ML090710074

Initial Written Retake Examination, 2009-301 Draft RO Written Exam

ML090710074
Person / Time
Site:	North Anna
Issue date:	02/10/2009
From:	NRC/RGN-II
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Download: ML090710074 (553)

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{{#Wiki_filter:QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

1. OOl-AK1.04 OOlINEW/1HI3IROINAPS/8/20/20081 Given the following conditions:

• RCS TAVE is 572°F.

  *   "D" bank rods are at 190 steps.

• Rod control is in AUTOMATIC.

Median/Hi TAVE input to automatic rod control fails LOW. Which ONE of the following identifies the Immediate Operator Action required, and the effect of the transient on Shutdown Margin? A. Verify redundant instrument channel indication NORMAL; Shutdown Margin has increased. B. Verify redundant instrument channel indication NORMAL; Shutdown Margin has not changed. C. Place Rods in MANUAL; Shutdown Margin has increased. O~ Place Rods in MANUAL; Shutdown Margin has not changed. Feedback

a. Incorrect but plausible since this is an immediate operator action (lOA) of AP-3 and would be correct if the failure were Tref vice tave; second part is plausible since rods have moved out.

b. Incorrect. First part is incorrect but plausible as discussed above; second part is correct there is no change in core reactivity so despite the fact that rods are further out SOM is still the same.

c. Incorrect. First part is correct as this is an lOA of AP-1.1. Second part is incorrect but plausible as discussed in distractor a ..

d. Correct. first part is the correct lOA for the given plant conditions; second part is also correct as discussed in distractor b.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Continuous Rod Withdrawal Knowledge of the operational implications of the following concepts as they apply to Continuous Rod Withdrawal: Effect of continuous rod withdrawal on insertion limits and 80M (CFR 41.8 /41.10/45.3) Tier: 1 Group: 2 Importance Rating: 3.7/3.9 Technical

Reference:

Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info:

rrl ==N=U=M=B=E=R==;:========P=R=O=C=E=D=U=R=E=T='=TL=E========Tj==R=,E~~~==il ll II ..... 1-AP-l.1 I CONTI~JUOIJS UNCONTROLLED ROD ~J!OTIO~~ 1 8 PAGE:! 2of5 II i!

  ---.. -.. = : , : : =                                                         . --.--------..-.....-.---.        = - - - - . - - . ___ i.J
                                                                              ~---------------------

ACTION! EXPECTED RESPONSE RESPONSE NOT OBTAINED

                                                           &-A-        IJA pS;          [ '"J               J ~ ~>t k c)        cfiA-1  1_   PUT CONTROL ROD BAN K        C;;::::.-                                            o peA/cJo r-SELECTOR SWITCH TO                        VVI.., 'VV~d, c'-.f-~                                     G.""- cl-ialV\.

MANUAL 2 J_ VERIFY ROD MOTION- o GO TO i-E-O, REACTOR TRIP OR SAFETY' STOPPED INJECTION.

3. VERIFY 1-RC-TI-140BA MEDIAN/HI o Initiate actions of Annunciator Panel "8" A-7 TAVG - NORMAL MEDIAN/HI TAVG < > TREF DEVIATION, while continuing with this procedure.

NOTE: When the Unit is in Mode 1 or Mode 2 with Keff greater than or equal to 1.0, then shutdown margin is restored when the control rods are above the LO-LO insertion limit.

4. VERIFY SHUTDOWN MARGIN: Do the following in accordance with Tech Spec 3.1.6:

o . Control Rods - ABOVE lO-LO o a) Initiate boration within one hour until the INSERTION LIMIT required shutdown margin is restored. AND b) Restore Control Rods to above the Insertion o . Control Rods'- ABOVE Limits within two hours by: INSERTION LIMIT OF STATION CURVE 1-SC-1.7 OR o . Manually withdrawing Control Rods COlR OR o -Manually reducing Turbine load using t-OP-2.2, Unit Power Operation from Mode 1 to Mode 2 I ~------------------------~-------- ___J

rr===N=U=M=B=E=R==~================P=R=O=C=E=D=U=R=E=T=IT=L=E================f=~R~E~~~!Si~t~=711 LOSS OF VITAL INSTRUMENTATION 23 1-------1 JI 1-AP-3 PAGE 2 of 19 II "I ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 1 ]_ VERIFY REDUNDANT o IF unable to determine Reactor is in a safe INSTRUMENT CHANNEL operating condition, THEN GO TO 1-E-O, INDICATION - NORMAL REACTOR TRIP OR SAFETY INJECTION, 2 J_ VERIFY STEAM GENERATOR ~ Do the following: LEVEL CONTROLLING , CHANNELS - NORMAL: (' a) Place the associated valves in MANUAL: o

• Steam Flow o
• Main Feed Reg Valves o
• Feed Flow o
• Main Feed Reg Bypass Valves o
• Steam Generator Level Ch III o b) Control Steam Generator level.

o

• Steam Pressure 3 ] __ VERIFY TURBINE FIRST STAGE o IF the controlling channel failed, THEN pla.ce PRESSURE INDICATIONS - Control Rod Mode Selector switch in MANUAL.

NORMAL ( 41_ VERIFY PRESSURIZER LEVEL IF any selected channel failed, THEN do the INDICATIONS - NORMAL following: o a) Place 1-CH-FCV-1122, Charging Flow Cont.rol Valve, in MANUAl. o b) Control Pressurizer level at program,

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) T -avg/T -ref Deviation Alarm 1.1 Objective U 11060 List the following information associated with the T-AVG/T-REF DEVIATION annunciator response (1B-A7).

• Purpose of the procedure
• Modes of applicability
• Entry conditions
• Immediate operator actions 1.1 Content

1. The purpose of the annunciator response for T-AVG/T-REF DEVIATION alarm (1 B-A7) is to provide information on the possible reasons for, and the response to Tavg differing from Tref by more than 5°F.

2. The alarm response is applicable in modes 1, 2 and 3.

3. The entry conditions for the procedure:

3.1. Operator attention/action is required if it should illuminate in modes 1, 2 or 3. 3.2. In mode 4 and below, this is an expected alarm and will actuate as soon as Tavg decreases to less than 542°F (5°F below no-load Tavg).

4. The AR itself does not have any immediate operator actions.

4.1. The operator should perform a review of plant conditions to determine the cause. 4.2. Plant conditions may require the performance of AP-3 or AP-1.1 immediate operator actions. 4.3. Blindly placing the control rods in manual during a turbine runback would override a valid automatic safety function. REACTOR OPERATOR Page 6 of 158 Revision 30, 11/06/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) Continuous Uncontrolled Rod Motion Topic 2.t AP.l.tPurpose, ApplicabiHty"cln9 Enfryqonditions 2.1 Objective U 11022 List the following information associated with 1-AP-1.1, "Continuous Uncontrolled Rod Motion."

• Purpose of the procedure
• Modes of applicability
• Entry conditions
• Immediate operator actions 2.1 Content

1. AP-1.1 provides guidance for the operator during continuous uncontrolled rod motion.

2. This procedure is applicable in modes 1 and 2 or any time the reactor trip breakers are closed and rod withdrawal is possible.

3. AP-1.1 should be entered when there is control rod movement concurrent with any or all of the following conditions:

3.1. Undesired Tavg change 3.2. Undesired power change 3.3. Rod Insertion Limit alarms(s) 3.4. Median/high Tavg <> T ref alarm.

4. AP-1.1 contains the following immediate operator actions:

4.1. Put the control rod bank selector switch to MANUAL 4.2. Verify rod motion stopped. 4.2.1.The RNO is to go to E-O. REACTOR OPERATOR Page 8 of 158 Revision 30, 11/06/2008

STUDENT GUIDE FOR INTEGRATED PLANT OPERATIONS (98) 1.2.2.The other is from the RWST, through the charging pump, to the RCS. 1.3. Since a Charging Pump must be available for both flow paths, the first check that is done is to show at least one operable pump is available, along with its suction and discharge valves. 15.5 Objective U 12545 Explain the purpose of a shutdown margin calculation. 15.5 Content

1. A shutdown margin calculation is performed to verify that the core is or can be shutdown by at least 1.77% ~k1k.

1.1. Considerations include RCS boron concentration, control rod position, RCS average temperature, fuel burnup, xenon concentration, and Samarium concentration. 1.2. The calculation assumes that all full-length rods are fully inserted except for the single rod of highest reactivity worth, which is assumed to be fully withdrawn. Instructor shows Shutdown Margin Hand Calculations Powerpoint. Have students perform practice calculations using the following data. PT-10A Unit 1 Cycle 19 - #1

• North Anna Unit 1 has been at 100% power for 200 hrs.
• Core age is 2000 MWD/MTU.
• RCS Boron is 1480 ppm.
• All rods are full out.
• A reactor trip occurs.

REACTOR OPERATOR Page 135 of 142 Revision 16, 08/20/2008

STUDENT GUIDE FOR INTEGRATED PLANT OPERATIONS (98)

• Two rods are stuck out.
• All other rods fully insert.
• It is desired to cooldown to 350 F.

How r1luch boration is the Gooldown can comrnence? creclit for the Xenon in core at NOTE: Solutions to Calculation #1 are on the attached pages of 1-PT-10A. REACTOR OPERATOR Page 136 of 142 Revision 16, 08/20/2008

STUDENT GUIDE FOR INTEGRATED PLANT OPERATIONS (98) PT-10A Unit 1 Cycle 19 - #2

• North Anna Unit 1 has been at 100% power for 200 hrs.
• Core age is 3000 MWD/MTU.
• RCS Boron is 1420 ppm.
• All rods are full out.
• A reactor trip occurs.
• Three rods are stuck out.
• All other rods fully insert.
• It is desired to cooldown to 350 0 F.

How much boration is required before the cooldown can commence? [Take credit for the Xenon in the core at the time of the trip.] NOTE: Solutions to Calculation #2 are on the attached pages of 1-PT-10A. PT-10A Unit 1 Cycle 19 - #3

• North Anna Unit 1 has been at 100% power for 200 hrs.
• Core age is 3500 MWD/MTU.
• RCS Boron is 1400 ppm.
• All rods are full out.
• A reactor trip occurs.
• All rods fully insert.

REACTOR OPERATOR Page 137 of 142 Revision 16, 08/20/2008

STUDENT GUIDE FOR INTEGRATED PLANT OPERATIONS (98)

• It is desired to cooldown to 350 0 F.

How much boration is required before the cooldown can commence? [Take credit for the Xenon in the core at the time of the trip.] NOTE: Solutions to Calculation #3 are on the attached pages of 1-PT-10A. Topic'15.6Shotdo'Nn MargioConcepfs 15.6 Objective U 14042 Explain the following concepts associated with shutdown margin.

• Definition of shutdown margin
• How shutdown margin is affected by a given plant condition
• Actions required if adequate shutdown margin does not exist 15.6 Content

1. SDM shall be the instantaneous amount of reactivity by which the reactor is subcritical or would be subcritical from its present condition assuming:

1.1. All rod cluster control assemblies (RCCAs) are fully inserted except for the single RCCA of highest reactivity worth, which is assumed to be fully withdrawn. With any RCCA not capable of being fully inserted, the reactivity worth of the RCCA must be accounted for in the determination of SDM; and 1.2. In MODES 1 and 2, the fuel and moderator temperatures are changed to the nominal zero power design level. (ITS definition)

2. Changes in plant conditions can either increase or decrease the shutdown margin.

REACTOR OPERATOR Page 138 of 142 Revision 16, 08/20/2008

STUDENT GUIDE FOR INTEGRATED PLANT OPERATIONS (98) 2.1. The following plant conditions will increase the SID margin 2.1.1.lncrease in the boron concentration 2.1.2.lncrease in fission product poisons 2.1.3.lncrease in RCS temperature 2.2. The following plant conditions will decrease the SID margin 2.2.1. Decrease in the boron concentration 2.2.2. Decrease in fission product poisons 2.2.3.Decrease in RCS temperature

3. ITS requires SDM to be within the limits provided in the COLR.

3.1. If the SDM requirements are not met, boration must be initiated promptly. 3.2. A Completion Time of 15 minutes is adequate for an operator to correctly align and start the required systems and components. 3.3. It is assumed that boration will be continued until the SDM requirements are met. (T.S. 3.1.1 Bases). REACTOR OPERATOR Page 139 of 142 Revision 16, 08/20/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

2. 002-Kl.ll 002IBANKINAPSIHI2IROINAPS//

Given the following conditions:

• Unit 1 is at 25% power and slowly ramping up following a refueling outage.
• The "8" Condensate Pump and "8" Main Feedwater Pump are both tagged out.
• Power is lost to the "8" Station Service 8us.

As a result of this transient, the OATC should initially expect to see level in the "8" SG _ _ _ __ and level in the "A" and "C" SGs (Assume no operator action) A. increase; increase B. increase; decrease C~ decrease; increase D. decrease; decrease Feedback

a. Incorrect but plausible since candidate may assume since heat input is reduced to 'B' SG it will over feed; second part is correct since the unaffected SGs will swell as a result of picking up load.

b. Incorrect. First part is plausible as discussed above; second part incorrect but plausible since steam will increase above feed on these SGs but the affect of swell is the overriding contributor to the level response.

c. Correct. As discussed the reduction in heat input to 'B' SG will cause it to shrink while increase demand on unaffected SGs causes them to swell.

d. Incorrect. First part is correct as discussed above; second part is incorrect but plausible as discussed in Distractor b.

QUESTIONS REPORT ( for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Reactor Coolant System (RCS) Knowledge of the physical connections and/or cause-effect relationships between the RCS and the following systems: S/GS, feedwater systems (CFR: 41.2 to 41.9 145.7 to 45.8) Tier: 2 Group: 2 Importance Rating: 4.1/4.2 Technical

Reference:

Lesson Plan Reactor Coolant System Proposed references to be provided to applicants during examination: None Learning Objective: Question History: bank additional info:

INSTRUCTOR GUIDE FOR REACTOR COOLANT SYSTEM (38) ( ,~ Integrated Plant Operations 11.1 Objective U 3534 Given the reactor coolant pump #1 seal differential pressure, determine the permissible #1 seal leakoff flow rate for starting a reactor coolant pump (1-0P-5.2). 11.1 Content Refer to 1-0P-5.2 applicable attachments.

1. The operating limits for #1 seal leakoff flow rate and delta-p are determined as follows:

1.1. For RCP startup, #1 sealleakoff flow must be at least 0.2 gpm and delta-p must be at least 200 psid. 1.2. For continuous pump operation, the allowable #1 seal leakoff flow rate depends upon the delta-p (e.g. - If seal delta-p is 1000 psid, the minimum leakoff flow rate is 0.5 gpm). 1.2.1.ln all cases, for continuous pump operation, the minimum and maximum allowable sealleakoff flow rates are 0.8 gpm and 5.9 gpm, respectively. 11.2 Objective U 12002 Given a set of plant conditions, evaluate Reactor Coolant System operations in light of the following issues.

• Effect of a failure, malfunction, or loss of a related system or component on this system
• Effect of a failure, malfunction, or loss of components in this system on related systems
• Expected plant or system response based on reactor coolant component interlocks or design features REACTOR OPERATOR Page 111 of 113 Revision 8, 07/15/2008

INSTRUCTOR GUIDE FOR REACTOR COOLANT SYSTEM (38)

• Impact on the technical specifications
• Response if limits or setpoints associated with this system or its components have been exceeded
• Proper operator response to the condition as stated 11.2 Content
• This objective has "NO" content.
• Integrated system knowledge will be required to answer any questions linked to this objective.

Summary This section is under development. ( REACTOR OPERATOR Page 112 of 113 Revision 8, 07/15/2008

1 10: 5737 Points:**1.00 Assume that, while the plant is operating at 20% power, the "8" reactor coolant pump trips and causes a transient in the "8" steam generator. As a result of the "8" reactor coolant pump trip, "A" and "C" steam generator steam flow would , and "A" and "C" steam generator level would _ _ _ __ A. increase; increase

8. increase; decrease C. decrease; increase D. decrease; decrease Answer: A Question 1 Info Question Type: Multiple Choice Status: Active Always select on test? No Authorized for practice? No Points: 1.00 Time to Complete: 0 Difficulty: 0.00 System ID: 25509 User-Defined ID: 5737 Cross Reference Number: NCRODP-26 Topic: 5737 : RCP trip effects Num Field 1:

Num Field 2: Text Field: 003000 Comments: Associated objective(s): Given a set of plant conditions, evaluate Reactor Coolant System operations in light of the following issues.

• Effect of a failure, malfunction, or loss of a related system or component on this system
• Effect of a failure, malfunction, or loss of components in this system on related systems
• Expected plant or system response based on reactor coolant component interlocks or design features
• Impact on the technical specifications
• Response if limits or setpoints associated with this system or its components have been exceeded
• Proper operator response to the condition as stated VA NAPS OPS Page: 1 of 1 01 December 2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

3. 003-A2.02 003INEW//L/2IROINAPSII With Unit 1 at 100% power, annunciator A-E5, Rep 1A VIBRATION ALERT/DANGER, is received.

The Backboards Operator reports the following:

  *   "A" Rep Seismic vibration = 7 mils.
  *   "A" Rep Proximity vibration = 7 mils.

Which ONE of the following identifies the status of "A" Rep vibration, and the actions required by AR-A-E5, Rep 1A VIBRATION ALERT/DANGER? A. Seismic vibration is above the ALERT level; Increase frequency of monitoring Rep vibration and consider shutting down "A" Rep if increasing trend continues. B~ Seismic vibration is above the DANGER level; Trip the reactor and perform the immediate operator actions of 1-E-O, Reactor Trip or Safety Injection, then stop "A" Rep. C. Proximity vibration is above the ALERT level; Increase frequency of monitoring Rep vibration and consider shutting down "A" Rep if increasing trend continues. D. Proximity vibration is above the DANGER level; Trip the reactor and perform the immediate operator actions of 1-E-O, Reactor Trip or Safety Injection, then stop "A" Rep. Feedback

a. Incorrect. Plausible if candidate is not familiar with the annunciator response procedure, or does not know the thresholds where action is required.

b. Correct. Limit has been exceeded and this is the required action.

c. Incorrect. Plausible if candidate reverses action for seismic vs. proximaty. Would be true for a value of 15 mils or greater, but 7 is well below the alert and there is no action required for this condition.

d. Incorrect. Plausrble if candidate reverses action for seismic vs. proximaty. Action is correct but, threshold for proximaty is 20 mils not 7 as given.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Reactor Coolant Pump System (RCPS) 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: Conditions which exist for an abnormal shutdown of an RCP in comparison to a normal shutdown of an RCP (CFR: 41.5/43.5/45.3/45/13) Tier: 2 Group: 1 Importance Rating: 3.7/3.9 Technical

Reference:

1-AR-A-E5 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info:

VIRGINIA POWER 1-EI-CB-21A ANNUNCIATOR E5 1-AR-A-E5 NORTH ANNA POWER STATION REV. 5 APPROVAL: ON FILE Effective Date:10/01/08 RCP 1A Seismic:Danger 5 mils VIBRATION Alert 3 mils ALERT/ Proximity:Danger 20 mils DANGER Alert 15 mils 1.0 Probable Cause 1.1 High OR low lube oil level. 1.2 Damage-to RCP seal. 1.3 High bearing temperature. 1.4 Detector Failure. CAUTION: *Extremely high RCP vibrations may over range the vibration sensor input causing the indications to fail high or low. Tripping the affected RCP should be considered upon receipt of a vibration alarm followed by indications that are off-scale high or low.

          *The Reactor shall NOT remain critical with less than three RCPs running-.--
          *IF RCP is required to be tripped AND Reactor is critical, THEN a Reactor Trip MUST be performed before securing the affected RCP.

NOTE: More than one indication should be used to verify that the vibration condition is valid, since the alarm could be caused by a detector failure. ( .0 Operator Action ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 2.1 CHECK SEISMIC VIBRATION - Do the following: LESS THAN 5 MILS

a. Use alternate indications to ensure a valid high vibration condition exists:

Other Seismic channel - ELEVATED OR IN ALARM Proximity Vibration - ELEVATED Bearing Temperatures - ABNORMAL Motor Amperage - ABNORMAL CC Flows - ABNORMAL Seal Injection AND Leak off Flows - ABNORMAL Vibration Indication - OFF SCALE HIGH OR LOW

b. IF valid indication of high vibration exists, THEN do the following:

1. GO TO 1-E-0, Reactor Trip or Safety Injection, while continuing with this procedure.

2. WHEN Reactor is verified shutdown, THEN stop 1-RC-P-1A, A Reactor Coolant Pump.

NOTE: TRM 3.4.6 requires an ultrasonic examination of the associated RCP Flow straightener, if RCP proximit vibration exceeds 20 mils. 2.2 CHECK PROXIMITY VIBRATION - Do the following: LESS THAN 20 MI./"

a. Use alternate indications to

(\ \¥"~t~ ensure a valid high vibration

                     / . Vl                  condition exists:
                    ~                          Other Proximity Channel -

ELEVATED OR IN ALARM Seismic Vibration - ELEVATED Bearing Temperatures - ABNORMAL Motor Amperage - ABNORMAL CC Flows - ABNORMAL Seal Injection AND Leak off Flows - ABNORMAL Vibration Indication - OFF SCALE HIGH OR LOW

b. IF valid indication of high Vibration exists, THEN do the following:

1. GO TO 1-E-0, Reactor Trip or Safety Injection, while continuing with this procedure.

2. WHEN Reactor is verified shutdown, THEN stop 1-RC-P-IA, A Reactor Coolant Pump.

2.3 CHECK SEISMIC VIBRATION - Do the following: LESS THAN 3 MILS a. Increase vibration surveillance.

b. Check lube oil level - NORMAL.

c. Check seals - NOT FAILED.

d. Check bearing temperatures

                                             - NORMAL.

2.4

                                   \

CHECK PROXIMITY VIBRATION -

e. Inform Operations Maintenance Advisor.

Do the following: LESS THAN 15 MILS a. Increase vibration surveillance.

b. Check lube oil level - NORMAL.

c. Check seals - NOT FAILED.

d. Check bearing temperatures

                                             - NORMAL.

e. Inform Operations Maintenance Advisor.

f. Notify Predictive Analysis to inform the insurance company.

2.5 RESET ALARM AND. VERIFY Return to Step 2.1. ALL VIBRATIONS - NORMAL

3.0 References 3.1 UFSAR 3.2 Westinghouse RCP tech manual. 3.3 11715-ESK-I0AFF. 3.4 TRM 3.4.6, ASME Code Class I, 2, and 3 Components 3.5 CTS 02-95-2127-003, Tech Spec Review 3.6 SER 2-97, Reactor Coolant Pump Damage from a Separated Component 3.7 CA080365, CRI05211, Revise RCP ARs for Detector Failure 4.0 Actuation 4.1 RCP frame and shaft vibration detectors.

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) Reactor Coolant Pump Malfunctions 9.1 Objective U 11099 List the following information associated with the RCP 1A1B/C VIBRATION ALERTIDANGER annunciator response (1A-E5, 1A-E6, 1A-E7).

• Purpose of the procedure
• Modes of applicability
• Entry conditions
• Immediate operator actions 9.1 Content

1. These annunciator responses provide guidance to respond to excessive Rep frame or shaft vibration.

1.1. The alarm is actuated by one of two probes and annunciates for proximity alert (15 mils-shaft), proximity danger (20 mils-shaft), seismic alert (3 mils-frame), or seismic danger (5 mils-frame). 1.2. If the vibrations are greater than 5 mils seismic or 20 mils proximity, then the reactor is tripped, the affected RCP is stopped, and 1-E-0 is entered. 1.3. If vibrations are greater than 3 mils seismic or 15 mils proximity then vibration surveillance is increased, the lube oil level, seal package, and bearing temperatures are checked to be normal and the Operations Maintenance Coordinator is notified. 1.4. The operator is cautioned that extremely high RCP vibrations may over-range the vibration sensor input and cause the indications to fail high or low. 1.4.1.lf an alarm is received followed by off-scale high or low indications, the crew should consider tripping the RCP.

2. Applicable in modes 1 through 5 REACTOR OPERATOR Page 49 of 158 Revision 30, 11/06/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91)

3. The annunciator response procedure is entered when the associated annunciator is actuated.

3.1. Probable causes for RCP vibration include high or low lube oil level, damage to the RCP seal, and high bearing temperature.

4. There are no immediate operator actions connected with these annunciator responses.

4.1. Confirmed indication of extremely high vibrations may warrant tripping the reactor in order to stop the affected RCP. Topic~.2.lnf6rl11ation .Associated *with AP-33.1 9.2 Objective U 11100 List the following information associated with 1-AP-33.1, "Reactor Coolant Pump Seal Failure,"

• Purpose of the procedure
• Modes of applicability
• Entry conditions 9.2 Content

1. The purpose of AP-33.1 is to provide guidance for the operator in the event of a reactor coolant pump seal failure.

2. AP-33.1 is applicable in modes 1 through 5.

3. The procedure is entered when any of the following conditions exist:

3.1. Abnormal seal leakoff on 1-CH-FR-1154A is indicated. 3.2. RCP 1A-8-C SEAL LEAK HI FLOW annunciator C-G7 is lit. 3.3. RCP 1A-8-C SHAFT SEAL WATER LO delta P annunciator C-G5 is lit. 3.4. RCP 1A-8-C SEAL LEAK LO FLOW annunciator C-G8 is lit. 3.5. RCP 1A18/C STANDPIPE HI LEVEL annunciator C-G1/G2/G3 is lit. REACTOR OPERATOR Page 50 of 158 Revision 30, 11/06/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

4. 003-A3.02 004INEW//H/3IROIII As the RCS is cooled down from Hot Standby to Cold Shutdown, RCP seal injection flows will

_ _ _ _ _ _ _ _ , and running RCP motor current will _ _ _ _ __ A. decrease; increase B'! increase; increase C. increase; remain the same D. decrease; remain the same Feedback

a. Incorrect. Plausible since candidate may not properly relate the effect of system pressure changes with seal injection flow rate; second part is correct, since more work is done pumping denser water the pump will draw more current.

b. Correct. First part is true the change in pressure causes an increase in flow rate; second part is correct as discussed above.

c. Incorrect. First part correct as discussed in Distractor b; second part incorrect but plausible, since other pumps have control valves that vary flow rate and RCPs do not, student may associated changes in pump motor current with these type pumps (e. g. MFPs) but not RCPs.

d. Incorrect. First part is incorrect but plausible as discussed in Distrasctor a; second part incorrect but plausible as discussed above.

Notes Reactor Coolant Pump System (RCPS) Ability to monitor automatic operation of the RCPS, including: Motor current (CFR: 41.7/45.5) Tier: 2 Group: 1 Importance Rating: 2.6/2.5 Technical

Reference:

Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info:

DOMINION 1-0P-3.2 North Anna Power Station Revision 69 Page 8 of 59 As RCS pressure is lowered, RCP Seal Injection flow will increase. Seal Injection flow is adjusted to maintain between 6 and 10 gpm to each RCP. In order to maintain maximum Letdown Purification, additional Letdown Orifice Isolation Valves are opened. This is done since the differential pressure between the RCS and VCT decreases as RCS pressure decreases. During plant heatup and cooldown, the temperature difference between the Pressurizer and the "C" loop Th leg is high due to the need to maintain sufficient pressure in the RCS to run RCPs. Under these conditions, there is a tendency for the water in the Pressurizer surge line to thermally stratify with the hotter Pressurizer water above the Loop water. Insurges can cause the stratified boundary layer to move up into the Pressurizer. Outsurges can cause the boundary layer to move down in the Pressurizer and Surge Line. Movement of the water can be sensed by the thermocouple on the Surge line. Caution must be exercised to prevent exceeding the TRM heatup rate limit of 100°FIhr and the TRM cooldown rate limit of200°FIhr. This is a real possibility in the bottom of the Pressurizer, when an insurge is followed by an outsurge. This can be avoided by establishing a continuous flow from the PRZR into the surge line by initiating PRZR heaters and spray with a stable or slowly decreasing PRZR level. FEED SGs USING CONDENSATE As stated earlier, steam pressure and steam flow decrease as T ave decreases. When Main Steam pressure is less than 500 psig, the Condensate Pumps are aligned to feed the SGs and the Main Feed Pumps are stopped. Operations Management determines if Load Shed should be removed from service. When RCS pressure lowers to 950 psig, the SI Accumulator Discharge MOV s are closed. Auxiliary Steam is transferred to Unit 2 or the Auxiliary Boilers and the cooldown is continued until the lowest Cold Leg temperature is between 325°F and 350°F. (

DOMINION 1-0P-3.2 North Anna Power Station Revision 69 Page 47 of 59 (Page 1 of 1) Attachment 2 Pressurizer Heatup I Cooldown Information (Reference 2.4.14) To prevent Pressurizer insurges and outsurges, establish a continuous flow from the Pressurizer into the Surge Line by initiating Pressurizer heaters and spray with a stable or slowly decreasing Pressurizer level. Pressurizer spray should be initiated slowly and maintained continuously during Res heatup AND cooldown evolutions. Minimizing the ~ T between the ReS hot leg and the Pressurizer will prevent violating the Pressurizer heatup and cooldown rates. This is accomplished by limiting the Pressurizer heatup (pressurization) during Res heatup evolutions and promptly reducing Pressurizer temperature (pressure) during Res cooldown evolutions. The ~ T is largest in Modes 4 and 5 with the ReS temperature low and the Pressurizer pressure high enough to allow Rep operation. Pressurizer level must be carefully controlled to prevent Pressurizer msurges and outsurges. The following is a list of conditions that will cause or require changes to charging and letdown flows and must be anticipated by the operator: DURING Cooldown: DURING Heatup: RCS cooldown shrink will cause a Pressurizer outsurge RCS heatup swell will cause a Pressurizer insurge RCS pressure reduction will increase seal injection flow RCS pressure increase will reduce seal injection flow Opening a letdown orifice during RCS cooldown Closing a letdown orifice during RCS heatup Securing RHR will remove a large amount of letdown Placing RHR letdown HCV in service flow Erratic operation of charging FCV Erratic operation of charging FCV Degas operations VCT Stripper level control Mixed Bed boration

DOMINION 1-0P-3.3 North Anna Power Station Revision 60 Page 47 of 49 (Page 1 of 1) Attachment 2 Pressurizer Heatup I Cool down Information (Reference 2.4.18) To prevent Pressurizer insurges and outsurges, establish a continuous flow from the Pressurizer into the Surge Line by initiating Pressurizer heaters and spray with a stable or slowly decreasing Pressurizer level. Pressurizer spray should be initiated slowly and maintained continuously during Res heatup AND cooldown evolutions. Minimizing the L1T between the ReS hot leg and the Pressurizer will prevent violating the Pressurizer heatup and cooldown rates. This is accomplished by limiting the Pressurizer heatup (pressurization) during Res heatup evolutions and promptly reducing Pressurizer temperature (pressure) during Res cooldown evolutions. The L1T is largest in Modes 4 and 5 with the Res temperature low and the Pressurizer pressure high enough to allow Rep operation. Pressurizer level must be carefully controlled to prevent Pressurizer insurges and outsurges. The following is a list of conditions that will cause or require changes to charging and letdown flows and must be anticipated by the operator: DURING Cooldown: DURING Heatup: RCS cooldown shrink will cause a Pressurizer outsurge RCS heatup swell will cause a Pressurizer insurge RCS pressure reduction will increase seal injection flow RCS pressure increase will reduce seal injection flow Opening a letdown orifice during RCS cooldown Closing a letdown orifice during RCS heatup Securing RHR will remove a large amount of letdown Placing RHR letdown HCV in service flow Erratic operation of charging FCV Erratic operation of charging FCV Degas operations VCT Stripper level control Mixed Bed boration

STUDENT GUIDE FOR CHEMICAL AND VOLUME CONTROL SYSTEM (41) Reactor Coolant Pump Seal Injection Subsystem Topic 6.1RCPSealfnjectiQI1 6.1 Objective U 358 Explain the following concepts associated with reactor coolant pump seal injection.

