the flow In accordance with the path that is not locked, sealed, or otherwise Inservice Test secured in position, can be moved to the correct Program.

position.

SR 3.7.8.3 Verify each ASW pump starts automatically on an 24 months actual or simulated actuation signal.

LCO Applicability 3.0 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY LCO 3.0.1 LCOs shall be met during the MODES or other specified conditions in the Applicability, except as provided in LCO 3.0.2 and LCO 3.0.7.

LCO 3.0.2 Upon discovery of a failure to meet an LCO, the Required Actions of the associated Conditions shall be met, except as provided in LCO 3.0.5 and LCO 3.0.6.

If the LCO is met or is no longer applicable prior to expiration of the specified Completion Time(s), completion of the Required Action(s) is not required unless otherwise stated.

LCO 3.0.3 When an LCO is not met and the associated ACTIONS are not met, an associated ACTION is not provided, or if directed by the associated ACTIONS, the unit shall be placed in a MODE or other specified condition in which the LCO is not applicable. Action shall be initiated within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to place the unit, as applicable, in:

a. MODE 3 within 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months ;

b. MODE 4 within 13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months ; and

c. MODE 5 within 37 hours4.282407e-4 days 0.0103 hours 6.117725e-5 weeks 1.40785e-5 months .

Exceptions to this Specification are stated in the individual Specifications.

Where corrective measures are completed that permit operation in accordance with the LCO or ACTIONS, completion of the actions required by LCO 3.0.3 is not required.

LCO 3.0.3 is only applicable in MODES 1, 2, 3, and 4.

LCO 3.0.4 When an LCO is not met, entry into a MODE or other specified condition in the Applicability shall only be made:

a. When the associated ACTIONS to be entered permit continued operation in the MODE or other specified condition in the Applicability for an unlimited period of time;

b. After performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering the MODE or other specified condition in the Applicability, and establishment of risk management actions, if appropriate; exceptions to this Specification are stated in the individual Specifications, or

c. When an allowance is stated in the individual value, parameter, or other Specification.

This Specification shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.

(continued)

DIABLO CANYON - UNITS 1 & 2 ts 3_0.doc - R2 1

LCO Applicability 3.0 3.0 LCO APPLICABILITY (continued)

LCO 3.0.5 Equipment removed from service or declared inoperable to comply with ACTIONS may be returned to service under administrative control solely to perform testing required to demonstrate its OPERABILITY or the OPERABILITY of other equipment. This is an exception to LCO 3.0.2 for the system returned to service under administrative control to perform the testing required to demonstrate OPERABILITY.

LCO 3.0.6 When a supported system LCO is not met solely due to a support system LCO not being met, the Conditions and Required Actions associated with this supported system are not required to be entered.

Only the support system LCO ACTIONS are required to be entered.

This is an exception to LCO 3.0.2 for the supported system. In this event, an evaluation shall be performed in accordance with Specification 5.5.15, "Safety Function Determination Program (SFDP)."

If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered.

When a support system's Required Action directs a supported system to be declared inoperable or directs entry into Conditions and Required Actions for a supported system, the applicable Conditions and Required Actions shall be entered in accordance with LCO 3.0.2.

LCO 3.0.7 Test Exception LCO 3.1.8, allows specified Technical Specification (TS) requirements to be changed to permit performance of special tests and operations. Unless otherwise specified, all other TS requirements remain unchanged. Compliance with Test Exception LCOs is optional.

When a Test Exception LCO is desired to be met but is not met, the ACTIONS of the Test Exception LCO shall be met. When a Test Exception LCO is not desired to be met, entry into a MODE or other specified condition in the Applicability shall be made in accordance with the other applicable Specifications.

DIABLO CANYON - UNITS 1 & 2 ts 3_0.doc - R2 2

SR Applicability 3.0 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY SR 3.0.1 SRs shall be met during the MODES or other specified conditions in the Applicability for individual LCOs, unless otherwise stated in the SR.

Failure to meet a Surveillance, whether such failure is experienced during the performance of the Surveillance or between performances of the Surveillance, shall be failure to meet the LCO. Failure to perform a Surveillance within the specified Frequency shall be failure to meet the LCO except as provided in SR 3.0.3. Surveillances do not have to be performed on inoperable equipment or variables outside specified limits.

SR 3.0.2 The specified Frequency for each SR is met if the Surveillance is performed within 1.25 times the interval specified in the Frequency, as measured from the previous performance or as measured from the time a specified condition of the Frequency is met.

For Frequencies specified as "once," the above interval extension does not apply.

If a Completion Time requires periodic performance on a "once per ..."

basis, the above Frequency extension applies to each performance after the initial performance.

Exceptions to this Specification are stated in the individual Specifications.

SR 3.0.3 If it is discovered that a Surveillance was not performed within its specified Frequency, then compliance with the requirement to declare the LCO not met may be delayed, from the time of discovery, up to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or up to the limit of the specified Frequency, whichever is greater.

This delay period is permitted to allow performance of the Surveillance.

A risk evaluation shall be performed for any Surveillance delayed greater than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and the risk impact shall be managed.

If the Surveillance is not performed within the delay period, the LCO must immediately be declared not met, and the applicable Condition(s) must be entered.

When the Surveillance is performed within the delay period and the Surveillance is not met, the LCO must immediately be declared not met, and the applicable Condition(s) must be entered.

SR 3.0.4 Entry into a MODE or other specified condition in the Applicability of an LCO shall only be made when the LCO's Surveillances have been met within their specified Frequency, except as provided by SR 3.0.3.

When an LCO is not met due to Surveillances not having been met, entry into a MODE or other specified condition in the Applicability shall only be made in accordance with LCO 3.0.4.

This provision shall not prevent entry into MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.

DIABLO CANYON - UNITS 1 & 2 ts 3_0.doc - R2 3

ASW B 3.7.8 B 3.7 PLANT SYSTEMS B 3.7.8 Auxiliary Saltwater System (ASW)

BASES BACKGROUND The ASW system provides a heat sink from the Pacific Ocean for the removal of process and operating heat from the CCW system. The CCW system then provides cooling to safety-related components during all modes of operation, including a DBA, and also to various non safety-related components during normal operation and shutdown.

The ASW consists of two, 100% capacity, safety related, cooling water trains. Each train consists of one 100% capacity pump, one component cooling water (CCW) heat exchanger, piping, valving, and instrumentation. The pumps are automatically started upon receipt of a safety injection signal or 4kV automatic transfer. Normal configuration is for one train operation with the second pump cross-tied in stand-by and the second heat exchanger valved out-of-service except when the UHS temperature is 64°F or higher; therefore no valve realignment occurs with a safety injection signal. Manual and remote manual system realignment provides for utilization of the second CCW heat exchanger, for use of the standby pump on the same unit, for cross-tying the standby ASW pump from opposite unit, and for train separation for long term cooling. The ASW unit cross-tie valve (FCV-601) allows one ASW pump on one unit to supply the CCW heat exchanger(s) on the other unit. In the event of a total loss of ASW in one unit, the capability to cross-tie units ensures the availability of sufficient redundant cooling capacity for the affected unit. If the unit cross-tie capability were used, the unit with no operable ASW train would enter LCO 3.0.3, and the unit from which ASW was being provided would be in a 72-hour action with the cross-tie then declared inoperable. FCV-601 is controlled by ECG 17.1.

Additional information about the design and operation of the ASW system, is presented in the FSAR, Section 9.2.7 (Ref. 1). The principal safety related function of the ASW system is the removal of decay heat from the reactor via the vital CCW System.

APPLICABLE The design basis of the ASW system is for one ASW train, in SAFETY conjunction with the CCW System and the containment cooling ANALYSES systems, to remove accident generated and core decay heat following a design basis LOCA as discussed in the FSAR, Section 6.2 (Ref. 2).

The ASW system can be re-configured to maintain the CCW temperature to within its design bases limits. The ASW system is designed to perform its function with a single failure of any active (continued)

ASW B 3.7.8 BASES APPLICABLE component, with or without the loss of offsite power. This assumes a SAFETY maximum ASW temperature of 64°F occurring simultaneously with ANALYSES maximum heat loads on the system. The ASW system, in conjunction (continued) with the CCW System, also cools the unit from residual heat removal (RHR) entry conditions to MODE 5 during normal and post accident operations. The time required for this evolution is a function of the number of ASW pumps, CCW heat exchangers, and RHR heat exchangers that are operating. One ASW train is sufficient to remove decay heat during subsequent operations in MODES 5 and 6.

However, in the split-train configuration during post-accident operation, operator action may be required to realign the ASW and CCW systems to prevent loss of all cooling to containment and safety-related systems following specific active failure scenarios.

The ASW system satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO Two ASW trains are required to be OPERABLE to provide the required redundancy to ensure that the system functions to remove post accident heat loads, assuming that the worst case single active failure occurs coincident with the loss of offsite power.

An ASW train is considered OPERABLE during MODES 1, 2, 3, and 4 when:

a. The pump is OPERABLE; and

b. The associated piping, valves, heat exchanger, and instrumentation and controls required to perform the safety related function are OPERABLE.

This requires that at least one vacuum relief valve be OPERABLE.

Each ASW train has a vacuum relief system consisting of two vacuum relief valves (check valves) which function to prevent water hammer in the system piping during an ASW pump trip and restart transient.

Check valves are passive components and, unless otherwise specified, are not considered in meeting the single failure criterion. The second vacuum relief valve on each header ensures reliability of the function.

If both vacuum relief valves on a single header are inoperable, water hammer during an ASW pump trip and restart transient could affect both ASW trains unless the ASW header cross-tie valve is closed and the ASW pump breaker or dc control power switch is opened for the affected ASW train, precluding the potential for water hammer in the train. See ECG 17.4, "ASW Pump Discharge Vacuum Relief Valves."

(continued)

ASW B 3.7.8 BASES LCO (continued) Both cross-tie valves FCV-495 and FCV-496 are required to be open to support single active failure criteria. The valves may be closed in post-accident long-term phase to support passive failure criteria, if system integrity is a concern. With one or both ASW trains in service with the cross-tie valves closed, a single active failure could result in a significant reduction or loss of heat removal capability. With both ASW trains in service, approximately one-half of the total CCW flow is routed through each CCW heat exchanger. In the event of a postulated ASW pump failure in this configuration, with the cross-tie valves closed, only one ASW pump will be operating and providing heat removal to one-half of the total CCW flow via its associated in-service CCW heat exchanger. In this situation, the ASWS heat removal capability is limited and may not meet the requirements of the system to maintain the CCW supply temperature within its design limits.

c. The associated pump vault drain check valve is OPERABLE.

The ASW pump vault check valves prevent flooding of the ASW pump vaults during design flood events.

APPLICABILITY In MODES 1, 2, 3, and 4, the ASW system is a normally operating system that is required to support the OPERABILITY of the equipment serviced by the ASW system and required to be OPERABLE in these MODES.

In MODES 5 and 6, the OPERABILITY requirements of the ASW system are determined by the systems it supports.

(continued)

SRO QUESTION 90 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 2 Group # _____ 1 K/A # 010 A2.03 Importance 4.2 Proposed Question:

PLANT CONDITIONS:

Unit 1 is at 35% in a normal lineup

All pressurizer heaters are ON

Green lights for RCS Spray valves, PCV-455A and PCV-455B are LIT

RCS pressure is 1945 psig and decreasing slowly

Pressurizer tailpipe temperature is 135ºF

Green and Red lights for Pressurizer PORVs PCV-474 are LIT with the switch in CLOSE Which of the following actions should be taken by the SFM?

A. Direct the operator to close block valve 8000A, power should be left to 8000A.

B. Direct the operator to trip the reactor and enter E-0, Reactor Trip or Safety Injection and close block valve 8000A.

C. Direct the operator to close block valve 8000A and within one hour remove power from 8000A.

D. Direct the operator to manually initiate Safety Injection and enter E-0, Reactor Trip or Safety Injection.

Proposed Answer:

B. Direct a reactor trip and enter E-0, Reactor Trip or Safety Injection and close block valve 8000A.

Explanation:

A incorrect, this is done if the PORV cannot be isolated.

B correct, RCS pressure is at the trip setpoint, the reactor should be tripped, as part of isolation, the block valve should be closed in an effort to stop the depressurization.

C incorrect, this action would be if the reactor was not tripped and the PORV was inoperable for causes other than seat leakage.

D incorrect, correct if only the PORV had to be isolated.

sro tier 2 group 1_90 rev2.doc

Technical Reference(s):

OP AP-13, Malfunction of Reactor Pressure Control System OIM B-6-4b TS 3.4.11 Proposed references to be provided to applicants during examination: none Learning Objective: 4587 - Explain the effect of failures on the Pressurizer Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 55.43 43.2 Comments:

K/A: 010 A2.03 - Ability to (a) predict the impacts of the following malfunctions or operations on the PZR PCS; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those malfunctions or operations: PORV failures sro tier 2 group 1_90 rev2.doc

Pressurizer PORVs 3.4.11 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.11 Pressurizer Power Operated Relief Valves (PORVs)

LCO 3.4.11 Each PORV and associated block valve shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS

NOTE-----------------------------------------------------------

Separate Condition entry is allowed for each PORV.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more PORVs A.1 Close and maintain 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable solely due to power to associated excessive seat leakage. block valve.

B. One PORV inoperable for B.1 Close associated block 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months reasons other than valve.

excessive seat leakage.

AND B.2 Remove power from 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months associated block valve.

AND B.3 Restore the Class I 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months PORV to OPERABLE status.

C. One block valve inoperable. ----------------NOTE------------------- 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Required Actions do not apply when block valve is inoperable solely as result of complying with Required Actions B.2 or E.3.

C.1 Place associated PORV in manual control.

AND (continued)

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP AP-13 NUCLEAR POWER GENERATION REVISION 5 DIABLO CANYON POWER PLANT PAGE 1 OF 5 ABNORMAL OPERATING PROCEDURE UNITS TITLE: Malfunction of Reactor Pressure Control System 1 2 AND 06/04/02 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. SCOPE 1.1 This procedure provides instructions in the event of a Reactor Pressure Control malfunction.

2. SYMPTOMS 2.1 Pressurizer pressure unexpectedly high or low.

2.2 Possible Main Annunciator Alarms:

2.2.1 PZR PRESSURE LOW (PK05-17) 2.2.2 PZR PRESSURE HIGH (PK05-16) 2.2.3 PZR SAFETY OR RELIEF LINE TEMP (PK05-23) 000661005.D O C 02 0120.0840

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP AP-13 DIABLO CANYON POWER PLANT REVISION 5 PAGE 2 OF 5 TITLE: Malfunction of Reactor Pressure Control System UNITS 1 AND 2 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. STOP any load changes in progress

2. CHECK PZR PORVs - CLOSED

PCV-474 IF PZR pressure LESS THAN

PCV-455C 2335 psig,

PCV-456 THEN Close PORV(s).

IF Any PORV can NOT be closed, THEN Close its block valve.