• How an increase or decrease in reactor coolant system pressure affects seal injection flow
• Why the seal injection throttle valves should be closed when starting the initial charging pump 6.1 Content

1. An increase in RCS pressure will cause seal injection flow to decrease due to increased backpressure on the seal injection line.

1.1. Conversely, a decrease in RCS pressure will cause seal injection flow to increase due to lower backpressure on the seal injection line.

2. Prior to starting the first charging pump, seal injection throttle valves should be closed to prevent a pressure surge on the RCP seals.

Topic6.2RCPSeal**lhjectiph**paramefers 6.2 Objective U 361 List the following information associated with reactor coolant pump seal injection.

• Means available in the auxiliary building to determine seal injection filter high differential pressure
• Normal flow rate for seal injection (1-0P-8.1)
• Technical specification limits associated with seal injection flow (TS-3.5.5)

REACTOR OPERATOR Page 73 of 86 Revision 10, 08/20/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

5. 004-K6.13 OOSINEWIIL/3IROINAPSII Given the following conditions:

• The OATC has established a 65 gpm dilution in accordance with 1-GOP-S.3.1, Placing the Blender in the Dilute Mode of Operation.
• The operator has adjusted the flow rate to the desired value, and matched the setpoint on the controller.

Shortly thereafter, the demand on controller 1-CH-FC-1114A, Primary Water to Blender Flow Controller, fails to 100%. Which ONE of the following identifies the response of the Blender? A. Annunciator B-D7, PG WATER TO BLENDER FLOW DEV, alarms as soon as the failure occurs; 1-CH-FCV-1114A, PG to Blender Flow Control Valve, automatically closes. B. Annunciator B-D7, PG WATER TO BLENDER FLOW DEV, alarms as soon as the failure occurs; 1-CH-FCV-1114B, Blender Makeup to VCT, automatically closes. C. Annunciator B-D7, PG WATER TO BLENDER FLOW DEV, alarms approximately 20 seconds after the failure occurs; 1-CH-FCV-1114A, PG to Blender Flow Control Valve, automatically closes. D~ Annunciator B-D7, PG WATER TO BLENDER FLOW DEV, alarms approximately 20 seconds after the failure occurs; 1-CH-FCV-1114B, Blender Makeup to VCT, automatically closes. Feedback

a. Incorrect. Plausible since the failure will create a deviation, the candidate who does not have detailed knowledge of the system may conclude that this response is logical; Second part is incorrect this valve will open because of the failure and only manual action would close it.

b. Incorrect. First part incorrect but plausible as discussed above; second part is correct this valve will automatically close becuase of the deviation.

c. Incorrect. First part is correct, the alarm only activates if the deviation is present for at least 20 seconds; second part incorrect but plausible as discussed above additionally similarity of nomenclature between alarm and valve tend to reinforce this distractor.

d. Correct. After approximately 20 second with a sustained flow deviation the annunciator will alarm and the subject valve will close concurrently.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Chemical and Volume Control System Knowledge of the effect of a loss or malfunction on the following CVCS components: Purpose and function of the borationldilution batch controller (CFR: 41.7/45.7) Tier: 2 Group: 1 Importance Rating: 3.1/3.3 Technical

Reference:

Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info:

VIRGINIA POWER l-EI-CB-21B ANNUNCIATOR D7 l-AR-B-D7 NORTH ANNA POWER STATION REV. 4 APPROVAL: ON FILE Effective Date: 09/10/08 ( PG WATER TO BLENDER +/- 10 GPM demand FLOW DEV after 20 sec TD NOTE: If in automatic, l-CH-FCV-1114B, BLENDER MAKEUP TO VCT, and l-CH-FCV-1113B, BLENDER MAKEUP TO CHG PP SUCTION HDR, will close when this alarm is received. 1.0 Probable Cause 1.1 Improper setting of pot for controller (l-CH-FC-1114A or l-CH-HFC-1114) 1.2 Improper PG lineup 1.3 l-CH-217 locked closed 1.4 PG pump not operating 2.0 Operator Action 2.1 Verify proper setting of flow controller. 2.2 Verify proper operation of l-CH-FCV-1114A. 2.3 If controller l-CH-FC-1114A is in manual, then the controller potentiometer setting may be adjusted to match actual PG flow to clear the annunciator as follows:

• IF AUTO or MANUAL makeup is in progress, THEN adjust the l-CH-HFC-1114 (half-station) potentiometer
• IF DILUTE or ALT DILUTE makeup is in progress, THEN adjust the l-CH-FC-1114A potentiometer 2.4 Check primary grade water system for proper line-up.

2.5 Monitor Reactor Power due to potential dilution. 3.0 References 3.1 11715-ESK-l0B and 10AAR 3.2 11715-FM-95B 3.3 Unit 1 Loop Book, page CH-19 3.4 DCP 95-807, Blender Flow Deviation Alarm Setpoint Change 4.0 Actuation 4.1 l-CH-YC-1114

STUDENT GUIDE FOR CHEMICAL AND VOLUME CONTROL SYSTEM (41) 4.12 Content

1. AUTOMATIC:

1.1. In the AUTO mode the in-service (AUTO) boric acid transfer pump will run in slow speed until an auto makeup signal is generated. 1.2. It will then run in FAST until the makeup is complete.

2. BORATE:

2.1. In the BORATE mode, the in-service (AUTO) boric acid transfer pump will run in FAST speed when the blender control switch is placed in START. Topi&4.13*. Bler1derFlhwConfrdl.Val~eResponse .to* Blendet*Opera~lQn* 4.13 Objective U 379 Describe the response of the blender flow control valves to blender operations in the following modes.

• AUTOMATIC
• BORATE
• ALTERNATE DILUTE
• DILUTE
• MANUAL 4.13 Content

1. AUTOMATIC:

1.1. In the automatic mode, a low level signal of 21.5 percent from the VCT level controller initiates makeup of a preselected blend of boric acid and water to the suction of the charging pumps. 1.2. Specifically, a low level signal: 1.2.1.Transfers the boric acid pump on low speed recirculation (AUTO) to high speed. REACTOR OPERATOR Page 44 of 86 Revision 10, 08/20/2008

STUDENT GUIDE FOR CHEMICAL AND VOLUME CONTROL SYSTEM (41) 1.2.2.Modulates the primary grade water flow control valve (FCV-1114A) and the boric acid flow control valve (FCV-1113A). 1.2.3.0pens the makeup stop valve (FCV-1113B) to the charging pump suction header. 1.3. At the 41.5 percent level, the make-up stops, and the boric acid transfer pump shifts to low speed.

2. BORATE:

2.1. When boration is initiated, the boric acid pump on low speed recirculation (AUTO) transfers to high speed, boric acid flow control valve FCV-1113A modulates, and makeup stop valve FCV-1113B opens to establish flow to the suction of the charging pumps.

3. ALTERNATE DILUTE:

3.1. The primary grade water flow control valve (FCV-1114A) modulates to hold the flow rate setpoint set on the controller. 3.2. The primary makeup stop valve to the charging pump suction header (FCV-1113B), as well as FCV-1114B to the top of the VCT open, injecting the primary water through two paths instead of one.

4. DILUTE:

4.1. The primary grade water flow control valve (FCV-1114A) opens and modulates to hold the flow rate setpoint set on the controller. 4.2. The primary grade makeup stop valve to the top of the VCT (FCV-1114B) opens to establish the flow to the VCT

5. MANUAL:

5.1. Flow regulating valves (FCV-1113A and/or 1114A) open and modulate, however the stop valves, FCV-1113B and/or -1114B, do not open and must be opened manually. REACTOR OPERATOR Page 45 of 86 Revision 10, 08/20/2008

STUDENT GUIDE FOR CHEMICAL AND VOLUME CONTROL SYSTEM (41) 2.5. Through the manual emergency borate valve 2.6. Into the charging pump suction header. Topic 4:.16 Chemical and Volume C6ntrolSyst$1J1 Alarms 4.16 Objective U 1985 List the conditions that will actuate each of the following Chemical and Volume Control System alarms.

• BORIC ACID TO BLENDER FLOW DEV
• PG WATER TO BLENDER FLOW DEV 4.16 Content

1. BORIC ACID TO BLENDER FLOW DEV:

( 1.1. The BORIC ACID TO BLENDER FLOW DEVIATION alarm (1 B-C7) actuates when actual boric acid flow rate deviates from the required flow rate by 2.0 gpm for 20 seconds.

2. PG WATER TO BLENDER FLOW DEV 2.1. The PRIMARY GRADE WATER TO BLENDER FLOW DEVIATION alarm (1B-D7) actuates when the actual primary grade water flow rate deviates from the required flow rate by more than 10 gpm for 20 seconds.

Topic 4.1tBlender BatchlriiegrcltQts 4.17 Objective U 377 Explain the following concepts associated with the blender batch integrators (SOER-94-2).

• Purpose (IN-96-69)

REACTOR OPERATOR Page 47 of 86 Revision 10, 08/20/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

6. 005-A4.04006INEWIIH/3IROIII Given the following conditions:

• RHR is in-service with 1-RH-P-1A running and 1-CC-P-18 running.
• 1-RH-P-18 and 1-CC-P-1 A are available with their respective control switches in AFTER-STOP.

The normal supply breaker to 1H 4160-Volt 8us is inadvertently opened. Which ONE of the following identifies the pump configuration after EDG loading is complete? A. ONLY 1-RH-P-18 running and ONLY 1-CC-P-18 running. B. ONLY 1-RH-P-18 running and 80TH 1-CC-P-1A & 1-CC-P-1 8 running. C. NO RHR pumps running and ONLY 1-CC-P-18 running. D~ NO RHR pumps running and 80TH 1-CC-P-1A & 1-CC-P-18 running. Feedback

a. Incorrect. First part incorrect but plausible since some loads like charging pumps "ride the bus"; second part also incorrect but plausible since this pump never lost power.

b. Incorrect. First part incorrect but plausible as discussed above; second part is correct since 1-CC-P-1 A is sequenced on following the bus UV.

c. Incorrect. First part correct, UV opens the RHR pump breaker; second part is incorrect since 1-CC-P-1 A is sequenced on following the bus UV.

d. Correct. First part correct as discussed above; second part is also correct because as noted previously 1-CC-P-1A is sequenced on.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Residual Heat Removal System (RHRS) Ability to manually operate and/or monitor in the control room: Controls and indication for closed cooling water pumps (CFR: 41.7 / 45.5 to 45.8) Tier: 2 Group: 1 Importance Rating: 3.1/2.9 Technical

Reference:

RHR & CC lesson plans Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info:

STUDENT GUIDE FOR RESIDUAL HEAT REMOVAL SYSTEM (40) 3.2 Content

1. The RHR pumps are powered from the Hand J emergency busses, via a stub bus.

Use ESK-5R to explain.

2. A ground or phase OC device initiates lockout protection (86 relay) to open the breaker.

3. The breaker also opens automatically due to UV on its associated emergency bus.

4. The seal cooler heat exchanger is a shell and tube type, two-pass heat exchanger. Reactor coolant flows through the tubes, and CC flows through the shell side.

5. The pump suction relief valve lift setpoint is 467 psig.

6. The flow rate through the mini-flow recirculation line is approximately 200 gpm 3.3 Objective U 10458 Explain the following concepts associated with swapping from one residual heat removal pump to the other pump.

• Sequence in which the running pump is stopped and the non-running pump is started
• Action required if the possibility exists that air has been trapped in the idle pump 3.3 Content

1. In accordance with OP-14.3, when swapping RHR pumps:

REACTOR OPERATOR Page 10 of 39 Revision 1, 04104/2007

STUDENT GUIDE FOR VITAL AND EMERGENCY ELECTRICAL DISTRIBUTION SYSTEM (35)

3. The following conditions that cause the stub bus breaker to trip are:

3.1. Under-voltage 3.2.86 UO (phase OC or GOC) 3.3. Manual 3.4. COA (via the 86 contact)

4. Following an under-voltage condition, the stub bus breaker will automatically re-close after 15 seconds if the associated RHR pump breaker is open.

5. Following a containment depressurization actuation (COA), the stub bus breaker can be manually reclosed if the following conditions are met:

5.1. COA has been reset. 5.2. The UV condition has been cleared for 15 seconds. 5.3. The 86 UO has been reset locally at breaker. 2.9 Objective U 5531 List the following information associated with emergency bus undervoltage and degraded voltage.

• Conditions which cause an undervoltage actuation
• Conditions which cause a degraded voltage actuation
• Automatic actions that will occur due to a degraded or undervoltage condition
• Function of the emergency bus residual voltage relays
• Interlocks associated with the emergency bus residual voltage relays REACTOR OPERATOR Page 24 of 36 Revision 4, 07/31/2008

STUDENT GUIDE FOR COMPONENT COOLING WATER SYSTEM (51)

• Interlocks associated with automatically tripping a pump 2.2 Content

1. The component cooling pumps are powered from the 4160 VAC emergency busses.

1.1. Component cooling pump 1-CC-P-1 A is powered from the 1H 4160 VAC stub bus. 1.2. Component cooling pump 1-CC-P-1 B is powered from the 1J 4160 VAC stub bus.

2. In order to manually start a component cooling pump, the following conditions must exist:

2.1. No ground or phase over-current 2.2. Normal voltage on the supply bus for at least 20 seconds 2.3. No Containment Depressurization Actuation (CDA) signal present

3. The component cooling pumps have automatic start capability provided the following start permissives are met:

3.1. The control switch must be in AUTO 3.2. No Containment Depressurization Actuation (CDA) signal present 3.3. No ground or phase overcurrent 3.4. Given that all start permissives are satisfied, the standby component cooling pump will automatically start under anyone of three conditions: 3.4.1.The running component cooling pump trips (breaker disagreement) and the standby pump's emergency bus voltage has been normal for at least 20 seconds. 3.4.2.The running pump's bus develops an under-voltage condition and the standby pump's emergency bus voltage has been normal for at least 20 seconds. 3.4.3.Under-voltage on the standby component cooling pump's emergency bus and normal voltage has been restored to the bus for at least 15 seconds but not more than 20 seconds. 3.5. Following an under-voltage on an emergency bus, the associated component cooling pump only has a 5 second time period to automatically start and load on the emergency bus. REACTOR OPERATOR Page 9 of 37 Revision 2, 05/23/2007

STUDENT GUIDE FOR COMPONENT COOLING WATER SYSTEM (51) 3.5.1.lf the pump fails to automatically start and load within 15 seconds to 20 seconds after voltage restoration, the automatic start signal will be blocked. 3.5.2.This prevents overloading the emergency diesel generator.

4. The following conditions will automatically trip a running component cooling pump:

4.1. Under-voltage condition on the associated emergency bus. 4.2. Containment Depressurization Actuation (CDA) on the associated unit. 4.3. Ground over-current or phase over-current. REACTOR OPERATOR Page 10 of 37 Revision 2, 05/23/2007

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

7. 005-AK2.02 007INEWINAPS/H/3/ROINAPSII Given the following conditions:

• Rod H-2, Control Bank D group 1 is mis-aligned LOW.
• Operators are preparing to realign the rod in accordance with 1-AP-1.3, Control Rod Out of Alignment.

1-AP-1.3 will direct the crew to _ _ _ _ _ _ _ _ _ ; as a result of this action, the crew should expect a alarm when Rod H-2 is withdrawn. A. Open the lift coil disconnect switches for Control Bank D, Gp 1 rods ONLY, EXCEPT for Rod H-2; Rod Control Non-Urgent Failure. B. Open the lift coil disconnect switches for Control Bank D, Gp 1 rods ONLY, EXCEPT for Rod H-2; Rod Control Urgent Failure. C. Open the lift coil disconnect switches for ALL Control Bank D rods, EXCEPT for Rod H-2; Rod Control Non-Urgent Failure. D~ Open the lift coil disconnect switches for ALL Control Bank D rods, EXCEPT for Rod H-2; Rod Control Urgent Failure. Feedback

a. Incorrect. Plausible since the affected rod is in this group; second part is plausible since an urgent failure locks up rods (but only in the AFFECTED cabinet) and the candidate who does not have detailed systems knowledge may eliminate the urgent failure as a possibility and default to this distractor.

b. Incorrect. First part incorrect but plausible as noted above; second part is correct provided the action to open lift coil disconnects is performed correctly.

c. Incorrect. First part is correct an necessary to prevent movement of rods in the other group within the bank; second part incorrect but plausible as discussed in Distractor a.

d. Correct. First part is correct as discussed in Distractor c; second part is also corrrect the source of the urgent failure is the regulation failure in power cabinet 2BD caused all of the lift coil disconnects for Bank D Grp II being open with rod motion demanded (will be demanded once the operator starts withdrawing H-2).

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Inoperable/Stuck Control Rod Knowledge of the interrelations between the Inoperable / Stuck Control Rod and the following: Breakers, relays, disconnects, and control room switches. (CFR 41.7 / 45.7) Tier: 1 Group: 2 Importance Rating: 2.5/2.6 Technical

Reference:

1-AP-1.3 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: New additional info: (

NUMBER PROCEDURE TITLE REVISION 11 1-AP-1.3 CONTROL ROD OUT OF ALIGNMENT PAGE 4 of 6 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

11. VERIFY THE CAUSE OF o WHEN the cause of misaligned rod is repaired, MISALIGNED ROD - REPAIRED THEN GO TO Step 12.

12. RECORD CURRENT POWER LEVEL:

Power level: _ _

13. REACTOR - CRITICAL o GO TO Step 15.

14. DETERMINE MAXIMUM ROD WITHDRAWAL RATE AND POWER RAMP RATE USING ATTACHMENT 4, MAXIMUM ROD WITHDRAWAL AND RAMP RATE

15. VERIFY NO NUCLEAR o Reset rate trip signal.

INSTRUMENTATION POWER RANGE RATE TRIP SIGNAL - LIT NOTE: More than one rod in the same group may be aligned simultaneously.

16. ALIGN AFFECTED RODS USING ONE OF THE FOLLOWING:

o

• ATTACHMENT 2, REALIGNING CONTROL ROD-ROD LOW OR o
• ATTACHMENT 3, REALIGNING CONTROL ROD - ROD HIGH

NUMBER ATTACHMENT TITLE ATIACHMENT 1-AP-1.3 2 REALIGNING CONTROL ROD REVISION -ROD LOW PAGE 11 1 of 4

1. !E the misaligned rod(s) are in the controlling bank, THEN position rods to place both groups in that bank at the same reading.

2. Record affected bank position:

Bank Steps

3. Record the misaligned rod(s) positions:

ROD(s) STEPS

4. Record the number of steps the rod(s) are misaligned:

ROD(s) STEPS MISALIGNED

5. Place the Rod Control Bank Selector switch in BANK SELECT for the bank containing the misaligned rod(s).

NOTE: A flashing Group Step Counter display indicates low battery.

6. Manually adjust the Group Step Counter for the affected group to the actual position of the misaligned rod(s) as recorded in Step 3, using the down (DN) or (UP) button, as required.

(

NUMBER ATIACHMENT TITLE ATTACHMENT 1-AP-1.3 2 REALIGNING CONTROL ROD - ROD LOW REVISION PAGE 11 20f4 NOTE: The shutdown banks do not have Pulse-to-Analog Converters.

7. Locally record the affected banks Pulse-to-Analog Converter readings (located in 1-EI-CB-41 Bin the Instrument Rack Room): steps NOTE: If the Pulse to Analog Converter is pulsed to zero, then the affected banks ROD BANK LO/

LO-LO LIMIT annunciator will alarm.

8. Locally reset the affected banks Pulse-to-Analog Converter by doing the following (located in the Instrument Rack Room):

_ a) Place the Manual/Automatic switch in MANUAL. b) Place the Pulse-to-Analog Bank Selector switch to the affected bank. c) Press the Down pulse button until the Pulse-to-Analog Converter reads the position of the misaligned rod(s). _ d) Place the Manual/Automatic switch in AUTOMATIC.

9. Open all Lift Coil Disconnect switches for the affected bank, except for the misaligned rod(s)

(located behind Main Control Room Vertical Board).

10. Have a second person independently verify that all Lift Coil Disconnect switches for the affected bank, except for the misaligned rod(s), are open.

11. Do the following during the Control Rod motion:

• Adjust Turbine load, as required at a rate consistent with the Tave change caused by rod motion AND ATTACHMENT 4, MAXIMUM ROD WITHDRAWAL AND RAMP RATE, as applicable.

AND

• Maintain Tave within 1.5 of of Tref by adjusting Turbine load or Steam Dumps as necessary.

NUMBER ATTACHMENT TITLE ATTACHMENT 1-AP-1.3 2 REALIGNING CONTROL ROD - ROD LOW REVISION PAGE 11 3 of 4 CAUTION:

• Exceeding the maximum withdrawal rate calculated on ATTACHMENT 4 could cause fuel damage.
• If the Reactor is subcritical, then the Reactor must be monitored for inadvertent criticality during control rod withdrawal.

NOTE: When the affected rod(s) are withdrawn, then Annunciator Panel "A" D-1, ROD CONTROL URGENT FAILURE, may annunciate, indicating the affected banks lift coils are de-energized.

12. Manually withdraw the affected rod(s) by placing the Rod Control switch in OUT:

_ a) Verify the OUT direction lamp is LIT. b) Verify the affected Group Step Counter indicates outward motion. ( c) !E affected rod(s) will NOT move, THEN have the System Engineer determine required actions AND obtain OMOC concurrence, before continuing with this procedure.

13. !E the misaligned rod is in Group 1 of the affected bank, THEN do the following:

_ a) Withdraw the Control Rod until it reaches a value of one step greater than the value recorded in Step 2 of this attachment. b) Drive the Control Rod in one step to the value recorded in Step 2 of this attachment.

14. !E the misaligned rod is in Group 2 of the affected bank, THEN withdraw the Control Rod until the affected Group Step Counter reaches the value recorded in Step 2 of this attachment.

15. Record affected Group Step Counter steps: _ _ _ _ steps

16. Verify the following conditions are met:

• All rods in the affected bank are at the same height.

AND

• All Rod Bottom lights in the affected bank are NOT LIT.
• IF either condition is NOT satisfied, THEN have the System Engineer determine required actions AND obtain OMOC concurrence, before continuing with this procedure.

( NUMBER ATTACHMENT TITLE ATTACHMENT 1-AP-1.3 2 REALIGNING CONTROL ROD - ROD LOW REVISION PAGE 11 4 of 4

17. Close all Lift Coil Disconnect switches.

18. Have a second qualified Operator verify that all lift Disconnect switches are closed.

19. Reset ROD CONTROL URGENT FAILURE alarm from the control board with the Alarm Reset pushbutton.

20. Step the affected banks Control Rods in one step and verify proper Group 2-Group 1 sequencing.

21. Step the affected banks Control Rods out one step and verify proper Group 1-Group 2 sequencing.

22. RETURN TO Step 17 of 1-AP-1.3, CONTROL ROD OUT OF ALIGNMENT.

(

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) Misaligned Control Rod TopiC4.1.il.*.nforrna.(tionAssociatedwith

• . . . 1-.APl f ..3 4.1 Objective U 11028 List the following information associated with 1-AP-1.3, "Control Rod Out of Alignment" (SOER-84-2).
• Purpose of the procedure
• Modes of applicability
• Entry conditions 4.1 Content

1. 1-AP-1.3 provides the operator instructions to follow when a control rod is discovered out of alignment.

2. This procedure is applicable in modes 1 or 2.

3. 1-AP-1.3 should be entered when 3.1. Any control rod is known to be out of alignment from its group step counter.

3.2. Group step counters differ by more than one step for a given bank of rods. 3.3. Multiple rods in the same group are known to be out of alignment by the same amount, less than 12 steps, from the group step counter demand position. 4.2 Objective U 11029 Explain the following concepts associated with 1-AP-1.3, "Control Rod Out of Alignment" (SOER-84-2).

• Indications of a misaligned rod
• Effect that withdrawing control rods too rapidly would have on plant operation REACTOR OPERATOR Page 21 of 158 Revision 30, 11/06/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91)

• How to determine the maximum withdrawal rate of the misaligned rods for a given plant condition
• How to determine the maximum ramp rate during misaligned rod recovery
• Why the misaligned rods are normally re-aligned and not the bank
• How only the misaligned rods are repositioned 4.2 Content

1. A misaligned control rod is indicated by individual or multiple individual rod position indicators (IRPls) reading several steps different from their respective group step counter.

1.1. Care must be used to ensure that indications observed on the suspect IRPls are not due to temperature induced drift. 1.2. If the operator does not immediately notice the IRPI out of alignment, an annunciator COMPUTER ALARM ROD DEVIATION SEQUENCE, will alert him to the problem.

2. Effect that withdrawing control rods too rapidly would have on plant operation.

2.1. As the unit operates with a misaligned control rod, the resulting distorted flux profile can cause power peaks and abnormal xenon distributions in the core. 2.2. In order to maintain fuel integrity, a limit must be placed on realigning the rod, if greater than or equal to 13 steps misaligned from group demand, depending on current reactor power level and time between rod misalignment and recovery completion. 2.3. If there will be less than one hour between the time the rod became misaligned and recovery completion, or 2.3.1.lf reactor power is less than or equal to 75% and there will be less than or equal to 24 hours between the time the rod became misaligned and recovery completion, then there is no restriction on misaligned rod withdrawal rate. 2.3.2. Restrictions on rod movement as delineated by the unit startup procedure 1-0P-2.1, may still apply and must be followed. 2.3.3.ln the absence of these restrictions, then the operator should limit rod motion based on plant response (temperature, pressure, SG levels ... etc.) and should monitor over-power and over-REACTOR OPERATOR Page 22 of 158 Revision 30, 11/06/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) temperature delta-T trip setpoints to ensure the penalty for rate of temperature increase does not drop the setpoints excessively.

3. Determine the maximum withdrawal rate of a rod misaligned greater than or equal to 13 steps from group demand.

3.1. If there will be less than one hour between the time the rod was misaligned and recovery completion, then the maximum withdrawal rate is unrestricted. 3.1.1.lf reactor power is less than or equal to 75% and there will be less than or equal to 24 hours between the time the rod was misaligned and recovery completion, then the maximum withdrawal rate is unrestricted. 3.2. As the unit operates with a misaligned control rod, the flux profile may become distorted, and cause power peaks and abnormal xenon distributions in the core. 3.3. In order to maintain fuel integrity, a limit may be placed on retrieving the misaligned rod depending on current reactor power level and time between rod misalignment and recovery completion. 3.3.1.lf reactor power is less than or equal to 75% and there will be greater than 24 hours between the time the rod was misaligned and recovery completion, then the maximum withdrawal rate is restricted to 5 step increments spaced every 30 minutes. 3.3.2.lf reactor power is greater than 75% and there will be greater than or equal to one hour between the time the rod was misaligned and recovery completion, then the following rod withdrawal restrictions are imposed. 3.3.2.1. For the first 100 steps of rod withdrawal, use the calculation below to determine the maximum rod withdrawal rate. Steps Per nour IT

                                                     = -0.5 P

P = fraction of rated power (80% power = 0.8) 3.3.2.2. For the remainder of withdrawal beyond the first 100 steps, use the calculation below to determine the maximum withdrawal rate. REACTOR OPERATOR Page 23 of 158 Revision 30, 11/06/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) Steps Per Hour = -1 P P =fraction of rated power (80% power =0.8) 3.3.3.The rod should be recovered in whole step increments. 3.3.3.1. If calculate 0.5 steps per hour then withdraw 1 step every two hours 3.3.3.2. If calculate 1.25 steps per hour then withdraw 1 step every 48 minutes 3.3.4.lf OP-2.1 restrictions apply, then the more restrictive limits shall be followed.

4. Determine the maximum core power ramp rate during recovery of a rod misaligned greater than or equal to 13 steps from group demand.

4.1. If there will be less than one hour between the time the rod was misaligned and recovery completion, then the maximum core power ramp rate is unrestricted. 4.2. In order to maintain fuel integrity, a limit must be placed on core power ramp rate depending on the time from the rod misalignment to completion of recovery and core power level during the ramp. 4.2.1.lf there will be greater than or equal to one hour and less than or equal to 8 hours between the time the rod was misaligned and recovery completion, then the core power ramp rate is restricted to less than or equal to 30% per hour over the range of power increase. 4.2.2.lf there will be greater than 8 hours and less than or equal to 24 hours between the time the rod was misaligned and recovery completion, then the core power ramp rate is restricted as follows: 4.2.2.1. When power is ramped between 0% and 50%, then the core power ramp rate is restricted to less than or equal to 30% per hour. 4.2.2.2. When power is ramped between 50% and 90%, then the core power ramp rate is restricted to less than or equal to 15% per hour. 4.2.2.3. When power is ramped between 90% and 100%, then the core power ramp rate is restricted to less than or equal to 5% per hour. REACTOR OPERATOR Page 24 of 158 Revision 30, 11/06/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) 4.2.3.lf there will be greater than 24 hours between the time the rod was misaligned and recovery completion, then the core power ramp rate is restricted to less than or equal to 3% per hour over the range of power increase. 4.2.4.Following completion of misaligned rod alignment, the core power ramp rate restrictions are still applicable for the remainder of the recovery ramp to allow conditioning of the fuel. 4.3. If power ramp rate restrictions are imposed by 1-0-2.1, "Unit Startup from Mode 2 to Mode 1," then the more restrictive value must be used.

5. The misaligned rods are always moved to the proper bank position, regardless of whether it requires that rods be inserted or withdrawn.

5.1. This is done because our accident analysis assumes that we maintain proper control rod alignment, and intentionally moving an entire bank to match a misaligned rod does not support these assumptions. REACTOR OPERATOR Page 25 of 158 Revision 30, 11/06/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) 4.2. The affected bank's ROD BANK LO I LO-LO LIMIT will alarm when the PIA converter is pulsed down below the rod insertion limits for the current power level. 4.2.1.The alarm will clear during rod retrieval, as the rod is withdrawn above the insertion limits. 4.3. The ROD CONTROL URGENT FAILURE will be received when dropped rod retrieval begins. 4.3.1.The rod control system senses the feedback that a "move" command was sent to the non-affected group, but no rods moved in that group because its lift coil disconnect switches are open. 4.3.2.The alarm will clear when the operator pushes the ALARM RESET pushbutton on the main control board following retrieval of the dropped rod. ( REACTOR OPERATOR Page 20 of 158 Revision 30, 11/06/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

8. OOS-KS.09 008INEWIIH/3/ROINAPSII Unit 1 is in Mode 6.

Technical Specifications require ONE RHR loop operable and in operation whenever water level is _ _ _ _ _ _ _ _ _ ; compliance with this LCO ensures_ _ _ _ _ _ _ _ __ A'! greater than or equal to 23 feet above the top of the reactor vessel flange; proper mixing of RCS coolant to minimize the possibility of localized dilution. B. greater than or equal to 23 feet above the top of the reactor vessel flange; acceptable limits are maintained in the event of a fuel handling accident. C. less than 23 feet above the top of the reactor vessel flange; proper mixing of RCS coolant to minimize the possibility of localized dilution. D. less than 23 feet above the top of the reactor vessel flange; acceptable limits are maintained in the event of a fuel handling accident. Feedback

a. Correct. Because of the large heat sink only one loop is required. One of the LCD functions is mixing (prevent thermal stratification).

b. Incorrect. First part is correct. Second part is incorrect but plausible since fuel handling accident is a concern; the LCD for water level is established for the FHA however, this LCD is only for mixing and decay heat removal.

c. Incorrect. First part is incorrect but plausible since some candidates associate the need for two loop only during fuel movement and not directly with water inventory.

Second part is correct, as mixing is a function in both conditions (high or low water level)

d. Incorrect. First part is incorrect as discussed above; second part is incorrect as discussed in distractor b.

(

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Residual Heat Removal System (RHRS) Knowledge of the operational implications of the following concepts as they apply the RHRS: Dilution and boration considerations (CFR: 41.5/45.7) Tier: 1 Group: 2 Importance Rating: 3.213.4 Technical

Reference:

TS 3.9.5, 3.9.6 & basis Proposed references to be provided to applicants during examination: None Learning Objective: Question History: New additional info:

                  - NUCLEAR DESIGN INFORMATION PORTAL-RHR and Coolant Circulation-High Water Level 3.9.5 3.9   REFUELING OPERATIONS 3.9.5    Residual Heat Removal (RHR) and Coolant Circulation-High Water Level LCO 3.9.5          One RHR loop shall be OPERABLE and in operation.
                  - - - - - - - - - - - - NOTE - - - - - - - - - - - - -

The required RHR loop may be removed from operation for

                  ~ 1 hour per 8 hour period, provided no operations are permitted that would cause introduction into the Reactor Coolant System (RCS), coolant of boron concentration less than required to meet the minimum required boron concentration of LCO 3.9.1.

APPLICABILITY: MODE 6 with the water level ~ 23 ft above the top of reactor vessel flange. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. RHR loop requirements A.l Suspend operations Immediately not met. that would cause introduction into the RCS, coolant with boron concentration less than required to meet the boron concentration of LCO 3.9.1. AND A.2 Suspend loading Immediately irradiated fuel assemblies in the core. AND A.3 Initiate action to Immediately satisfy RHR loop requirements. AND (continued) North Anna Units 1 and 2 3.9.5-1 Amendments 231/212

RHR and Coolant Circulation-High Water Level 3.9.5 ( ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.4 Close equipment hatch 4 hours and secure with four bo lts. AND A.5 Close one door in each 4 hours installed air lock. AND A.6.1 Close each penetration 4 hours providing direct access from the containment atmosphere to the outside atmosphere with a manual or automatic isolation valve, blind flange, or equivalent. ( OR A.6.2 Verify each 4 hours penetration is capable of being closed by an OPERABLE Containment Purge and Exhaust Isolation System. SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.5.1 Verify one RHR loop is in operation and 12 hours circulating reactor coolant at a flow rate of 2': 3000 gpm. North Anna Units 1 and 2 3.9.5-2 Amendments 231/212

                  -  NUCLEAR DESIGN INFORMATION PORTAL-RHR and Coolant Circulation-Low Water Level 3.9.6 3.9 REFUELING OPERATIONS 3.9.6    Residual Heat Removal (RHR) and Coolant Circulation-Low Water Level LCO 3.9.6          Two RHR loops shall be OPERABLE, and one RHR loop shall be in operation.
                  - - - - - - - - - - - - NOTES - - - - - - - - - - - - -

1. All RHR pumps may be removed from operation for

                      ~ 15 minutes when switching from one train to another provided:

a. The core outlet temperature is maintained> 10°F below saturation temperature;

b. No operations are permitted that would cause a reduction of the Reactor Coolant System boron concentration; and

c. No draining operations to further reduce RCS volume are permitted.

2. One required RHR loop may be inoperable for up to 2 hours for surveillance testing, provided that the other loop is OPERABLE and in operation.

APPLICABILITY: MODE 6 with the water level < 23 ft above the top of reactor vessel flange. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Less than the required A.1 Initiate action to Immediately number of RHR loops restore required RHR OPERABLE. loops to OPERABLE status. OR A.2 Initiate action to Immediately establish ~ 23 ft of water above the top of reactor vessel flange. North Anna Units 1 and 2 3.9.6-1 Amendments 231/212

                      - NUCLEAR DESIGN INFORMATION PORTAL-RHR and Coolant Circulation-Low Water Level 3.9.6 ACTIONS CONDITION                 REQUIRED ACTION           COMPLETION TIME B. No RHR loop in         B.1    Suspend operations        Immediately operation.                    that would cause introduction into the RCS, coolant with boron concentration less than required to meet the boron concentration of LCO 3.9.1.

AND B.2 Initiate action to Immediately restore one RHR loop to operation. AND B.3 Close equipment hatch 4 hours and secure with four bolts. AND B.4 Close one door in each 4 hours installed air lock. AND B.5.1 Close each penetration 4 hours providing direct access from the containment atmosphere to the outside atmosphere with a manual or automatic isolation valve, blind flange, or equivalent. OR (continued) North Anna Units 1 and 2 3.9.6-2 Amendments 231/212

                 - NUCLEAR DESIGN INFORMATION PORTAL-RHR and Coolant Circulation-Low Water Level 3.9.6 ACTIONS CONDITION                     REQUIRED ACTION           COMPLETION TIME B.  (continued)                B.5.2 Verify each                4 hours penetration is capable of being closed by an OPERABLE Containment Purge and Exhaust Isolation System.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.6.1 Verify one RHR loop is in operation and 12 hours circulating reactor coolant at a flow rate of:

a. ~ 3000 gpm, or

b. ~ 2000 gpm if RCS temperature ~ 140°F and time since entry into MODE 3

                    ~ 100 hours.

SR 3.9.6.2 -------------------NOTE-------------------- Not required to be performed until 24 hours after a required RHR pump is not in operation. Verify correct breaker alignment and 7 days indicated power available to the required RHR pump that is not in operation. North Anna Units 1 and 2 3.9.6-3 Amendments 231/212

RHR and Coolant Circulation-High Water Level B 3.9.5 B 3.9 REFUELING OPERATIONS B 3.9.5 Residual Heat Removal (RHR) and Coolant Circulation-High Water Level BASES BACKGROUND The purpose of the RHR System in MODE 6 is to remove decay heat and sensible heat from the Reactor Coolant System (RCS) to provide mixing of borated coolant and to prevent boron stratification (Ref. 1). Heat is removed from the RCS by circulating reactor coolant through the RHR heat exchanger(s), where the heat is transferred to the Component Cooling Water System. The coolant is then returned to the RCS via the RCS cold leg(s). Operation of the RHR System for normal cool down or decay heat removal is manually accomplished from the control room. The heat removal rate is adjusted by controlling the flow of reactor coolant through the RHR heat exchanger(s) and the bypass. Mixing of the reactor coolant is maintained by this continuous circulation of reactor coolant through the RHR System. APPLICABLE If the reactor coolant temperature is not maintained below SAFETY ANALYSES 200°F, boiling of the reactor coolant could result. This could lead to a loss of coolant in the reactor vessel. Additionally, boiling of the reactor coolant could lead to a reduction in boron concentration in the coolant due to boron plating out on components near the areas of the boiling activity. The loss of reactor coolant and the reduction of boron concentration in the reactor coolant would eventually challenge the integrity of the fuel cladding, which is a fission product barrier. One train of the RHR System is required to be operational in MODE 6, with the water level

                 ~ 23 ft above the top of the reactor vessel flange, to prevent this challenge. The LCO does permit removal of the RHR loop from operation for short durations, under the condition that the boron concentration is not diluted. This conditional removal from operation of the RHR loop does not result in a challenge to the fission product barrier.

The RHR System satisfies Criterion 4 of 10 CFR

50. 36 (c) (2) ( i i ) .

LCO Only one RHR loop is required for decay heat removal in MODE 6, with the water level ~ 23 ft above the top of the reactor vessel flange. Only one RHR loop is required to be (continued) North Anna Units 1 and 2 B 3.9.5-1 Revision 0

                       - NUCLEAR DESIGN INFORMATION PORTAL-RHR and Coolant Circulation-High Water Level B 3.9.5 BASES LCO               OPERABLE, because the volume of water above the reactor (continued)     vessel flange provides backup decay heat removal capability.

At least one RHR loop must be OPERABLE and in operation to provide:

a. Removal of decay heat;

b. Mixing of borated coolant to minimize the possibility of criticality; and

c. Indication of reactor coolant temperature.

An OPERABLE RHR loop includes an RHR pump, a heat exchanger, valves, piping, instruments, and controls to ensure an OPERABLE flow path and to determine the RHR discharge temperature. The flow path starts in one of the RCS hot legs and is returned to at least one of the RCS cold legs. The LCO is modified by a Note that allows the required operating RHR loop to be removed from operation for up to 1 hour per 8 hour period, provided no operations are permitted that would dilute the RCS boron concentration by introduction of coolant into the RCS with boron concentration less than required to meet the minimum boron concentration of LCO 3.9.1. Boron concentration reduction with coolant at boron concentrations less than required to assure the RCS boron concentration is maintained is prohibited because uniform concentration distribution cannot be ensured without forced circulation. This permits operations such as core mapping or alterations in the vicinity of the reactor vessel hot leg nozzles and RCS to RHR isolation valve testing. During this 1 hour period, decay heat is removed by natural convection to the large mass of water in the refueling cavity. APPLICABILITY One RHR loop must be OPERABLE and in operation in MODE 6, with the water level ~ 23 ft above the top of the reactor vessel flange, to provide decay heat removal. The 23 ft water level was selected because it corresponds to the 23 ft requirement established for fuel movement in LCO 3.9.7, IIRefueling Cavity Water Level." Requirements for the RHR System in other MODES are covered by LCOs in Section 3.4, Reactor Coolant System (RCS). RHR loop requirements in MODE 6 with the water level < 23 ft are located in LCO 3.9.6, "Residual Heat Removal (RHR) and Coolant Circulation-Low Water Level." North Anna Units 1 and 2 B 3.9.5-2 Revision 0

RHR and Coolant Circulation-High Water Level B 3.9.5 BASES ACTIONS RHR loop requirements are met by having one RHR loop OPERABLE and in operation, except as permitted in the Note to the LCO. A.I If RHR loop requirements are not met, there will be no forced circulation to provide mixing to establish uniform boron concentrations. Suspending positive reactivity additions that could result in failure to meet the minimum boron concentration limit is required to assure continued safe operation. Introduction of coolant inventory must be from sources that have a boron concentration greater than what would be required in the RCS for minimum refueling boron concentration. This may result in an overall reduction in RCS boron concentration, but provides acceptable margin to maintaining subcritical operation. A.2 If RHR loop requirements are not met, actions shall be taken immediately to suspend loading of irradiated fuel assemblies in the core. With no forced circulation cooling, decay heat removal from the core occurs by natural convection to the heat sink provided by the water above the core. A minimum refueling water level of 23 ft above the reactor vessel flange provides an adequate available heat sink. Suspending any operation that would increase decay heat load, such as loading a fuel assembly, is a prudent action under this condition. A.3 If RHR loop requirements are not met, actions shall be initiated and continued in order to satisfy RHR loop requirements. With the unit in MODE 6 and the refueling water level ~ 23 ft above the top of the reactor vessel flange, corrective actions shall be initiated immediately. A.4, A.5, A.6.I, and A.6.2 If LCO 3.9.5 is not met, the following actions must be taken:

a. the equipment hatch or equipment hatch cover must be closed and secured with at least four bolts;

b. one door in each installed air lock must be closed; and (continued)

North Anna Units 1 and 2 B 3.9.5-3 Revision 0

DESIGI\I INFOBIVIATIOI'I RHR and Coolant Circulation-High Water Level B 3.9.5 BASES ACTIONS A.4, A.5, A.6.1, and A.6.2 (continued)

c. each penetration providing direct access from the containment atmosphere to the outside atmosphere must be either closed by a manual or automatic isolation valve, blind flange, or equivalent, or verified to be capable of being closed by an OPERABLE Containment Purge and Exhaust Isolation system.

With RHR loop requirements not met, the potential exists for the coolant to boil and release radioactive gas to the containment atmosphere. Performing the actions described above ensures that all containment penetrations are either closed or can be closed so that the dose limits are not exceeded. The Completion Time of 4 hours allows fixing of most RHR problems and is reasonable, based on the low probability of the coolant boiling in that time. SURVEILLANCE SR 3.9.5.1 REQUIREMENTS ( This Surveillance demonstrates that the RHR loop is in operation and circulating reactor coolant. The flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability and to prevent thermal and boron stratification in the core. The Frequency of 12 hours is sufficient, considering the flow, temperature, pump control, and alarm indications available to the operator in the control room for monitoring the RHR System. REFERENCES 1. UFSAR, Section 5.5.4. North Anna Units 1 and 2 B 3.9.5-4 Revision 0

Refueling Cavity Water Level B 3.9.7 B 3.9 REFUELING OPERATIONS B 3.9.7 Refueling Cavity Water Level BASES BACKGROUND The movement of irradiated fuel asse~blies within containment requires a minimum waterilevel of 23 ft above the top of the reactor vessel flange.j During refueling: this maintains sufficient water level in the containment, refueling canal, fuel transfer canal~ refueling cavity~ and spent fuel pool. Sufficient water is;necessary to retain iodine fission product activity in the water in the event of a fuel handling accident (Refs. 1 and 2). Sufficient iodine activity would be retained to limit Offsite doses from the accident to the limits of Regulatory!Guide 1.183. APPLICABLE During movement of irradiated fuel a~semblies. the water SAFETY ANALYSES level in the refueling canal and the ~refueling cavity is an initial condition design parameter in, the analysis of a fuel handling accident in containment, as ipostulated by Regulatory Guide 1.183 (Ref. 1). A mi'nimum water level of 23 fta110ws an effective iodine decontamination factDr of 200 (Appendix B Assumption 2 of Ref. :1) to be used "in the accident analysis for iodine. This relates to the assumption that 99.5% of the total iodine relea~ed from the pellet to I cladding gap of all the dropped fuel lassernbJy rods is ________ ~__ _ retained by the refueling cavity watelr. The fuel pellet to cladding gap is assumed to contain 8%1 of the fuel rod 1-131 inventory and 5% of all other i od; ne '; sotopes, wh i ell are included as other halogens (Ref. 1). I The fuel handling accident analysis inside containment is described in Reference 2. With a minimum water level of 23 ft, the analysis and test programsidemonstrate that the iodine release due to a postulated fu~l handling accident is adequately captured by the water and offsite doses are maintained within allowable limits (Ref. 1).

            \..7.." Refueling cavity water level satisfies: Criterion    2 of 10 CFR
             ~     /50.36(c)(2)(ii}.

A minimum refueling cavity water level of 23 ft above the reactor vessel flange is required to ensure that the radiological consequences of a postulated fuel handling accident inside containment are within acceptable lim'its. North Anna Units 1 and 2 B 3.9.7-1 Revision 20

STUDENT GUIDE FOR FUEL HANDLING SYSTEM (48) 9.13 Content

1. The manipulator crane main hoist must have a minimum capacity of 3250 pounds, and an overload cutoff limit of less than or equal to 2850 pound.

2. A SFP gate may be moved over spent fuel assemblies in the spent fuel pit if the following conditions are satisfied:

2.1. The top of the gate is no higher than 15 inches above the top of the moveable platform crane deck support beam while over irradiated fuel. 2.2. Gate is rigged to slack-free safety cables while over irradiated fuel. 2.3. Irradiated fuel assemblies that contain an RCCA are excluded along the load path. 2.4. SFP gates may NOT be moved over irradiated fuel in the cask area. ( 9.14 Objective U 9051 List the following technical specification information concerning water level restrictions during the refueling operations.

• Minimum number of residual heat removal loops required to be operable with the reactor cavity water level :::0: 23 feet above the vessel flange (TS-3.9.5)
• Minimum number of residual heat removal loops required to be operable with the reactor cavity water level < 23 feet above the vessel flange (TS-3.9.6)
• Minimum water level above the vessel flange during movement of fuel within the containment (TS-3.9.7)
• Minimum water level above the top of the irradiated fuel in the spent fuel storage racks (TS-3.7.16)
• Basis for the minimum water level above irradiated fuel (TS-3.7.16) 9.14 Content

1. Tech specs requires that at least one RHR loop is operable in mode 6 with greater than 23 feet of water above the vessel flange.

REACTOR OPERATOR Page 56 of 58 Revision 1, 04/11/2007

STUDENT GUIDE FOR FUEL HANDLING SYSTEM (48) 1.1. There is one exception to this requirement, and that is the situation where the core alterations are being performed in the vicinity of the pressure vessel hot legs. 1.2.ln this case, the RHR loop may be removed from service for up to 1 hour in an 8-hour period.

2. Tech specs requires that two RHR loops be operable when the reactor is in mode 6 with less than 23 feet of water above the vessel flange.

2.1. This ensures that a single failure of an operating RHR loop does not result in a complete loss of RHR capability.

3. There must be at least 23 feet of water over the top of the reactor pressure vessel flange during core alterations when in mode 6.

3.1. The restrictions on minimum water level ensure that sufficient water depth is available so that fuel assemblies or control rods are not exposed above the water surface during core alterations.

4. There be at least 23 feet of water over the top of irradiated fuel assemblies stored in the storage racks in the SFP.

5. The restrictions on minimum water level ensure that sufficient water depth is available to remove 99 percent of the assumed 10 percent iodine gap activity released from the rupture of an irradiated fuel assembly.

Topic9~15. 9.15 Objective U 11983 Given a set of plant conditions, evaluate Fuel Handling System operations in light of the following issues.

• Effect of a failure, malfunction, or loss of a related system or component on this system
• Expected plant or system response based on fuel handling component interlocks or design features REACTOR OPERATOR Page 57 of 58 Revision 1, 04/11/2007

STUDENT GUIDE FOR FUEL HANDLING SYSTEM (48)

• Impact on the technical specifications
• Response if limits or setpoints associated with this system or its components have been exceeded
• Proper operator response to the condition as stated 9.15 Content REACTOR OPERATOR Page 58 of 58 Revision 1, 04/11/2007

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

9. 006-A1.17 009INEW/1H/3IROINAPS//

Operators are responding to a LOCA and are performing Step 12 of 1-E-1, Loss of Reactor or Secondary Coolant, which directs them to "Check if Low-Head SI Pumps Should be Stopped." The following plant conditions exist:

• One charging pump is running and no others are available to be started.
• RCS pressure is 450 psig and stable.
• Containment pressure is 17 psia and slowly decreasing.
• RWST level is 58% and slowly decreasing.

Based on these plant conditions, which ONE of the following identifies the action required by 1-E-1, and the basis for the action? A. Leave Low-Head SI pumps running since they are providing core cooling. B. Leave Low-Head SI pumps running to prepare for the transfer to Cold Leg Recirc. C~ Stop Low-Head SI pumps to minimize the potential for pump and motor overheating. D. Stop Low-Head SI pumps to minimize the potential for contaminating the RWST. Feedback

a. Incorrect. Plausible since the candidate who does not have detailed systems/EOP knowledge may assume the LHSI pumps are injecting and/or that under loca condtions where SI termination criteria is NOT met the pumps would not be shutdown.

b. Incorrect. Plausible since plant conditions indicate this is imminent, however the background document states that shutting dowm the pumps to ensure future operability (Le. cold leg recirc) is the correct action.

c. Correct. Since LHSI pumps are running on recirc they are stopped to ensure they do not over heat and subsequently fail, thus resulting in a loss of cold leg recirc capability.

d. Incorrect. Plausible since they do recirc to the RWST and this is a concern for loca scenarios.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Emergency Core Cooling System (ECCS) Ability to predict and/or monitor changes in parameters (to prevent exceeding design limits) associated with operating the ECCS controls including: ECCS flow rate (CFR: 41.5/45.5) Tier: 2 Group: 1 Importance Rating: 4.2/4.3 Technical

Reference:

1-E-1 and Background Document Proposed references to be provided to applicants during examination: None Learning Objective: Question History: New additional info:

NUMBER PROCEDURE TITLE REVISION 23 1-E-1 LOSS OF REACTOR OR SECONDARY COOLANT PAGE 12 of 27 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

  *11. MAINTAIN CONTAINMENT PRESSURE:

o a) Check Recirc Spray Sump level - o a) GO TO Step 12. GREATER THAN 4 FT 10 IN o b) Operate at least one train of Recirc Spray o b) Operate at least two Recirc Spray Pump(s) with SW aligned to maintain Pump(s) with SW aligned to maintain Containment pressure less than 13 psia Containment pressure less than 13 psia. CAUTION: If RCS pressure decreases in an uncontrolled manner to less than 225 psig [450 psig], then the Low-Head SI Pumps should be manually restarted to supply water to the RCS. (

  *12. CHECK IF LOW-HEAD SI PUMPS SHOULD BE STOPPED:

a) Check RCS pressure: 0 1) Pressure - GREATER THAN 0 1) GO TO Step 14. 225 PSIG [450 PSIG] 0 2) Pressure - STABLE OR 0 2) GO TO Step 13. INCREASING b) Check Low Head SI Pump Suctions From 0 b) GO TO Step 13. Containment Sump - CLOSED: 0

• 1-S 1- MOV-1860A

{i~> \S t\.. ) 'rv~v- loc....;-e.J. f fOVi).oJ

                                                                              ~' t-i7JVL<?

0

• 1-SI-MOV-1860B [fv f * .i l ~ .\:- Ct--* . I 0 c) Reset both trains of SI if required 0 d) Stop Low-Head SI Pumps and put in AUTO-STANDBY

STEP DESCRIPTION TABLE FOR E-1 Step -.lL STEP: Check If Low-Head SI Pumps Should Be Stopped PURPOSE: To stop the low-head SI pumps if RCS pressure is above their shutoff head to prevent damage to the pumps BASIS: Upon safety injection initiation all safeguard pumps are started regardless of the possibility of high RCS pressure with respect to the low-head safety injection pump shutoff head. On low-head systems where the pump recirculates on a small volume circuit there is concern for pump and motor overheating. Shutdown of the pump and placement in the standby mode, when the RCS pressure meets the criteria outlined in this step, allows for future pump operability. If SI has not been previously reset and the low-head S1 pumps should be stopped, SI should be reset prior to stopping the pumps. SI can be reset regardless of containment pressure. ACTIONS: o Determine if RCS pressure is greater than (B.07) psig [(B.08) psig for adverse containment] o Determine if RCS pressure is stable or increasing o Reset SI signal if necessary o Determine if any low-head SI pump is running with suction aligned to the RWST. o Stop low-head SI pumps and place in standby INSTRUMENTATION: oRCS pressure indication o Low-head SI pumps status indication o SI signal reset status indication CONTROL/EQUIPMENT: o Low-head SI pump switches o SI reset switches E-l Background 64 HP-Rev. 2, 4/30/2005 HElBG .doc

STEP DESCRIPTION TABLE FOR E-1 Step ~ KNOWLEDGE: This step is a continuous action step. 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. E-1 Background 65 HP-Rev. 2. 4/30/2005 HE1BG.doc

STUDENT GUIDE FOR EMERGENCY PROCEDURES (92) 2.5. The excess letdown relief valve 2.6. The residual heat removal pump suction relief valves 2.25 Objective U 12472 Explain the following concepts concerning checking if the low-head safety injection pumps should be stopped in 1-E-0, "Reactor Trip or Safety Injection."

• Basis
• Required action if Reactor Coolant System pressure decreases after the pumps are stopped 2.25 Content

1. During a small break loss-of-coolant accident, RCS pressure may remain relatively high.

1.1. In this type of scenario, RCS pressure will stabilize at some pressure above low head safety injection pump discharge pressure or even accumulator pressure. 1.2. Continued operation of the low head safety injection pumps at their shutoff head can result in pump damage due to heat up. 1.3. If RCS pressure is above 225 psig and it is stable or increasing, E-O directs the operator to stop the low head safety injection pumps and place them in AUTO-STANDBY.

2. It should be noted that once safety injection has been reset, protection interlock P-4 prevents automatic re-initiation of safety injection.

2.1. Consequently, the low head safety injection pumps will not automatically start if conditions subsequently degrade. 2.2. E-O, therefore, cautions the operator to manually restart the low head safety injection pumps if later in the event RCS pressure decreases in an uncontrolled manner to less than 225 psig. REACTOR OPERATOR Page 62 of 187 Revision 19, 11/06/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

10. 007-A3.01 OlOIBANKINAPS/L/2IROINAPSII During 100% power operation, PRT in-leakage is identified as increasing.

Which ONE of the following identifies a possible source? A'! RCP seal return relief valve leakage. B. Reactor vessel head vent valve leakage. C. RCS loop stop valve stem leakoff. O. RCP #2 sealleakoff. Feedback

a. Correct. this component relieves to the PRT.

b. Incorrect. Plausible since both the PRT and POTT have several loads and which goes to what could easily be confused by the candidate who lacks detailed systems knowledge.

c. Incorrect. Plausible as discussed in Oistractor b.

d. Incorrect. Plausible as discussed in Oistractor b.

Notes Pressurizer Relief Tank/Quench Tank System (PRTS) Ability to monitor automatic operation of the PRTS, including: Components which discharge to the PRT (CFR: 41.7/45.5) Tier: 2 Group: 1 Importance Rating: 2.712.9 Technical

Reference:

Lesson Plan Proposed references to be provided to applicants during examination: None Learning Objective: Question History: New additional info:

STUDENT GUIDE FOR REACTOR COOLANT SYSTEM (38) Pressurizer Relief Tank 8.1 Objective U 3509 Explain the purpose and basis of the pressurizer relief tank. 8.1 Content

1. The PRESSURIZER RELIEF TANK (PRT) condenses and cools the relief discharge from various primary systems, most notably, the PRZR safety valves and PORVs.

1.1. The tank design is based on the requirement to accept a steam discharge from the pressurizer equal to 110 percent of the pressurizer steam volume at full power. 1.1.1.The tank is not designed to accept a continuous discharge from the pressurizer. 1.1.2.The volume of water in the tank is capable of absorbing the heat from the design discharge, assuming an initial temperature of 120°F, increasing to a final temperature of 200°F. 8.2 Objective U 3510 List the following information associated with inputs to the pressurizer relief tank (PRT).

• All inputs to the tank
• Setpoints of all the relief valves which discharge to the tank 8.2 Content

1. The inputs to the PRT are:

1.1. Sparger line. 1.2. Nitrogen supply. SHIFT TECHNICAL ADVISOR Page 85 of 111 Revision 8, 10109/2008

STUDENT GUIDE FOR REACTOR COOLANT SYSTEM (38) 1.3. Primary grade water.