8000A for PCV-474 8000B for PCV-455C 8000C for PCV-456 IF Block valve can NOT be closed, THEN Manually Initiate Safety Injection AND GO TO EOP E-0.

3. CHECK PZR Safety Relief Valves: IF A PZR safety has lifted and will not reseat,

a. Sonic flow indicators B 0 THEN Manually Initiate Safety

b. Tail pipe temp 185° Injection AND GO TO EOP E-0 IF A PZR safety is leaking, THEN Refer to AR PK05-23.

000661005.D O C 02 0120.0840

Reactor Trip Signals (Continued)

Pressurizer System Signals Trip Setpoint** Coincidence Interlock Protection Afforded Low Pressure 1950psig 2/4 P-7

DNB High Pressure 2385psig 2/4

RCS Integrity High Level 90% 2/3 P-7 Prevent water relief RCS Integrity Secondary System Signals Trip Setpoint** Coincidence Interlock Protection Afforded Steam 15%*** 2/3 Sensors of

Loss of Heat Sink Generator 1/4 Loops Low-Low Level Turbine Trip Auto Stop Oil 2/3 P-9

Limit temperature/pressure

<50psig transients on the RCS

-OR-Stop Valves 4/4 Closed Miscellaneous Signals Trip Setpoint** Coincidence Interlock Protection Afforded Manual 1/2 Operator Judgement Safety Injection Any "S" Signal

Limit the consequences of accidents Seismic 0.30g 2/3 sensors Trip the reactor in the (In the same event of a double design direction) earthquake SSPS General Train A&B SSPS 2/2 Trip RX in event of failure Warning simultaneously of protection system

Protection assumed in FSAR accidents.

- Reset values are approximately 1% different than the setpoint value (see the appropriate setpoint documentation for the exact values).

- - An increasing time delay to trip is allowed, from 50% power to 0% power (based on loop delta-T) from approximately 27.8 to 464.1 seconds (non-linear), once SG level drops under 15%. There is no time delay from 50% to 100% power. The Steam Generator level transmitters do not correlate directly to the associated RCS loop delta-T used to generate the timing signal (i.e., LT-529, LT-539, and Loop 1 delta-T are used to generate the error signal for Protection Set I).

B-6-4b Rev 22

SRO QUESTION 91 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 2 Group # _____ 2 K/A # 014 G2.4.10 Importance 3.1 Proposed Question:

While a load rejection is occurring, the operator reports PK03-21, DRPI FAILURE/ROD BOTTOM has alarmed and there is no indication on the DRPI panel. Indicated rod speed is 72 steps per minute.

Which of the following actions should be taken by the SFM?

A. Direct the operator to place rods in MANUAL and implement AP-6, Emergency Boration.

B. Direct the operator to monitor Group Step demand counters.

C. Direct a reactor trip and enter E-0, Reactor Trip or Safety Injection.

D. Direct the actions of AP-25, Rapid Load Reduction while performing the actions of the annunciator response as time permits .

Proposed Answer:

C. Direct a reactor trip and enter E-0, Reactor Trip or Safety Injection.

Explanation:

Per PK03-21:

5.2 If DRPI power failure:

5.2.1 Place Rod Control in MANUAL.

5.2.2 Refer to ITS 3.1.7.

5.2.3 Place DRPI on backup per OP A 3:I, Section 6.1.

5.2.4 If power cannot be restored:

a. Continue attempts to restore power to DRPI.

b. Notify Operations Management.

c. If evidence of a plant transient occurs:

1. With Shift Foreman concurrence, trip the Reactor, and

2. GO TO EOP E-0.

C correct, due to the rods moving at max speed and a plant transient in progress, the reactor should be tripped.

sro tier 2 group 2_91 rev1.doc

Technical Reference(s):

PK03-21, DRPI FAILURE/ROD BOTTOM Proposed references to be provided to applicants during examination: none Learning Objective:

4918 - State the DRPI parameters that produce alarms.

Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 _____

55.43 43.6 Comments:

K/A: 014 G2.4.10 - Knowledge of annunciator response procedures.

sro tier 2 group 2_91 rev1.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK03-21 NUCLEAR POWER GENERATION REVISION 15 DIABLO CANYON POWER PLANT PAGE 1 OF 3 ANNUNCIATOR RESPONSE UNIT TITLE: DRPI FAILURE/ROD BOTTOM 102/09/01 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. LOGIC DIAGRAM K2 K1 ALARM K5 K4

2. ALARM INPUT DESCRIPTION DEVICE ALARM ANNUNCIATOR TYPEWRITER NUMBER INPUT PRINTOUT SETPOINT K2 478 Rod Pos Ind Rod Bottom LT 6 steps K1 551 Rod Pos Ind Rods at Bottom LT 6 steps K5 552 Rod Pos Ind Non-Urgent Loss of RPI data A or B K4 553 Rod Pos Ind Urgent Loss of RPI data A & B

3. PROBABLE CAUSE 3.1 One or more dropped control rods.

3.2 Rod position channel data coil failure.

3.3 DRPI power transient.

212616115.D O C 16 0120.1248

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK03-21 DIABLO CANYON POWER PLANT REVISION 15 PAGE 2 OF 3 TITLE: DRPI FAILURE/ROD BOTTOM UNIT 1

4. AUTOMATIC ACTIONS 4.1 Probable reactor trip if one or more rods are dropped at power.

4.2 Loss of capability of every other position indicating light on the control rod with a failed data coil.

4.2.1 Flashing general warning light above affected rod(s).

4.2.2 Flashing data channel A or B failure lights.

4.2.3 Loss of all position indicating lights on a control rod with a failure of both data coils.

a. Rod urgent alarm light.

b. Rod bottom alarm and light.

c. Flashing general warning light.

d. Flashing data channel A and B failure lights.

5. OPERATOR ACTIONS 5.1 If reactor trips, go to EOP E-0.

5.2 If DRPI power failure:

5.2.1 Place Rod Control in MANUAL.

5.2.2 Refer to ITS 3.1.7.

5.2.3 Place DRPI on backup per OP A-3:I, Section 6.1.

5.2.4 If power cannot be restored:

a. Continue attempts to restore power to DRPI.

b. Notify Operations Management.

c. If evidence of a plant transient occurs:

1. With Shift Foreman concurrence, trip the Reactor, and

2. GO TO EOP E-0.

212616115.D O C 16 0120.1248

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK03-21 DIABLO CANYON POWER PLANT REVISION 15 PAGE 3 OF 3 TITLE: DRPI FAILURE/ROD BOTTOM UNIT 1 5.3 GO TO OP AP-12C for a dropped rod without a reactor trip.

5.4 For loss of one data channel (Rod Pos Ind Non-Urgent), the SFM may choose to select the OPERABLE channel (A ONLY or B ONLY) with switch S106 on the back of the DRPI panel while initiating troubleshooting and repair of the failed channel. This will place DRPI in "half accuracy" for all control rod positions.

5.5 If BOTH A and B data channels on one or more rods in any bank have failed, place Rod Control in MANUAL and refer to ITS 3.1.7.

NOTE: Per DRPI tech. manual, if both channels are indicated failed it is possible due to the electronic system not knowing which is the good channel. This may be remedied by selecting first one channel, then the other to see which works.

Regardless, whenever loss of both data channels are encountered, action step 5 above must be followed.

212616115.D O C 16 0120.1248

SRO QYESTION 92 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 2 Group # 2 K/A # 034 A2.01 Importance 4.4 Proposed Question:

PLANT CONDITIONS:

Core offload is in progress

The manipulator crane is transferring a spent fuel assembly from the reactor vessel to the transfer canal

The assembly is currently close to the transfer canal.

CVI actuates due to high radiation.

Which of the following describes what the Refueling SRO should direct be done with the spent fuel assembly?

A. Return it to its original core position.

B. Leave the assembly in the mast of the manipulator crane.

C. Place the assembly in the containment side upender and lower the upender.

D. Place the assembly in the containment side upender, lower the upender, and send the assembly into the fuel handling building.

Proposed Answer:

C. Place the assembly in the containment side upender and lower the upender.

Explanation:

A incorrect, if closer to the core, the fuel assembly is placed any open core position.

B incorrect, this is not an option.

C correct, if close to the upender, AP-21 placed in the upender and lowered.

D incorrect, not a required action.

Technical Reference(s): AP-21, Irradiated Fuel Damage.

Proposed references to be provided to applicants during examination: None sro tier 2 group 2_92 rev1.doc

Learning Objective: 6619 Explain the actions for fuel damage, actual or suspected Question Source: Bank # DCPP P-1729 Question History: Last NRC Exam DCPP RO 10/94 Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 41.13 55.43 _____

Comments:

K/A: 034 A2.01 - Fuel Handling Equipment - Ability to (a) predict the impacts of the following malfunctions or operations on the Fuel Handling System; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those malfunctions or operations: Dropped fuel element.

sro tier 2 group 2_92 rev1.doc

1 P-1729 Points: 1.00 Multiple Choice PLANT CONDITIONS:

Refueling is in progress

The manipulator crane is transferring a spent fuel assembly from the reactor vessel to the transfer canal

The assembly is currently close to the transfer canal.

RE-44A and 44B go into high alarm and CVI actuates.

Which ONE of the following describes what should be done with the spent fuel assembly?

A. Place the assembly in the containment side upender and lower the upender B. Leave the assembly in the mast of the manipulator crane C. Place the assembly in the containment side upender D. Place the assembly in the containment side upender, lower the upender, and send the assembly into the fuel handling building Answer: A ASSOCIATED INFORMATION:

Associated objective(s):

6619 Explain the actions for fuel damage, actual or suspected Reference Id: P-1729 Must appear: No Status: Active User Text: 6619.110341 User Number 1: 3.00 User Number 2: 4.10 Difficulty: 2.00 Time to complete: 3 Topic: LPA-21 Fuel handling accident actions Cross

Reference:

LPA21, OP AP-21 Comment: DCPP RO EXAM 10/94 modified due to RE-7 going into high alarm is a remote chance given the condition of being in refueling. Changed to RE-44A and B to drive home a problem in containment atmosphere.

1 &2 D IABLO C ANYON P OWER P LANT OP AP-21 ABNORMAL OPERATING PROCEDURE REV. 10 UNITS PAGE 1 OF 4 Irradiated Fuel Damage 05/06/03 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. SCOPE This procedure gives guidance in the event an irradiated fuel assembly is damaged during fuel handling or is found to have existing damage sustained from the previous cycle.

2. SYMPTOMS 2.1 Refueling crew observation of fuel damage.

2.2 While in the process of withdrawing a fuel assembly from the core, the refueling crew might observe release of gas bubbles from the fuel assembly with the following possible additional symptoms:

2.2.1 Drag withdrawal limit exceeded (Dillon Cell at Manipulator Crane Control Console).

2.2.2 Red overload light is ON (Manipulator Crane Control Console).

2.2.3 Null meter indicates excessive positive drag accompanied by an audible alarm (Manipulator Crane Control Console).

2.2.4 Auto Stop of upward hoist movement.

2.3 Local alarm/revolving red beacon light from area radiation monitors or portable continuous air monitors (e.g., SPING-3A/AMS-3/IM-11), as applicable.

2.4 Fuel Handling Building (FHB) evacuation horn is automatically sounded, if fuel handling incident is in the FHB.

2.5 Possible Main Annunciator Alarms:

2.5.1 FHB HIGH RADIATION RE-58 and 59 (PK11-10) 2.5.2 HIGH RADIATION (PK11-21) 2.5.3 CONTMT VENT ISOLATION (PK02-06) 2.5.4 If in Unit 1 CONTMT RADIATION (PK11-19) 2.5.5 If in Unit 2 HI-LEVEL RAD MONITOR SYSTEM (PK11-19) 2.6 Possible Containment Ventilation Isolation (CVI) if fuel handling incident is in Containment.

2.7 FHB ventilation transfers to Iodine removal mode if incident is in FHB. (As this is an expected action along with the automatic sounding of the FHB evacuation horn whenever RE-58 or 59 alarm is activated, Control Room call to the crew is to confirm the incident.)

02 00035310.DOC 0506.0737 Page 1 of 4

Irradiated Fuel Damage U1&2 OP AP-21 REV. 10 PAGE 2 OF 4 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. SUSPEND Core Alteration/Fuel Movement

2. CHECK Fuel Assembly (F/A) Is In Safe Place the F/A in a safe position per direction of Position: the refueling SRO.

F/A is resting in a core position OR

F/A is resting in a Spent Fuel Pool grid position OR

F/A is in the Upender and the Upender has been lowered

3. DIRECT Refueling Crew Members To Get Off Manipulator Crane Or Spent Fuel Pool Bridge Crane, As Applicable

4. CHECK Radiation Monitors

- NOT in alarm

a. CONTMT Radiation - NORMAL IF Containment radiation alarms are determined to be valid by the Refueling SRO or SFM,

- Containment Area Monitor RE-2 THEN 1) Activate CONTMT evacuation NORMAL alarm

- Containment Radiogas Monitor 2) Evacuate personnel from RE-12 NORMAL Containment

- Containment Vent Monitor 3) Initiate Containment Closure RM44A/RM44B (AD8.DC54)

- PORTABLE Cams 4) VERIFY Containment Ventilation Isolation

Containment Purge Exhaust (RCV-11,12) - Closed

Containment Purge Supply (FCV-660,661) - Closed

Containment Pressure Vacuum Relief (FCV-662, 663, 664) -

Closed

Containment Radiogas Sample Valves (FCV-678, 679, 681) -

Closed

- THIS STEP CONTINUED ON NEXT PAGE -

02 00035310.DOC 0506.0737 Page 2 of 4

Irradiated Fuel Damage U1&2 OP AP-21 REV. 10 PAGE 3 OF 4 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED

4. CHECK Radiation Monitors 5) Start fan E-15 and E-16, CONTMT

- NOT in alarm (Continued) Iodine Removal Units

6) Secure fans E-3/S-3.

7) Observe plant vent Rad monitors for any potential off-site releases.

IF Readings indicate GREATER THAN NORMAL, THEN Perform EP R-2 calculations.

b. FHB Radiation - NORMAL b. Perform the following:

RE-58 AND RE-59 1) Evacuate the FHB.

Portable CAMS 2) Select Iodine Removal for the FHB Vent system.

3) Observe plant vent rad monitors for any potential off-site releases.

IF Readings indicate GREATER THAN NORMAL, THEN Perform EP R-2 calculations.