2. Setpoints of all relief valves that discharge to the PRT are:

2.1. Safeties

2485 psig 2.2. PORV 1456: 2335 psig (and LTOP setpoints) 2.3. PORV 1455C: 92.5 % controller output (and LTOP setpoints)

2.4. Letdown

600 psig 2.5. RHR pump suction: 467 psig 2.6. Seal water return: 150 psig 2.7. Excess letdown: 150 psig 2.8. PDTT: 150 psig 8.3 Objective U 15847 Explain the following concepts associated with the pressurizer relief tank rupture discs.

• Purpose of the rupture discs
• Pressure at which the rupture discs are designed to function
• Indicated PRT pressure at which the rupture disc would be expected to function
• Means available in the control room to determine that the rupture discs have functioned 8.3 Content

1. Two 18-inch rupture discs, located on top of the tank, provide overpressure protection for the PRT.

1.1. The rupture discs have a combined capacity equal to that of the pressurizer safety valves.

2. The rupture discs are designed to blow at 100 psid.

SHIFT TECHNICAL ADVISOR Page 86 of 111 Revision 8, 10/09/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Pressurizer Vapor Space Accident Knowledge of events related to system operation/status that must be reported to internal organizations or external agencies, such as the State, the NRC, or the transmission system operator. (CFR: 41.10/43.5/45.11) Tier: 1 Group: 1 Importance Rating: 2.7/4.1 Technical

Reference:

EPIP-1.01 and VPAP-2802 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: modified additional info:

NUMBER PROCEDURE TITLE REVISION 32 EPIP-2.01 NOTIFICATION OF STATE AND LOCAL GOVERNMENTS PAGE 2 of 17 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 1 INITIATE PROCEDURE: o . By: Date: _ _ _ _ _ _ _ _ __ Time: _ _ _ _ _ _ _ _ __ Location: _ _ _ _ _ _ _ __ 2 CHECK FIRST REPORT OF o IF procedure previously initiated, THEN EMERGENCY FOR EVENT - REQUIRED continue from step in effect identified during relieflturnover. NOTE:

• The initial notification of any emergency classification must be made (meaning contact initiated with the first agency) within 15 minutes of declaring the emergency class.
• Items 6 through 9 on Attachment 2 are optional for a message reporting initial entry into the Emergency Plan or an emergency class change, including emergency termination and may be checked 'Excluded from this message.'
• Attachment 1, Instructions for Completing Report of Emergency to State and Local Governments, may be referenced as needed.

3 RECORD INFORMATION ON ATTACHMENT 2 (REPORT OF EMERGENCY TO STATE AND LOCAL GOVERNMENTS) 4 CHECK EMERGENCY - REMAINS IN  !.E emergency terminated before message EFFECT sent, THEN do the following: o a) Record reason event terminated in item 5. o b) Record "State EOC-only portion of message not applicable" on bottom of Attachment 2 Page 3.

NUMBER PROCEDURE TITLE REVISION 18 EPIP-2.02 NOTIFICATION OF NRC PAGE 2 of 6 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE:

• NRC notification shall be made immediately after notification of State and local governments and in all cases within 1 hour from the time of event declaration.
• EROS shall be activated as soon as possible and in all cases within 1 hour after declaring an Alert or higher classification.
• The NRC may require that a continuous open communication channel be maintained throughout the event.

1 INITIATE PROCEDURE: D

• By:

Date: _ _ _ _ _ __ Time: _ _ _ _ __ NOTE:

• Items appearing on Attachment 1, NRC EVENT NOTIFICATION WORKSHEET, may be marked "N/A" if they do not pertain to the incident.
• Items 10 and 21 of Attachment 1 are normally completed during communications with the NRC.

2 COMPLETE THE FOLLOWING ITEMS ON ATTACHMENT 1, NRC EVENT NOTIFICATION WORKSHEET: D

• Items 1 - 9 D
• Items 11 - 18 D
• Item 19 (applicable for radiological releases only)

D

• Item 20 (applicable for LOCA or SGTR events only)

STUDENT GUIDE FOR EMERGENCY PLAN IMPLEMENTING PROCEDURES (90) 1.5 Objective U 13138 Given that a particular emergency class (e.g., site area emergency) exists in more than one event category, explain why all applicable event categories should be noted when classifying the event. 1.5 Content

1. If a particular emergency class (e.g. Alert) exists in more than one event category (e.g. RCS event and Radioactivity event), all applicable event categories shall be noted when classifying the event.

1.1. This ensures that the emergency class is not inadvertently downgraded in one event category when a higher classification still exists in another event category. 1.6 Objective U 14046 Given a plant condition, determine the maximum time allowed between when an event's indications are available to the control room operators and when the event is officially classified. 1.6 Content

1. Classification of an emergency should be completed within 15 minutes after an event's indications are available to the control room operators.

1.7 Objective U 13134 State the maximum allowable time between declaring an emergency and the initial notification to the following agencies (EPIP-1.01).

• State and local governments
• Nuclear Regulatory Commission SENIOR REACTOR OPERATOR Page 8 of 12 Revision 3, 05/22/2007

STUDENT GUIDE FOR EMERGENCY PLAN IMPLEMENTING PROCEDURES (90) 1.7 Content

1. State and local governments must be notified (meaning contact initiated with the first agency) within 15 minutes of event declaration.

2. The Nuclear Regulatory Commission must be notified as soon as possible (immediately after notification of state and local governments), and in all cases within one hour of event declaration.

1.8 Objective U 13135 Identify by title the individual who is responsible for ensuring that off-site agencies are notified of an emergency under the following circumstances.

• Prior to activation of the TSC and LEOF
• Following activation of the TSC and LEOF 1.8 Content

1. Prior to activation of the TSC and LEOF, the Interim Station Emergency Manager is responsible for notifying off-site agencies of an emergency.

2. When the interim SEM is relieved, the NRC communicator and the State and Local Government communicator will relocate from the control room to the TSC.

2.1. Following activation of the TSC: 2.1.1. The SEM is responsible for NRC notification throughout the remainder of the event. 2.1.2.The SEM is responsible for State and Local Government notification, until that function is transferred to the LEOF (or CEOF as backup). 2.2. Following activation of the LEOF, the Recovery Manager will assume responsibility for State and Local government notification. SENIOR REACTOR OPERATOR Page 9 of 12 Revision 3, 05/22/2007

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

12. 008-G2.1.27 0 12/BANKINAPS/L/2/ROINAPSI/

One of the purposes of the CC System is to cool the unit from _ _ _ to 1400 F within _ _ _ _ in the event of a Steam Generator Tube Rupture. A'! 350 o F; 16 hours B. 350 o F; 24 hours C. 547 o F; 16 hours D. 547 o F; 24 hours Feedback

a. Correct. this is identified in the lesson plan and the safety analysis section of the Tech Spec Basis.

b. Incorrect. Temperature is correct; time is incorrect but plausible since this is consistent with Tech Spec requirements for getting to Mode 5 and the candidate who does not have detailed knowledge of the system may default to this Distractor.

c. Incorrect. Temperature is incorrect but plausible since the candidate may perceive that since the CC system is required by TS in mode 4 and above and a SGTR accident would likely occur in mode 1 that this would be a logical performance requirement; time is correct, but again it is for starting at 350 not 547.

d. Incorrect. First part incorrect but plausible as discussed above; time requirement incorrect but plausible as discussed in distractor b.

Notes Component Cooling Water Knowledge of system purpose and/or function. (CFR: 41.7) Tier: 2 Group: 1 Importance Rating: 3.9/4.0 Technical

Reference:

lesson plan and TS Basis Proposed references to be provided to applicants during examination: None Learning Objective: Question History: Bank additional info:

                -   NUCLEAR DESIGN INFORMATION PORTAL-CC System B 3.7.19 B 3.7 PLANT SYSTEMS B 3.7.19 Component Cooling Water (CC) System BASES BACKGROUND         The CC System provides a heat sink for the removal of process and operating heat from components during normal operation.

The CC System serves as a barrier to the release of radioactive byproducts between potentially radioactive systems and the Service Water System, and thus to the environment. The CC System consists of four subsystems shared between units. Each subsystem consists of one pump and one heat exchanger. The design basis of the CC System is a fast cooldown of one unit while maintaining normal loads on the other unit. Three CC subsystems are required to accomplish this function. With only two CC subsystems available, a slow cool down of one unit while maintaining normal loads on the other unit can be accomplished. The removal of normal operating heat loads (including common systems) requires two CC sUbsystems. During normal operation, the CC subsystems are cross connected between the units with two CC pumps and four CC heat exchangers in operation. Two pumps are normally running, with the other two in standby. A vented surge tank common to all four pumps ensures that sufficient net positive suction head is available. The CC System serves no accident mitigation function and is not a system which functions to mitigate the failure of or presents a challenge to the integrity of a fission product barrier. The CC System is not designed to withstand a single failure. The CC System supports the Residual Heat Removal (RHR) System. The RHR system does not perform a design basis accident mitigation function. Additional information on the design and operation of the system, along with a list of the components served, is presented in the UFSAR, Section 9.2.2 (Ref. 1). The principal function of the CC System is the removal of decay heat from the reactor via the Residual Heat Removal (RHR) System. North Anna Units 1 and 2 B 3.7.19-1 Revision 0

CC System B 3.7.19 BASES APPLICABLE The CC System serves no accident mitigation function. The SAFETY ANALYSES CC System functions to cool the unit from RHR entry conditions (T co1d < 350°F), to Tcold < 140°F. The time required to cool from 350°F to 140°F is a function of the number of CC and RHR trains operating. The CC System is designed to reduce the temperature of the reactor coolant from 350°F to 140°F within 16 hours based on a service water temperature of 95°F and having two CC subsystems in service for the unit being cooled down. The CC System has been identified in the probabilistic safety assessment as significant to public health and safety. The CC System satisfies Criterion 4 of 10 CFR 50.36(c) (2) (ii). LCO Should the need arise to cool down one unit quickly while the other unit is operating, three CC subsystems would be needed

                 - two to support the quick cool down of one unit and one to support the normal heat loads of the operating unit. To ensure this function can be performed a total of three CC subsystems shared with the other unit are required to be OPERABLE.

A CC subsystem is considered OPERABLE when:

a. The pump and common surge tank are OPERABLE; and

b. The associated piping, valves, heat exchanger, and instrumentation and controls required to perform the function are OPERABLE.

Each CC subsystem is considered OPERABLE if it is operating or if it can be placed in service from a standby condition by manually unisolating a standby heat exchanger and/or manually starting a standby pump. APPLICABILITY In MODES 1, 2, 3, and 4, the CC System is a normally operating system. In MODE 4 the CC System must be prepared to perform its RCS heat removal function, which is achieved by cooling the RHR heat exchanger. In MODE 5 or 6, the OPERABILITY requirements of the CC System are determined by the systems it supports. North Anna Units 1 and 2 B 3.7.19-2 Revision 0

CC System B 3.7.19 BASES ACTIONS A.1 If one required CC subsystem is inoperable, action must be taken to restore OPERABLE status within 7 days. In this Condition, the remaining OPERABLE CC subsystems are adequate to perform the heat removal function. The 7 day Completion Time is reasonable, based on the redundant capabilities afforded by the OPERABLE subsystems. B.1 and B.2 If the required CC subsystem cannot be restored to OPERABLE status within the associated Completion Time, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 6 hours and in MODE 5 within 30 hours. 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 unit systems. C.1 and C.2 If two required CC subsystems are inoperable, action must be taken to cool the unit to MODE 4 within 12 hours. Action must be initiated to place the unit in MODE 5, where the LCO does not apply, within 13 hours. 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 unit systems. 0.1 and 0.2 With no CC water available to supply the residual heat removal heat exchangers, action must be taken to cool the unit to MODE 4 within 12 hours. Alternate means to cool the unit must be found and the unit placed in MODE 5, where the LCO does not apply. 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 unit systems. North Anna Units 1 and 2 B 3.7.19-3 Revision 0

                      -  NUCLEAR DES!GN INFORMATION PORTAL-CC System B 3.7.19 BASES SURVEILLANCE      SR 3.7.19.1 REQUIREMENTS Verifying the correct alignment for manual, power operated, and automatic valves in the CC flow path to the RHR heat exchangers provides assurance that the proper flow paths exist for CC operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves are verified to be in the correct position prior to locking, sealing, or securing. This SR also does not apply to valves that cannot be inadvertently misaligned, such as check valves. This Surveillance does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position.

The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions. REFERENCES 1. UFSAR, Section 9.2.2. North Anna Units 1 and 2 B 3.7.19-4 Revision 0

STUDENT GUIDE FOR COMPONENT COOLING WATER SYSTEM (51) ( 1.1. Of major concern are the detectors and cabling associated with the excore nuclear instruments. 1.2. Prolonged exposure to temperatures in excess of 175°F can cause severe damage to the detectors and the cabling. 1.3. A short-term temperature excursion to 175°F is allowed for less than 8 hours. 1.4. However, temperatures should normally be maintained at 135°F or less. 8.9 Objective U 11250 List the ITS bases for Component Cooling Water System operability in modes 1, 2, 3, and 4. 8.9 Content

1. Component Cooling Water System operability requirements for modes one through four are found in Technical Specification ITS 3.7.19.

1.1. This technical requirement states that three Component Cooling (CC) Water Sub-systems (shared with the other unit) shall be operable in modes one through four. 1.2. A Component Cooling Water Sub-system is defined as containing one OPERABLE pump and one OPERABLE heat exchanger. 1.3. In order to be considered operable, each SUb-system must meet one of the following conditions: 1.3.1.The Component Cooling Water Sub-system is operating or; 1.3.2.1s capable of be placed in service manually by starting the standby pump and/or manually unisolating the standby heat exchanger. 1.4. The Component Cooling Water System is designed a fast cooldown of one unit while maintaining normal loads on the other unit. 1.5. Three Component Cooling Water Sub-systems must to be operable to accomplish this function. 1.6. The Component Cooling System is designed to reduce the Reactor Coolant System temperature from 350°F to 140°F within 16 hours during plant cooldown, based on: REACTOR OPERATOR Page 35 of 37 Revision 2, OS/23/2007

STUDENT GUIDE FOR COMPONENT COOLING WATER SYSTEM (51) 1.6.1.A service water temperature of 95°F and; 1.6.2.Two CC pumps and two heat exchangers in service for the unit being cooled down. 1.7. Therefore to ensure cooldown of one unit within 16 hours and maintain the other unit in normal full power operation three of the four subsystems must be operable. 8.10 Objective U 11251 List the technical specification bases for Component Cooling Water System operability in modes 5 and 6 (lTR-3.7.15). 8.10 Content ( 1. When both units are in a cold shutdown condition (Mode 5 and 6), Technical Requirement 3.7.15 states that two Component Cooling (CC) Water Sub-systems (shared with the other unit) shall be OPERABLE. 1.1. Two OPERABLE Component Cooling Sub-systems are capable of providing the Residual Heat Removal System with the heat sink required to remove core decay heat when both units are either in COLD SHUTDOWN or REFUELING. 1.2. A Component Cooling Sub-system is comprised off one OPERABLE pump and one OPERABLE heat exchanger. 1.3. To be considered OPERABLE, the Component Cooling Sub-system must meet one of the following conditions: 1.3.1. The sUb-system is operating or; 1.3.2.The sUb-system is in a standby condition and capable of being placed in service by manually starting the standby pump and/or manually unisolating the standby heat exchanger. REACTOR OPERATOR Page 36 of 37 Revision 2, OS/23/2007

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

13. 009-EK1.02 013IMODIFIEDINAPSIH!3IROINAPS//

Unit 1 was operating at 100% power when a LOCA occurred inside containment. The following plant conditions exist:

• The crew is currently implementing 1-E-0, Reactor Trip or Safety Injection.
• Containment pressure is 21 psi a and stable.
• Containment pressure peaked at 25 pSia.
• Core Exit TCs indicate 510°F.
• RCS pressure is 1100 psig.
• Total high-head safety injection flow to the core is 500 gpm.

Based on these plant conditions, the Reactor Coolant Pumps should _ _ __ A. not be secured B. be secured because RCS pressure is less than 1275 psig C'!'" be secured due to low subcooling O. be secured due to loss of component cooling flow Feedback

a. Incorrect. Plausible since this would be correct if not for adverse containment conditions.

b. Incorrect. Plausible as low RCS pressure is one component of subcooling, however this is part of Charging pump recirc criteria (which also checks if RCPs are secured),

NOT RCP trip criteria.

c. Correct. RCS subcooling is -50 degrees F which is above the normal setpoint but less than the adverse setpoint so the action is required based on plant conditions.

d. Incorrect but plausible under LOCA conditions, however since CNTMT pressure peaked at 25 psia COA is NOT actuated (28 psia setpoint) so CC flow would still be available to the RCPs.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Small Break LOCA Knowledge of the operational implications of the following concepts as they apply to the small break LOCA: Use of steam tables (CFR 41.8/41.10/45.3) Tier: 1 Group: 1 Importance Rating: 3.5/4.2 Technical

Reference:

1-E-O Proposed references to be provided to applicants during examination: Steam Tables Learning Objective: Question History: New additional info:

CONTINUOUS ACTION PAGE FOR l-E-O

1. ADVERSE CONTAINMENT CRITERIA IF either of the following conditions exist, THEN use setpoints in brackets:

0., 20 psia Containment pressure, OR o .. Containment radiation has reached or exceeded 1.0E5 R/hr (70% on High Range Recorder),

2. SI FLOW CRITERIA o IF SI is actuated AND High-Head Cold Leg SI flow is NOT indicated, THEN initiate ATTACHMENT 6, MANUAL VERIFICATION OF SI FLOWPATH.

3. RCP TRIP CRITERIA CLrvV' 'e d-IF both conditions listed below exist, THEN trip all RCPs:

o* Charging Pumps - AT LEAST ONE RUNNING AND FLOWING TO RCS, AND 0.. RCS subcooling based on Core Exit TCs - LESS THAN 25°F [85°F].

4. CHARGING PUMP RECtRC PATH CRITERIA __ Jr<;;Jv-c,-ofcJY

o. IF RCS pressure decreases to less than 1275 psig [1475 psig] AND RCPs tripped, THEN close Charging Pump Recirc Valves.

o .. IF RCS pressure increases to 2000 psig, THEN open Charging Pump Recirc Valves.

5. ECST LEVEL CRITERIA o WHEN the ECST level decreases to 40%, THEN initiate l-AP-22.5, LOSS OF EMERGENCY CONDENSATE STORAGE TANK l-CN-TK-1.

6. CDA ACTUATION CRITERIA

( IF Containment press exceeds 28 psia, THEN do the following: o a. Manually actuate CD cJ ":s~.,- c +cnr' o b. Ensure CC Pumps OPPED. o c. Stop all RCPs. o d. Ensure QS Pumps RUNNING. o e. Ensure QS Pump Discharge MOVs OPEN. t Initiate the following Attachments, when directed by ATTACHMENT 4, EQUIPMENT VERIFICATION: o ~ ATTACHMENT 2, VERIFICATION OF PHASE B ISOLATION o

• ATTACHMENT 3, PRIMARY PLANT VENTILATION ALIGNMENT

7. FAULTED SG ISOLATION o IF SI is in progress, THEN ATTACHMENT 7, FAULTED SG ISOLATION may be used for guidance on faulted SG(s) isolation and AFW flow control.

8. RUPTURED SG ISOLATION o IF SI is In progress, THEN ATTACHMENT 8, RUPTURED SG ISOLATION may be used for guidance on ruptured SG{s) Isolation and AFW flow control.

9. CONTAINMENT RECIRC MODE CRITERIA o To prevent possible radioactive release from the RWST, VCT level should be maintained greater than 12%.

10. RCP CRITERIA o Seal injection flow should be maintained to all RCPs.

11. REACTIVITY CONTROL CRITERIA o An Operator should be sent to focally close and lock 1-CH-217, PG to Blender Isolation Valve.

STUDENT GUIDE FOR EMERGENCY PROCEDURES (92) 4.2. However, once adverse containment setpoints are implemented as a result of high radiation levels, they are to be used for the duration of the event even if containment radiation levels decrease below 105 Rlhr. 4.3. Instruments exposed to excessive radiation are subject to cumulative damage. 4.4. As such, an engineering evaluation must be performed on the affected instruments to determine the extent of damage prior to terminating the use of adverse setpoints. 4.5. It is essential that the unit supervisor/procedure reader be informed immediately when conditions are met to enter or exit adverse containment criteria. 4.6. The STA can assist in monitoring for adverse containment conditions since they will be monitoring these parameters anyway as part of the Critical Safety Functions. 2.3 Objective U 12451 Explain the following concepts concerning the reactor coolant pump (RCP) trip criteria in the emergency response guideline procedures.

• Type of accident that requires the RCP trip criteria to be met in order to ensure that core protection is provided
• Consequences of not tripping the RCPs when the criteria are met
• Conditions that require the RCPs to be tripped
• Why RCPs should remain running when no high-head safety injection flow is being delivered to the RCS
• Why RCS subcooling based on core exit thermocouples is used as an RCP trip criteria 2.3 Content

1. Running reactor coolant pumps during accident conditions is beneficial in most cases.

1.1. Reactor coolant pumps enhance core decay heat removal since they provide forced flow circulation of the reactor coolant. 1.2. In addition, reactor coolant pump operation allows the use of pressurizer spray for RCS pressure control. REACTOR OPERATOR Page 33 of 187 Revision 19, 11/06/2008

STUDENT GUIDE FOR EMERGENCY PROCEDURES (92) ( 1.3. However, under certain accident conditions running reactor coolant pumps for extended periods could result in negative consequences. 1.4. The foldout page of E-O contains criteria, which directs the operator to trip the reactor coolant pumps based on observed plant conditions. 1.5. Reactor coolant pump trip criteria is generally required for small-break-Ioss-of-coolant accidents. 1.6. Reactor Coolant System inventory depletion exasperated by extended reactor coolant pump operation could cause the core to uncover under certain conditions.

2. During small break loss-of-coolant accidents, the major objective is to leave the reactor coolant pumps running until the point at which the RCS break becomes uncovered.

2.1. When RCS inventory has been reduced to the point where the break is uncovered, the reactor coolant pumps are secured in order to allow the coolant to separate into a distinct liquid and vapor phase. 2.2. Once phase separation occurs, steam will vent from the RCS break. 2.3. Venting steam will allow for a greater RCS pressure reduction with minimum RCS inventory depletion. 2.4. As RCS pressure is reduced, more high-head safety injection flow will be delivered to the core. 2.5. If reactor coolant pump operation continues beyond the point at which the break uncovers, excessive RCS inventory depletion will occur as a two-phase water steam mixture issues from the break. 2.6. The core would uncover if the reactor coolant pumps were to be tripped later in the event. 2.7. After the phase separation occurs, the core would be blanketed by steam since insufficient liquid inventory would be present.

3. All reactor coolant pumps must be tripped when the following criteria is satisfied:

3.1. At least one charging pump must be running and flowing to the RCS and; 3.2. RCS subcooling based on core exit thermocouples is less than 25°F [85°]. REACTOR OPERATOR Page 34 of 187 Revision 19, 11/06/2008

STUDENT GUIDE FOR EMERGENCY PROCEDURES (92)

4. If high head safety injection is not in service, the reactor coolant pumps should be left running even when the subcooling criterion is met.

4.1. Without a source of high-pressure makeup to the RCS, the core would eventually uncover once the reactor coolant pumps are secured and the phase separation occurs. 4.2. Following the phase separation, depletion of RCS inventory will continue with no make up. 4.3. As such, the reactor coolant pumps are left running to allow the circulation of a two-phase mixture and ensure that some degree of core cooling is maintained. 4.4. Additionally, continued reactor coolant pump operation will help expedite RCS depressurization. 4.5. Makeup for RCS inventory depletion will occur once the RCS has been depressurized to the point where injection of the safety injection accumulators occurs followed by LHSI flow.

5. It should be noted that it is not necessary to secure the reactor coolant pumps unless there is a loss of RCS inventory.

5.1. The rate at which RCS inventory is lost begins to decrease only when the break uncovers and the reactor coolant pumps are secured (only steam flow out the break). 5.2. RCS subcooling is used to monitor the extent of RCS voiding during a small-break-Ioss-of-coolant accident. 5.3. The upper core area will be the first region of the core to uncover when the reactor coolant pumps are secured. 5.4. It is therefore prudent to monitor RCS subcooling using the temperature at the core exit. 5.5. As long as adequate RCS subcooling exists, RCS inventory should be such that the upper region of the core will remain covered if the reactor coolant pumps are tripped. 5.6. If RCS subcooling based on core exit thermocouples is adequate, the reactor coolant pumps should be left running. 5.7. Their continued operation will enhance core cooling and RCS pressure control. 5.8. However, inadequate core subcooling is an indication of excessive RCS voiding. 5.9. In this case, the reactor coolant pumps should be secured to minimize RCS inventory loss and the potential for uncovering the core. REACTOR OPERATOR Page 35 of 187 Revision 19, 11/06/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

14. OlO-K5.01 014INEW/1H/3IROINAPS//

Operators are stabilizing the plant following a reactor trip due to a loss of offsite power. The following plant conditions exist:

• RCS temperature is 551°F and stable.
• PRZR pressure is 2100 psig and stable with one group of heaters energized.
• PRZR liquid temperature is 600°F and stable.
• Charging flow is 40 gpm and constant with 1-CH-FCV-1122 in MANUAL.
• Seal injection flows are 8 gpm each.
• Sealleakoff flows are 3 gpm each.

PRZR level increased to 35%; the crew has just placed 1-CH-HCV-1200B in service and letdown flow indicates 73 gpm. Which ONE of the following describes the plant response? A. PRZR level will remain stable; PRZR pressure will remain stable B. PRZR level will decrease; PRZR pressure will remain stable C. PRZR level will remain stable; PRZR pressure will decrease D'! PRZR level will decrease; PRZR pressure will decrease

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Feedback

a. Incorrect. Second part plausible if candidate bases pressure response on vapor temperature or concludes that level is constant and pressure will be held up because of that; first part plausible if flow balance not correctly determined.

b. Incorrect. Second part plausible if candidate bases pressure response on vapor temperature; first part correct flow balance given means there is an 18 gpm mismatch so level will decrease.

c. Incorrect. Second part is correct; first part plausible if flow balance not correctly determined.

d. Correct. Second part is correct, as level decreases due to charging letdown mis-match pressure will approach saturation pressure for PRZR liquid temperature (decrease); first part correct flow balance given means there is an 18 gpm mismatch so level will decrease.

Notes Pressurizer Pressure Control System (PZR PCS) Knowledge of the operational implications of the following concepts as the apply to the PZR PCS: Determination of condition of fluid in PZR, using steam tables (CFR: 41.5 / 45.7) Tier: 2 Group: 1 Importance Rating: 3.5/4.0 Technical

Reference:

1-ES-0.1 and background document Proposed references to be provided to applicants during examination: Steam Tables Learning Objective: Question History: New additional info: Question based on flow balance and generic EOP step "turn on PRZR heaters to saturate the PRZR".

STEP DESCRIPTION TABLE FOR ES-l.l Step 23 STEP: Check RCP Status - AT LEAST ONE RUNNING PURPOSE: To establish forced coolant flow, if possible, or to verify natural circulation flow if RCPs cannot be started BASIS: Forced coolant flow is the preferred mode of operation to allow for normal RCS cooldown and provide PRZR spray. If no RCP is running, certain conditions are normally desired prior to starting an RCP. In addition, RCPs are normally started in a preferred order to obtain normal PRZR spray flow capability as soon as possible. If RCPs cannot be started, then natural circulation flow should be verified using Attachment A to ensure adequate RCS heat removal. If natural circulation cannot be verified, steam dump should be increased to remove heat from the primary system and reestablish natural circulation. Refer to the document NATURAL CIRCULATION in the Generic Issues section of the Executive Volume for additional discussion on natural circulation and the conditions listed in Attachment A. To limit the pressure decrease upon RCP restart, saturated conditions should first be established in the PRZR. If the PRZR is not saturated, starting an RCP will cause the PRZR level and pressure to decrease faster than if the PRZR were saturated. The PRZR pressure and level will still decrease when an RCP is started under saturated conditions, but the rate of decrease is slower since vapor is created as the pressure drops. If all seal cooling has been lost long enough that the maximum RCP seal parameters identified in the RCP Vendor Manual have been exceeded, seal injection and CCW thermal barrier cooling should not be established to the affected RCP(s). Both of these methods of seal cooling could have unintended consequences that result in additional pump damage or the failure of plant safety systems. Seal cooling should instead be restored by cooling the RCS, which will reduce the temperature of the water flowing through the pump seals. ES-l.l Background 48 HP-Rev. 2, 4/30/2005 HESIIBG.doc

STEP DESCRIPTION TABLE FOR ES-1.1 Step 23 ACTIONS: o Determine if igf~IIUlII~lImlIlIiD[~IILi~ !'l1llll~t!g _. _____________ , J.- o Determine if an RCP cannot be started ,, o Determine if RVLIS upper range is less than (J.01)% o Increase PRZR level to greater than (D.10)% [(D.11)% for adverse containment] o Increase RCS subcooling based on core exit TCs to greater than (R.05)OF [(R.06)OF for adverse containment] o Use PRZR heaters, as necessary to saturate the pressurizer water o Determine if natural circulation cannot be verified o Establish conditions for an RCP o Start l,iRIII.iJIIUlnl!:gilll1 _.... _ ....... J . . o Refer to Attachment A to verify natural circulation o Increase dumping steam INSTRUMENTATION: o PRZR level indication o RVLIS upper range indication o RCP status indication o RCP support conditions status indications oRCS pressure indication o Core exit TCs temperature indication o Steam pressure indication oRCS hot leg temperature indication oRCS cold leg temperature indication o PRZR heater status indication o Position indication for: Condenser steam dump valves SG PORVs CONTROL/EQUIPMENT: o RCP switches o RCP support equipment controls o Controls for: Steam dump to condenser SG PORVs PRZR heaters ES-1.1 Background 49 HP-Rev. 2, 4/30/2005 HESllBG.doc

STUDENT GUIDE FOR PRESSURIZER CONTROL AND PROTECTION SYSTEM (74) Pressurizer Pressure Control and Protection System Overview 1.1 Objective U 8848 Describe what occurs during a pressurizer insurge and outsurge. 1.1 Content

1. An insurge occurs when RCS temperature has increased, such as on a reduction in steam demand.

1.1. When RCS temperature increases, the volume of the coolant increases, causing an insurge of water to the PRZR. 1.2. The insurge causes a compression of the steam bubble. 1.3. As compression occurs, the pressure in the PRZR increases. 1.4. When Psat rises above Tsat, some of the saturated steam will condense, mitigating the pressure increase. 1.5. If pressure rises high enough, the spray valves open, spraying into the steam bubble, condensing some of the bubble, further mitigating the pressure rise.

2. An outsurge occurs when RCS temperature has decreased, such as on an increase in steam demand.

2.1. When RCS temperature decreases, the volume of the coolant decreases, causing an outsurge of

         . water from the PRZR.

2.2. As the outsurge continues, the steam bubble expands causing a drop in RCS pressure 2.3. As Psat goes below Tsat, some of the saturated liquid will flash to steam, mitigating the magnitude of the pressure drop. 2.4. If pressure drops low enough, the heaters will energize in order to increase the liquid temperature, raising pressure and restoring it to normal. ( REACTOR OPERATOR Page 4 of 52 Revision 1, 05/02/2007

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

15. 012-KS.02 OlSIMODIFIEDINAPS/H/3IROINAPSII The ensures that the allowable heat generation rate (kw/ft) is not exceeded; the setpoint for this trip is _ _ _ _ _ __

A. Overpower DT trip; 126.4% B~ Overpower DT trip; 107.9% C. Power Range Neutron Flux trip - High SIP; 109% D. Power Range Neutron Flux trip - High SIP; 110% Feedback

a. Incorrect. Trip is correct, second part is incorrect but plausible since this is the OTL\T setpoint.

b. Correct. Trip is correct, second part is also correct.

c. Incorrect. Plausible since kw/ft does imply "power" but this trip is to prevent DNB as discussed in Tech Spec Bases 3.3.1, second part is correct.

d. Incorrect. This trip is for DNB as discussed above, second part incorrect but plausible since this is the allowable value from Table 3.3.1-1 of Tech Specs.

Notes Reactor Protection System Knowledge of the operational implications of the following concepts as the apply to the RPS: Power density (CFR: 41.5 145.7) Tier: 2 Group: 1 Importance Rating: 3.1/3.3 Technical

Reference:

RPS lesson plan Proposed references to be provided to applicants during examination: None Learning Objective: Question History: New additional info:

RTS Instrumentation B 3.3.1 BASES APPLICABLE 6. Overtemperature AT (continued) SAFETY ANALYSES. LCO, channels shared with other RTS Functions. Failures that and affect multiple Functions require entry into the APPLICABILITY Conditions applicable to all affected Functions. In MODE 1 or 2, the Overtemperature AT trip must be OPERABLE to prevent DNB. 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 AT The Overpower AT trip Function ensures that protection

                        ;s 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. This trip Function also limits the required range of the Overtemperature AT trip Function and provides a backup to the Power Range Neutron Flux-High Setpoint trip. The Overpower AT trip Function ensures that the allowable heat generation rate (kW/ft) of the fuel is not exceeded. It uses the AT of each loop as a measure of

( reactor power with a setpoint that is automatically varied with the following parameters:

• reactor coolant average temperature-the 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. The function generated by the rate lag controller for Tavg dynamic compensation is represented by the expression: t3s/1+t3S. The time

                          ~onstant utilized in the rate lag controller for Tava 1 S t3'                                                -

The Overpower AT trip Function is calculated for each loop as per Note 2 of Table 3.3.1-1. Trip occurs if Overpower AT is indicated in two loops. Note that this Function also provides a signal to generate a turbine runback prior to reaching the Allowable Value. A turbine runback will reduce turbine power and reactor power. (continued) ( North Anna Units 1 and 2 B 3.3.1-18 Revision 0

RTS Instrumentation Trip Setpoints 4.3 Table 4.3-1 (page 4 of 4) Reactor Trip Instrumentation Trip Setpoints Note 2: Overpower 6. T~ 6. To[K4 - KS(l :3:3 S) T- K6(T - r) - f 2(6.1)]

. Where:      6.To = Indicated 6.T at RTP T = Average temperature, of TI = Indicated Tavg at RTP ~ 586.8°F K4 = 1.079 Ks = 0.02/oF for increasing average temperature Ks = o for decreasing average temperature K6 = 0.00164 for T > TI K6 = o for T ~ TI
                    =   The function generated by the rate lag controller for Ta'{g dynamic compensation 1:3 -'Time constants utilized in the rate lag controller for Tav9 1:3 = 10 secs
                ,S = Laplace transform operator (sec- l )

f2 (6.I) = 0 for all 6.1 NAPSTRM 4.3-5 Rev 46, 04/02/04

RTS*lnstrumentation Trip Setpoints 4.3 ( Table 4.3-1 (page 3 of 4) Reactor Trip Instrumentation Trip Setpoints Note 1: Where: ATo = Indicated AT at RTP T = Average temperature, of T' = Indicated Tav9 at RTP S 586.8°F P = Pressurizer pressure. pSig P' = 2235 psig (indicated ReS nominal operating pressure) 1 + 't 1S

                    = The function generated by the lead-lag controller for Tavg 1 +'t2S         dynamic compensation t1  & 't2 = Time constants utilized in the lead-lag controller for Tav9
                        'tl = 25 secs, 't2 = 4 secs S = Laplace transform operator (sec-i)

Kl - '\~264 & \ SJ.ra..c.~ K2 = 0.0220 K3 = O~001152 and fl{Al) is a function of the indicated difference between top and bottom detectors of the power-range nuclear ion chambers; with gains to be selected based on measured instrument response during plant startup tests such that: (i) for qt - qb between -35 percent and +3 percent, fl (AI) = 0 (where qt and qb are percent RTP in the top and bottom halves of the core respectively, and qt + qb is total THERMAL POWER in percent of RTP). (ii) for each percent that the magnitude of (qt - qb) exceeds -35 percent, I the AT trip setpoint shall be automatically reduced by 1.67 percent of its value at RTP. (iii) for each percent that the magnitude of (qt - qb) exceeds +3 percent, the AT trip setpoint shall be automatically reduced by 2.00 percent of its value at RTP. NAPS TRM 4.3-4 Rev 46, 04/02/04

RTS Instrumentation B 3.3.1 BASES APPLICABLE 2. Power Range Neutron Flux SAFETY ANALYSES, LCO. The NIS power range detectors are located external to and the reactor vessel and measure neutrons leaking from the APPLICABILITY core. The NIS power range detectors provide input to the (continued) Rod Control System and the Steam Generator (SG) Water Level Control System. Therefore, 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. Note that this Function also provides a signal to prevent automatic and manual rod withdrawal prior to initiating a reactor trip. Limiting further rod withdrawal may terminate the transient and eliminate the need to trip the reactor.

a. Power Range Neutron Flux-High The Power Range Neutron Flux-High trip Function ensures that protection is provided, from all power levels, against a positive reactivity excursion leading to DNB during power operations. These can be caused by rod withdrawal or reductions in ReS temperature.

The LCO requires all four of the Power Range Neutron Flux-High channels to be OPERABLE. In MODE 1 or 2, when a positive reactivity excursion could occur, the Power Range Neutron Flux-High trip must be OPERABLE. This Function will terminate the reactivity excursion and shut down the reactor prior to reaching a power level that could damage the fuel. In MODE 3, 4, 5, or 6, the NIS power range detectors cannot detect neutron levels in this range. In these MODES, the Power Range Neutron Flux-High does not have to be OPERABLE because the reactor is shut down and reactivity excursions into the power range are extremely unlikely. Other RTS Functions and administrative controls provide protection against reactivity additions when in MODE 3, 4, 5, or 6. North Anna Units 1 and 2 B 3.3.1-11 Revi sian {)

RTS Instrumentation 3.3.1 ~, Table 3.3.1-1 (page 1 of 5) Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS ALLOWABLE VALUE

1. Manual Reactor Trip I, 2 2 B SR 3.3.1.14 NA 3(a). 4(a). Sea) 2 C SR 3.3.1.14 NA

2. tower Range Neutt:12D Ellix

                                ~                                              I, 2          4          D     SR SR SR 3.3.1.1 3.3.1.2 3.3.1.3 SR  3.3.1.7
                     .. _------_....._--_.._-_._..... _ . __.                                                 SR 3.3.1.11 SR 3.3.1.16

b. Low 1(b). 2 4 E SR 3.3.1.1 S 26% RTP SR 3.3.1.8 SR 3.3.1.11 SR 3.3.1.16

3. Power Range Neutron Flux Rate

a. High Positive Rate I, 2 4 E SR 3.3.1.7 S 5.5%RTP SR 3.3.1.11 with time constant

                                                                                                                            ~    2 sec

',( ~

b. High Negative Rate I, 2 4 E SR 3.3.1.7 SR 3.3.1.11

                                                                                                                            $    5.5% RTP with time SR 3.3.1.16   constant
                                                                                                                            ~ 2 sec

4. Intermediate Range Neutron Flux 1 (b). 2{c) 2 F~ G SR 3.3.1.1 S 40% .RT-P SR 3.3.1.8 SR 3.3.1.11

5. Source Range Neutron Flux Zed) 2 H, I SR 3.3.1.1  :::; 1.3 E5 cps SR 3.3.1.8 SR 3.3.1.11 SR 3.3.1.16 3{a). 4(a). Sea) 2 I. J SR 3.3.1.1  :;; 1.3 E5 cps SR 3.3.1.7 SR 3.3.1.11 SR 3.3.1.16 3{e), 4(e), see) K SR 3.3.1.1 NA SR 3.3.1.11 (al With Rod Control System capable of rod withdrawal or one or more rods not fully inserted.

(b) Below the P-IO (Power Range Neutron Flux) interlocks. (c) Above the P-6 (Intermediate Range Neutron Flux) interlocks. (d) Below the P-6 (Intermediate Range Neutron Flux) interlocks. ee) With the Rod Control System incapable of rod withdrawal. In this condition, source range Function does not provide reactor trip but does provide indication

• North Anna Units 1 and 2 3.3.1-13 Amendments 231/212

RTS Instrumentation Trip Setpoints

                                                                     .                   4.3
                                                   \J Table 4.3-1 (page 1 of 4)

Reactor Trip Instrumentation Trip Setpo1nts FUNCTION TRIP SETPOINT

1. Manual Reactor Trip N.A.

2. Power Range Neutron Flux . cA~c~

a~ High SetPoint~ RTP

b. Low low Setpoint: ~ 25% of RTP

3. Power Range Neutron Flux Rate

a. High Positive Rate ~ 5% of RTP with a time constant

                                       ~   2.25 seconds

b. High Negative Rate ~ 5% of RTP with a time constant

                                       ~   2.25 seconds

4. Intermediate Range Neutron ~ 35% of RTP Flux

5. Source Range Neutron Flux ~ lE5 cps "':.:"':

6. Overtemperature AT See Note 1

7. Overpower AT See Note 2  ; ~.' .,. "

8. Pressurizer Pressure 'j' ;" !"':" ~:: ;..'. f' .

a. low ~ 1870 psig

b. High ~ 2360 psig

9. Pressurizer Water Level-High  ::; 92%

10. Reactor Coo 1ant Flow-Low. ~ 90%

II. Reactor Coolant Pump (Rep) N.A. Breaker Position

12. Undervo 1ta.ge Reps ~ 3013.5. volts-each bus

13. Underfrequency Reps ~ 56.3 Hz-each bus

14. Steam Generator (SG) Water ~18%

leve l-Low Low

15. 5G Water Level-low ~ 25%

COincident with Steam ~ 40% of full steam flow at RTP Flow/Feedwater Flow Mismatch NAPS TRM 4.3-2 Rev 46. 04/02/04

STUDENT GUIDE FOR REACTOR PROTECTION SYSTEM (77 -A) Reactor Trips and Interlocks 3.1 Objective U 8964 List the following information as it applies to each of the automatic reactor trips.

• Instruments that supply the trip signal
• Coincidence and setpoint
• Interlocks associated with enabling and/or disabling the trip 3.1 Content Use graphic SB1211C, CS1576A, and BP142 (or similar) to review reactor trips.

3.2 Objective U 8965 Explain the technical specification basis for each of the automatic reactor trips (TS-3.3.1). 3.2 Content Use graphic SB1211C to explain.

1. The Technical Specifications Bases for each reactor trip are as follows:

1.1. Manual Reactor Trip - backup to automatic reactor trip, gives manual trip capability. 1.2. Power-range neutron flux (low setpoint) reactor trip - provides protection against positive reactivity excursion beginning from low power conditions. 1.3. Power-range neutron flux (high setpoint) reactor trip - provides reactor protection against a positive reactivity excursion leading to DNB during power operations. These can be caused by rod withdrawal or reductions in RCS temperature. REACTOR OPERATOR Page 16 of 49 Revision 2, OS/24/2007

STUDENT GUIDE FOR REACTOR PROTECTION SYSTEM (77 -A) ( 1.13. Loss of flow reactor trip - provide core protection to prevent DNB in event of one or more reactor coolant pumps is lost. 1.13.1. Reactor Coolant Pump (RCP) breaker position anticipates the reactor coolant flow low trips to avoid RCS heatup that would occur before the low flow trip actuates. 1.14. Steam generator water level low/low reactor trip - protection of core by preventing operation with steam generator level below minimum volume for heat removal capacity and actuates the Auxiliary Feedwater (AFW) System prior to uncovering the SG tubes. 1.15. Steam/Feed water flow mismatch and low steam generator water level - anticipatory loss of heat sink redundant to low-low level trip; ensures that protection is provided against a loss of heat sink. 1.16. Undervoltage on reactor coolant pump bus - protects against DNB due to a loss of flow in two or more RCS loops, and ensures trip signal generated before the low flow trip setpoint is reached. 1.16.1. Time delays prevent spurious trips from electrical transients. 1.17. Underfrequency on reactor coolant pump bus - protects against DNB due to a loss of flow in two or more RCS loops, and ensures trip signal generated before low flow trip setpoint is reached. 1.17.1. Time delays prevent spurious trips from electrical transients. 1.18. Turbine trip reactor trip - reduces severity of transients. 1.19. Safety injection reactor trip - protects core against LOCA and backs up reactor trip. 1.20. General Warning - not Tech Spec. 3.3 Objective U 8898 Explain what protection is afforded by the following reactor trips.

• Overtemperature ~T REACTOR OPERATOR Page 18 of 49 Revision 2, OS/24/2007

STUDENT GUIDE FOR REACTOR PROTECTION SYSTEM (77 -A)

• Overpower ~T 3.3 Content

1. Overtemperature Delta-T reactor trip - protects core against DNB, provided transient is slow with respect to piping transient delays from core to temperature detectors and pressure is between high and low trip setpoints (three loop flow is assumed). This trip function also limits the range over which OP Delta-T must provide protection.

2. Overpower Delta-T reactor trip - protects against fuel melt, limits clad strain to less than 1%, backs up the power range high flux trip and limits OT Delta-T required range of protection.

3.4 Objective U 10353 Explain how changes in Reactor Coolant System pressure and T avg will affect the following reactor trip setpoints.

• Overtemperature ~T
• Overpower ~T 3.4 Content

1. Overtemperature Delta-T setpoints are affected by changes in RCS temperature and pressure.

1.1. Increasing temperature, decreasing pressure, or AFD outside of the band (-35% to +3%) will cause the OT Delta-T setpoint to be decreased (minus adjustment). 1.2. Decreasing temperature or increasing pressure will cause the OT Delta-T setpoint to be increased (plus adjustment).

2. Overpower Delta-T setpoints are affected by changes in RCS temperature.

2.1. Increasing temperature will cause the OP Delta-T setpoint to be decreased (minus adjustment). REACTOR OPERATOR Page 19 of 49 Revision 2, 05/24/2007

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

16. 013-K6.01 016IMODIFIEDINAPSIHI3IROINAPS//

Given the following conditions:

• Unit 1 is at 100% power.
• Containment Pressure Protection Channel II (1-LM-P-100B) failed on the previous shift.
• All bistables for the failed channel have been placed in TEST in accordance with 1-MOP-55.75, Containment Pressure Protection Instrument.

Subsequently, Containment Pressure Protection Channel III (1-LM-P-100C) fails HIGH. Which ONE of the following identifies the response of the Engineered Safeguards Features Actuation System? A. No automatic actuations. B. Safety Injection actuation ONLY. C~ Safety Injection actuation and Main Steam Line Isolation ONLY. O. Safety Injection actuation, Main Steam Line Isolation, and CDA. Feedback

a. Incorrect. Plausible since Ch. I of containment pressure is ONLY used for COA, thus if Ch. I were the failed channel vice channel" this answer would be the correct answer.

b. Incorrect. Plausible because this will occur; only the Hi-Hi bistables are bypassed when placing a channel in test, but if candidate mistakenly assumes the intermediate hi-hi bistables are also bypassed they would conclude that this is the correct answer.

c. Correct. 2/3 logic is made up and these functions will actuate.

d. Incorrect. Plausible since candidate may not be aware that the hi-hi bistable is bypassed when taken to test and thus conclude that this is the correct answer.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Engineered Safety Features Actuation System (ESFAS) Knowledge of the effect of a loss or malfunction on the following will have on the ESFAS: Sensors and detectors (CFR: 41.7/45.5 to 45.8) Tier: 2 Group: 1 Importance Rating: 2.7/3.1 Technical

Reference:

RPS lesson plan and MOP-56.75 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: New additional info:

DOMINION 1-MOP-55.75 North Anna Power Station Revision 7 Page 8 of 25 5.2 Placing Containment Pressure Protection Channel II (P-LM-100B) in Test 5.2.1 Verify Initial Conditions are satisfied. 5.2.2 Review Precautions and Limitations.

DOMINION 1-MOP-55.75 North Anna Power Station Revision 7 Page 90f25 CAUTION IF one of the coincident channel annunciators is LIT, THEN the following apply:

• Placing this channel in TEST could cause a Safety Injection, Steam Line Isolation, Containment Spray, or Phase "B" isolation.
• IF placing this channel in TEST would cause a Reactor Protection System actuation, THEN comply with the following:
• The channel must NOT be placed in TEST .
• The unit must be placed in the mode required by Tech Spec 3.0.3.

NOTE: Placing Bistable (BS) switch CB-425, BS-3 (I-LM-PTS-IOOB-3) in TEST will put HI-HI Containment Pressure Channel II in TEST BYPASS and block an output to SSPS for Spray Actuation (Containment depressurization) and Containment Isolation Phase B. 5.2.3 Verify coincident channels are not in bypass by verifying the following annunciators are NOT LIT:

• Panel "K" H-4, CONTAINMENT DEPRESSURIZTN ACT BISTABLE BYPASSED
• Panel "N" D-5, CNTMT PRESS HI-HI TEST BYP CHNL I
• Panel "N" D-7, CNTMT PRESS HI-HI TEST BYP CHNL III
• Panel "N" D-8, CNTMT PRESS HI-HI TEST BYP CHNL IV

DOMINION 1-MOP-55.75 North Anna Power Station Revision 7 Page 10 of 25 5.2.4 Verify coincident channels are not tripped by verifying the following annunciators are NOT LIT:

• Panel "N" A-7, CNTMT PRESS HI CHNL III
• Panel "N" A-8, CNTMT PRESS HI CHNL IV
• Panel "N" B-7, CNTMT INTER PRESS HI-HI CHNL III
• Panel "N" B-8, CNTMT INTER PRESS HI-HI CHNL IV 5.2.5 Using Attachment 1, Instrument Rack Room Cabinet Layout, go to the Instrument Rack Room and locate Channel II Protection Cabinet B.

5.2.6 Unlock and open Channel II Protection Cabinet B and verify that annunciator Panel "P" 0-6, PCC CAB II VIOLATED DOOR OPEN, is LIT.

DOMINION 1-MOP-55.75 North Anna Power Station Revision 7 Page 11 of 25 NOTE: Attachment 2, Balance of Plant Typical2-Bay Cabinet, will aid in identifying the correct card and Attachment 3, Process Typical Channel Test Card, will aid in identifying the correct switch on the card. NOTE: The Channel Test Status light on the top edge of the Channel Test Card comes on only when the loop is properly in TEST with the master test switch in NORMAL. Attachment 3 will aid in identifying the Channel Test Status light. 5.2.7 Place the following Bistable (BS) switches in TEST and verify the associated annunciators are LIT and computer alarm prints out (P-250) or actuates (Phase 2 PCS):

a. CB-425, BS-l (l-LM-PTS-lOOB-l) sv

• Panel "N" A-6, CNTMT PRESS HI CHNL II

(

• Panel "K" H-l, CONTAINMENT HI PRESS CH II-Ill-IV
• Computer Point PI002D, CONTAINM HI P 3 SI PART RE (P-250),

OR CONTAINMENT HI PRESSURE CH II (Phase 2 PCS)

b. CB-425, BS-2 (l-LM-PTS-IOOB-2) sv

• Panel "N" B-6, CNTMT INTER PRESS HI-HI CHNL II
• Panel "K" H-2, CONTAINMENT INTER HI-HI CONT PRESS CH II-Ill-IV

DOMINION 1-MOP-55.75 North Anna Power Station Revision 7 Page 12 of 25

c. CB-425, BS-3 (l-LM-PTS-100B-3) sv

• Panel "K" H-4, CONTAINMENT DEPRESSURIZTN ACT BISTABLE BYPASSED
• Panel "N" D-6, CNTMT PRESS HI-HI TEST BYP CHNL II 5.2.8 Close and lock Channel II Protection Cabinet B and verify that annunciator Panel "P" G-6, PCC CAB II VIOLATED DOOR OPEN, is NOT LIT.

5.2.9 Record the failed instrument channel in the Action Statement Status Log. 5.2.10 Notify the Instrument Department that Containment Pressure Protection Channel II (P-LM-IOOB) failed and has been placed in trip. Completed by: _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ Date: - - - -

DOMINION 1-MOP-55.75 North Anna Power Station Revision 7 Page 13 of 25 5.3 Placing Containment Pressure Protection Channel III (P-LM-IOOC) in Test 5.3.1 Verify Initial Conditions are satisfied. 5.3.2 Review Precautions and Limitations.

DOMINION 1-MOP-55.75 North Anna Power Station Revision 7 Page 14 of 25 CAUTION IF one of the coincident channel annunciators is LIT, THEN the following apply:

• Placing this channel in TEST could cause a Safety Injection, Stearn Line Isolation, Containment Spray, or Phase "B" isolation.
• IF placing this channel in TEST would cause a Reactor Protection System actuation, THEN comply with the following:
• The channel must NOT be placed in TEST.
• The unit must be placed in the mode required by Tech Spec 3.0.3.

NOTE: Placing Bistable (BS) switch CC-423, BS-3 (l-LM-PTS-IOOC-3) in TEST will put HI-HI Containment Pressure Channel III in TEST BYPASS and block an output to SSPS for Spray Actuation (Containment depressurization) and Containment Isolation Phase B. 5.3.3 Verify coincident channels are not in bypass by verifying the following annunciators are NOT LIT:

• Panel "K" H-4, CONTAINMENT DEPRESSURIZTN ACT BISTABLE BYPASSED
• Panel "N" D-5, CNTMT PRESS HI-HI TEST BYP CHNL I
• Panel "N" D-6, CNTMT PRESS HI-HI TEST BYP CHNL II
• Panel "N" D-8, CNTMT PRESS HI-HI TEST BYP CHNL IV

DOMINION 1-MOP-55.75 North Anna Power Station Revision 7 Page 15 of 25 5.3.4 Verify coincident channels are not tripped by verifying the following annunciators are NOT LIT:

• Panel "N" A-6, CNTMT PRESS HI CHNL II
• Panel "N" A-8, CNTMT PRESS HI CHNL IV
• Panel "N" B-6, CNTMT INTER PRESS HI-HI CHNL II
• Panel "N" B-8, CNTMT INTER PRESS HI-HI CHNL IV 5.3.5 Using Attachment 1, Instrument Rack Room Cabinet Layout, go to the Instrument Rack Room and locate Channel III Protection Cabinet C.

5.3.6 Unlock and open Channel III Protection Cabinet C and verify that ( annunciator Panel "P" G-7, PCC CAB III VIOLATED DOOR OPEN, is LIT.

DOMINION 1-MOP-55.75 North Anna Power Station Revision 7 Page 16 of 25 ( NOTE: Attachment 2, Balance of Plant Typical2-Bay Cabinet, will aid in identifying the correct card and Attachment 3, Process Typical Channel Test Card, will aid in identifying the correct switch on the card. NOTE: The Channel Test Status light on the top edge of the Channel Test Card comes on only when the loop is properly in TEST with the master test switch in NORMAL. Attachment 3 will aid in identifying the Channel Test Status light. 5.3.7 Place the following Bistable (BS) switches in TEST and verify the associated annunciators are LIT and computer alarm prints out (P-250) or actuates (Phase 2 PCS):

a. CC-423, BS-l (l-LM-PTS-IOOC-l) sv

• Panel "N" A-7, CNTMT PRESS HI CHNL III
• Panel "K" H-l, CONTAINMENT HI PRESS CH II-Ill-IV
• Computer Point PIOOID, CONTAINM HI P 2 SI PART RE (P-250),

OR CONTAINMENT HI PRESSURE CH III (Phase 2 PCS)

b. CC-423, BS-2 (1-LM-PTS-IOOC-2) sv

• Panel "N" B-7, CNTMT INTER PRESS HI-HI CHNL III
• Panel "K" H-2, CONTAINMENT INTER HI-HI CONT PRESS CH II-Ill-IV

DOMINION 1-MOP-55.75 North Anna Power Station Revision 7 Page 17 of 25

c. CC-423, BS-3 (l-LM-PTS-100C-3) sv

• Panel "K" H-4, CONTAINMENT DEPRESSURIZTN ACT BISTABLE BYPASSED
• Panel "N" D-7, CNTMT PRESS HI-HI TEST BYP CHNL III 5.3.8 Close and lock Channel III Protection Cabinet C and verify that annunciator Panel "P" G-7, PCC CAB III VIOLATED DOOR OPEN, is NOT LIT.

5.3.9 Record the failed instrument channel in the Action Statement Status Log. 5.3.10 Notify the Instrument Department that Containment Pressure Protection Channel III (P-LM-100C) failed and has been placed in trip. Completed by: _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ Date: - - - -

STUDENT GUIDE FOR REACTOR PROTECTION SYSTEM (77 -A)

10. The (containment) spray test panel contains test pushbuttons to allow testing the associated containment spray energize-to-actuate relays.

Use graphics KC593A and BP141 to explain flowpath. 2.2 Objective U 8959 List the following information as it applies to the Reactor Protection System.

• Input relays that are energize-to-actuate
• Design features that ensure that a loss of power neither causes nor prevents an actuation 2.2 Content

1. The containment spray actuation, and the RCP breaker position reactor trip input relays are normally deenergized, and will energize to actuate. RWST low level energizes to actuate automatic swap to containment sump.

1.1. These functions are energize-to-actuate, to prevent inadvertent containment spray actuation, to prevent reactor trip on loss of vital bus power, and to prevent inadvertent automatic re-alignment of the Emergency Core Cooling System to cold-leg recirculation mode.

2. To ensure that a loss of power neither causes nor prevents an actuation:

2.1. Coincidence is tested to ensure that one input won't cause an actuation, and that two inputs will cause an actuation. REACTOR OPERATOR Page 11 of 49 Revision 2, OS/24/2007

STUDENT GUIDE FOR c REACTOR PROTECTION SYSTEM (77 -A) 4.2. This will not cause a trip, unless a redundant channel is also in a tripped condition for all trips but two. The two trips that will occur on a loss of power to a single channel are SOURCE RANGE HIGH FLUX and INTERMEDIATE RANGE HIGH FLUX unless they are blocked.

5. The train "A" and train "8" logic cabinets provide outputs from the universal logic cards to the Control 80ard (Hathaway demultiplexer vital bus IV) and Computer Demultiplexers (inverter from dc bus III), for the purpose of actuating Main Control Room annunciator alarms, status lights and computer alarms.

Use graphic KC593A to explain flowpath. 2.4 Objective U 8961 Explain why the following Reactor Protection System input relays are energize-to-actuate.

• Containment depressurization actuation
• Reactor coolant pump breaker position
• Automatic switch over to containment sump (RWST Low-Low Level) 2.4 Content

1. The Containment depressurization actuation is energized to trip to prevent an inadvertent containment spray actuation.

2. The reactor coolant pump breaker position actuation is energized to actuate to prevent a reactor trip on the loss of a vital bus.

3. The automatic switch over to containment sump (RWST Low-Low Level) is energized to actuate to prevent an inadvertent automatic re-alignment of the Emergency Core Cooling System to cold-leg recirculation mode.

REACTOR OPERATOR Page 13 of 49 Revision 2, OS/24/2007

STUDENT GUIDE FOR REACTOR PROTECTION SYSTEM (77 -A) Reactor Trips and Interlocks 3.1 Objective U 8964 List the following information as it applies to each of the automatic reactor trips.

• Instruments that supply the trip signal
• Coincidence and setpoint
• Interlocks associated with enabling and/or disabling the trip 3.1 Content Use graphic SB1211C, CS1576A, and BP142 (or similar) to review reactor trips.

3.2 Objective U 8965 Explain the technical specification basis for each of the automatic reactor trips (TS-3.3.1). 3.2 Content Use graphic SB1211C to explain.