5. VERIFY Ventilation Alignments:

Damper failure panel lights - OFF Select S Signal Test on POV-1 AND POV-2:

IF Damper failure panel lights are still on, THEN Perform the following:

a. On RCV-1 AND RCV-2, select POV-1 CONTROL AND POV-2 CONTROL switches - OFF.

b. Select ONE exhaust AND ONE supply fan to ON to restore the Aux Bldg Vent System:

1) E-1 OR E-2

2) S-31 OR S-32

c. Select ONE exhaust AND ONE supply fan to ON to restore the Fuel Handling Bldg Vent System:

1) E-5 OR E-6

2) S-1 OR S-2 02 00035310.DOC 0506.0737 Page 3 of 4

Irradiated Fuel Damage U1&2 OP AP-21 REV. 10 PAGE 4 OF 4 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED

6. CONFIRM With Radiation Protection IF Radiological conditions are NOT that Radiological Condition of The acceptable, Affected Building Is Acceptable For THEN Prohibit reentry of personnel to the Occupancy building until condition becomes acceptable for occupancy as verified by Radiation Protection

- OR -

As permitted and directed by Radiation Protection via an SWP if reentry is required.

7. DETERMINE Extent Of Fuel Damage:

a. Check for torn or missing grid strap(s)

b. Check for excessive fuel rod misalignment

c. Check for loose fuel pellets

8. IMPLEMENT Long Term Recovery Actions prescribed by Plant Management

- END -

3. APPENDICES None

4. ATTACHMENTS None 02 00035310.DOC 0506.0737 Page 4 of 4

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP B-8DS1 DIABLO CANYON POWER PLANT REVISION 34 PAGE 4 OF 12 TITLE: Core Unloading UNITS 1 AND 2 5.2.2 In the event of a required halt in fuel movement, fuel assemblies should not be left suspended, but moved to a suitable and safe location, such as a supported core location or the upender. A corner baffle is the preferred core location.

5.2.3 In the event of a refueling cavity leak indicated by rapidly decreasing level, the Refueling SRO shall ensure that the fuel element in transit is stored at the lowest elevation possible.

a. If the fuel element is in the upender, lower the upender.

b. If the fuel element is in the manipulator and over the core area, lower the element into the core.

c. Close the fuel transfer tube gate valve (SFS-50), shut the SFP swing gate and inflate the gate seal.

5.2.4 If a containment evacuation alarm occurs, CORE ALTERATIONS shall be suspended immediately and all personnel shall assemble in the main airlock.

The Refueling SRO shall inquire about the cause of the alarm and determine the response to be taken. If it is determined that no hazards to personnel exist, evacuation need not proceed any further.

5.2.5 If a portable radiation monitor alarm occurs on the manipulator crane while handling fuel, CORE ALTERATIONS shall be suspended immediately and refueling personnel shall commence evacuation after placing the fuel in a safe condition. The Refueling SRO shall make a determination of the cause of the alarm and, if the alarm appears valid, the Control Room shall be notified to sound the Containment Evacuation Alarm. If it is determined that no hazards to personnel exist, evacuation need not proceed any further.

5.2.6 If the Refueling SRO or power production engineer (Nuclear) suspects that continued operation will involve undue risk to personnel or equipment or will compromise the Technical Specifications or license provisions, operations will be suspended pending resolution.

5.2.7 If tornado or severe weather warnings go into effect, fuel handling activities shall be suspended and action taken immediately to close the equipment hatch.

00014334.DOC 02 0824.0908

SRO QUESTION 93 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 2 Group # _____ 2 K/A # 011 A2.05 Importance 3.7 Proposed Question:

A load rejection occurs on Unit 1.

The crew has entered AP-25, Rapid Load Rejection. RCS pressure is 2260 psig. AR PK 05-22, PZR LEVEL HI/LO CONTROL is in alarm.

When checking Pressurizer heaters, the CO reports all backup pressurizer heaters are OFF.

What action should the SFM take?

A. Direct the heaters energized to ensure mixing of RCS and pressurizer boron.

B. Direct the heaters energized to heat the subcooled water entering the pressurizer.

C. Continue with the procedure, high RCS pressure is the cause for the heaters not being energized.

D. Continue with the procedure, heaters should not be energized to prevent possibly lifting a pressurizer PORV.

Proposed Answer:

B. Direct the heaters energized to heat the subcooled water entering the pressurizer.

Explanation:

A incorrect, this is true when borating or diluting B correct, heaters should turn on when level is +5 above program (as during a load rejection), this heats the subcooled water entering the pressurizer.

C incorrect, normally heaters would be off and this would be appropriate for normal plant conditions.

D incorrect, heaters should be energized.

sro tier 2 group 2_93 rev1.doc

Technical Reference(s):

OP AP-25, Rapid Load Rejection, STG A4A, Pressurizer AR PK 05-22 Proposed references to be provided to applicants during examination: none Learning Objective:

4514 - Explain the bases for Pressurizer Level Control operations.

Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 55.43 43.5 Comments:

K/A: 011 A2.05 - Ability to (a) predict the impacts of the following malfunctions or operations on the PZR LCS; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those malfunctions or operations:

Loss of PZR heaters sro tier 2 group 2_93 rev1.doc

Rapid Load Reduction U1&2 OP AP-25 REV. 9 PAGE 2 OF 9 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. REDUCE Turbine Load:

a. IF Turbine runback or programmed ramp is in progress, THEN Go to step 2

b. Place DEH MW and IMP feedbacks in service

c. Set TARGET to desired load NOTE: DFWCS should satisfactorily control S/G levels in AUTO IF the ramp rate is kept below 225 MW/Minute.

d. Set desired RAMP RATE per SFM discretion

e. Push GO NOTE: Maintain rods above RIL and AFD within the doghouse.

2. VERIFY Control Rods Inserting in Manually insert control rods to maintain TAVG AUTO and TREF within 5°F.

3. VERIFY PZR Backup Heaters - ON

4. VERIFY at Least One CCP In Service

5. VERIFY DFWCS Controlling S/G Levels in AUTO:

a. Verify MFW control valves in AUTO a. Control S/G levels in MANUAL.

b. MFP speed controllers in AUTO b. Control FW/STM HDR P in MANUAL.

6. BORATE RCS:

Refer to the Reactivity Handbook to determine the quantity of boric acid to add 02 01302609.DOC 1109.0721 Page 2 of 9

PACIFIC GAS AND ELECTRIC COMPANY NUMBER AR PK05-22 NUCLEAR POWER GENERATION REVISION 8A DIABLO CANYON POWER PLANT PAGE 1 OF 3 ANNUNCIATOR RESPONSE UNIT TITLE: PZR LEVEL HI/LO CONTROL 1 09/15/99 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. LOGIC DIAGRAM LC459EX LC459CX1 ALARM LC460CX1 LC459G

2. ALARM INPUT DESCRIPTION DEVICE ALARM ANNUNCIATOR TYPEWRITER NUMBER INPUT PRINTOUT SETPOINT LC 459EX 543 PZR Lvl Dev High From REF Backup Htrs On + 5% GT LREF LC 459CX1 544 PZR Lo Lvl Letdn Iso All Htrs Off LT 17%

LC 460CX1 544 PZR Lo Lvl Letdn Iso All Htrs Off LT 17%

LC 459G 315 PZR High Charging Flow Demand 8% Below Level Program

3. PROBABLE CAUSE 3.1 Reduction or increase in plant load.

3.2 Malfunction of rod control system.

3.3 Malfunction of pressurizer level control system.

3.4 Malfunction of pressurizer pressure control system.

3.5 Tavg signal failing high.

3.6 Overfeeding or underfeeding the steam generators.

3.7 RCS loss of coolant accident, steam generator tube rupture, or loss of secondary coolant accident.

3.8 RCS leak.

3.9 Insufficient charging flow.

3.10 Failure of charging or letdown line.

221425008.D O C 16 1

Pressurizer Level Control Level Control Circuit, Continued Bases for

The level deviation-high is assumed to be an insurge produced by a energizing decrease in load. Subcooled water enters the Pressurizer.

heaters on +5%

If a subsequent outsurge were to occur, the subcooled water would not level deviation assist in maintaining pressure by flashing to steam.

Obj 42

It is conservatively assumed that a subsequent outsurge will occur. The backup heaters are energized as an anticipatory measure.

This feature also helps during other insurge transients as the backup heaters will be needed to heatup the larger than normal amount of cold water entering the pressurizer to normal saturation temperature (whether outsurge occurs or not, the heaters will turn on in anticipation of saturation temperature dropping).

A4A.DOC 2.3 - 9 REV. 12

SRO QUESTION 94 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 3 Group # _____ 1 K/A # G2.1.10 Importance 3.9 Proposed Question:

The crew is responding to a reactor trip initiated by an earthquake tripping all 3 channels of the seismic monitors.

Which of the following describes the action the crew must take, if any, regarding the fire detection instrumentation to meet the requirements of ECG 18.3, Fire Detector Instrumentation?

A. Patrols of fire zones listed in ECG 18.3 must be initiated within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

B. Inspection for fires in fire zones listed in ECG 18.3 must be completed within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

C. Patrols of fire zones with equipment in operation and listed in ECG 18.3 must be initiated within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

D. No action is required, the threshold as stated in ECG 18.3 has not been met.

Proposed Answer:

B. Inspection for fires in fire zones listed in ECG 18.3 must be completed within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

Explanation:

A incorrect, inspection must be complete in 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

B correct, per clarification sent 10/18/2004, ..all zones listed in ECG 18.3 have to be inspected for fires within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . ..It is a requirement of our facility license to have this inspection complete in 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

C incorrect, all zones listed must be patrolled.

D incorrect, the threshold (>0.02 g) has been exceeded, trip setpoint is 0.03 g.

sro tier 3 group 1_94.doc

Technical Reference(s):

ECG 18.3 Email from Mark Lemke dated 10/18/2004 Proposed references to be provided to applicants during examination: ECG 18.3 Learning Objective: 66056 - Discuss the requirements of System 18 ECGs.

Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 _____

55.43 43.2 Comments:

K/A: G2.1.10 - Knowledge of conditions and limitations in the facility license.

sro tier 3 group 1_94.doc

Fire Detection Instrumentation 18.3 18.0FIRE PROTECTION 18.3Fire Detection Instrumentation ECG 18.3 The fire detection instrumentation for each fire detection zone shown in Table 18.0-3 shall be OPERABLE*.

APPLICABILITY: Whenever equipment protected by the fire detection instrument is required to be OPERABLE*.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. With less than the minimum A.1 Establish a fire watch 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months number of required patrol to inspect the instruments operable per zone(s) with the AND Table 18.0-3, for one or inoperable instrument(s). Once per hour more zones outside thereafter.

containment.

B. With less than the minimum B.1 Establish a fire watch 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months number of required patrol to inspect the instruments operable per containment. AND Table 18.0-3, for one or Once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months more zones inside OR thereafter.

containment.

B.2 Monitor the containment 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months air temperature at locations AND TE-85 or TE-861, Once per hour TE-87 or TE-882, thereafter.

TE-89 or TE-903, and TE-91 or TE-924.

(continued) 1 Approximately 100 ft elevation between crane wall and containment wall.

2 Approximately 100 ft elevation between steam generators.

3 Approximately 140 ft elevation near equipment hatch or stairs at 270°, respectively.

4 Approximately 184 ft elevation on top of steam generator missile barriers away from steam generators.

As defined in the Diablo Canyon Power Plant Technical Specifications.

Diablo Canyon Units 1 & 2 Rev. 7 01341007.DOC 1

Fire Detection Instrumentation 18.3 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. Following a seismic event C.1 Inspect the zones in 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months in excess of 0.02g. Table 18.0-3 for fires.

AND C.2 Perform an engineering 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months evaluation to verify the OPERABILITY* of the Fire Detection System.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 18.3.1 Perform a CHANNEL FUNCTIONAL TEST* of each 6 months of the required fire detection instruments which are accessible during plant operation.

SR 18.3.2 Perform a CHANNEL FUNCTIONAL TEST* of each During each COLD of the required fire detection instruments which are SHUTDOWN*

not accessible during plant operation. exceeding 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months unless performed in the previous 6 months.

SR 18.3.3 Demonstrate the OPERABILITY* of the supervision 6 months circuitry associated with the detector alarms of each of the required fire detection instruments.

SR 18.3.4 For SSPS room detectors connected to panel POFC, 18 months verify the system (detectors, control room alarm and panel) actuate automatically upon receipt of a simulated test signal (STP M-19B).

As defined in the Diablo Canyon Power Plant Technical Specifications.

Diablo Canyon Units 1 & 2 Rev. 7 01341007.DOC 2

Fire Detection Instrumentation 18.3 BASES The OPERABILITY* of the detection instrumentation ensures that adequate warning capability is available for prompt detection of fires. This capability is required in order to detect and locate fires in their early stages. Prompt detection of fires will reduce the potential for damage of safety-related equipment and is an integral element in the overall facility Fire Protection Program.

In the event that a portion of the fire detection instrumentation is inoperable, the establishment of frequent fire patrols in the affected areas is required to provide detection capability until the inoperable instrumentation is restored to OPERABILITY*.

Action C.1 requires inspecting the zones in Table 18.0-3 for fires within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months following a seismic event in excess of 0.02g. The basis for the 2-hour Completion Time is that fire detectors are nonseismic and cannot be relied upon to detect fires after an earthquake. Since safe shutdown systems are protected by barriers rated at two hours or more, any fire after an earthquake should be detected by this inspection before redundant safe shutdown equipment is affected (Reference 7). For the purposes of this inspection, entry into a closed room or enclosure, including containment, is sufficient to meet the requirement to "inspect for fires."

Presence of a fire (smoke, odor, flame, heat) would be self evident upon entry.

Some fire detectors are located in areas not normally accessible during plant operation.

Detectors not normally accessible during plant operations, such as in containment, will be tested (channel functional test) during each COLD SHUTDOWN* exceeding 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months unless the surveillance has been performed in the previous six months. Under these conditions, surveillance requirement 18.3.2 must be satisfied prior to leaving COLD SHUTDOWN* and re-entering MODE 4.

Table 18.0-3 includes detectors credited to protect safety-related equipment and equipment required for safe shutdown. The detectors which protect safe shutdown equipment are credited in the 10 CFR 50, Appendix R Safe Shutdown Analysis and, if credited, in the technical basis of approved deviations from 10 CFR 50, Appendix R, Section III.G. Some of the detectors are also credited in the technical basis for Fire Hazards Appendix R Evaluations.

As defined in the Diablo Canyon Power Plant Technical Specifications.

(continued)

Diablo Canyon Units 1 & 2 Rev. 7 01341007.DOC 3

Fire Detection Instrumentation 18.3 BASES (continued)

REFERENCES 1. FSAR Update Appendices 9.5A and 9.5H

2. Emergency Plan Implementing Procedure, EP M-4, "Earthquake"

3. License Amendment Request 90-11, "Revision of Fire Protection License Conditions, Relocation of Fire Protection Technical Specifications, and Clarification of AFW Water Sources"

4. Supplement No. 23 to Safety Evaluation Report (SSER 23) for Diablo Canyon Power Plant, Approved Deviations from the Requirements of Section III.G of Appendix R of Title 10 of the Code of Federal Regulations, Part 50 (10 CFR 50) for Unit 1.

5. SSER No. 31 for Diablo Canyon Power Plant, Approved Deviations from the Requirements of Section III.G of 10 CFR 50, Appendix R, for Unit 2.