1. The Technical Specifications Bases for each reactor trip are as follows:

1.1. Manual Reactor Trip - backup to automatic reactor trip, gives manual trip capability. 1.2. Power-range neutron flux (low setpoint) reactor trip - provides protection against positive reactivity excursion beginning from low power conditions. 1.3. Power-range neutron flux (high setpoint) reactor trip - provides reactor protection against a positive reactivity excursion leading to DNB during power operations. These can be caused by rod withdrawal or reductions in RCS temperature. REACTOR OPERATOR Page 16 of 49 Revision 2, OS/24/2007

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

17. 015-A2.04 017INEW//H/3IROINAPS//

Given the following conditions:

• A spurious turbine runback occurs and is terminated at 80% power.
• Operators are stabilizing the unit, and annunciator A-H7, A.F.D MONITOR, has just alarmed.

Which ONE of the following identifies the MINIMUM number of NI channels with an AFD that exceeds the allowable limits of the Reactor Data book to consider the alarm valid, and the Technical Specification required action? A. 2 NI channels; reduce power to < 75% within 30 minutes. B:' 2 NI channels; reduce power to < 50% within 30 minutes. C. 3 NI channels; reduce power to < 75% within 30 minutes. D. 3 NI channels; reduce power to < 50% within 30 minutes. Feedback

a. Incorrect. First part is correct; second part is incorrect but plausible since other specs (e.g. rods) have 75% power reductions as required actions.

b. Correct. First part is correct; action requirement (second part) is also correct.

c. Incorrect. Plausible since TS and procedure discuss having 3 channels within limits to be in compliance, candidate may erroneously assume that 3 would need to be out of limits to require action; second part also incorrect as discussed in Distractor A.

d. Incorrect. First part incorrect but plausible as discussed in Distractor C; second part is correct.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Nuclear Instrumentation System Ability to (a) predict the impacts of the followingmalfunctions or operations on the NIS; and (b based on those predictions, use procedures to correct, control, or mitigatethe consequences of those malfunctions or operations: Effects on axial flux density of control rod alignment and sequencing, xenon production and decay, and boron vs. control rod reactivity changes (CFR: 41.5/43.5/45.3/45.5) Tier: 2 Group: 2 Importance Rating: 3.3/3.8 Technical

Reference:

AR-A-H-7 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: New additional info:

AFD 3.2.3 3.2 POWER DISTRIBUTION LIMITS 3.2.3 AXIAL FLUX DIFFERENCE (AFD) LCO 3.2.3 The AFD in % flux difference units shall be maintained within the limits specified in the COLR.

                  - - - - - - - - - - - - NOTE - - - - - - - - - - - - -

The AFD shall be considered outside limits when two or more OPERABLE excore channels indicate AFD to be outside limits. APPLICABILITY: MODE 1 with THERMAL POWER ~ 50% RTP. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. AFD not within limits. A.1 Reduce THERMAL POWER 30 minutes to < 50% RTP. SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.3.1 Verify AFD within limits for each OPERABLE 7 days excore channel. North Anna Units 1 and 2 3.2.3-1 Amendments 231/212

Rod Group Alignment Limits 3.1.4 3.1 REACTIVITY CONTROL SYSTEMS 3.1.4 Rod Group Alignment Limits LCO 3.1.4 All shutdown and control rods shall be OPERABLE. AND Individual indicated rod positions shall be within 12 steps of their group step counter demand position.

                 - - - - - - - - - - - - NOTE - - - - - - - - - - - - -

When THERMAL POWER is ~ 50% RTP, the indicated position of each rod as determined by its individual rod position indicator may be within 24 steps from its group step counter demand position for up to 1 hour per 24 hours. This NOTE is not applicable for control rods known to be greater than 12 steps from the rod group step counter demand position. APPLICABILITY: MODES 1 and 2. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more rod(s) A.1.1 Verify SDM to be 1 hour inoperable. within the limits provided in the COLR. OR A.1.2 Initiate boration to 1 hour restore SDM to within 1i mi t. AND A.2 Be in MODE 3. 6 hours North Anna Units 1 and 2 3.1.4-1 Amendments 231/212

                       - NUCLEAR DESIGN INFORMATION PORTAL--

Rod Group Alignment Limits 3.1.4 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. One rod not within B.1.1 Verify SDM to be 1 hour alignment limits. within the limits provided in the COLR. AND Once per 12 hours thereafter OR B.1.2 Initiate boration to 1 hour restore SDM to within 1imi t. AND B.2.1 Reduce THERMAL POWER 2 hours to ::; 75% RTP. OR B.2.2.1 Perform SR 3.2.1.1. 72 hours AND B.2.2.2 Perform SR 3.2.2.1. 72 hours AND B.3 Re-evaluate safety 5 days analyses and confirm results remain valid for duration of operation under these conditi ons. C. Required Action and C.1 Be in MODE 3. 6 hours associated Completion Time of Condition B not met. North Anna Units 1 and 2 3.1.4-2 Amendments 231/212

VIRGINIA POWER 1-EI-CB-21A ANNUNCIATOR H7 1-AR-A-H7 NORTH ANNA POWER STATION REV. 3 APPROVAL: ON FILE Effective Date: 02/25/03 (- A. F. D. 2 operable Power Range M 0 NIT 0 R detectors ~0 outside operational limits NOTE: Prior to the implementation of DCP 01-007, the input to this annunciator is dependent upon which computer system has been selected on the Unit 1 PCS. 1.0 Probable Cause 1.1 Alarm or Computer malfunction 1.2 Operation with Control Rods inserted too far 1.3 Xenon oscillation 2.0 Operator Action 2.1 Determine alarm validity:

• IF ~0 is outside the allowable limits as determined from the Reactor Data Book on at least 2 Power Range NIs, THEN the alarm is valid.
• IF ~0 is within the allowable limits as determined from the Reactor Data Book on at least 3 Power Range NIs, THEN the alarm is invalid.

2.2 IF alarm is valid, THEN reduce thermal power to <50% RTP within 30 minutes. 2.3 IF alarm is invalid, THEN declare the alarm INOPERABLE, and perform 1-PT-20.1. 3.0 References 3.1 11715-ESK-10A, Sheet 2 3.2 11715-ESK-10AAJ 3.3 Virginia Power Computer Program 3.4 Tech Spec 3.2.3 3.5 Tech Spec SR 3.2.3.1 3.6 COLR 3.7 DCP 01-007, Phase 2 PCS Installation and P-250 Removal 4.0 Actuation 4.1 Unit 1 P-250 Computer program utilizing average nuclear power, Delta Flux Limit Band, and actual Power Range Delta Flux (if Unit 1 P-250 not removed by DCP 01-007) 4.2 Unit 1 PCS program utilizing average nuclear power, Delta Flux Limit Band, and actual Power Range Delta Flux

STUDENT GUIDE FOR EX-CORE NUCLEAR INSTRUMENTATION SYSTEM (62) ( 9.11 Content

1. ITS 3.3.1 actions D. and E. contain a note that allows bypassing an inoperable power range channel for up to 12 hours for surveillance testing and setpoint adjustment of operable channels.

9.12 Objective U 17392 Explain the significance of the occurrence of QPTR alarms at 100% power, with no apparent underlying condition such as a dropped or misaligned rod. 9.12 Content

1. Nuclear Analysis & Fuel determined that the in-core flux was oscillating less than 3%, peak to peak, on approximately 4-second intervals.

1.1. This flux oscillation was postulated (from the Te and RVLl8 data) to be due to a thermo-hydraulic local variation at the core inlet. 1.2. The alarms were determined to be valid for the conditions observed. 1.3. NA&F concluded that all safety analyses were determined to be valid and bounding for the observed conditions. 1.4. Contact reactor engineering when temporary QPTR alarms occur. 9.13 Objective U 10319 Determine the requirements of ITS-3.2.1 if the axial flux difference is not within the limits of the Core Operating Report. 9.13 Content

1. ITS-3.2.1 stipulates that AFD shall be within the limits of the core operating limits report on 3 out of 4 (2 c, out of 3 with one inoperable PRNI) nuclear instruments if in mode 1 above 50% power.

REACTOR OPERATOR Page 66 of 86 Revision 3, 12/11/2007

STUDENT GUIDE FOR EX-CORE NUCLEAR INSTRUMENTATION SYSTEM (62) 1.1. If outside these limits, then ITS-3.2.1 directs the reduction of power to less than 50% within 30 minutes. 9.14 Objective U 10320 Given that one power-range nuclear instrument channel has failed, explain how a quadrant power tilt ratio calculation can be performed. 9.14 Content

1. If a power-range nuclear instrument is inoperable, a QPTR may still be performed.

1.1. This is done either by entering 1,2,3 or 4 as applicable into VALUE 1 for the computer calculation, or by marking the inoperable instrument data NIA in the hand calculation. 9.15 Objective U 15936 Describe the following concepts associated with SOER-96-02, Design and Operating Considerations associated with Reactor Cores

• Type of industry events that have occurred as a result of changes in core design
• Evaluate how specific events contained in SOER 96-02 could have been prevented
• Why it is important for reactor engineering and operations to communicate
• Type of change management that should be utilized in response to changes in core design and operating strategies
• How the recommendations contained in SOER 96-02 have been implemented at North Anna 9.15 Content SOER 96-2 REACTOR OPERATOR Page 67 of 86 Revision 3, 12/11/2007

QUESTIONS REPORT ( for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

18. 01S-AA1.22 018/BANKINAPS/L/3IROINAPS/8/22/081 Which ONE of the following responses is NOT an indication that the #2 seal has failed on a Reactor Coolant Pump?

A'! Increasing seal injection flow. B. Increased level in the Primary Drains Transfer Tank. C. #1 seal leakoff is lower than normal. D. RCP Standpipe Hi level alarm lit. Feedback

a. Correct. The inverse would be true for a excessive #2 seal leakage.

b. Incorrect. Plausible since the candidate may not link the cause and effect relationship unless they have a detailed understanding of the RCP seals.

c. Incorrect. Plausible since again the candidate who does not have detailed knowledge in this are may conclude that there is no relationship between this parameter and the #2 seal.

d. Incorrect. Plausible since again the candidate without detailed knowledge may conclude that a problem would involve lack of sufficent leakoff (often a concern with the #1 seal) and if anything standpipe level would be low, and thereby default to this disctractor.

Notes Reactor Coolant Pump (RCP) Malfunctions Ability to operate and / or monitor the following as they apply to the Reactor Coolant Pump Malfunctions (Loss of RC Flow): RCP seal failure/malfunction (CFR 41.7 /45.5/45.6) Tier: 1 Group: 1 Importance Rating: 4.0/4.2 Technical

Reference:

1-AP-33.1 Proposed references to be provided to applicants during examination: None Learning Objective: U60058 Question History: Bank additional info:

VIRGINIA POWER 1-EI-CB-21C ANNUNCIATOR G1 1-AR-C-G1 NORTH ANNA POWER STATION REV. 2 C,Jl.PPROVAL: ON FILE Effective Date: 10-12-01 RCP 1A Approximately 1 foot STANDPIPE above orifice level HI LEVEL on standpipe 1.0 Probable Cause 1.1 Excessive leakage from #2 seal 1.2 Overfilling by operator 1.3 Primary grade water leaking through 1-RC-TV-1522A 1.4 Drain line to PDTT plugged or isolated 2.0 Operator Action 2.1 Check 1-RC-TV-1522A closed. 2.2 Check primary drain transfer tank level. 2.3 Evaluate the need to drain stand pipe down and watch for increasing level. 2.4 Check #1 seal leakoff flow. 2.5 Refer to 1-AP-33.1, Reactor Coolant Pump Seal Failure, as applicable. 2.6 Notify System Engineering to evaluate seal injection limits. 3.0 References 3.1 11715-FM-93B Reactor Coolant. 3.2 11715-LSK-25-1. 3.3 NAPS instrumentation RC 022. 3.4 W Precautions, limitations, and setpoints. 3.5 11715-ESK-10C, 10AAG. 3.6 Westinghouse Technical Bulletin NSD-TB-93-01-RO 4.0 Actuation 4.1 1-RC-LC-1406A

VIRGINIA POWER 1-EI-CB-21C ANNUNCIATOR D8 1-AR-C-D8 NORTH ANNA POWER STATION REV. 3 APPROVAL: ON FILE Effective Date:01/28/04 ( PDTT Hi-Hi 68% HI/ HI-HI LEVEL Hi 36.S% 1.0 Probable Cause 1.1 Normal valve leakage 1.2 Excessive valve leakage 1.3 Overflow of RCP standpipe 1.4 Draining of PZR relief tank 1.S Excessive letdown diverted to PDTT 1.6 Draining of loops 1.7 Draining of accumulators 1.8 Tube leak PDTT cooler 2.0 Operator Action 2.1 IF alarm was due to normal condition, THEN pump PDTT, using 1-DG-P-1A or 1-DG-P-1B. 2.2 IF alarm is due to abnormal leakage, THEN do the following: 2.2.1 Determine the source of leakage. 2.2.2 Perform an RCS leakrate using 1-PT-S2.2 or 1-PT-S2.2A. 2.2.3 Refer to Tech Spec 3.4.13, RCS Operational Leakage.

 ~.O  References 3.1  1171S-FM-90C Vent and drains 3.2  1171S-LSK-34-3A 3.3  1171S-ESK-66F 3.4  NAPS instrumentation DG-002 3.S  S&W switch setpoint study system sort pg 26 3.6  Tech Spec 3.4.13 3.7  Memo from Michael Bourdeau to Ben Spencer, PDTT Hi and Hi-Hi Level Alarms, dated 12/06/02 (see rev 2) 4.0  Actuation 4.1  1-DG-LS-100 4.2  1-DG-LS-102

VIRGINIA POWER l-EI-CB-21C ANNUNCIATOR G8 l-AR-C-G8 NORTH ANNA POWER STATION REV. 2 APPROVAL: ON FILE Effective Date:09/10/08 RCP lA-B-C SEAL LEAK < .8 gpm LO FLOW 1.0 Probable Cause 1.1 Differential pressure across #1 seal less than 275 psi due to low Reactor Coolant system pressure 1.2 Excessive leakage on #2 seal 1.3 Damage to #1 seal 1.4 Instrument Failure 2.0 Operator Action 2.1 Check recorder l-CH-FR-1154B to determine which RCP has Lo Flow conditions. 2.2 Evaluate increasing flow to the affected RCP by throttling the corresponding RCP Seal Injection Header Inlet Isol Valve: lA l-CH-318 lB l-CH-314 lC . l-CH-310 2.3 Check Standpipe indication for affected RCP to determine if #2 Seal has excessive leakage. 2.4 Check the following parameters to determine if the alarm is valid:

• Seal return temperature
• Lower radial bearing temperature
• Seal leakoff and other parameters of unaffected RCPs
• Thermal barrier temperature
• Seal Delta P
• RCP Vibration and current
• Delta T between seal return and lower radial bearing 2.5 IF Alarm is valid, THEN go to l-AP-33.1, RCP Seal Failure.

2.6 Determine if l-CH-HCV-1307 RCP Seal Bypass Isolation valve may be opened by ensuring that ALL of the following conditions are met: 2.6.1 Verify RCP lower seal water bearing (pump bearing) temperature approaches 179°F OR No.1 seal leakoff (seal water outlet) temperature approaches 184°F. 2.6.2 Verify that the applicable RCP seal isolation valve is open: l-CH-HCV-1303A, l-RC-P-1A Seal Leakoff Isol Valve l-CH-HCV-1303B, l-RC-P-1B Seal Leakoff Isol Valve l-CH-HCV-1303C, l-RC-P-1C Seal Leakoff Isol valve 2.6.4 No.1 seal leakoff flow is less than 1 gpm 2.6.5 RCS pressure is between 100 and 1000 psig 2.6.6 Seal injection flow to each RCP is greater than 6 gpm 2.7 IF ALL the conditions in the Step 2.6 are met, THEN with SRO concurrence, do the following: 2.7.1 Place l-EP-CB-26B, Bkr 11, l-CH-HCV-1307, RCP Seal Bypass Isolation in ON. (DC SOV Panel 1-2 Unit 1 Hathaway Room)

2.7.2 Open 1-CH-HCV-1307, RCP Seal Bypass Isolation Valve. 2.7.3 WHEN ANY of the conditions in Step 2.6 are NOT met, THEN do the I following:

a. Close 1-CH-HCV-1307, RCP Seal Bypass Isolation Valve.

b. Place 1-EP-CB-26B, Bkr 11, 1-CH-HCV-1307, RCP Seal Bypass Isolation in OFF.

2.8 IF alarm is NOT valid, THEN do the following:

        ~Submit   CR to repair the transmitter(s) .

• Increase surveillance of alternate parameters (Step 2.4).

3.0 References 3.1 W RCP technical manual 3.2 11715-LSK-25-1 3.3 11715-FM-95C CVCS 3.4 NAPS instrumentation CH 054; 056, 088 3.5 11715-ESK-10C, 10AAF 3.6 W Inst. and Cont 6007D78 D98, 6008D36 3.7 Westinghouse Technical Bulletin NSD-TB-93-01-RO 4.0 Actuation 4.1 1-CH-FT-1154B, 1-CH-FC-1154B (C7-128) 4.2 1-CH-FT-1155B, 1-CH-FC-1155B (C6-128) 4.3 1-CH-FT-1156B, 1-CH-FC-1156B (C5-128)

NUMBER PROCEDURE TITLE REVISION ( 14 1-AP-33.1 REACTOR COOLANT PUMP SEAL FAILURE PAGE 5 of 12 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE: ATTACHMENT 2 contains a list of gages and PCS points, that may be used to check RCP Bearing/Seal temperatures and RCP seal water return temperature.

3. CHECK AFFECTED RCP FOR NO.2 SEAL FAILURE:

0 a) Check RCP Standpipe Hi level o a) GO TO Step 4. alarm - LIT b) Check if EITHER of the following o b) Monitor RCP seal performance and contact temperatures are steadily Operations Manager on call. increasing: 0

• RCP pump radial o GO TO Step 4.

temperature OR 0

• RCP seal water return temperature c) Do the following:

0 1) GO TO 1-E-O, REACTOR TRIP OR SAFETY INJECTION, while continuing with this procedure 0 2) WHEN the Reactor is tripped, THEN stop the affected RCP 0 3) Verify loop flow indicates o 3) WHEN the RCP indicates stopped, THEN affected RCP is stopped proceed with Step 3c4. (STEP 3 CONTINUED ON NEXT PAGE)

STUDENT GUIDE FOR REACTOR COOLANT SYSTEM (38) (

4. The following control room indications can be used to determine low seal bypass flow:

4.1. RCP 1A (1B, 1C) SEAL WTR BYPASS LO FLOW alarms 1C-E1(E2, E3). 5.5 Objective U 3495 List the following information associated with the reactor coolant pump #2 seal.

• Type of seal
• Design flow rate through the seal
• Indications that occur as a result of a #2 seal failure
• Means available in the control room to determine that the reactor coolant pump standpipe level is normal 5.5 Content

1. The #2 seal is a face-rubbing seal.

2. The design flow rate through the #2 seal is 3 gph with a 30 psid differential pressure across the seal.

3. Failure of the #2 seal results in increased leakoff flow to the RCP standpipe.

3.1. The excess flow overflows the standpipe, combines with the normal orificed flow from the standpipe and is returned to the PDTT. 3.2. The associated standpipe high level alarm will annunciate before the standpipe begins to overflow to the PDTT. 3.3. PDTT pumping frequency will increase.

4. Direct indication of RCP standpipe level is not provided in the control room.

4.1. Level is assumed to be normal if the high level and low level annunciators are not lit. ( SHIFT TECHNICAL ADVISOR Page 39 of 111 Revision 8, 10109/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

19. 016-K3.03 019IMODIFIEDINAPSIHI3/ROINAPSII Given the following conditions:

• Unit 1 was initially at 100% power.
• The crew started ramping the unit 10 minutes ago to perform a Turbine Valve Freedom Test.
• T AVE is presently 3 degrees higher than T REF' 1-MS-PT-1446, Channel III First Stage Pressure, is selected for control.

Based on these plant conditions, which ONE of the following identifies how the steam dumps will respond if 1-MS-PT-1447, Channel IV First Stage Pressure fails LOW? A'I Steam dumps arm but remain closed because there is insufficient demand signal. B. Steam dumps arm and ONLY banks 1 & 2 modulate open until T AVE matches T REF' C. Steam dumps DO NOT arm and are disabled since the T REF input is failed LOW. D. Steam dumps arm and all valves modulate open until T AVE matches T REF' Feedback

a. Correct. 447 produces an arming signal based on the load reject program, and for the given conditions the TavglTref delta is insufficient to cause actuation of the dumps in either the trip open or modulate modes.

b. Incorrect. Plausible as dumps arm as discussed above and the candidate who does not have detailed knowledge of the load rejection program may assume that there is suffiecient delta to cause them to open.

c. Incorrect. Plausible since the other channel (446) provides the tref input; the candidate may reverse the function of the two channels and thus sellect this distractor.

d. Incorrect. Plausible since all would be armed due to the magnitude of the failure and the candidate who does not understand the cause and effect relationship between the Turbine EHC controls and the dumps may erroneoudly conclude that this distractor is correct.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Non-Nuclear Instrumentation Knowledge of the effect that a loss or malfunction of the NNIS will have on the following: SDS (CFR: 41.7 / 45.6) Tier: 2 Group: 2 Importance Rating: 3.0/3.1 Technical

Reference:

STeam Dump Lesson Plan Proposed references to be provided to applicants during examination: None Learning Objective: Question History: Modified additional info:

VIRGINIA POWER 1-EI-CB-21P ANNUNCIATOR E4 1-AR-P-E4 NORTH ANNA POWER STATION REV. 1 APPROVAL: ON FILE Effective Date:07/30/03 C-7 PERM Turbine load decreasing STM DUMP by greater than 10 ARMED FROM percent in 120 seconds LOSS OF LOAD NOTE: The Steam Dump Armed from Loss of Load permissive is cleared by momentarily placing the Steam Dump Mode Selector in the RESET position. 1.0 PROBABLE CAUSE Turbine load rejection

2.0 REFERENCES

2.1 NA-DW-5655D33, Nuclear Steam Supply System, Functional Diagrams, Steam Dump Control, Units 1 and 2, Sheet 10 of 16 2.2 11715-ESK-10CAF, Trip-Permissive and Bypass Status Lights, Sheet 6 of 8 2.3 11715-FE-7X, Wiring Diagram Annunciator, Demultiplexer ANJ64 to ANJ67 2.4 11715-MS-131, Main Steam System, Turbine First Stage Pressure Channel IV 2.5 11715-MS-172, Main Steam System, Low Turbine 1st Stage Pressure Channel IV 2.6 ICP-P-1-P-447, P-447 First Stage Pressure Protection Channel IV 2.7 NCRODP-23, Main Steam System 2.8 NCRODP-75, Main Turbine Generator Control and Protection System 2.9 NCRODP-77, Reactor Protection System 3.0 ACTUATION 1-MS-PC-1447AX

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                                                           ;                                                                                                                        i CONDENSER AVA   !L~;L-E-~~ ~;H-L~- --- --]                                                                                                   ~-----~

OU~1P CONTROL HODE SELECTOR S\1l TCH CIRCULATION \,;;TER " CONDENSEF, PUHP I ' L i ""~l:1~( ~'~:::'i TAve, I STEAH PRESS.

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CDHHIG FROH TUR8H,E PRESSURE TAP~, TO I~EET THE S ;i\'GLi:: tA" i~ I (I'IOTE 6 i

                                                                                                                                                                                           ;::LL TEI~PERATURE BISTABLE:; ON TH,S SHEET MID TURBlr'!E 11~PULSE CHAI*1BER PRESSURE BISTABLE ~PB-447A ARE ";:I'IER[,1.2:E -:-0 ACTUATE" HiGHE'Sr   EQU[PI~1EIH CLASSJFICATjQ1; m'l THIS        is NUCLEAR STEAM SUPPLY SYSTEM FUNCTIONAL DIAGRAMS
                                                                                                                                                                      'I;'OTE 21
                                                                                                                                                                                      ~                             STEAM DUMP CONTROL UN ITS 1 & 2 VIRGINIA         POWER R:O-~~:I::~------------------------------- (~IOTE                                                                                       Ri:VlSEO F'ER OCR '¥I-um                                                       NORTH ANNA      POWER STATION 3    TH1SOIIGSLf'ERSEOES tHE REV 2OR1GlNAL C"'~"                                                                                     SH   10 OF         16         3

INSTRUCTOR GUIDE FOR STEAM DUMP CONTROL AND PROTECTION SYSTEM (23-8) 3.1. Prior to closing the main steam trip valves, the STEAM DUMP INTERLOCK switches should be placed in OFF/RESET to attempt to close the steam dump valve. Topici6.3Response*tolnstromenfFailures in TaY9.Mode 6.3 Objective U 10248 With the steam dump mode selector switch in the Tav9 position, describe the steam dump response to the following instrument failures.

• Turbine first stage pressure PT-MS-446 fails low
• Turbine first stage pressure PT-MS-446 fails high
• Turbine first stage pressure PT-MS-447 fails low
• Turbine first stage pressure PT-MS-447 fails high or as is
• Median/select Tav9 TI-408A fails low
• Median/select Tav9 TI-408A fails high 6.3 Content

1. If turbine first stage pressure PT-446 fails low, Tref goes to 54rF.

1.1.lf Tav9 is >551 of, a demand signal is generated. 1.2. Steam dumps stay closed unless an arming signal is present.

2. If turbine first stage pressure PT-446 fails high, Tref goes to maximum.

2.1. Steam dumps will not open on a load reject.

3. If turbine first stage pressure PT-447 fails low and the failure occurs at a high enough rate, steam dumps will arm due to C-7 load reject Signal.

4. It turbine first stage pressure PT-447 fails high or fails as is, steam dumps will not arm on a load reject.

REACTOR OPERATOR Page 24 of 28 Revision 1, 08/08/2008

INSTRUCTOR GUIDE FOR STEAM DUMP CONTROL AND PROTECTION SYSTEM (23-8) 5.1. This signal is used to create a demand signal to the positioner to control the air signal to modulate the steam dump valves. T()pic3.3Delta-TSetpoints forM()ciulatingSteam Dumps 3.3 Objective U 8865 List the differential temperature setpoint at which each bank of steam dump valves will modulate open in response to the following controllers.

• Load reject controller
• Turbine trip controller 3.3 Content

1. The load reject controller modulates steam dump valves open based on the temperature error signal as follows.

1.1. Bank 1 begins modulating open when the temperature error exceeds 4°F and fully opens at 7°F. 1.2. Bank 2 begins modulating open when the temperature error exceeds YOF and fully opens at 10°F. 1.3. Bank 3 begins modulating open when the temperature error exceeds 10°F and fully opens at 13°F. 1.4. Bank 4 begins modulating open when the temperature error exceeds 13°F and fully opens at 16°F.

2. The turbine trip controller modulates steam dump valves open based on the temperature error Signal as follows.

2.1. Bank 1 begins modulating open when the temperature error exceeds OaF and fully opens at 8°F. 2.2. Bank 2 begins modulating open when the temperature error exceeds 8°F and fully opens at 16°F. 2.3. Bank 3 begins modulating open when the temperature error exceeds 16°F and fully opens at 24°F. 2.4. Bank 4 begins modulating open when the temperature error exceeds 24°F and fully opens at 32°F. REACTOR OPERATOR Page 16 of 28 Revision 1, 08/08/2008

INSTRUCTOR GUIDE FOR STEAM DUMP CONTROL AND PROTECTION SYSTEM (23-8) Top ic .j.4[)~lta~TSetpointsfortrippin gOpellSteamDu I1IPS 3.4 Objective U 8866 List the coincidences and setpoints at which each bank of steam dump valves will trip open in response to the following controllers.

• Load reject controller
• Turbine trip controller 3.4 Content

1. The load reject controller energizes SOV-3 and trips open steam dump valves based on the temperature error signal as follows.

1.1. Banks 1 & 2 trip open when the temperature error exceeds 10°F. 1.2. Banks 3 & 4 trip open when the temperature error exceeds 16°F.

2. The turbine trip controller energizes SOV-3 and trips open steam dump valves based on the temperature error signal as follows.

2.1. Banks 1 & 2 trip open when the temperature error exceeds 16°F. 2.2. Banks 3 & 4 trip open when the temperature error exceeds 32°F. Steam Pressure Mode ropiC4.1Steam-pres~ureM6cJe 4.1 Objective U 8869 List the following information associated with the steam-pressure mode of steam dump operation.

• Inputs to the steam-pressure controller
• Plant conditions under which the steam-pressure mode is used REACTOR OPERATOR Page 17 of 28 Revision 1, 08/08/2008

I 1212cond Vac> 26" Median Tave Tref 2/4 CWPp Closed If: Bkrs Closed DT> 10°F (Bank 1,2) DT> 16°F (Bank 3,4)

                                                                        ¥ 213                                          C7 ASO                                          Load
                  -------------~----------------------~"                               S45#                                         Reject Closed If:

DT> 16°F (Bank 1,2) DT> 32°F (Bank 3,4) Tr. uB" r Tr. uA" C-8 Tr. uB" ---------------- -----~~~- ----------T---- ---------T- --"'dPEN Cooldown Valves On On ONLY Tu~ Tu~ r--....L.----!. Trip OPEN Trip Tave > 543 T T aveS543 I In Same Stm As Tave rPress",\ SOV-1 ONO. B/P ..L l ON After B/P Intlk Intlk-,- -,- B/P Intlk PT-1464 Stm Stm Dump Stm Press t-----;.-""I Trip Open t - - -...I Dmps . .,"'~----I 1 Activation Armed M I A IA I Positioner!-I- - - - I

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

20. OI7-K5.01 020INEW//L/3IROINAPSII 10 CFR 50.46, ECCS Acceptance Criteria, states that the ECCS is designed to ensure peak cladding temperature is maintained less than or equal to during a Large Break LOCA; The CETC temperature that is used to monitor the Core Cooling CSF Status tree is _ _ _ _ __

A. 1200°F; the average temperature of ALL CETCs in that ICCM train. B. 1200°F; the average temperature of the five highest CETCs in that ICCM train. C. 2200°F; the average temperature of ALL CETCs in that ICCM train. D~ 2200°F; the average temperature of the five highest CETCs in that ICCM train. Feedback

a. Incorrect. Plausible since this is the transition to FR-C.1; second part also plausible since the candidate who does not have detailed knowledge might assume the using an average would be more representative and default to this distractor.

b. Incorrect. Plausible since this is the transition to FR-C.1; second part is correct the ICCM algorithm performs this function to meet design requirements.

c. Incorrect. First part is correct this ECCS acceptance criteria; second part plausible as discussed in distractor a.

d. Correct. This is the ECCS acceptance criteria as discussed in the safety analysis section of the TS Basis; second part also correct as discussed in distractor b.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes In-Core Temperature Monitor System (ITM) Knowledge of the operational implications of the following concepts as they apply to the ITM system: Temperature at which cladding and fuel melt (CFR: 41.5/45.7) Tier: 2 Group: 2 Importance Rating: 3.1/3.9 Technical

Reference:

ITM lesson plan and TS Basis/10 CFR 50.46 acceptance criteria Proposed references to be provided to applicants during examination: None Learning Objective: Question History: New additional info:

                        - NUCLEAR DESIGN INFORMATION PORTAL-ECCS-Operating B 3.5.2 BASES APPLICABLE        The LCO helps to ensure that the following acceptance SAFETY ANALYSES   criteria for the ECCS, established by 10 CFR 50.46 (Ref. 2),

will be met following a LOCA:

a. Maximum fuel element cladding temperature is ~ 2200°F for small breaks, and there must be a high level of probability that the peak cladding temperature does not exceed 2200°F for large breaks;

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 generated if all of the metal in the cladding cylinders surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react;

d. Core is maintained in a cool able geometry; and

e. Adequate long term core cooling capability is maintained.

The LCO also limits the magnitude of post trip return to power following an MSLB event and ensures that containment temperature limits are met. Each ECCS subsystem is taken credit for in a large break LOCA event at full power (Refs. 3 and 4). This event establishes the maximum flow requirement for the ECCS pumps. The HHSI pumps are credited in a small break LOCA event. This event relies upon the flow and discharge head of the HHSI pumps. The SGTR and MSLB events also credit the HHSI pumps. The OPERABILITY requirements for the ECCS are based on the following LOCA analysis assumptions:

a. A large break LOCA event, with loss of offsite power and a single failure disabling one LHSI pump (both EDG trains are assumed to operate due to requirements for modeling full active containment heat removal system operation);

and

b. A small break LOCA event, with a loss of offsite power and a single failure disabling one Emergency Diesel Generator.

(continued) North Anna Units 1 and 2 B 3.5.2-4 Revi si on 13

VIRGINIA POWER 1-0P-5.6 NORTH ANNA POWER STATION REVISION 8 PAGE 12 OF 20 5.2 Thermocouple Monitoring 5.2.1 Verify the Initial Condition is satisfied. 5.2.2 Review the Precautions and Limitations. 5.2.3 Press TC P/B on the four-button keypad. 5.2.4 Verify PIT CURVE Page is displayed and do the following:

• Observe the Saturation, Overpressure, and Cooldown Limit Curves that are displayed.
• Observe WR Press and A VG 5 HIGH Thermocouples that are used to plot RCS conditions.

NOTE: The current coolant conditions are shown with the square shaped figure on the graph. 5.2.5 Press the PAGE P/B to scroll to the INCORE THERMOCOUPLE MAP Page and observe the temperature of each thermocouple for the applicable train that is shown in the appropriate core location. 5.2.6 Press the PAGE P/B to scroll to the QUADRANT

SUMMARY

Page and do the following:

• Observe the maximum, minimum, and average temperatures that are shown for each quadrant.
• Observe the margin to saturation that is displayed in the center of the page as SUB COOL (TC).

5.2.7 Press the PAGE P/B to scroll to the QUADRANT IIII THERMOCOUPLE Page and observe the thermocouple location, tag number, and temperature that are shown for each thermocouple.

VIRGINIA POWER 1-0P-S.6 NORTH ANNA POWER STATION REVISION 8 PAGE 18 OF 20 ATTACHMENT 2 (Page 1 of 1) PAGE 1, THERMOCOUPLE INPUT AND OUTPUT DATA POINTS Validyne Inputs Description Train A Train B TIC 1 BOS A08 TIC 2 C08 Abandoned B10 TIC 3 C12 E07 TIC 4 D03 E08 Abandoned TIC S DOS E 14 Abandoned TIC 6 E04 F03 TIC 7 E10 FOS TIC 8 E12 F09 TIC 9 F13 Fll TIC 10 G02 G01 TIC 11 G08 G06 TIC 12 GIS H08 TIC 13 H03 Abandoned H11 TIC 14 HOS HIS TIC IS H09 J02 TIC 16 H13 JlO TIC 17 Jl2 K03 TIC 18 K08 KOS TIC 19 L06 Kll TIC 20 L08 M09 TIC 21 L12 Mll TIC 22 L14 N04 TIC 23 M03 N06 Abandoned TIC 24 N10 N08 TIC 2S P07 P08 Abandoned Labeled Displayed Outputs

• Hottest Thermocouple TCHOn XXX TCHOn XXX
• 2nd Hottest Thermocouple TCHOT2XXX TCHOT2XXX
• 3rd Hottest Thermocouple TCHOT3XXX TCHOT3 XXX
• 4th Hottest Thermocouple TCHOT4XXX TCHOT4XXX
• Sth Hottest Thermocouple TCHOTSXXX TCHOTSXXX
• NOTE: XXX = the thermocouple core location (for example, G08)

VIRGINIA POWER 1-0P-S.6 NORTH ANNA POWER STATION REVISION 8 PAGE 19 OF 20 ATTACHMENT 3 (Page 1 of 1) PAGE 2, THERMOCOUPLE INPUT AND OUTPUT DATA POINTS Validyne Inputs Description Train A Train B Quadrant I Maximum Temperature MAXI MAXI Quadrant I Average Temperature AVGI AVGI Quadrant I Minimum Temperature MINI MINI Quadrant II Maximum Temperature MAX II MAX II Quadrant II Average Temperature AVGIl AVGIl Quadrant II Minimum Temperature MINH MIN II Quadrant III Maximum Temperature MAX III MAX III Quadrant III Average Temperature AVG III AVGIII Quadrant III Minimum Temperature MIN III MIN III Quadrant IV Maximum Temperature MAX IV MAX IV Quadrant IV Average Temperature AVGN AVGIV Quadrant IV Minimum Temperature MIN IV MIN IV Average S High AVGSHIGH AVGS HIGH Margin to Saturation (TIC) SUB COOL (TIC) SUBCOOL (TIC) Digital Outputs Approach-to-Saturation Alarm I SAT ALM I SAT ALM Analog Outputs Margin to Saturation (TIC) I SUBCOOL (AO) I SUBCOOL (AO)

STUDENT GUIDE FOR SAFETY INJECTION SYSTEM (52) System Overview 1.1 Objective U 3381 Explain the purpose of the Safety Injection System. 1.1 Content

1. The Safety Injection System or Emergency Core Cooling System (ECCS) will provide borated chilled cooling water to the Reactor Coolant System (RCS) for the entire spectrum of RCS break sizes.

1.1. The borated water is used to limit core temperatures, maintain core integrity/geometry, and provide additional shutdown margin (SDM). 1.2 Objective U 3881 List the following information associated with the Safety Injection System.

• Four accidents that the system is designed to mitigate
• Five criteria which are used to evaluate the system's design (10-CFR-50.46)
• Six major sources of water in the containment sump following a loss of reactor coolant accident
• Automatic safety injection initiation signals, including coincidence and setpoints
• Safety injection signals which may be manually blocked, including the conditions which must be present to allow blocking them
• Means provided in the control room to determine that safety injection has been actuated 1.2 Content

1. The Safety Injection System is designed to mitigate four accidents:

1.1. Loss of Coolant REACTOR OPERATOR Page 4 of 55 Revision 4, 07/16/2008

STUDENT GUIDE FOR SAFETY INJECTION SYSTEM (52) 1.2. Main Steam Line Break 1.3. Steam Generator Tube Rupture 1.4. Control Rod Ejection

2. There are five criteria used to evaluate the system's design (10-CFR-50.46):

2.1. Peak Clad temperature shall not exceed 2200°F. 2.2. Maximum Cladding Oxidation shall not exceed 0.17 of the total of cladding thickness prior to the oxidation. 2.3. Maximum Hydrogen Generation from chemical reaction, of the clad, shall not exceed 0.01 of the amount generated if all the clad were to be oxidized. 2.4. A coolable geometry of the core must be maintained. 2.5. Long term cooling must be maintainable so we can remove the cores decay heat.

3. There are six major sources of water in the containment sump following a loss of reactor coolant accident:

3.1. Water volume of the RCS (via the pipe break, provided that the source of leakage is in the containment) 3.2. SI Accumulator water 3.3. Injected water from the RWST via SI 3.4. Water from the RWST via the QS System 3.5. The water from the Casing Cooling Tank 3.6. Water from the Chemical Additional Tank 3.7. Water volume of the Boron Injection Tank

4. The four automatic SI initiation signals, with coincidence and setpoints, are as follows:

4.1. Lo-Lo-Pressurizer pressure. 4.1.1.Coincidence and setpoint is 2 out of 3 channels (channels 1, 2, and 3) < 1780 psig. 4.2. High containment pressure. 4.2.1.Coincidence and setpoint is 2 out of3 channels (channels 2, 3, and 4) >17 psia. REACTOR OPERATOR Page 5 of 55 Revision 4, 07/16/2008

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95) 1.3 Objective U 13016 Explain the following concepts associated with monitoring the critical safety function status trees (1-F-0).

• How to proceed through each critical safety function attachment
• Required frequency of monitoring when a red or orange terminus exists
• How adverse containment criteria are applied to monitoring critical safety function status trees 1.3 Content

1. Each status tree is entered at the left side of the page, proceeding through the tree by answering YES or NO to each question until a terminus is reached on the right side of the page.

2. Status tree monitoring shall be continuous if any red or orange condition exists.

3. Numbers in brackets are used if adverse containment conditions are exceeded.

3.1. Once exceeded, adverse containment criteria apply to neutron monitoring indication for the duration of the event. 3.2. For the remainder of the parameters monitored adverse containment criteria are not used when containment pressure drops below 20 psia. 3.3. As always, adverse containment criteria must be used for the remainder of the event if containment radiation levels exceed 1 X 105 Rlhr. 1.4 Objective U 12705 List the plant conditions that result in reaching a red path terminus for each of the following critical safety functions (1-F-0). REACTOR OPERATOR Page 9 of 99 Revision 14, 11/06/2008

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95)

• Subcriticality
• Core cooling
• Heat sink
• Integrity
• Containment 1.4 Content

1. For Subcriticality, the red path condition is:

1.1. Power range;::: 5% [gamma-metrics WR power;::: 5 x 10°]

2. For Core Cooling, the red path condition is:

2.1. Either of the following: 2.1.1.Core exitT/Cs;::: 1200°F, OR 2.1.2.AII of the following: 2.1.2.1. RCS subcooling :0; 25°F [75°F] 2.1.2.2. No RCPs running 2.1.2.3. Core exit TICs;::: 700°F 2.1.2.4. RVLlS full range :0; 48%

3. For Heat Sink, the red path condition is:

3.1. All SG narrow range levels :0; 11 % [22%] AND total feedwater flow :0; 340 gpm

4. For Integrity, the red path condition is:

4.1. Temperature decrease in any RCS cold leg;::: 100°F in the last 60 minutes AND any RCS pressure-cold leg temperature point to the left of limit "A"

5. For Containment, the red path condition is:

5.1. Containment pressure;::: 60 psia REACTOR OPERATOR Page 10 of 99 Revision 14, 11/06/2008

STUDENT GUIDE FOR INADEQUATE CORE COOLING MONITOR SYSTEM (64)

4. The submultiplexers receive optical data from several remote multiplexers and transmit data via fiber optic cable to their respective master receivers.

5. Each Validyne master receiver provides short-term data storage in random access memory (RAM) where it has the capacity to store data from one scan of 4096 possible input channels or plant sensors.

3.2 Objective U 7734 List the following information as it applies to the Core Exit Temperature Monitoring Subsystem.

• Type of thermocouple used
• Total number of thermocouples that provide input to each train
• Definition of a valid thermocouple
• Three temperature values displayed for each core quadrant on the QUADRANT

SUMMARY

PAGE

• Temperature values displayed for each train on the TICs TREND PAGE 3.2 Content

1. Chromel-alumel, type-K, ungrounded thermocouples are used in the Core Exit Temperature Monitoring Subsystem

2. The total number of thermocouples that provide input to each train are:

2.1.25 for train A 2.2.25 for train B

3. A valid thermocouple is one that is not disabled, disconnected, offscale low, nor offscale high; plus does not have a data entry error, nor a calibration error.

REACTOR OPERATOR Page 21 of 32 Revision 0, 10101/2006

STUDENT GUIDE FOR INADEQUATE CORE COOLING MONITOR SYSTEM (64)

4. On the QUADRANT

SUMMARY

PAGE, the highest (MAX), lowest (MIN), and average (AVG) thermocouple temperatures are shown for each quadrant.

5. The following temperature values are displayed for each train on the TICs TREND PAGE:

5.1.AVG 5 HIGH 5.2. SUBCOOL (TIC) 5.3.5 HIGHEST TIC'S 5.4. The trending of the AVG 5 HIGH value is given for the immediately preceding 30-minute period. 3.3 Objective U 9967 List the span of indication provided by the core exit thermocouples. 3.3 Content

1. The span of indication provided by the core exit thermocouples is 40°F - 2300 of 3.4 Objective U 7735 Explain the following concepts as they apply to the Core Exit Temperature Monitoring Subsystem.

• How a thermocouple is used to generate a temperature signal
• How the operability of a thermocouple is determined (1-PT-44.7)

REACTOR OPERATOR Page 22 of 32 Revision 0, 10101/2006

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

21. 022-AKl.O 1 021IMODIFIEDINAPS/L/2IROINAPSII 1-ECA-O.O, Loss of All AC Power, Attachment 4 (Attempting to Restore Power to 1H [1J] Emergency Bus) directs the crew to place all charging pumps in Pull-To-Lock if RCP temperature exceeds 235°F; this action is taken to _ _ _ _ _ _ __

A'! Seal Water Outlet; prevent damage to the RCP seal package B. Seal Water Outlet; prevent damage to the thermal barrier heat exchanger C. Pump Radial Bearing; prevent damage to the RCP seal package D. Pump Radial Bearing; prevent damage to the thermal barrier heat exchanger Feedback

a. Correct. This parameter is used in determining when seal cooling CANNOT be reestablished. The concern (thermal shock to seal package) for exasperating seal leakage is also correct.

b. Incorrect. This parameter is used in determining when seal cooling CANNOT be reestablished. The concern is not correct but is plausible since there is discussion in the background document regarding steam forming in CC system, etc.

c. Incorrect. This parameter is NOT used in determining when seal cooling CANNOT be reestablished, but is plausible since pump radial bearing will increase since all seal cooling is lost in this scenario. The concern (thermal shock to seal package) for exasperating seal leakage is correct.

d. Incorrect. This parameter is NOT used in determining when seal cooling CANNOT be reestablished, but is plausible since pump radial bearing will increase since all seal cooling is lost in this scenario. The concern is not correct but is plausible since there is discussion in the background document regarding steam forming in CC system, etc.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Loss of Reactor Coolant Makeup Knowledge of the operational implications of the following concepts as they apply to Loss of Reactor Coolant Makeup: Consequences of thermal shock to RCP seals (CFR 41.8 /41.10/45.3) Tier: 1 Group: 1 Importance Rating: 2.8/3.2 Technical

Reference:

ECA-O.O and bachground document Proposed references to be provided to applicants during examination: None Learning Objective: Question History: modified additional info:

NUMBER ATTACHMENT TITLE ATTACHMENT ( 1-ECA-O.O 4 ATTEMPTING TO RESTORE POWER TO 1H (1J) EMERGENCY BUS REVISION PAGE 22 1 of 3 NOTE: RCP Seal Water Outlet Temperature PCS points:

• T0181A
• T0182A
• T0183A

 *1. Check RCP Seal Water Outlet Temperatures:

_ a) Access Unit 1 RCP Seal Water Outlet Temperatures on the PCS RCP Motor Temperature Summary, as follows or other desired method: o 1) GROUP DISP MENU o 2) MOTOR TEMP INFORMATION o 3) RC - REACTOR COOLANT _ b) Monitor Seal Water Outlet Temp for all RCPs. ( c) IF any Rep Seal Water Outlet Temp exceeds 235°F OR point can NOT be accessed, THEN do the following:

1) Stop attempts to start EDGs and energizing Emergency buses.

2) Have SRO do the following:

o a. Place Unit 1 Charging pumps in PTL, prior to continuing power restoration. o b. Initiate ATTACHMENT 3, RCP SEAL ISOLATION.

3) WHEN Unit 1 Charging Pumps are placed in PTL, THEN continue attempts to start EDGs and energizing Emergency Buses.

4) i.E any Emergency Bus is re-energized AND 1-ECA-O.O is exited at procedure Step 9, THEN have SRO do the following:

o a. Ensure ATTACHMENT 3, RCP SEAL ISOLATION is complete. o b. Start Unit 1 Charging Pumps, as required.

STEP DESCRIPTION TABLE FOR ECA-O.O Step _8_ STEP: Dispatch Personnel To Locally Close Valves To Isolate RCP Seals And Place Valve Switches In CLOSED Position PURPOSE: To isolate the RCP seals BASIS: This step groups three actions, with different purposes, aimed at isolating the RCP seals. The actions are grouped since all require an auxiliary operator, dispatched from the control room, to locally close containment isolation valves (the reference plant utilizes motor operated valves for the RCP seal return, RCP thermal barrier CCW return lines and RCP seal injection lines). This grouping assumes that the subject valves are located in the same penetration room area and that they are accessible. Concurrent with dispatching the auxiliary operator, the control room operator should place the valve switches for the motor operated valves in the closed position so that the valves remain closed when ac power is restored. Isolating the seal return line prevents seal leakage from filling the volume control tank (VCT) (via seal return relief valve outside containment) and subsequent transfer to other auxiliary building holdup tanks (via VCT relief valve) with the potential for radioactive release within the auxiliary building. Such a release, without auxiliary building ventilation available, could limit personnel access for local operations. Isolating the RCP seal injection lines prepares the plant for recovery while protecting the RCPs from seal and shaft damage that may occur when a charging/SI pump is started as part of the recovery. With the RCP seal ECA-O.O Background 97 HP-Rev. 2, 4/30/2005 HECAOOBG.doc

NUMBER PROCEDURE TITLE REVISION 22 1-ECA-O.O LOSS OF ALL AC POWER PAGE 8 of 22 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION:

• If an SI signal exists or an SI is actuated during this procedure, then SI should be reset to allow manual loading of equipment on a recovered AC Emergency Bus.
• When power is restored to any AC Emergency Bus, then, to facilitate recovery actions, recovery should continue starting with Step 29.

10. PUT THE FOLLOWING EQUIPMENT IN PTL:

D

• All Charging Pumps D
• Both CC Pumps D
• All PRZR Heaters D
• Both Low-Head SI Pumps D
• Both Quench Spray Pumps D
• All Recirc Spray Pumps D
• Both Service Water Pumps D
• Auxiliary Service Water Pump D
• Both Motor-Driven AFW Pumps D
• All Containment Air Recirc Fans

-     INITIATE ATTACHMENT 3 TO LOCALLY ISOLATE RCP SEALS

STEP DESCRIPTION TABLE FOR ECA-O.O Step _8_ injection lines isolated, a charging/SI pump can be started in the normal charging mode without concern for cold seal injection flow thermally shocking the RCPs. Seal injection can subsequently by established to the RCP consistent with appropriate plant specific procedures. Isolating the RCP thermal barrier CCW return outside containment isolation valve prepares the plant for recovery while protecting the CCW system from steam formation due to RCP thermal barrier heating. Following the loss of all ac power, hot reactor coolant will gradually replace the normally cool seal injection water in the RCP seal area. As the hot reactor coolant leaks up the shaft, the water in the thermal barrier will heat up and potentially form steam in the thermal barrier and in the CCW lines adjacent to the thermal barrier. Subsequent automatic start of the CCW pump would deliver CCW flow to the thermal barrier, flushing the steam into the CCW system. If abnormal RCP seal leakage had developed in a pump, the abnormally high leakage rate could exceed the cooling capacity of the CCW flow to that pump thermal barrier and tend to generate more steam in the RCP thermal barrier CCW return lines. Isolating these lines prevents the potential introduction of this steam into the main portion of the CCW system upon CCW pump start. This keeps the main portion of the CCW system available for cooling equipment necessary for recovering the plant when ac power is restored. ACTIONS: o Dispatch personnel to locally close valves o Place following switches in closed position: RCP seal return outside containment isolation valve RCP seal injection outside containment isolation valves RCP thermal barrier CCW return outside containment isolation valve INSTRUMENTATION: Switch position indication for: o RCP seal return outside containment isolation valve o RCP seal injection outside containment isolation valves o RCP thermal barrier CCW return outside containment isolation valve ECA-O.O Background 98 HP-Rev. 2, 4/30/2005 HECAOOBG.doc

STUDENT GUIDE FOR EMERGENCY CONTINGENCY ACTION PROCEDURES (94) ( 1.4 Content

1. A caution before step 9 in ECA-O.O directs that should an SI signal exist or an SI is actuated during performance of the procedure, that the SI be reset to allow the manual loading of equipment on a recovered AC emergency bus.

2. The procedure directs the following equipment to be placed in PTL to allow the equipment to manually start when an emergency bus is recovered:

2.1. Charging pumps 2.2. Low-head SI pumps 2.3. Quench spray pumps 2.4. Inside and outside Recirc Spray pumps 2.5. Service Water pumps 2.6. Component Cooling pumps 2.7. Motor-driven AFW pumps 2.8. PRZR heaters 2.9. Containment air recirc fans. 1.5 Objective U 13833 Explain why seal injection, sealleakoff, and component cooling water are isolated to the reactor coolant pumps during the response to a loss of all AC power. 1.5 Content

1. Seal injection, sealleakoff, and CC to the RCPs are isolated during ECA-O.O to isolate the RCP seals.

1.1. Isolating the RCP seal injection lines prepares the plant for recovery while protecting the RCPs from seal and shaft damage that may occur when a charging/SI pump is started as part of the recovery. REACTOR OPERATOR Page 8 of 8 Revision 7, 09/17/2008

STUDENT GUIDE FOR EMERGENCY CONTINGENCY ACTION PROCEDURES (94) 1.1.1.With the RCP seal injection lines isolated, a charginglSI pump can be started in the normal charging mode without concern for cold seal injection flow thermally shocking the RCPs. 1.1.2.Seal injection can subsequently be established to the RCP consistent with appropriate plant specific procedures. 1.2. Isolating the seal return line prevents seal leakage from filling the volume control tank (VCT) (via seal return relief valve outside containment) and subsequent transfer to other auxiliary building holdup tanks with the potential for radioactive release within the auxiliary building. 1.2.1.Such a release, without auxiliary building ventilation available, could limit personnel access for local operations. 1.3. Isolating the RCP thermal barrier CC return outside containment isolation valve prepares the plant for recovery while protecting the CC System from steam formation due to RCP thermal barrier heating. 1.3.1.Following the loss of all ac power, hot reactor coolant will gradually replace the normally cool ( seal injection water in the RCP seal area. 1.3.2.As the hot reactor coolant leaks up the shaft, the water in the thermal barrier will heat up and potentially form steam in the thermal barrier and in the CC lines adjacent to the thermal barrier. 1.3.3.Subsequent automatic start of the CC pump would deliver CC flow to the thermal barrier, flushing the steam into the CC System. 1.3.4.lf abnormal RCP seal leakage had developed in a pump, the abnormally high leakage rate could exceed the cooling capacity of the CC flow to that pump thermal barrier and tend to generate more steam in the RCP thermal barrier CC return lines. 1.3.S.lsolating these lines prevents the potential introduction of this steam into the main portion of the CC System upon CC pump start. 1.3.6.This keeps the main portion of the CC System available for cooling equipment necessary for recovering the plant when ac power is restored. ( REACTOR OPERATOR Page 9 of 9 Revision 7, 09/17/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

22. 022-K4.03 022INEW/IH/3/RO///

Given the following conditions:

• The crew has tripped Unit 1 and initiated Safety Injection due to a loss of RCS inventory.

Conditions continue to degrade and COA automatically actuates. Based on the above conditions, which ONE of the following identifies the automatic response of the Containment Cooling System? A. CARFs tripped when Safety Injection was initiated; Cooling water to CARFs isolated when Safety Injection was initiated. B. CARFs tripped when COA actuated; Cooling water to CARFs isolated when Safety Injection was initiated. C. CARFs tripped when Safety Injection was initiated; Cooling water to CARFs isolated when COA actuated. O~ CARFs tripped when COA actuated; Cooling water to CARFs isolated when COA actuated. Feedback

a. Incorrect. Plausible since neither the CARFs nor the CROM fans are needed for accident mitigation.

b. Incorrect. Plausible since the candidate may mistakenly assume that cooling water to CARFs are phase A valves, these are in fact Phase B valves that will remain open until COA.

c. Incorrect. Plausible since as noted above CARFs are not needed for accident mitigation, additionally they trip on UV/OV on their associated emergency bus and candidate may conclude that under SI conditions the CARFs would be tripped; cooling water isolation is correct.

d. Correct. Actuation of COA will result in CARFs tripping and cooling water isolation.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Containment Cooling System (CCS) Knowledge of CCS design feature(s) and/or interlock(s) which provide for the following: Automatic containment isolation (CFR: 41.7) Tier: 2 Group: 1 Importance Rating: 3.6/4.0 Technical

Reference:

RPS lesson plan Proposed references to be provided to applicants during examination: None Learning Objective: Question History: modified additional info:

NUMBER ATTACHMENT TITLE ATTACHMENT 1-E-O 2 VERIFICATION OF PHASE B ISOLATION REVISION PAGE 39 7 of 9 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

6. VERIFY THE FOLLOWING AUTOMATIC o Manually do operations as indicated:

OPERATIONS ON THE UNIT 1 VENTILATION PANEL: o a) Verify all Containment Air Recirc Fans - STOPPED: 1_1-HV-F-1 A 1-HV-F-1C 1-HV-F-1B 1-HV-F-1C o b) Verify all CRDM fans - STOPPED: 1-HV-F-37A 1-HV-F-37B 1-HV-F-37C 1-HV-F-37D 1-HV-F-37E 1-HV-F-37F o c) Verify Service Water Supply and Return for Recirc Air Coolers CLOSED (GREEN): CLOSED (GREEN) CLOSED (GREEN) 1-SW-TV-101A-1 1-SW-TV-101A-2 1-SW-TV-1 01 B-1 1-SW-TV-101 B-2 (STEP 6 CONTINUED ON NEXT PAGE)

CONTINUOUS ACTION PAGE FOR 1-E-0

1. ADVERSE CONTAINMENT CRITERIA IF either of the following conditions exist, THEN use setpoints in brackets:

D

• 20 psia Containment pressure, OR D
• Containment radiation has reached or exceeded 1.0E5 R/hr (70% on High Range Recorder).

2. SI FLOW CRITERIA D IF SI is actuated AND High-Head Cold Leg SI flow is NOT indicated, THEN initiate ATTACHMENT 6, MANUAL VERIFICATION OF SI FLOWPATH.

3. RCP TRIP CRITERIA IF both conditions listed below exist, THEN trip all RCPs:

D

• Charging Pumps - AT LEAST ONE RUNNING AND FLOWING TO RCS, AND D
• RCS subcooling based on Core Exit TCs - LESS THAN 25°F [85°F].

4. CHARGING PUMP RECIRC PATH CRITERIA D

• IF RCS pressure decreases to less than 1275 psig [1475 psig] AND RCPs tripped, THEN close Charging Pump Recirc Valves.

D

• IF RCS pressure increases to 2000 psig, THEN open Charging Pump Recirc Valves.

5. ECST LEVEL CRITERIA D WHEN the ECST level decreases to 40%, THEN initiate 1-AP-22.5, LOSS OF EMERGENCY CONDENSATE STORAGE TANK 1-CN-TK-1.

6. CDA ACTUATION CRITERIA IF Containment pressure exceeds 28 psia, THEN do the following:

D a. Manually actuate CDA. D b. Ensure CC Pumps STOPPED. D c. Stop all RCPs. D d. Ensure QS Pumps RUNNING. D e. Ensure QS Pump Discharge MOVs OPEN.

f. Initiate the following Attachments, when directed by ATTACHMENT 4, EQUIPMENT VERIFICATION:

D

• ATTACHMENT 2, VERIFICATION OF PHASE B ISOLATION D
• ATTACHMENT 3, PRIMARY PLANT VENTILATION ALIGNMENT

7. FAULTED SG ISOLATION D IF SI is in progress, THEN ATTACHMENT 7, FAULTED SG ISOLATION may be used for guidance on faulted SG(s) isolation and AFW flow control.

8. RUPTURED SG ISOLATION D IF SI is in progress, THEN ATTACHMENT 8, RUPTURED SG ISOLATION may be used for guidance on ruptured SG(s) isolation and AFW flow control.

9. CONTAINMENT RECIRC MODE CRITERIA D To prevent possible radioactive release from the RWST, VCT level should be maintained greater than 12%.

10. RCP CRITERIA D Seal injection flow should be maintained to all RCPs.

11. REACTIVITY CONTROL CRITERIA D An Operator should be sent to locally close and lock 1-CH-217, PG to Blender Isolation Valve.

STUDENT GUIDE FOR PRIMARY VENTILATION SYSTEM (47) Containment Ventilation 1.1 Objective U 4477 List the following components in sequential order as they appear in the containment recirculation air flow path.

• Coolers
• Fans and discharge dampers
• Ring duct 1.1 Content

1. The containment recirculation air fans draw air across the recirculation air coolers; the air is then drawn through the fan and then discharged through the discharge damper to the ring duct.