6. Calculation M-928, 10 CFR 50 Appendix R Safe Shutdown Analysis

7. SSER No. 8 for Diablo Canyon Power Plant, Section 9.6.1, Fire Protection System - Seismically Induced Fires.

11/02/04 Effective Date Diablo Canyon Units 1 & 2 Rev. 7 01341007.DOC 4

Fire Detection Instrumentation 18.3 TABLE 18.0-3 FIRE DETECTION INSTRUMENTS PANEL A ZONE INSTRUMENT LOCATION MINIMUM INSTRUMENTS OPERABLE SMOKE HEAT OR FLAME

1. Cable Spreading Room 10 4(1)

3. 4kV Switchgear Bus F Room 1 N.A.

4kV Switchgear Bus G Room 1 N.A.

4kV Switchgear Bus H Room 1 N.A.

4kV Switchgear Ventilation Fan Room 1 N.A.

Exciter Field Breaker Room 2 N.A.

4. 4kV Switchgear Bus F Cable Spreading Area 1 N.A 4kV Switchgear Bus G Cable Spreading Area 1 N.A.

4kV Switchgear Bus H Cable Spreading Area 1 N.A.

107' Corridor at Outside Wall (North/South) 1 N.A.

5. 12 kV Switchgear Room 8 N.A.

6. 73' Turb Bldg, 4/12kV Cable Spreading Room 8 N.A.

7. Containment Electrical Penetration Zone 7 4 N.A.

8. Containment Electrical Penetration Zone 8 3 N.A.

9. Rod Control Programmer/Reactor Trip 3 N.A.

Breaker Area Battery No. 1 Charger Room 1 N.A.

Battery No. 2 Charger Room 1 N.A.

Battery No. 3 Charger Room 1 N.A.

10. 480 Volt Bus F Area 1 N.A.

480 Volt Bus G Area 1 N.A.

480 Volt Bus H Area 1 N.A.

Hot Shutdown Panel 1 N.A.

(2)

12. Inside Containment 17 N.A.

13. Control Room Ventilation Return/Exhaust 1 N.A.

14. Control Room Ventilation Return/Exhaust 1 N.A.

15. Outside the Auxiliary Salt Water Pump Room 1 N.A.

Diablo Canyon Units 1 & 2 Rev. 7 01341007.DOC 5

Fire Detection Instrumentation 18.3 TABLE 18.0-3 (Continued)

FIRE DETECTION INSTRUMENTS PANEL B ZONE INSTRUMENT LOCATION MINIMUM INSTRUMENTS OPERABLE SMOKE HEAT OR FLAME

1. Residual Heat Removal Pump No. 1 Room 1 N.A.

Residual Heat Removal Pump No. 2 Room 1 N.A.

2. Component Cooling Water Pump No. 1 Room 1 N.A.

Component Cooling Water Pump No. 2 Room 1 N.A.

Component Cooling Water Pump No. 3 Room 1 N.A.

Charging Pump No. 1 Area 1 N.A.

Charging Pump No. 2 Area 1 N.A.

Charging Pump No. 3 Area 1 N.A.

Containment Spray Pump No. 1 Area 1 N.A.

Containment Spray Pump No. 2 Area 1 N.A.

73' Aux Bldg East-West Corridor 5 N.A.

3. Safety Injection Pump No. 1 Room 1 N.A.

Safety Injection Pump No. 2 Room 1 N.A.

Boric Acid Evaporator Area 1 N.A.

4. Chemistry Lab and adjacent Rooms 10 N.A.

CCW Heat Exchanger Room 2 N.A.

Electrical Raceway Space G Bus 2 N.A.

Electrical Raceway Space H Bus 1 N.A.

5. Auxiliary Feedwater Pump No. 1 Area 1 N.A.

Auxiliary Feedwater Pumps Nos. 2 & 3 Area 1 N.A.

Boric Acid Transfer Pumps Area 1 N.A.

(5)

6. Fire Pumps Area 1 N.A.

Unit 2 Auxiliary Building Supply Fan Room 1 N.A.

Control Room Ventilation Equipment Room 1 N.A.

7 & 8. Auxiliary Building Ventilation System 12 6 Charcoal Filter Bank, EFC-1

11. Fuel Handling Building Ventilation System 6 3 Charcoal Filter Bank, EFC-5

12. Fuel Handling Building Ventilation System 6 3 Charcoal Filter Bank, EFC-6 Diablo Canyon Units 1 & 2 Rev. 7 01341007.DOC 6

Fire Detection Instrumentation 18.3 TABLE 18.0-3 (Continued)

FIRE DETECTION INSTRUMENTS PANEL B ZONE INSTRUMENT LOCATION MINIMUM INSTRUMENTS OPERABLE SMOKE HEAT OR FLAME

13. Control Room - Control Console 3 N.A.

Control Room Board 10 N.A.

14. PPC/SSPS/SFM Office 4 N.A.

15. Control Room - Radiation Monitoring 2 N.A.

Control Room Nuclear Instrumentation 3 N.A.

16. (1) Unit 1 Auxiliary Building Supply Fan Room 1 N.A.

Control Room Ventilation Equipment Room 1 N.A.

16. (2) Boric Acid Tanks Area 1 (3) N.A.

Not Diesel Generator No. 1 Room N.A. 2 (1)

Assigned Diesel Generator No. 2 Room N.A. 2 (1) to Zone Diesel Generator No. 3 Room N.A. 2 (1)

Not Circulating Water Pump 1-1 N.A. 2 (1)

Assigned Circulating Water Pump 1-2 N.A. 2(1) to Zone Circulating Water Pump 2-1 N.A. 2 (1)

Circulating Water Pump 2-2 N.A. 2 (1)

Not Solid State Protection System 3 (4) N.A.

Assigned Room (panel POFC) to Zone Diablo Canyon Units 1 & 2 Rev. 7 01341007.DOC 7

Fire Detection Instrumentation 18.3 TABLE 18.0-3 (Continued)

FIRE DETECTION INSTRUMENTS PANEL D ZONE INSTRUMENT LOCATION MINIMUM INSTRUMENTS OPERABLE SMOKE HEAT OR FLAME

6. Access Control and Adjacent Rooms 28 N.A.

Electrical Raceway Space H Bus 1 N.A.

Electrical Raceway Space G Bus 2 N.A.

TABLE NOTATIONS (1)

Heat sensors actuate CO2 flooding and are tested per ECG 18.5.1.3, 18.5.1.4, and 18.5.2.5. ECG 18.3.1, 18.3.2, and 18.3.3 do not apply.

(2)

The fire detection instruments located within the containment are not required to be OPERABLE* during the performance of Type A Containment Leakage Rate Tests.

(3)

Unit 1 Boric Acid Tank Detectors are in Zone 16, Unit 2.

(4)

Smoke sensors actuating POFC and alarms are tested per ECG 18.3.4. ECG 18.3.1, 18.3.2, and 18.3.3 do not apply.

(5)

The fire pumps 0-1 and 0-2 are common to both units and are located on the Unit 1 side and on the Unit 1 Fire Detection Instrument Panel only.

As defined in the Diablo Canyon Power Plant Technical Specifications.

Diablo Canyon Units 1 & 2 Rev. 7 01341007.DOC 8

SRO QUESTION 95 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 3 Group # _____ 1 K/A # G2.1.22 Importance 3.3 Proposed Question:

Of the 3 conditions listed below, which of the following causes a MODE change from MODE 6 to MODE 5?

1. RCS temperature increases above 200ºF.

2. One reactor vessel head closure bolt is fully tensioned.

3. The last reactor vessel head closure bolt is fully tensioned.

A. Condition 2 only.

B. Condition 3 only.

C. Condition 1 or condition 2.

D. Condition 1 or condition 3.

Proposed Answer:

B. Condition 3 only.

Explanation:

A incorrect, this is the mode change from 5 to 6.

B correct, to transition from mode 6 to mode 5, all reactor vessel head closure bolts are fully tensioned.

C and D incorrect, no mode change if temperature increases above 200ºF Technical Reference(s): DCPP Tech Specs section 1.1, Definitions.

Proposed references to be provided to applicants during examination: none Learning Objective:

9696 - Define Technical Specification items found in the Definition Section Question Source:

Modified Bank # DCPP S-52672 sro tier 3 group 1_95.doc

Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 _____

55.43 43.2 Comments:

K/A: G2.1.22 - Ability to determine Mode of Operation sro tier 3 group 1_95.doc

Definitions 1.1 Table 1.1-1 (page 1 of 1)

MODES AVERAGE REACTIVITY % RATED REACTOR MODE TITLE CONDITION THERMAL COOLANT (keff) POWER(a) TEMPERATURE

(°F) 1 Power Operation 0.99 >5 NA 2 Startup 0.99 5 NA 3 Hot Standby < 0.99 NA 350 4 Hot Shutdown(b) < 0.99 NA 350 > TAVG > 200 5 Cold Shutdown(b) < 0.99 NA 200 6 Refueling(c) NA NA NA (a)

Excluding decay heat.

(b)

All reactor vessel head closure bolts fully tensioned.

(c)

One or more reactor vessel head closure bolts less than fully tensioned.

DIABLO CANYON - UNITS 1 & 2 8S9IDD05.DOC - R5 7

1 S-52672 Points: 1.00 Multiple Choice Which one of the following events, at the end of refueling, would require a log entry to signify the transition from MODE 6 to MODE 5?

A. ALL reactor vessel head bolts fully tensioned B. Steam Generator nozzle dams removed C. Reactor vessel head in place with NO reactor vessel head bolts tensioned D. First reactor vessel head bolt tensioned Answer: A ASSOCIATED INFORMATION:

Associated objective(s):

9696 Define Technical Specification items found in the Definitions Section Reference Id: S-52672 Must appear: No Status: Active User Text: 9624.13ALLN User Number 1: 2.70 User Number 2: 3.90 Difficulty: 2.00 Time to complete: 2 Topic: Criteria for Mode 6 to 5 transition Cross

Reference:

M-8 OBJ 6 Comment: Obj. 9696

SRO QUESTION 96 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 3 Group # _____ 2 K/A # G2.2.27 Importance 3.5 Proposed Question:

Which of the following identifies the FIRST core alteration activity requiring the presence of the Refueling SRO in Containment?

A. Unlatching RCCAs B. Lifting the upper internals C. Moving the first fuel assembly D. Lifting the reactor vessel head Proposed Answer:

A. Unlatching RCCAs Explanation:

A correct, per OP B-8DS2, the Refueling SRO is responsible for supervising Core Alterations. RCCA unlatching and moving of fuel assemblies are core alterations.

Unlatching is performed prior to removal of the fuel assembly.

B incorrect, performed after unlatching RCCAs.

C incorrect, core alteration after unlatching.

D incorrect, prior to unlatching, but not a core alteration.

Technical Reference(s):

OP L-6, Refueling OP B-8DS1, Core Unloading OP B-8D attachment 9.1 Core Unloading Prerequisites Checklist Proposed references to be provided to applicants during examination: none Learning Objective:

6497 - State the responsibilities and duties of Refueling SRO sro tier 3 group 2_96.doc

5827 - Explain which activities are considered core alterations and which are not.

Question Source: Bank #

Modified Bank # INPO 23199 New ______

Question History: Last NRC Exam Salem 11/02 Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 _____

55.43 43.6 Comments:

K/A: G2.2.27 - Knowledge of the refueling process sro tier 3 group 2_96.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP L-6 DIABLO CANYON POWER PLANT REVISION 50 PAGE 13 OF 29 TITLE: Refueling UNITS 1 AND 2 DATE/TIME/INITIALS 6.2.23 Notify maintenance and establish communications with maintenance personnel at Seal Table and check for leaks during flooding of Reactor Cavity. / /

6.2.24 If the RCS is to be drained after the Core is fully offloaded, begin voiding the S/G U-tubes per OP A-2:IV. / /

6.2.25 Obtain NSSS asset team leader concurrence that refueling cavity ready for flood up. / /

NSSS ATL Signature 6.2.26 Flood the Refueling Cavity per OP B-2:II. / /

6.2.27 If PCV-135 was bypassed to increase flow for RCS cleanup, return to normal per OP B-1A:XVII, step 6.5. N/A [ ] / /

6.2.28 Remove tags and verify open RHR-1005 and RHR-933, RHR-8703 equalizing line isolation valves per Attachment 9.2. / /

6.2.29 Complete the OP L-0 Transition checklist for MODE 6 to Core Alterations. / /

NOTE: Unlatching RCCA drive shafts IS considered a Core Alteration.

6.2.30 When RCCA unlatching requirements are met per OP B-8D, authorize maintenance to uncouple the RCCA drive shafts. / /

6.2.31 Verify Refueling Cavity level is greater than 137'8" elevation. / /

6.2.32 Verify the Outage Safety Checklist requirements are satisfied for Mode 6 internals removal. / /

6.2.33 Authorize maintenance to remove the Upper Internals. / /

6.2.34 When the upper internals move is complete, the equipment hatch and personnel hatch doors may be opened and administrative controls established over containment penetrations for core alterations per TS 3.9.4. / /

00307850.DOC 02 0120.0713

INPO Licensed Operator Exam Bank - PWR Questions ID: 23199 A refueling outage is in progress on Unit 1.

Which one of the following choices correctly identifies the FIRST activity requiring presence of the Refueling SRO in Containment?

Ans Lifting the upper internals D1 De-tensioning the first reactor head stud D2 Lifting the reactor vessel head.

D3 Moving the first fuel assembly.

AbbrevLocName ExamDate Vendor Type ExamType Cog Level ExamLevel RefMaterial ParentId Salem Unit 1 11/4/2002 WEC PWR ILO 1 R QuestionComment Explanation (Optional): A., B. - Head can be removed; D. Upper internals come out after "head is removed".

Distract1Comment Explanation (Optional): A., B. - Head can be removed; D. Upper internals come out after "head is removed".

Distract2Comment Explanation (Optional): A., B. - Head can be removed; D. Upper internals come out after "head is removed".

Distract3Comment Explanation (Optional): A., B. - Head can be removed; D. Upper internals come out after "head is removed".

KaNumber KaSegment1 KaSegment2 KaSegment3 KaSegment4 KaSegment5 KaRevision

..G2.2.27 G2 2 27 Tuesday, September 21, 2004 Page 8887 of 9479

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP B-8DS1 NUCLEAR POWER GENERATION REVISION 34 DIABLO CANYON POWER PLANT PAGE 1 OF 12 OPERATING PROCEDURE UNITS TITLE: Core Unloading 1 2 AND 08/24/04 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. SCOPE 1.1 This procedure describes core unloading for Units 1 and 2.

2. DISCUSSION 2.1 This procedure provides step by step guidance for core unloading. Core loading and insert shuffling and are discussed in OP B-8DS2, PEP R-8DS2, OP B-8DS3 and PEP R-8DS3 respectively.

3. RESPONSIBILITIES 3.1 Shift foreman for operation of the plant and plant equipment.

3.2 The Refueling SRO is responsible for coordinating and supervising the following activities.

3.2.1 All fuel handling operations.

3.2.2 Core Alterations.

3.2.3 Safe and orderly evacuation of the refueling crew in the event of a high radiation alarm at a refueling station.

3.2.4 Determining the cause of the high radiation alarm.

3.2.5 Training the shift's upender operators, to the satisfaction of the SRO, that they can operate the upender station safely.

3.3 The Refueling SRO may delegate supervisory responsibilities at the other duty stations outside of containment to a designated operations representative.

3.4 Senior power production engineer (operations) for refueling procedures.

3.5 PPE (Nuclear) for technical guidance.

3.6 Control Room operator to assist with Control Room activities associated with fuel movements. This includes:

In accordance with OP1.DC12, "Conduct of Routine Operations," assuring three-way communication of correct fuel assembly location prior to latching or unlatching;

and providing a verification of fuel assembly locations when moving fuel.

00014334.DOC 02 0824.0908

11/27/04 Page 1 of 4 DIABLO CANYON POWER PLANT TITLE: Core Unloading Prerequisites Checklist OP B-8D ATTACHMENT 9.1 1 2 AND ITEM RESPONSIBLE DEPT REVIEWED (SFM)

NO. DESCRIPTION INITIALS/DATE INITIALS/DATE C = Chemistry Manager ANSS = NSSS Asset Team Leader RP = Radiation Protection Manager ACRE = Control Room/Electrical Asset Team Leader RX Eng = Reactor Engineering ASUP = Maintenance Support Asset Team Leader Eng = Engineering OP = Shift Manager/SFM Prior to RCCA unlatching, verify Items 1 through 10 are current.

1. Temporary nozzle dams removed, or use approved by PSRC. N/A [ ] OP ______/______ _____/______

2. Applicable portions of the FHB and Containment have been classified as an FME area per AD4.ID6. All cleanliness requirements are in effect and being monitored by Maintenance. (FHB) ANSS ______/______ ______/______

(CONT) ANSS ______/______ ______/______

3. Verify STP M-42 was performed within 100 hours0.00116 days 0.0278 hours 1.653439e-4 weeks 3.805e-5 months of Rx head removal. (ECG 42.3) ENG ______/______ ______/______

4. After the Refueling Cavity has been filled, initiate a separate SFM Clearance and tag the following valves closed. CR NUMBER ___________________ OP ______/______ ______/______

Do NOT take credit for tags hung per OP L-6.

a. LWS-91 Refueling Cavity Drain Line

b. LWS-92 Refueling Canal Drain to RCDT

c. LWS-HCV-111 Refueling Canal Flushing Valve

d. The flange downstream of HCV-111 is installed, or the filter assembly flange isol valve is CAUTION tagged closed.

e. RCS-8032 Leak Detection Return to RCDT.

5. Portable radiation monitor(s) are available for use on the manipulator crane and spent fuel pool bridge crane, and a continuous air monitor is located in Containment (140' el.) and the Fuel Handling Building. RP ______/______ ______/______

00307240.DOC 02 1201.0806

11/27/04 Page 2 of 4 OP B-8D (UNITS 1 AND 2)

ATTACHMENT 9.1 TITLE: Core Unloading Prerequisites Checklist PRIOR TO RESPONSIBLE ITEM DESCRIPTION CORE ALT. DEPARTMENT REVIEWED (SFM)

NO. COMPLETE INIT./DATE INIT. HOUR/DATE WITHIN

6. Verify all OP L-0 items for Mode 6/ Core Alterations are complete. 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months OP ___/___ ____ ____/____

7. ECG 42.5, Verify refueling cavity water level >23 feet above irradiated fuel assemblies within the reactor. (elev. 126 ft. 6 in.) 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months OP ___/___ ____ ____/____

8. ECG 42.2, Establish direct communications between the control room and the refueling stations. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months OP ___/___ ____ ____/____

9. Test Evacuation Alarm. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months OP ___/___ ____ ____/____

10. SRO for fuel handling operations only and licensed RO required for continuous monitoring of count rate data during CORE ALTERATIONS. OP ___/___ ____ ____/____

RCCA Unlatching Commenced ______/______ ______ RCCA Unlatching Completed ______/______ ______

TIME DATE SFM TIME DATE SFM 00307240.DOC 02 1201.0806

11/27/04 Page 3 of 4 OP B-8D (UNITS 1 AND 2)

ATTACHMENT 9.1 TITLE: Core Unloading Prerequisites Checklist ITEM RESPONSIBLE DEPT REVIEWED (SFM)

NO. DESCRIPTION INITIALS/DATE INITIALS/DATE NOTE: Prior to core unloading, verify Items 1 through 5 and 11 through 25 are current.

11. Fuel accountability computer graphical display or boards for control of fuel assembly and insert locations during refueling operations are available for use in the appropriate areas (See TS6.ID2). RX ENG ______/______ ______/______

12. If handling recently irradiated fuel per TS 3.7.13 ensure FHB Ventilation is capable of supporting fuel movement by verifying the following are satisfied: N/A [ ] OP ______/______ ______/______

a. Complete OP H-7:I, Attachment 9.2.

b. Active SFM clearance exists on the 140' partition wall locks and 115' roll-up door chains.

CR NUMBER ___________________

c. The Refueling SRO or designee has possession of the keys to the roll-up doors to prevent them from being opened.

13. Verify an active SFM Admin Clearance exists on the source range speaker in containment. OP ______/______ ______/______

14. All critical personnel participating in the core unloading have been adequately trained for their part in the fuel handling operations including nuclear engineering/operations fuel handlers. RX ENG ______/______ ______/______

OP ______/______ ______/______

15. Core unloading sequence completed and issued by reactor engineering to determine: RX ENG ______/______ ______/______

Acceptable spent fuel storage locations (TS 3.7.17)

The fuel movement sequence insures that the core is neutronically coupled to the two source range detectors to be used.

Fuel rack absorber specimen tree located in proper storage rack cell.

16. Verify that RCP D-220 Controls are in place (High Rad Areas locked for fuel transfer). Setting the controls too early may hinder maintenance activities. RP ______/______ ______/______

17. Perform a spot check of the Manipulator Crane indexing after upper internals removal. Check a minimum of two widely separated core locations. OP ______/______ ______/______

18. A test run of the fuel transfer system and manipulator crane should be made with the dummy assembly if possible. OP ______/______ ______/______

00307240.DOC 02 1201.0806

11/27/04 Page 4 of 4 OP B-8D (UNITS 1 AND 2)

ATTACHMENT 9.1 TITLE: Core Unloading Prerequisites Checklist PRIOR TO RESPONSIBLE NEXT (SFM) RETEST ITEM DESCRIPTION UNLOADING DEPARTMENT REVIEWED (SFM) RETEST DUE COMPLETED NO. COMPLETE INIT./DATE INIT. HOUR/DATE FREQUENCY DATE INIT.

WITHIN HOUR/DATE

19. Procedure MP I-4.4-2A, Spent Fuel Pool crane load cell calibration. 6 months ANSS ___/___ ____ ____/____ 6 mo. ____ ____ ____/____

20. LT 13-2, Spent Fuel Pool Temperature Channel TIC-651 Calibration. 31 days ANSS ___/___ ____ ____/____ 92 days ____ ____ ____/____

21. STP M-27, Fuel handling interlocks. 7 days OP ___/___ ____ ____/____ N/A

22. Verify acceptability of the SFP cooling system status per Attachment 9.4 of OP B-8DS1. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months OP ___/___ ____ ____/____ 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months See OP B-8DS1

23. TS 3.9.7, Verify refueling cavity water level

>23 feet over the reactor vessel flange.

(elev. 137 ft. 8 in.) 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months OP ___/___ ____ ____/____

24. ECG 42.2, Establish direct communications between the control room and the refueling stations. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months OP ___/___ ____ ____/____ 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months See STP I-1A

a. Test Evacuation Alarm. C. O. Logs

25. SRO for fuel handling operations only and licensed operator required for continuous monitoring of count rate data during CORE ALTERATIONS. MODE 6 OP ___/___ ____ ____/____ ALL TIME Core Unloading Commenced ______/______ ______ Core Unloading Completed ______/______ ______

TIME DATE SFM TIME DATE SFM 00307240.DOC 02 1201.0806

08/26/04 Page 3 of 6 OP B-8D (UNITS 1 AND 2)

ATTACHMENT 9.2 TITLE: Core Loading Prerequisites Checklist PRIOR TO RESPONSIBLE NEXT (SFM) RETEST ITEM DESCRIPTION LOADING. DEPARTMENT REVIEWED (SFM) RETEST DUE COMPLETED NO. COMPLETE INIT./DATE INIT. HOUR/DATE FREQUENCY DATE INIT.

WITHIN HOUR/DATE

9. High Flux at Shutdown

a. Alarm setpoint calculated for Mode 6 (STP R-28). N/A RX ENG ___/___ ___ ____/____

b. Alarm setpoint current for Mode 6. N/A ACRE ___/___ ____ ____/____

c. Hi flux at shutdown switch on NIS Panel in NORMAL. N/A OP ___/___ ____ ____/____ 7 days _____ _____ ____/___

00307240.DOC 02 1201.0806

08/26/04 Page 4 of 6 OP B-8D (UNITS 1 AND 2)

ATTACHMENT 9.2 TITLE: Core Loading Prerequisites Checklist ITEM RESPONSIBLE DEPT REVIEWED (SFM)

NO. DESCRIPTION INITIALS/DATE INITIALS/DATE

10. Fuel accountability computer graphical display or boards for control of fuel assembly and insert locations during loading operations are available for use in the appropriate areas (See TS6.ID2). RX ENG ______/______ ______/______

11. Core loading sequence completed and issued by reactor engineering to ensure the core is neutronically coupled to the two source range detectors to be used. RX ENG ______/______ ______/______

12. All critical personnel participating in the core loading have been adequately trained for their part in the fuel handling operations including nuclear engineering/operations/fuel handling. RX ENG ______/______ ______/______

OP ______/______ ______/______

13. Portable radiation monitor(s) are available for use on the manipulator crane and spent fuel pool bridge crane and a continuous air monitor is located in Containment (140' el.) and the Fuel Handling Building. RP ______/______ ______/______

14. Underwater TV cameras with video taping capability and adequate underwater lighting for post-loading verification: RX ENG ______/______ ______/______

a. in operation on the reactor guide pin, OR

b. available to be mounted onto the manipulator crane after reload.

15. If handling recently irradiated fuel per TS 3.7.13 ensure FHB Ventilation is capable of supporting fuel movement by verifying the following are satisfied: N/A [ ] OP ______/______ ______/______

a. Completing OP H-7:I Attachment 9.2.

b. Active SFM clearance exists on the 140' partition wall locks and 115' roll-up door chains. CR NUMBER ___________________

c. The Refueling SRO or designee has possession of the keys to the roll-up doors to prevent them from being opened.

00307240.DOC 02 1201.0806

08/26/04 Page 5 of 6 OP B-8D (UNITS 1 AND 2)

ATTACHMENT 9.2 TITLE: Core Loading Prerequisites Checklist PRIOR TO RESPONSIBLE NEXT (SFM) RETEST ITEM DESCRIPTION LOADING. DEPARTMENT REVIEWED (SFM) RETEST DUE COMPLETED NO. COMPLETE INIT./DATE INIT. HOUR/DATE FREQUENCY DATE INIT.

WITHIN HOUR/DATE

16. Verify an active SFM clearance exists on the source range speaker in containment. OP ___/___ ____ ____/____

17. STP I-4C, Calibration of Audio Count Rate/Scaler Timer Channel, current (should be performed in conjunction with STP I-4A). N/A ACRE ___/___ ____ ____/____ 18 months

18. Verify that RCP D-220 Controls are in place (High Rad Areas locked for fuel transfer). Setting the controls too early may hinder maintenance activities. RP ___/___ ____ ____/____ ALL TIME

19. Verify all OP L-0 items for Core offload to Mode 6/Core Alterations are complete. 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months OP ___/___ ____ ____/____

20. ECG 42.2, Communications, establish direct communications between the Control Room and the refueling stations. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months OP ___/___ ____ ____/____ 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months See STP I-1A

a. Test Evacuation Alarm. C. O. Logs

21. SRO for refueling operations only and licensed operator required for continuous monitoring of count rate data during CORE ALTERATIONS. MODE 6 OP ___/___ ____ ____/____ ALL TIME Core Loading Commenced ______/______ ______ Core Loading Completed ______/______ ______

TIME DATE SFM TIME DATE SFM 00307240.DOC 02 1201.0806

08/26/04 Page 6 of 6 OP B-8D (UNITS 1 AND 2)

ATTACHMENT 9.2 TITLE: Core Loading Prerequisites Checklist PRIOR TO RESPONSIBLE NEXT (SFM) RETEST ITEM DESCRIPTION LOADING. DEPARTMENT REVIEWED (SFM) RETEST DUE COMPLETED NO. COMPLETE INIT./DATE INIT. HOUR/DATE FREQUENCY DATE INIT.

WITHIN HOUR/DATE NOTE: Prior to RCCA Latching, verify Items 1, 2, 5, 8, 9, 13, and 21 are all current.

22. ECG 42.5, Verify refueling cavity water level

>23 feet above irradiated fuel assemblies within the reactor.

(elev. 126 ft. 6 in). 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months OP ___/___ ____ ____/____ ALL TIME See STP I-1B RCCA Latching Commenced ______/______ ______ RCCA Latching Completed ______/______ ______

TIME DATE SFM TIME DATE SFM 00307240.DOC 02 1201.0806

SRO QUESTION 97 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # 3 Group # 3 K/A # G2.3.4 Importance 3.1 Proposed Question:

A Site Area Emergency has been declared due to a LOCA Outside Containment with limited makeup to the RWST available.

An operator volunteers to make an emergency entry into the penetration area to attempt to isolate the leak. This action would result in a significant reduction in offsite dose. The individual has all the required approvals and the following exposure history:

Age 25 yrs.

Total Lifetime exposure 3800 mrem TEDE

Current Year exposure 800 mrem TEDE What is the MAXIMUM exposure the operator may receive while performing this action?

A. 4200 mrem TEDE B. 5000 mrem TEDE C. 24,200 mrem TEDE D. 25,000 mrem TEDE Proposed Answer:

D. 25,000 mrem TEDE Explanation:

A incorrect, this includes a reduction of federal limit (5 rem TEDE) less current exposure B incorrect, this is the federal limit and emergency exposure limit for radiological assessment sampling C incorrect, this takes into account the current TEDE which does not apply D correct, to save a life or for dose saving to population, 25 rem is the guideline.

Technical Reference(s): EP RB-2, DCPP Emergency Exposure Guidelines sro tier 3 group 3_97.doc

Proposed references to be provided to applicants during examination: none Learning Objective: 7954 - State the emergency dose limits Question Source: Bank # INPO 20049 Question History: Last NRC Exam Braidwood 10/2001 Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 _____

55.43 43.4 Comments: K/A: G2.3.4 - Knowledge of radiation exposure limits and contamination control, including permissible levels in excess of those authorized.

sro tier 3 group 3_97.doc

10/07/93 Page 1 of 2 DIABLO CANYON POWER PLANT TITLE:

EP RB-2 ATTACHMENT 9.6 DCPP Emergency Exposure Guidelines 1 2 AND The following table contains guidelines for use in authorizing emergency exposures when lower doses are not practicable:

RADIOLOGICAL PROPERTY DOSE SAVING LIFESAVING ASSESSMENT SAVING TO TO SAMPLING POPULATION* INDIVIDUAL*

Emergency Sampling Under Mitigating Damage Corrective Actions, Lifesaving Actions, Actions----> Emergency to Valuable stop/reduce a 1st Aid, Search and Part of Body Conditions Property release rescue Irradiated Whole Body 5 rem TEDE 10 rem TEDE 25 rem TEDE 25 rem TEDE Skin & any 50 rem SDE 100 rem SDE 250 rem SDE 250 rem SDE Extremity Lens of the Eye 15 rem LDE 30 rem LDE 75 rem LDE 75 rem LDE Any Organ or 50 rem 100 rem 250 rem 250 rem Tissues (CDE+DDE) (CDE+DDE) (CDE+DDE) (CDE+DDE)

NOTES: 1. Radiological Assessment Sampling, includes collection of atmospheric, liquid, and environmental radiological activity samples as well as chemistry samples involving high activity or high radiation. Emergency exposure limits may be authorized for selected individuals, for emergency assessment functions, in addition to annual occupational dose to date.

2. Property Saving, for example, might be dispatching the Fire Brigade to extinguish a fire in a Very High Radiation Area to protect plant equipment though no immediate threat exists to compromising Plant Safety.

3. Dose Saving to Population, includes activities that justify a potential overexposure to a few workers in order to save even a small average dose in a large population. (May also include Traffic Control for Evacuees or other Security Plan Functions.)

4. Lifesaving to Individual, includes the activity of search and rescue in very high dose rates or high airborne activity.

Extreme situations may occur in which a dose in excess of 25 rem TEDE would be unavoidable for either Dose Saving to (Large) Population or Lifesaving to (An)

Individual.

An authorization of emergency exposure with NO LIMITS may be made under those conditions, but only to volunteers who are fully aware of the risks involved, including the numerical levels of dose at which acute effects of radiation will be incurred and the numerical estimates of the risk of delayed effects.

00030605.DOC 03B 0323.0310

INPO Licensed Operator Exam Bank - PWR Questions ID: 20049 Given the following information for a rad worker qualified operator:

- Age 25 yrs.

- Total Lifetime exposure 3800 mrem TEDE

- Current Year exposure 800 mrem TEDE A Site Area Emergency has been declared due to a LOCA Outside Containment with limited makeup to the RWST available. The above operator volunteers to make an emergency entry into the penetration area to attempt to isolate the leak. This action would result in a significant reduction in offsite dose. The individual has all the required approvals. What is the MAXIMUM exposure the operator may receive while performing this action?

Ans 25000 mrem TEDE.

D1 1200 mrem TEDE.

D2 4200 mrem TEDE.

D3 24200 mrem TEDE.

AbbrevLocName ExamDate Vendor Type ExamType Cog Level ExamLevel RefMaterial ParentId Braidwood 1 10/20/2001 WEC PWR ILO R QuestionComment Distract1Comment Distract2Comment Distract3Comment KaNumber KaSegment1 KaSegment2 KaSegment3 KaSegment4 KaSegment5 KaRevision

..2.3.1 2 3 1 Tuesday, September 21, 2004 Page 7432 of 9479

SRO QUESTION 98 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 3 Group # _____ 3 K/A # G2.3.8 Importance 3.2 Proposed Question:

A discharge of Gas Decay Tank 1-2 is planned.

The current conditions exist:

Current time and date - 2200, 17 July

RE-22 declared inoperable at 0100 on 3 July

The planned discharge will take 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months

2 samples have been independently drawn and analyzed Which of the following describes whether the planned discharge may or may not occur?

A. The planned discharge may not occur until RE-22 is restored to OPERABLE status.

B. The planned discharge may proceed in its entirety.

C. The discharge may occur, but only for 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months , then it must be terminated.

D. The discharge may not proceed because during the discharge the allowable time RE-22 may be inoperable will expire.

Proposed Answer:

A. The planned discharge may not occur until RE-22 is restored to OPERABLE status.

Explanation:

A correct, as of 0100 on 17 July, the 14 days allowed by ECG (and procedure OP G-2:V) has been exceeded. A discharge is not allowed.

B incorrect, 14 days exceeded.

C incorrect, 14 days already exceeded.

D incorrect, if there is time available, the discharge could have continued for a short period of time.

sro tier 3 group 3_98.doc

Technical Reference(s):

ECG 39.4 OP G-2:V, Gaseous Radwaste System - Gas Decay Tank Discharge Proposed references to be provided to applicants during examination:

OP G-2:V ECG 39.4 Learning Objective:

7428 - State gaseous radwaste system administrative controls 66068 - Discuss the requirements of System 39 ECGs.

Question Source:

New X Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 _____

55.43 43.2 Comments:

K/A: G2.3.8 - Knowledge of the process for performing a planned gaseous radioactive release.

sro tier 3 group 3_98.doc

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP G-2:V NUCLEAR POWER GENERATION REVISION 9 DIABLO CANYON POWER PLANT PAGE 1 OF 6 OPERATING PROCEDURE UNIT TITLE: Gaseous Radwaste System - Gas Decay Tank Discharge 107/30/02 EFFECTIVE DATE PROCEDURE CLASSIFICATION: QUALITY RELATED

1. SCOPE 1.1 This procedure is intended to provide a method of safely discharging the contents of a Gas Decay Tank. The primary goal is to prevent an inadvertent or unmonitored release.

2. DISCUSSION 2.1 This procedure should be performed in conjunction with CAP A-6.

3. RESPONSIBILITIES 3.1 Chemistry Engineer/Foreman is responsible for preparation of the Authorization for Gas Decay Tank (GDT) discharge.

3.2 The Shift Foreman is responsible for the following:

3.2.1 Reviewing Discharge Authorization and verifying compliance with ECG's 24.3 and 39.4.

3.2.2 Authorizing and issuing the Discharge Authorization.

3.2.3 Reviewing completed Discharge Authorization and forwarding it to Chemistry Section.

3.3 The Auxiliary Building Sr and/or Auxiliary Building NO are responsible for completing the Discharge Authorization and returning it to the Shift Foreman.

4. PREREQUISITES 4.1 The Gaseous Radwaste System is aligned per OP G-2:I, Gaseous Radwaste System - Make Available.

4.2 The Auxiliary Building Ventilation Exhaust Treatment System shall be operable at all times. Refer to Tech Spec 3.7.12.

4.3 An Authorization for Gas Decay Tank Discharge, (Form 69-9351), has been prepared and signed by Chemistry Section Engineer/Foreman.

002370009.D O C 02 0120.1112

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP G-2:V DIABLO CANYON POWER PLANT REVISION 9 PAGE 2 OF 6 TITLE: Gaseous Radwaste System - Gas Decay Tank UNIT 1 Discharge

5. PRECAUTIONS AND LIMITATIONS 5.1 Do not commence a discharge until the Discharge Authorization is approved and issued by Chemistry.

5.2 RE-22 should be operable for all GDT discharges. If RE-22 is inoperable, discharges may occur so long as additional precautions are taken as required by ECG 39.4. These precautions are detailed in this procedure.

5.3 Ventilation dilution flow should be maintained throughout the discharge.

5.4 Only one GDT can be discharged (vented) at a time.

5.5 Only a tank NOT selected for FILL or STANDBY can be discharged (vented).

5.6 A GDT discharge should NOT be performed if the actual tank pressure is NOT in agreement with the tank pressure indicated on the Discharge Authorization, (Form 69-9351).

5.7 Valve alignment verification is performed and documented on the Discharge Authorization, (Form 69-9351).

6. INSTRUCTIONS 6.1 Review the Prerequisites and Precautions and Limitations sections of this procedure.

6.2 Verify RE-22 operable for monitoring GDT release.

NOTE: If the Discharge Authorization requires HASP to be readjusted prior to the discharge, contact the Shift MS Tech and request the setpoint be changed to the value prescribed by the Chemistry Engineer/Foreman.

6.2.1 Check RE-22 Operable by doing the following:

a. Check that the instrument calibration has not expired.

b. Perform a CHANNEL CHECK as follows:

1. Power light is ON.

2. Operation Selector set to OPERATE.

3. Range Selector set to WIDE.

4. Normal meter reading with slight movement of needle.

5. Red Low Alarm lamp is OFF.

c. Perform a source check on RE-22.

1. Place the operation selector switch to CHECK SOURCE position.

2. Read the SOURCE count rate.

3. Place the operation selector switch to RESET and then to OPERATE.

002370009.D O C 02 0120.1112

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP G-2:V DIABLO CANYON POWER PLANT REVISION 9 PAGE 3 OF 6 TITLE: Gaseous Radwaste System - Gas Decay Tank UNIT 1 Discharge

d. Log the SOURCE count rate on Part 3 of the Discharge Authorization.

e. If RE-22 is operable, proceed to Step 6.3.

6.2.2 If RE-22 is inoperable, proceed as follows:

CAUTION: Gaseous Radwaste discharges may continue for up to 14 days after RE-22 is declared inoperable if the applicable ACTION statements in ECG 39.4 are followed.

a. Note the date and time that RE-22 is declared inoperable in the Shift Log.

b. Review the applicable portions of ECG 39.4.

c. Attach a CAUTION Tag to the control switch for the key operated discharge valve, 1-FCV-410, made out to the Shift Foreman.

Indicate on the tag, the date and time of the expiration of the 14 day period when termination of all releases, via this pathway, is required.

d. Request Chemistry Section to obtain and analyze a second independent GDT sample.

e. Initiate an Action Request (AR) to initiate repair of RE-22.

f. Fill out the appropriate sections of the Discharge Authorization.

6.2.3 If RE-22 has been inoperable for less than or equal to 14 days:

CAUTION: Gaseous Radwaste discharges may continue for up to 14 days after RE-22 is declared inoperable if the ACTION statements in ECG 39.4 are followed.

a. Review the applicable portions of ECG 39.4.

b. Request Chemistry Section to obtain and analyze a second independent GDT sample.

c. Ensure that the release rate calculations are verified by at least two qualified staff members.

d. If the tank activity is below the limits stated in CAP A-6, fill out the appropriate sections of the Discharge Authorization.

6.2.4 If RE-22 has been inoperable for greater than 14 days:

CAUTION: Gaseous Radwaste discharges may NOT continue when RE-22 has been declared inoperable for greater than 14 days.

a. Review the applicable portions of ECG 39.4.

002370009.D O C 02 0120.1112

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP G-2:V DIABLO CANYON POWER PLANT REVISION 9 PAGE 4 OF 6 TITLE: Gaseous Radwaste System - Gas Decay Tank UNIT 1 Discharge

b. Terminate the Gaseous Radwaste discharge process.

c. Initiate an Admin Tagout to the Shift Foreman to attach a CAUTION Tag to the control switch for the key operated discharge valve, 1-FCV-410.

d. Notify SFM that RE-22 inoperability must be resolved.

6.3 The Shift Foreman should report off the Admin. Tagout used for placing the GDT in holdup.

CAUTION: If Items 6.4 or 6.5 are not met, discontinue this procedure and notify the Shift Foreman.

6.4 At the Auxiliary Control Board, verify actual Gas Decay Tank pressure is consistent with the pressure logged in Part 1 of the Discharge Authorization. Log the prerelease pressure in Part 3 of the Discharge Authorization.

6.5 Verify the following valves CLOSED and Caution tagged as required by OP G-2:11, when originally placing the tank in holdup, then remove Admin Tagout.

6.5.1 GDT Fill Valve 6.5.2 GDT Purge Valve 6.5.3 GDT N2 Supply Valve 6.5.4 GDT Gas Analyzer Sample has been removed from scan and CAUTION Tag is hung on panel.

NOTE: If GDT 1-3 was on holdup, perform this on the U-2 Gas Analyzer also.

6.5.5 GW-0-FCV-417, IF GDT 1-3 is in holdup.

6.6 Just prior to the start of discharge, notify the Control Operator that the GDT discharge is about to begin.

6.7 Notify the Chemistry Section that the discharge will commence. Log the date and time on Part 3 of the Discharge Authorization.

6.8 Select the GDT to be discharged on the tank vent selector switch and OPEN the appropriate tank vent valve listed below:

6.8.1 GDT 1-1, 1-FCV-404 6.8.2 GDT 1-2, 1-FCV-405 6.8.3 GDT 1-3, 1-FCV-406 6.9 Complete independent verification of valve alignment and record valve numbers used on Part 3 of Discharge Authorization.

002370009.D O C 02 0120.1112

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP G-2:V DIABLO CANYON POWER PLANT REVISION 9 PAGE 5 OF 6 TITLE: Gaseous Radwaste System - Gas Decay Tank UNIT 1 Discharge 6.10 Obtain authorization from the Shift Foreman to discharge the GDT following his review of the discharge authorization. Both Shift Foreman and Chemistry Engineer/Foreman must have signed the Discharge Authorization to make the authorization valid.

6.11 The Operator who will perform the discharge shall obtain the key for the Gaseous Radwaste discharge valve, 1-FCV-410, and receive any pertinent instructions concerning the discharge from the Shift Foreman.

6.12 Start the discharge by opening the key operated discharge valve, 1-FCV-410.

Log time and Batch No. in NO log and document performance of line up and date and time on Part 3 of Discharge Authorization.

6.13 Record the release information required on the Discharge Authorization during and following the release.

6.14 If RE-22 alarms due to an actual high rad condition during the discharge:

6.14.1 Ensure 1-RCV-17 has closed.

6.14.2 Close 1-FCV-410 and remove the key.

6.14.3 Notify the Shift Foreman.

6.14.4 Notify the Chemistry Section.

6.14.5 Complete the Discharge Authorization Form and note in the comments section the reason for discharge termination.

6.15 If RE-22 fails during the discharge due to a component problem, proceed as follows:

6.15.1 Ensure 1-RCV-17 has closed.

6.15.2 Close 1-FCV-410 and remove the key.

6.15.3 Notify the Shift Foreman.

6.15.4 Notify the Chemistry Section.

6.15.5 If RE-22 is repaired, verify that the GDT has not been selected to "FILL" or "PURGE" following the termination of the discharge. To continue the tank discharge, consult the Shift Foreman.

6.16 When the GDT pressure decreases to approx. 5 psig, terminate the discharge by closing the tank vent valve. Log final GDT pressure on Part 3 of Discharge Authorization.

NOTE: If the GDT is being discharged in preparation for clearing, (OP G-2:III), or in conjunction with N2 purging, (OP G-2:IV), terminate the discharge when the GDT pressure decreases to approx. 0.5 psig.

6.17 Close 1-FCV-410 and remove key. Record date and time of release termination.

Complete all portions (Part 3) on the Discharge Authorization. Sign and return the Discharge Authorization and the key for 1-FCV-410 to the Shift Foreman.

002370009.D O C 02 0120.1112

PACIFIC GAS AND ELECTRIC COMPANY NUMBER OP G-2:V DIABLO CANYON POWER PLANT REVISION 9 PAGE 6 OF 6 TITLE: Gaseous Radwaste System - Gas Decay Tank UNIT 1 Discharge

7. REFERENCES 7.1 Technical Specifications 3.7.12, ECG's 24.2 and 24.3.

7.2 Equipment Control Guidelines, ECG 39.4.

7.3 CAP A-6, "Gaseous Radwaste Discharge Management."

8. RECORDS The authorization for GDT discharge must be routed to the Chemistry Section for update and retention.

9. ATTACHMENTS None 002370009.D O C 02 0120.1112

Radioactive Gaseous Effluent Monitoring Instrumentation 39.4 39.0 INSTRUMENTATION 39.4 Radioactive Gaseous Effluent Monitoring Instrumentation ECG 39.4 The radioactive gaseous effluent monitoring instrumentation channels for each function shown in Table 39.4-1 shall be OPERABLE with their alarm/trip setpoints set to ensure the limits of the Radioactive Effluent Controls Program (CY2.ID1) are not exceeded. The alarm/trip setpoints of these channels shall be determined and adjusted in accordance with the methodology and parameters in the Offsite Dose Calculations (CAP A-8).

APPLICABILITY: In accordance with Table 39.4-1.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more A.1 Enter the Condition referenced in Immediately functions listed in Table 39.4-1 for the channel.

Table 39.4-1 with the required channel inoperable.

B. Required Gaseous ---------------------NOTE (B)--------------------

Radwaste System The contents of the tank(s) may be Noble Gas Activity released to the environment for up to 14 Monitor channel days provided that prior to initiating the inoperable. release:

a. At least two independent samples of the tanks contents are analyzed, and

b. At least two technically qualified members of the facility staff independently verify the release rate calculations and discharge valve line up.

Otherwise, comply with Action B.1 B.1 Suspend release of radioactive Immediately effluents via this pathway.

AND B.2.1 Restore the Monitor to 14 days OPERABLE status.

OR B.2.2 Explain in Effluent Release Next submittal of the Report pursuant to TS 5.6.3 why Effluent Release this inoperability was not Report corrected within the time specified.

(continued)

Diablo Canyon Units 1 & 2 Rev. 8 2EH1VW08.DOA 1

Radioactive Gaseous Effluent Monitoring Instrumentation 39.4 (continued)

C. Two Plant Vent -------------------NOTE (C)----------------------

System Noble Gas Effluent release via this pathway may Activity Monitor continue for up to 30 days provided grab channels samples are taken at least once per 12 inoperable. hours and these samples are analyzed for radioactivity within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

C.1.1 Implement a sampling program 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months as described in NOTE C.

OR C.1.2 Suspend release of radioactive Immediately effluents via the associated pathway.

AND C.2.1 Restore one Monitor channel to 30 days OPERABLE status.

OR C.2.2 Explain in Effluent Release Next submittal of the Report pursuant to TS 5.6.3 why Effluent Release this inoperability was not Report corrected within the time specified.

D. Two Plant Vent -------------------NOTE (D)----------------------

System Iodine Effluent releases via the affected Sampler channels pathway may continue for up to 30 days inoperable provided samples are continuously (cartridge and filter collected with auxiliary sampling only) equipment.

OR ------------------------------------------------------

Two Plant Vent D.1.1 Implement a sampling program 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months System Particulate as described in Note D.

Sampler channels OR inoperable.

D.1.2 Suspend release of radioactive Immediately effluents via this pathway.

AND D.2.1 Restore one Sampler channel to 30 days OPERABLE status.

OR D.2.2 Explain in Effluent Release Next submittal of the Report pursuant to TS 5.6.3 why Effluent Release this inoperability was not Report corrected within the time specified.

(continued)

Diablo Canyon Units 1 & 2 Rev. 8 2EH1VW08.DOA 2

Radioactive Gaseous Effluent Monitoring Instrumentation 39.4 (continued)

E. Two Plant Vent -------------------NOTE (E)----------------------

System Flow Rate Effluent releases via this pathway may Monitor channels continue for up to 30 days provided the inoperable flow rate is estimated at least once per 4 OR hours.

Two Plant Vent E.1.1 Estimate the flow rate as 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months System Iodine described in Note E.

Sampler Flow Rate Monitor channels OR inoperable. E.1.2 Suspend release of radioactive Immediately effluents via this pathway.

AND E.2.1 Restore one Monitor channel to 30 days OPERABLE Status.

OR E.2.2 Explain in Effluent Release Next submittal of the Report pursuant to TS 5.6.3 why Effluent Release this inoperability was not Report corrected within the time specified.

Diablo Canyon Units 1 & 2 Rev. 8 2EH1VW08.DOA 3

Radioactive Gaseous Effluent Monitoring Instrumentation 39.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 39.4.1 Perform CHANNEL CHECK. Prior to each release.

SR 39.4.2 Perform CHANNEL CHECK. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months SR 39.4.3 ------------------------------------NOTE------------------------------------- 7 days The CHANNEL CHECK shall consist of verifying that the iodine cartridge and particulate filter are installed in the sample holders.

Perform CHANNEL CHECK.

SR 39.4.4 Perform SOURCE CHECK. Prior to each release.

SR 39.4.5 Perform SOURCE CHECK. 31 days SR 39.4.6 -----------------------------------NOTE--------------------------------------- 18 months The initial CHANNEL CALIBRATION shall be performed using one or more of the reference standards certified by the National Institute of Standards and Technology (NIST) or using standards that have been obtained from suppliers that participate in measurement assurance activities with NIST.

These standards shall permit calibrating the system over its intended range of energy and measurement range. For subsequent CHANNEL CALIBRATION, sources that have been related to the initial calibration shall be used.

Perform CHANNEL CALIBRATION.

SR 39.4.7 Perform CHANNEL CALIBRATION. 18 months SR 39.4.8 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 39.4.9 -----------------------------------NOTE--------------------------------------- 92 days The CHANNEL FUNCTIONAL TEST shall also demonstrate that control room alarm annunciation occurs if any of the following conditions exist:

a. Instrument indicates measured levels above the Alarm Setpoint, or

b. Circuit failure, or

c. Instrument indicates a downscale failure, or

d. Instrument controls not set in operate mode.

Perform CHANNEL FUNCTIONAL TEST. (continued)

Diablo Canyon Units 1 & 2 Rev. 8 2EH1VW08.DOA 4

Radioactive Gaseous Effluent Monitoring Instrumentation 39.4 SURVEILLANCE REQUIREMENTS (continued) SURVEILLANCE FREQUENCY SR 39.4.10 -----------------------------------NOTE--------------------------------------- 92 days The CHANNEL FUNCTIONAL TEST shall also demonstrate that automatic isolation of this pathway and control room alarm annunciation occurs if any of the following conditions exist:

a. Instrument indicates measured levels above the Alarm/Trip Setpoint (isolation and alarm), or

b. Relay control circuit failure (isolation only), or

c. Instrument indicates a downscale failure (alarm only),

or

d. Instrument controls not set in operate mode (alarm only).

Perform CHANNEL FUNCTIONAL TEST.

Diablo Canyon Units 1 & 2 Rev. 8 2EH1VW08.DOA 5

Radioactive Gaseous Effluent Monitoring Instrumentation 39.4 Table 39.4-1 Radiological Gaseous Effluent Monitoring Instrumentation REQUIRED NUMBER ECG 39.4 OF REQUIRED ACTION SURVEILLANCE FUNCTION CHANNELS MODE CONDITION REQUIREMENTS

1. Gaseous Radwaste 1 At all times B SR 39.4.1 System SR 39.4.4 Noble Gas Activity Monitor SR 39.4.6

- Providing alarm and SR 39.4.10 automatic termination of release

2. Plant Vent System

a. Noble Gas Activity 1 per Unit At all times C SR 39.4.2 Monitor SR 39.4.5 SR 39.4.6 SR 39.4.9

b. Iodine Sampler (the 1 At all times D SR 39.4.3 cartridge and filter only)

c. Particulate Sampler 1 At all times D SR 39.4.3 (the cartridge and filter only)

d. Plant Vent Flow Rate 1 At all times E SR 39.4.2 Monitor SR 39.4.7 SR 39.4.8

e. Iodine Sampler Flow 1 At all times E SR 39.4.2 Rate Monitor SR 39.4.7 SR 39.4.8

3. Containment Purge TS 3.3.6 TS 3.3.6 TS 3.3.6 System (In Accordance With TS)

Noble Gas Activity Monitor Diablo Canyon Units 1 & 2 Rev. 8 2EH1VW08.DOA 6

Radioactive Gaseous Effluent Monitoring Instrumentation 39.4 BASES BACKGROUND The radioactive gaseous effluent instrumentation is provided to monitor and control, as applicable, the release of radioactive materials in gaseous effluents during actual or postulated radiological releases. The alarm/trip setpoints for these instruments shall be calculated and adjusted in accordance with the methodology and parameters in the Offsite Dose Calculation Manual (ODCM-TS 5.5.1) to ensure that the alarm/trip will occur prior to exceeding 10 CFR Part 20 limits.

The gaseous radwaste system gas decay tank noble gas discharge monitor, RM-22 (channel R-22), detects radioactive noble gases and provides an alarm and automatic termination of release. When actuated, the instrument channel provides a control output signal initiating the closure of valve RCV-17 (Reference 6). When activity level is sufficiently low, these gases are released from the gas decay tanks, passed through a HEPA filter, and vented directly to the atmosphere via the plant vent system (Reference 4). The gas decay tanks are common to both units.

The plant vent system includes additional monitoring instrumentation in the release vents. Noble gas monitors RM-14 and RM-14R (channels R-14 and R-14R) provide an alarm when high radiation is detected in the plant vent. The plant vent iodine monitors, RM-24 and RM-24R (channels R-24 and R-24R), sample air exhausted through the plant vent to determine the radioactive iodine concentration. Similarly, the plant vent radioactive particulate monitors, RM-28 and RM-28R (channels R-28 and R-28R), sample the exhaust air for radioactive particulate concentrations.

In conjunction, flow rate monitoring channels FT-813 and FT-814, (associated with iodine sampler channels R-24 and R-24R), measure the flow rates, which are used as inputs in determining the iodine activity.

Loop flow transmitter FT-12 or its redundant counterpart, FT-12R, feeds a signal to flow recorder FR-12, which monitors the gaseous effluent flow rate in the plant vent. (Reference 7). The containment exhaust radiation monitors, RM-44A and RM-44B (channels R-44A and R-44B), monitor the air exhausted from containment through the containment purge and exhaust lines, and are covered by TS 3.3.6, Containment Ventilation Isolation Instrumentation.

The operability and use of this instrumentation is consistent with the requirements of 10 CFR Part 50, Appendix A, General Design Criteria 60, 63, and 64. The sensitivity of any noble gas activity monitors used to show compliance with the gaseous effluent release requirements of the ODCM (commitment for operation 6.1.7.1 of CY2.ID1) shall be such that concentrations as low as 1 x 10-5 microcurie/mL are measurable.

(continued)

Diablo Canyon Units 1 & 2 Rev. 8 2EH1VW08.DOA 7

Radioactive Gaseous Effluent Monitoring Instrumentation 39.4 (continued)

APPLICABLE Several plant features are in place to limit the amount of activity that could SAFETY be released in the event of a design basis accident (DBA) gas decay tank ANALYSES rupture. Limits on primary coolant activity restrict the total curies present in the gas decay tanks as do the physical dimensions of each individual tank. Radiation monitors allow for the early detection of release and isolation valves allow operators to terminate the release upon detection.

The plant vent system is equipped with two channels of radioactive noble gas monitors, iodine monitors, and particulate monitors. Failure of any one of the two channels does not render the monitoring instrumentation inoperable. Sampling programs can be implemented to compensate for a failure of the channel required for operability.

LCO The radioactive gaseous effluent monitoring instrumentation must be OPERABLE to ensure that radioactive gas from the decay tanks is not released to the atmosphere via the plant vent system until its activity is sufficiently low.

The LCO requires that the single gaseous radwaste system noble gas activity monitor channel (R-22) be OPERABLE at all times as a primary means of detection and transmittal of an automatic isolation signal in the event of a gas decay tank rupture. The radiation monitoring channels in the plant vent system release vent detect the concentration of radioactive noble gases, iodine, and particulates. The plant vent system radiation monitoring channels and the plant vent flow rate monitors associated with each function have two channels, but only one is required for operability.

APPLICABILITY ECG 39.4 is applicable at all times because the effects of an uncontrolled release of a gas decay tanks contents are not dependent on plant operational mode.

ACTIONS A.1 With one or more functions (as listed in Table 39.4-1) with the required channel inoperable, the appropriate actions must be taken to restore operability to the instrumentation in order to ensure that a radioactive gaseous effluent release is not vented to the atmosphere in the case of a gas decay tank rupture. When one or more function is inoperable, the release of gaseous effluents is suspended or a compensatory action is taken to ensure the safe release of gaseous effluent until the equipment is made OPERABLE.

B.1 Suspending release of radioactive effluents via this pathway ensures that no potentially radioactive gases are released from the decay tanks to the plant vent while the monitoring function is inoperable. As described in Required Action Note B, the contents of the tank may be released for up to 14 days provided that the compensatory analysis and verification are performed.

(continued)

Diablo Canyon Units 1 & 2 Rev. 8 2EH1VW08.DOA 8

Radioactive Gaseous Effluent Monitoring Instrumentation 39.4 (continued)

ACTIONS B.2.1 and B.2.2 During the 14-day allotment the channel shall be repaired so that the activity in the gaseous effluent can be determined and the automatic valve closure function is available if the activity exceeds the alarm/trip setpoint.

If the channel is not repaired in the allotted time, an explanation is required in the next submittal of the Effluent Release Report. The 14 day completion time is reasonable based on the low probability of uncontrolled release and provides ample time to repair the channel.

C.1.1 The purpose of the sampling program is to manually sample and analyze the gaseous effluent for radiation when the release vent radiation monitoring channels are inoperable. The gaseous radwaste system noble gas activity monitoring channel (R-22) ensures gaseous effluent release to the plant vent system via the gas decay tanks has sufficiently low activity.

In addition to the gas decay tanks, several other release pathways are routed to the plant vent system, making it necessary to sample at this frequency.

C.1.2 Suspending release of radioactive effluents via this pathway ensures that no potentially radioactive gases are vented to the atmosphere while the radioactive noble gas monitoring channel in the release vent is inoperable and initiating a sampling program is not feasible.

C.2.1 and C.2.2 After suspending release of effluents via this pathway or initiating the sampling program, 30 days are allotted to repair the channel. The completion time is based on the time necessary to restore operability to the channel and the low probability of radioactive release concurrent with channel inoperability. If the channel is not repaired in the allotted time, an explanation is required in the next submittal of the Effluent Release Report.

D.1.1 To respond to the low flow alarm, determine that a simple fix cannot be made and that an auxiliary sampler is needed, move the sampler in, and hook up and verify operation. A maximum of two hours is considered a reasonable time to initiate the continuous sampling program Over two hours should be considered as exceeding the time limitation of this ECG.

D.1.2 Suspending release of radioactive effluents via this pathway ensures that no potentially radioactive gases are vented to the atmosphere while either the iodine sampler or particulate sampler is inoperable and continuous sampling is not possible.

(continued)

Diablo Canyon Units 1 & 2 Rev. 8 2EH1VW08.DOA 9

Radioactive Gaseous Effluent Monitoring Instrumentation 39.4 (continued)

ACTIONS D.2.1 and D.2.2 After suspending release of effluents via this pathway or initiating the sampling program, 30 days are allotted to repair the channel, based on the time demonstrated necessary by experience to restore operability. If the channel is not repaired in the allotted time, an explanation is required in the next submittal of the Effluent Release Report.

E.1.1 Effluent release via the plant vent may continue for up to 30 days provided the flow rate is estimated at least once every four hours in order to ensure detection of significant releases.

E.1.2 Suspending release of radioactive effluents via this pathway is a conservative measure that ensures no potentially radioactive gases are vented to the atmosphere while the flow rate monitors are inoperable and the flow rate cannot be estimated per the frequency specified in Required Action E.1.

E.2.1 and E.2.2 After suspending effluent release, 30 days are allotted to repair the channel If the channel is not repaired in the allotted time, an explanation is required in the next submittal of the Effluent Release Report.

SURVEILLANCE SR 39.4.1 REQUIREMENTS Performing a CHANNEL CHECK on the gas decay tank noble gas activity monitor (RM-22) ensures normal behavior of the channel prior to each release. By confirming operability, a CHANNEL CHECK also ensures that the instrumentation is able to send a high radiation signal to the isolation valve to terminate gaseous effluent release.

SR 39.4.2 A CHANNEL CHECK is performed on the noble gas plant vent monitors (RM-14 and RM-14R), the iodine sampler flow rate monitors, and the plant vent flow rate monitor (flow recorder, FR-12) once every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . This surveillance ensures reliability of concentration measurements in the case of a gas decay tank rupture. The frequency is based on the low probability of an uncontrolled release.

SR 39.4.3 A CHANNEL CHECK is performed every 7 days on the iodine sampler and particulate sampler; the monitors associated with these samplers are RM-24 and RM-24R, and RM-28 and RM-28R, respectively. The CHANNEL CHECK consists of verifying that the iodine cartridge and particulate filter are installed in the sample holders.

(continued)

Diablo Canyon Units 1 & 2 Rev. 8 2EH1VW08.DOA 10

Radioactive Gaseous Effluent Monitoring Instrumentation 39.4 (continued)

SURVEILLANCE SR 39.4.4 REQUIREMENTS A SOURCE CHECK is the qualitative assessment of channel response when the channel sensor is exposed to a radiological source of known activity. A SOURCE CHECK is performed on the gas decay tank noble gas activity monitor prior to each release to ensure that the radiation monitor (RM-22) is capable of accurate detection and measurement. The surveillance frequency ensures that the radiation monitor is functioning prior to a release and is based on the low probability of an uncontrolled release.

SR 39.4.5 A SOURCE CHECK is performed on the plant vent system noble gas activity monitors (RM-14 and RM-14R) every 31 days as a routine check of radiation monitor functionality. The surveillance frequency is based on the low probability of an uncontrolled release.

SR 39.4.6 and SR 39.4.7 A CHANNEL CALIBRATION shall be the adjustment, as necessary, of the channel output such that it responds within the necessary range and accuracy to known values of the parameter that the channel monitors.

The CHANNEL CALIBRATION shall encompass all devices in the channel required for channel OPERABILITY. CHANNEL CALIBRATION is performed on the gas decay tank noble gas activity monitor (RM-22), the plant vent system noble gas activity monitors (RM-14 and RM-14R), the plant vent system flow rate monitor (FR-12) and the iodine sampler flow transmitters (FT-813 and FT-814). These surveillances are performed every 18 months, which has been shown to be acceptable by experience.

SR 39.4.8, SR 39.4.9, and SR 39.4.10 A CHANNEL FUNCTIONAL TEST is performed on the plant vent flow recorder and its associated flow transmitters (FR-12 fed from FT-12 and FT-12R), the iodine sampler flow transmitters (FT-813 and FT-814), the plant vent system noble gas activity monitors (RM-14 and RM-14R), and the gas decay tank noble gas activity monitor (RM-22) every 92 days to ensure channel OPERABILITY. The frequency is based on operator experience and the low probability of channel inoperability concurrent with a DBA.

REFERENCES CY2.ID1, Radioactive Effluent Controls Program.

CAP A-8, Offsite Dose Calculations.

DCPP Technical Specifications, Sections 3.3.6, 5.4.1, 5.5.1, and 5.6.2.

FSAR, Chapter 11, Radioactive Waste Management.

FSAR, Chapter 15, Accident Analyses.

DCM S-39, Radiation Monitoring System.

DCM T-24, Design Criteria for DCPP Instrumentation and Controls.

12/18/2002 Effective Date Diablo Canyon Units 1 & 2 Rev. 8 2EH1VW08.DOA 11

SRO QUESTION 99 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 3 Group # _____ 4 K/A # G2.4.41 Importance 4.1 Proposed Question:

A radiological emergency event is in progress. The release could result in exceeding EPA PAGs near the site boundary.

Which of the following Emergency Event Classifications would be appropriate?

A. Unusual Event B. Alert C. Site Area Emergency D. General Emergency Proposed Answer:

C. Site Area Emergency Explanation:

C correct, definition of SAE:

Events which are in progress or have occurred involving actual or likely major failures of plant functions needed for protection of the public.

Reflects conditions where there is a clear potential for radioactive release.

Radioactive releases or their potential may exceed EPA PAGs, but only near the site boundary Technical Reference(s): LEP-2, Emergency Plan Procedures Proposed references to be provided to applicants during examination: none Learning Objective: 8535 - State the definition of the four emergency event classifications Question Source: Bank # E-36020 sro tier 3 group 4_099.doc

Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge X Comprehension or Analysis ____

10 CFR Part 55 Content: 55.41 _____

55.43 43.4 Comments:

K/A: G2.4.41 - Knowledge of the emergency action level thresholds and classifications.

sro tier 3 group 4_099.doc

LESSON: EMERGENCY PLAN PROCEDURES LESSON NO.: LEP-2 EP G-1, Emer. Classification and E-Plan Activation, Continued 15 Minute Time

The time frame for initial notification starts after the SM/ISEC:

Frame analyzes the event or conditions, and Obj 7 determines that event classification criteria are met.

This gives the SM/ISEC a reasonable period of time (15 minutes per NRC guidance and management expectations) to assess and classify an emergency condition once indications are available to the Control Room operators that an EAL has been exceeded.

Note that in the previous discussions there are two-15 minute times being discussed:

Goal: to have classification made within 15 minutes of event initiation.

Requirement: to have notifications performed within 15 minutes of classification.

Therefore, the time between event initiation and notification completion can be up to 30 minutes[TRP5].

Follow-up Follow-up notifications to the county and state should be made approximately Notifications every 45 minutes, even if the event classification is unchanged.

Obj 5, 6

Keeps everyone up-to-date of changing plant conditions

Notification still required within 15 minutes if event classification changes Emergency DCPP (and the commercial nuclear industry) uses four standard emergency Classifications classifications for categorizing events. They are (least to most severe):

Notification of Unusual Event (NUE) or Unusual Event

Alert

Site Area Emergency (SAE)

General Emergency (GE)

Unusual Event

Off-normal conditions are in progress OR have occurred which:

(NUE) Indicate a potential degradation of level of plant safety if proper action Obj 8 is not taken.

OR If circumstances beyond the control of operating staff, making the situation more serious from a safety standpoint.

No releases of radioactive material requiring off-site response or monitoring are expected.

Continued on next page LEP2X.DOC PAGE 11 OF 43 REV. 8

LESSON: EMERGENCY PLAN PROCEDURES LESSON NO.: LEP-2 EP G-1, Emer. Classification and E-Plan Activation, Continued Alert Obj 8 Events in progress or having occurred, involving an actual or potentially substantial degradation of the plant safety level.

Any radioactive releases that may occur (greater than Technical Specification limits) are expected to be limited to a small fraction of EPA Protective Action Guides (PAGs) at the site boundary.

The lowest classification level where off-site emergency response is anticipated.

It is expected that for most Alerts, the plant will be placed in a safe condition and releases, if any, will be minimal.

Site Area Emergency Events which are in progress or have occurred involving actual or likely (SAE) major failures of plant functions needed for protection of the public.

Obj 8

Reflects conditions where there is a clear potential for radioactive release.

Radioactive releases or their potential may exceed EPA PAGs, but only near the site boundary.

Because the possible release is significant, care must be taken in alerting offsite authorities to distinguish whether the release is merely potential, likely, or actually occurring.

A core meltdown situation is NOT indicated based on current information.

General Events are in progress OR have occurred which indicate actual or imminent Emergency substantial core damage with potential for containment loss.

(GE)

Radioactive releases can be expected to exceed EPA PAG off-site exposure Obj 8 levels.

Command and Command and control of an emergency begins with the ISEC and, if required, Control is transferred to the SEC and then to the Recovery Manager (RM).

Hierarchy Only the general responsibilities of these three positions, as they pertain to EP G-1, are listed below.

Specific duties and responsibilities are discussed later.

Continued on next page LEP2X.DOC PAGE 11 OF 43 REV. 8

1 E36020 Points: 1.00 Multiple Choice Which one of the following emergency event classification levels assumes that dose rates at the Site Boundary due to a radioactive release are well below Emergency Action Plan (EAP) Protection Action Guidelines (PAGs)?

A. Notification of Unusual Event B. Alert C. Site Area Emergency D. General Emergency Answer: B ASSOCIATED INFORMATION:

Associated objective(s):

8535 State the definition of the four emergency event classifications Reference Id: E36020 Must appear: No Status: Active User Text:

User Number 1: 0.00 User Number 2: 0.00 Difficulty: 2.00 Time to complete: 2 Topic: LEP2 - Definition of events Cross

Reference:

ECP Obj. 7.1 Comment: From O/E database DLH4 6/5/00

SRO QUESTION 100 Question Worksheet Examination Outline Cross-

Reference:

Level RO SRO Tier # _____ 3 Group # _____ 4 K/A # G2.4.45 Importance 3.6 Proposed Question:

A Unit 1 shutdown from full power is in progress at 1%/min.

The following events occur:

PK15-22 alarms on Unit 2 due to Alarm Input 1531- Main Annun Unit 1 Train A and B Failure.

On Unit 1 ALL annunciator windows are blank, and the alarm typewriter and CRT have NOT responded for 18 minutes.

The PPC and SPDS are not responding What Classification or notification is required to be made?

A. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Non-emergency report.

B. Unusual Event.

C. Alert.

D. Site Area Emergency.

Proposed Answer:

B. Unusual Event.

Explanation:

A incorrect, threshold for emergency classification exceeded.

B correct, UE 16.

C incorrect, no major transient in progress and PPC and SPDS not responding.

D incorrect, no major transient in progress.

Technical Reference(s):

EP G-1 Attachment 7.1 sro tier 3 group 4_100.doc

Proposed references to be provided to applicants during examination:

EP G-1 Attachment 7.1 Learning Objective: 5464 - Explain the classification of emergency conditions Question Source:

Modified Bank # DCPP B-0621 Question History: Last NRC Exam N/A Question Cognitive Level:

Memory or Fundamental Knowledge ____

Comprehension or Analysis X 10 CFR Part 55 Content: 55.41 _____

55.43 43.5 Comments:

K/A: G2.4.45 - Ability to prioritize and interpret the significance of each annunciator or alarm.

sro tier 3 group 4_100.doc

07/28/04 Page 6 of 10 EP G-1 (UNITS 1 AND 2)

ATTACHMENT 7.1 TITLE: Emergency Action Level Classification Chart UNUSUAL EVENT ALERT SITE AREA EMERGENCY GENERAL EMERGENCY VII. 12. Loss of all off-site power for 13. Loss of all off-site power for 6. Loss of all on-site AND off-site AC See General Emergency LOSS OF greater than 15 minutes AND at greater than 15 minutes AND power for > 15 minutes Condition #5 under LOSS OF POWER OR least 2 D/Gs are supplying their only 1 D/G is supplying its vital (Modes 1-4). ENGINEERED SAFETY ALARMS OR vital busses (Modes 1-4). bus (Modes 1-4). FEATURE.

ASSESSMENT OR COMMUNICATI 13. Loss of all off-site power for 14. Loss of all off-site and on-site ONS greater than 15 minutes AND at AC power for greater than least 1 D/G is supplying its vital 15 minutes in Modes 5 or 6.

bus (Modes 5 and 6).

14. Loss of all vital DC power as 15. Loss of all vital DC power as 7. Loss of all vital DC power as indicated by DC Bus 11(21), indicated by DC Bus 11(21), 12 indicated by DC Bus 11 (21), 12 12(22), and 13(23) undervoltage (22) and 13 (23) undervoltage (22) and 13 (23) undervoltage for >

for > 15 minutes (Modes 5-and 6) for < 15 minutes (Modes 1-4). 15 minutes (Modes 1-4).

15. Loss of assessment capabilities as indicated by a total loss of SPDS in the Control Room AND simultaneous loss of all displays for any "Accident Monitoring" variable in Tech Spec Table 3.3.3-1 for > 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months while in Modes 1, 2 or 3.

16. Main Control Room Annunciators 16. Main Control Room 8. Main Control Room Annunciators PKs 1 through 5 AND display Annunciators PKs 1 through 5 PKs 1 through 5 AND display capabilities AND the seismically AND display capabilities AND capabilities AND the seismically qualified annunciator display all do the seismically qualified qualified annunciator display all do not respond to an alarm condition annunciator display all do not not respond to an alarm condition in Modes 1-4 for over 15 minutes. respond to an alarm condition in in MODES 1-4 for over 15 minutes MODES 1-4 for over 15 minutes AND AND the plant is in a significant transient the plant is in a significant AND backup, nonannunciating transient (plant trip, SI, or systems are not available (PPC, generator runback >25 Mw/min), SPDS).

nonannunciating systems available.

NOTE: SIMULTANEOUS EALS THAT INCREASE THE PROBABILITY OF RELEASE REQUIRE ESCALATION OF THE CLASSIFICATION TO ONE LEVEL ABOVE THE HIGHER EAL.

ML050890447

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