1 .2 Objective U 4478 List the following information as it applies to the containment air recirculation units.

• Power supply for each fan
• Position to which a fan's discharge damper fails on a loss of instrument air
• Interlock conditions required to start a fan
• Interlock conditions which will automatically stop a fan 1.2 Content

1. The power supply for each CARF is:

1.1. Fan 1A is powered from 1H1 emergency bus. 1.2. Fan 1B is powered from 1J 1 emergency bus. REACTOR OPERATOR Page 5 of 65 Revision 3, 07/24/2008

STUDENT GUIDE FOR PRIMARY VENTILATION SYSTEM (47) 1.3. Fan 1C is powered from 1H or 1J emergency bus.

2. The CARFs are equipped with backdraft discharge dampers.

2.1. These dampers open when the associated fan is started and close, with the assistance of a weighted arm, when the fan is stopped.

3. The interlock conditions required to start a CARF:

3.1. No Undervoltage/Oegraded voltage signal, for the past 30 seconds (30 sec TO for A, and B fan only) 3.2. No COA signal exists 3.3. Over-current reset

4. The interlock conditions which will automatically stop a CARF:

4.1. Undervoltage/Oegraded voltage signal 4.2. COA signal 4.3. Over-current 1.3 Objective U 4479 List the means available in the control room to determine the following abnormal conditions as they apply to the containment air recirculation units.

• Abnormal cooling water flow to the coolers
• Fan has tripped
• Running fan's discharge damper is not open REACTOR OPERATOR Page 6 of 65 Revision 3, 07/24/2008

STUDENT GUIDE FOR CHILLED WATER SYSTEM (15) Integrated Plant Operations 4.1 Objective U 1892 Describe the effects on the mechanical chiller if chilled water flow to the containment air recirculation fan were isolated without first establishing an alternate chilled water flow path. 4.1 Content

1. During operation of the mechanical chiller, if chilled water flow is to be removed from the containment recirculation air fans, an alternate chilled water flow path should be established.

2. This will prevent the mechanical chiller from tripping due to low chilled water temperature or low chilled water flow as this major heat load is removed.

3. Shutdown of the mechanical chiller should be evaluated if a suitable alternate flow path can not be establ ished.

4.2 Objective U 1893 List the following information associated with the containment air recirculation fans.

• Indications which would alert the control room operator to an abnormal temperature in the chilled water supply
• Indications available for chilled water flow to containment
• Effects of a loss of instrument air or electrical power on the containment trip valves
• Interlocks for closing the containment trip valves automatically
• Alternate source of cooling water REACTOR OPERATOR Page 24 of 28 Revision 0, 10101/2006

STUDENT GUIDE FOR CHILLED WATER SYSTEM (15) 4.2 Content

1. The control room operator would be alerted to an abnormal temperature in the chilled water supply by the following alarm:

1.1. TE-CC-166 provides MCR vertical board indication and input to the CHILLED WATER TO AIR RECIRCULATION COOLERS HIGH-LOW TEMPERATURE alarm (window 1G-B2). 1.2. The high supply temperature alarm setpoint is 75°F. 1.3. The low supply temperature alarm setpoint is 40°F.

2. The discharge flow of the containment recirculation air coolers is monitored by flow element FE-CC-128.

2.1. The sensor provides MCR indication on vertical board 1-2. ( 3. On a loss of instrument air or electrical power on the containment trip valves, the valves fail closed.

4. The chilled water containment isolation valve shuts when either the CLOSE pushbutton is depressed or when a phase B containment isolation signal is present.

5. The Service Water System provides an alternate source of cooling water to each unit's containment air recirculation coolers, if emergency backup cooling is required.

/
\

REACTOR OPERATOR Page 25 of28 Revision 0, 10101/2006

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

23. 024-AA1.10 023INEWIIH/4/ROIII Given the following conditions:

Following a reactor trip, Unit 1 was stabilized with all parameters on program and stable. The crew initiated emergency boration in accordance with 1-ES-0.1, Reactor Trip Response. With 1-CH-P-1 B initially in service, a loss of off-site power occurs. Following the loss of offsite power, the OATC notes the following:

• 1-CH-P-1A breaker closed with 75 amps indicated.
• 1-CH-P-1 B breaker closed with 10 amps indicated.
• 1-CH-P-1C secured.

Annunciator C-G6, RCP 1A-B-C LABYTH SEAL LO FLOW, is lit.

• Annunciator C-C5, CHG PP TO REGEN HX HI-LO FLOW, is lit.
• Annunciator C-A7, CHG PP 1C 15H7 LOCKOUT, is lit.
• PRZR level 20% and slowly decreasing.
• VCT level 44% and slowly increasing.

Which ONE of the following identifies the cause of these conditions, and the procedure that should be implemented to correct these conditions? A'! Discharge check valve failure on 1-CH-P-1 B; 1-AP-49, Loss of Normal Charging. B. Charging line rupture upstream of 1-CH-FCV-1122; 1-AP-16, Excessive RCS Leakage. C. Alarms are consistent with the loss of offsite power; 0-AP-10, Loss of Electrical Power. D. Rupture of RCP seal injection line upstream of 1-CH-HCV-1186; 1-AP-33.2, Loss of RCP Seal Cooling.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Feedback

a. Correct. High amps on 'A' chg pp with low amps on '8' chg pp indicate '8' chg pp has a sheared shaft and its associated discharge check has failed to close; AP-49 contains the steps necessary to isolate the failed chg pp and restore normal chg.

b. Incorrect. Plausible since the candidate may key on the flow indications and not properly evaluate other indications which are not consistent with a leak.

c. Incorrect. Plausible since the candidate may conclude that the electrical transient precipitated this event, that in itself is not unreasonable, implementing AP-1 0 (which would be done as a result of the loss of offsite power), will not correct the condition as specified in the question stem.

d. Incorrect. Plausible since again the candidate may focus on the reduction or loss of seal injection and assume that AP-33.2 would need to be implemented, however once again AP-33.2 will not correct the problem with '8' chg pp and its associated discharge check valve.

Notes Emergency Boration Ability to operate and / or monitor the following as they apply to Emergency Boration: CVCS centrifugal charging pumps (CFR 41.7 /45.5/45.6) Tier: 1 Group: 2 Importance Rating: 3.5/3.4 Technical

Reference:

1-Ap-49 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: New additional info:

A Dominion" NORTH ANNA POWER STATION ABNORMAL PROCEDURE NUMBER PROCEDURE TITLE REVISION 14 1-AP-49 LOSS OF NORMAL CHARGING (WITH TWO ATTACHMENTS) PAGE 1 of 18 PURPOSE To provide the instructions to follow in the event of a Loss of Normal Charging Flow. ENTRY CONDITIONS This procedure is entered when the following conditions exist:

• 1-CH-FI-1122 is off scale high OR low OR erratic, or
• 1-CH-PI-1121 is off scale low OR below normal, or
• 1-CH-PI-1121 is erratic, or
• Charging Pump amps are abnormal OR erratic, or
• Charging Pump is suspected of gas binding.

CONTINUOUS USE

NUMBER PROCEDURE TITLE REVISION 14 1-AP-49 LOSS OF NORMAL CHARGING PAGE 2 of 18 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. CHECK CHARGING PUMP FOR GAS 0 GO TO Step 3.

BINDING: 0

• Running Charging Pump suspected of gas binding AND
• One of the following conditions exist:

0

• 1-CH-PI-1121, Discharge Header pressure - ERRATIC OR 0
• 1-CH-FI-1122, Charging flow

         - ERRATIC OR 0

• Motor amps - ERRATIC

NUMBER PROCEDURE TITLE REVISION 14 1-AP-49 LOSS OF NORMAL CHARGING PAGE 3 of 18 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

2. SECURE CVCS SYSTEM:

a) Isolate letdown by closing the following valves:

1) Letdown Orifice Isolation Valves:

o

• 1-CH-HCV-1200A o
• 1-CH-HCV-1200B o
• 1-CH-HCV-1200C

2) Letdown Isolation Valves:

o

• 1-CH-LCV-1460A o
• 1-CH-LCV-1460B o b) Place non-running Charging Pumps in PTL o c) Place running Charging Pump in PTL o d) Thoroughly vent the Charging pump to be placed in service using ATTACHMENT 2, VENTING CHARGING PUMPS, while continuing with Step 10

NUMBER PROCEDURE TITLE REVISION 14 1-AP-49 LOSS OF NORMAL CHARGING PAGE 4 of 18 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

3. VERIFY CHARGING PUMP Do the following:

MANIPULATIONS - IN PROGRESS a) Isolate letdown by closing the following valves:

1) Letdown Orifice Isolation Valves:

D

• 1-CH-HCV-1200A D
• 1-CH-HCV-1200B D
• 1-CH-HCV-1200C

2) Letdown Isolation Valves:

D

• 1-CH-LCV-1460A D
• 1-CH-LCV-1460B D b) GO TO Step 10.

4. CLOSE DISCHARGE MOVs ON Do the following:

PREVIOUSLY RUNNING CHARGING PUMP D a) Place non-running Charging Pumps in PTL. D b) Place running Charging Pump in PTL. D c) Manually close 1-CH-FCV-1122, Charging Flow Control Valve. D d) WHEN Charging Pump discharge pressure has decreased to minimum, THEN start the previously running Charging Pump. D e) Manually restore charging flow using 1-CH-FCV-1122, Charging Flow Control Valve.

NUMBER PROCEDURE TITLE REVISION 14 1-AP-49 LOSS OF NORMAL CHARGING PAGE 5 of 18 ACTION! EXPECTED RESPONSE RESPONSE NOT OBTAINED

5. VERIFY RUNNING CHARGING Do the following:

PUMP - NORMAL: o

• 1-CH-PI-1121, Discharge a) Isolate letdown by closing the following valves:

Header pressure - NORMAL o

• 1-CH-FI-1122, Charging flow - 1) Letdown Orifice Isolation Valves:

NORMAL o

• 1-CH-HCV-1200A o
• Motor amps - STABLE o
• 1-CH-HCV-1200B o
• 1-CH-HCV-1200C

2) Letdown Isolation Valves:

o

• 1-CH-LCV-1460A o
• 1-CH-LCV-1460B o b) GO TO Step 10.

NUMBER PROCEDURE TITLE REVISION ( 14 1-AP-49 LOSS OF NORMAL CHARGING PAGE 6 of 18 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

6. CHECK LETDOWN - IN SERVICE Do the following:

o a) Control 1-CH-FCV-1122 to establish at least 25 gpm Charging flow. o b) Put 1-CH-PCV-1145 in MANUAL and open to 100%. c) Open the following Letdown Isolation Valves: o

• 1-CH-TV-1204A o
• 1-CH-TV-1204B o
• 1-CH-LCV-1460A o
• 1-CH-LCV-1460B d) Open one of the following Letdown Orifice Isolation Valves:

o

• 1-CH-HCV-1200A OR o
• 1-CH-HCV-1200B OR o
• 1-CH-HCV-1200C o e) Adjust 1-CH-PCV-1145 to establish 300 psig letdown pressure and put 1-CH-PCV-1145 in AUTO.

o f)!E auto PRZR level control is desired, THEN place 1-CH-FCV-1122 in AUTO. (STEP 6 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 14 1-AP-49 LOSS OF NORMAL CHARGING PAGE 7 of 18 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

6. CHECK LETDOWN - IN SERVICE (Continued) g) Maintain PRZR pressure at 2235 psig by operating the following:

o

• PRZR Heaters o
• PRZR Spray Valves NOTE: 1-CH-P-1 C, C CHARGING PUMP, has no Auto-start features.

7. CHECK STANDBY CHARGING o Place standby Charging Pumps in PUMPS - IN AUTO-AFTER-STOP AUTO-AFTER-STOP as directed by SRO.

8. SUBMIT WORK REQUEST FOR FAILED CHARGING PUMP DISCHARGE CHECK VALVE

9. RETURN TO PROCEDURE AND STEP IN EFFECT

10. VERIFY VCT LEVEL - GREATER o Increase VCT level to greater than 12%.

THAN 12% o IF level cannot be immediately restored, THEN GO TO Step 14.

VIRGINIA POWER 1-EI-CB-21C ANNUNCIATOR G6 1-AR-C-G6 NORTH ANNA POWER STATION REV. 4 APPROVAL: ON FILE Effective Date:07/29/04 ( RCP 1A-B-C LABYTH < 6.5 gpm SEAL LO FLOW 1.0 Probable Cause 1.1 Increasing RCS Pressure 1.2 Loss of Seal Water Injection flow 1.3 Decreasing Charging header pressure or loss of Charging 1.4 Seal Injection filter high ~P 1.5 Transmitter failure 2.0 Operator Action NOTE: All indications (Control Room, local, alarm, and computer) for each RCP come off of the same transmitter. 2.1 Check the following Seal Injection indicators to determine which RCP has the low flow condition:

• 1-CH-FI-1130, 1A RCP Seal Flow Indicator
• 1-CH-FI-1127, 1B RCP Seal Flow Indicator
• 1-CH-FI-1124, 1C RCP Seal Flow Indicator 2.2 Using all available parameters (charging flow, Pressurizer level, VCT level, seal leak-off flow) evaluate for transmitter failure. IF transmitter failure, THEN submit Work Request and Plant Issue.

2.3 IF Seal Injection AND Thermal Barrier flow are NOT indicated, THEN GO TO 1-AP-33.2, Loss of RCP Seal Cooling. 2.4 Increase Seal Injection flow to AFFECTED RCPs to maintain approximately S gpm in accordance with, 1-0P-S.10, Seal Injection Flow Adjustment. (Reference 3.9) 2.5 Monitor AFFECTED RCPs Seal leakoff flows. CAUTION: Westinghouse has determined that RCPs without Seal Injection AND initial #1 Seal Leakoff flows of less that 2.5 gpm will likely have seal and bearing overheating within 2 hours. NOTE: Seal leakrates are expected to increase during a loss of Seal Injection event. 2.6 IF Seal Injection flow is NOT indicated, THEN do the following for the AFFECTED RCPs: 2.6.1 IF initial Seal leakoff flow is less than 2.5 gpm, THEN closely monitor RCPs radial bearing temperature AND do the

following:

a. IF a RCP radial bearing temperature approaches 22SoF, THEN perform 1-E-0 AND stop AFFECTED RCPs.

b. Perform an orderly shutdown and cooldown to Mode S to prevent two-phase flow in the #1 Seal leakoff line.

c. IF two-phase flow in the #1 Seal leakoff line is suspected, THEN raise VCT pressure high in the band to increase seal backpressure.

2.6.2 IF initial Seal leakoff flow is greater than 2.S gpm, THEN monitor RCPs radial bearing temperatures. 3.0 References 3.1 W RCP tech. manual 3.2 1171S-FM-9SC CVCS 3.3 1171S-LSK-2S-1 3.4 W precautions limitations and setpoints 3.S NAPS instrumentation CH OSS, OS9, 060 3.6 1171S-ESK-10C, 10AAE 3.7 W Inst and Cont. DWG 600SD3S, 6007D97, D77 3.S NSAL-99-00S, RCP operation during Loss of Seal Injection 3.9 PI N-2001-3S33, Operator Intended to Adjust Seal Injection Flows On Unit 2 But Instead Adjusted Unit l's

.0 Actuation 4.1  1-CH-FT-1124, 1-CH-FC-1124 (C7-124) 4.2  1-CH-FT-1127, 1-CH-FC-1127 (C6-124) 4.3  1-CH-FT-1130, 1-CH-FC-1130 (CS-124)

VIRGINIA POWER 1-EI-CB-21C ANNUNCIATOR C5 1-AR-C-C5 NORTH ANNA POWER STATION REV. 3 APPROVAL: ON FILE Effective Date:01/27/00 C* CH PP TO REGEN HX > 125 gpm HI-LO FLOW < 25 gpm 1.0 Probable Cause 1.1 1-CH-FCV-1122 open excessively due to 10 PZR level or valve failure (Hi) 1.2 1-CH-FCV-1122 closed excessively due to Hi PZR level or valve failure (Lo) 1.3 1-CH-FC-1122 malfunction (Master flow controller) 1.4 Pressurizer level controlling channel failure 1.5 Charging line rupture 2.0 Operator Action 2.1 Take manual control of 1-CH-FCV-1122 to restore PZR level to normal and maintain proper flow. CAUTION: IF the Low Temperature Overpressure Protection System (LTOPS) is in service, THEN an uncontrolled mass addition transient must be terminated within ten minutes. PORV N2 Accumulators are sized to allow PORVs to cycle continuously for ten minutes only. 2.2 IF 1-CH-FCV-1122 has failed open and can NOT be controlled from the Control Room, AND it is desired to isolate Charging flow, THEN do the following:

a. Isolate Letdown by closing the following valves:

• 1-CH-HCV-1200A, A Letdown Orifice Isolation Valve
• 1-CH-HCV-1200B, B Letdown Orifice Isolation Valve
• 1-CH-HCV-1200C, C Letdown Orifice Isolation valve
• 1-CH-LCV-1460A, Letdown Isol Valve
• 1-CH-LCV-1460B, Letdown Isol valve

b. Isolate Charging by closing 1-CH-MOV-1289A, Normal Charging Isolation Valve.

c. GO TO 1-AP-49, Loss of Normal Charging.

2.3 IF 1-CH-FCV-1122 has failed open and can NOT be controlled from the Control Room, AND it is desired to control Charging flow from the Auxiliary Shutdown Panel, THEN do the following: 2.3.1 At the Auxiliary Shutdown Panel, place 1-CH-FCV-1122 Local-Remote switch to LOCAL and adjust output to maintain PZR level between 28% and 64%.

2.3.2 IF l-CH-FCV-1122 can NOT be controlled from the Auxilary Shutdown Panel, THEN do the following: ( a. Isolate Letdown by closing the following valves:

• l-CH-HCV-1200A, A Letdown Orfice Isolation Valve
• l-CH-HCV-1200B, B Letdown Orfice Isolation Valve
• l-CH-HCV-1200C, C Letdown Orfice Isolation Valve

                         ** l-CH-LCV-1460A, l-CH-LCV-1460B, Letdown Isol Valve Letdown Isol Valve

b. Isolate Charging by closing l-CH-MOV-1289A, Normal Charging Isolation Valve.

c. IF Charging flow is isolated, THEN GO TO l-AP-49, Loss of Normal Charging.

2.4 IF charging flow is low, THEN refer to l-AP-49, Loss of Normal Charging. 2.5 Place l-RC-LC-1459G in manual and return to previous setpoint until failure is corrected. 2.6 IF the Low Temperature Overpressure Protection System (LTOPs) is in service and the uncontrolled RCS mass addition can not be terminated, THEN stop all RCPs and Charging Pumps and GO TO l-AP-49, Loss of Normal Charging. (, .0 References 3.1 l17l5-FM-95B and C CVCS 3.2 W system descriptions 3.3 W precautions limitations and setpoints 3.4 NAPS instrumentation CH-OOI 3.5 l17l5-ESK-lOC, 10AAS 3.6 W Inst and Cont. DWG 6008D25 3.7 CTS Assignment 02-97-2268, Commitment 001 4.0 Actuation 4.1 l-CH-FT-1122 4.2 l-CH-FC-1122B (C6-525) (

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) Chemical and Volume Control System Operations 19.1 Objective U 11405 List the following information associated with 1-AP-49, "Loss of Normal Charging" (SOER-97-1).

• Purpose of the procedure
• Modes of applicability
• Entry conditions 19.1 Content

1. 1-AP-49, Loss of Normal Charging, provides guidance for the operator during a loss of normal charging flow.

(

2. It is applicable in modes 1,2, and 3 (can be used as a guide in mode 4 and 5).

3. 1-AP-49 is entered when any of the following conditions exist:

3.1. Charging line flow 1-CH-FI-1122 is off scale high OR low. 3.2. Charging pump discharge pressure 1-CH-PI-1121 is off scale low, below normal, or erratic. 3.3. Charging pump amps are abnormal/erratic, or charging pump is suspected of gas binding. 19.2 Objective U 11406 Explain the purpose of the following high-level action steps associated with 1-AP-49, "Loss of Normal Charging" (SOER-97-1, SER-2-05 Rev. 1).

• Verify that charging pump manipulations are in progress.

REACTOR OPERATOR Page 102 of 158 Revision 30, 11/06/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) (

• Close the discharge motor-operated valves on previously running charging pumps.
• Verify that charging pump parameters have returned to normal.
• Establish a letdown flow path.
• Establish a charging flow path.

19.2 Content

1. The step to verify that charging pump manipulations are in progress is used to determine if isolation of a previously running pump is needed due to the possibility of a failed check valve.

2. Closing the discharge motor-operated valves on a previously running charging pump isolates a possible stuck open check valve.

3. Verifying that charging pump parameters have returned to normal determines if charging system is returned to normal or if other problems exist (Le., charging line rupture) and addresses those problems

( systematically.

4. Establishing a letdown flow path is used to place letdown in service.

5. The step for establishing a charging flow path is used to restore the charging system back to its normal configuration.

19.3 Objective U 356 Explain why 1-AP-49, "Loss of Normal Charging," requires the operator to close discharge valves on the previously running pump if charging pump manipulations are in progress. REACTOR OPERATOR Page 103 of 158 Revision 30, 11/06/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

24. 025-AKl.O 1 024IBANKINAPS/H/3IROINAPSII Following successful completion of maintenance, Unit 1 is exiting an outage that began 4 days ago.

Given the following conditions:

• The RCS is solid.
• RCS temperature is 256°F and stable.
• RCS pressure is 300 psig and stable.
• RHR is in service.

A loss of ALL instrument air (inside and outside containment) occurs, and the crew entered 1-AP-28, Loss of Instrument Air, but was unable to restore a source of air. Which ONE of the following identifies the ReS temperature response, and the action required by 1-AP-28 assuming the crew is unable to restore IA pressure? A'! RCS temperature will increase; operate RHR H/X CC Outlet Isolation Valves 1-CC-TV-103A & -103B locally. B. RCS temperature will decrease; operate RHR H/X CC Outlet Isolation Valves 1-CC-TV-103A & -103B locally. C. RCS temperature will increase; adjust RHR Heat Exchanger Return Valves 1-CC-MOV-100A & -100B. D. RCS temperature will decrease; adjust RHR Heat Exchanger Return Valves 1-CC-MOV-100A & -100B. Feedback

a. Correct. AP-28 has specific action to locally restore CC to RHR HXs if air cannot be restored, based on the information provided this action is necessary to restore RHR cooling.

b. Incorrect. Plausible since the candidate who does not have detailed systems and integrated plant knowledge may conclude the conservative failure mode would be to have these valves fail open (to ensure core cooling) and default to this distractor.

c. Incorrect. Plausible temperature will increase and normally these valve can be used to control temperature but wolud not be effective since the CC-TVs will be closed based on the information (Loss of all air) provided in the stem. Several valves at NAPS have backup seismic air flasks a coomon misconception would be to assume these valves because of their importance are so equiped, this however is not the case.

d. Incorrect. First part incorrect but plausible as discussed above since the failure mode that would assure cooling would seem logical; second part also incorrect but plausible as discussed above.

QUESTIONS REPORT ( for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Loss of Residual Heat Removal System (RHRS) Knowledge of the operational implications of the following concepts as they apply to Loss of Residual Heat Removal System: Loss of RHRS during all modes of operation (CFR 41.8 /41.10/45.3) Tier: 1 Group: 1 Importance Rating: 3.9/4.3 Technical

Reference:

1-AP-11 and 1-AP-28 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info:

NUMBER PROCEDURE TITLE REVISION 30 1-AP-28 LOSS OF INSTRUMENT AIR PAGE 23 of 25 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

44. CHECK RHR SYSTEM STATUS:

o a) RHR System - IN SERVICE o a) IF RHR System is required to be in service, THEN initiate 1-AP-11, LOSS OF RHR. o IF NOT, THEN GO TO Step 46. b) Verify the following RHR Heat b) Do the following: Exchanger CC Outlet Isolation Valves - OPEN: o 1) Initiate ATIACHMENT 3 to open valves. o

• 1-CC-TV-1 03A o 2) Enter the action of Tech Spec 3.6.3 due to not meeting the LCO of Tech Spec 3.6.3.

o

• 1-CC-TV-103B o c) Control RHR flow using c) Throttle the in-service RHR Outlet Isolation 1-RH-FCV-1605, RHR Bypass Valve:

Flow Control Valve o

• 1-RH-MOV-1720A OR o
• 1-RH-MOV-1720B

45. MAINTAIN RCS TEMPERATURE BY Maintain RCS temperature by adjusting RHR Heat ADJUSTING 1-RH-HCV-1758, RHR Exchanger Return Valves:

HEAT EXCHANGER OUTLET VALVE o

• 1-CC-MOV-100A o
• 1-CC-MOV-100B

46. CHECK ANY RCPS - RUNNING Do the following:

o a)!E on Natural Circulation, THEN initiate ATIACHMENT 2. o b) GO TO Step 48.

NUMBER ATTACHMENT TITLE ATTACHMENT 1-AP-28 3 LOCAL OPERATION OF 1-CC-TV-103A AND 1-CC-TV-103B REVISION PAGE 30 1 of 3 NOTE:

• A key is required to unlock the Appendix R storage cabinet.
• An adjustable wrench is required to connect the nitrogen jumper rig.

1. Obtain Nitrogen/Air Jumper Rig from the Appendix R storage cabinet (located in the TSC HVAC room).

2. Obtain Nitrogen/Air Bottle, containing less than 4000 psig, from the bottle storage area.

NUMBER ATTACHMENT TITLE ATTACHMENT 1-AP-28 3 LOCAL OPERATION OF 1-CC-TV-103A AND 1-CC-TV-103B REVISION PAGE 30 2 of 3

3. In the Unit 1 Auxiliary Building Penetration Area, open the RHR Heat Exchanger CC Outlet Isolation Valves as follows:

_ a) Close the local air supply isolations to 1-CC-TV-103A and 1-CC-TV-103B. _ b) Connect the Nitrogen/Air Jumper Rig to the Nitrogen/Air Bottle. c) Connect the Nitrogen/Air Jumper Rig to 1-CC-TV-1 03A actuator as follows:

1) Disconnect the Instrument Air copper tubing from the end of the actuator.

2) Remove the tube to pipe 90 0 fitting from the bushing on the actuator.

3) Connect the quick disconnect adapter from the Nitrogen/Air Bottle hose to the bushing at the end of the actuator.

4) Connect the hose from the Nitrogen/Air Jumper Rig to the quick disconnect adapter at the end of the actuator.

d) Connect the Nitrogen/Air Jumper Rig to 1-CC-TV-103B actuator as follows:

1) Disconnect the Instrument Air copper tubing from the end of the actuator.

2) Remove the tube to pipe 90 0 fitting from the bushing on the actuator.

3) Connect the quick disconnect adapter from the Nitrogen/Air Bottle hose to the bushing at the end of the actuator.

4) Connect the hose from the Nitrogen/Air Jumper Rig to the quick disconnect adapter at the end of the actuator.

_ e) Adjust the regulator to full counterclockwise direction. _ f) Open Nitrogen/Air Bottle isolation valve. _ g) Open both Nitrogen/Air Jumper Rig shut-off valves. _ h) Slowly increase the regulator setpoint until the RHR Heat Exchanger CC Outlet Isolation Valves are open.

4. Notifythe Control Room that the RHR Heat ExchangerCC Outlet Isolation Valves are open.

5. Make a Jumper Log entry.

NUMBER ATIACHMENT TITLE ATTACHMENT 1-AP-28 3 LOCAL OPERATION OF 1-CC-TV-103A AND 1-CC-TV-103B REVISION PAGE 30 3 of 3 Regulator Shut Off Valves Nitrogen/Air Bottle Valve Operating Cylinders For 1-CC-TV-1 03A&B l Quick Disconnect Adapter Bushing NITROGEN JUMPER RIG CONNECTION DIAGRAM

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

25. 026-AA2.04025INEW//L/2fRO///

Unit 1 is at 100% power and a loss of ALL CC flow has occurred. In accordance with 1-AP-15, Loss of Component Cooling, the reactor shall be tripped and affected RCPs stopped if RCP rises to 195°F. A'I Motor Bearing temperature B. Pump Radial Bearing temperature C. Stator Winding temperature D. Seal Water Outlet temperature Feedback

a. Correct. This is the RNO for temperature < 195°F, thus if temperature increases to the given value the action is required.

b. Incorrect. Plausible since this component is monitored by 1-AP-15 but the threshold for action is 225°F.

c. Incorrect. Plausible since this component is monitored by 1-AP-15 but the threshold for action is 300°F.

d. Incorrect. Plausible since although not specifically looked at by 1-AP-15 it is monitored in other APs related to RCP cooling and there is a PCS alarm point associated with this parameter.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Loss of Component Cooling Water (CCW) 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 (CFR: 43.5/45.13) Tier: 1 Group: 1 Importance Rating: 2.5/2.9 Technical

Reference:

1-AP-15 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info:

NORTH ANNA POWER STATION ( ABNORMAL PROCEDURE NUMBER PROCEDURE TITLE REVISION 21 1-AP-15 LOSS OF COMPONENT COOLING (WITH SIX ATTACHMENTS) PAGE 1 of 9 PURPOSE To provide the actions to take in the event of a loss of Unit 1 Component Cooling System. ENTRY CONDITIONS This procedure is entered when any of the following conditions exist:

• Annunciator Panel "G" A-1, CC SURGE TK HI-La LEVEL, is LIT, or
• Annunciator Panel "G" F-5, CaMP COOL PP 1A AUTO TRIP, is LIT, or
• Annunciator Panel "G" E-8, CaMP COOL PP 1B AUTO TRIP, is LIT, or
• Annunciator Panel "G" B-3, CC HX 1A-1B CC OUTLET La FLOW, is LIT, or
• Annunciator Panel "G" C-3, CC HX OUTLET La PRESS, is LIT, or
• Excess Letdown Heat Exchangers low flow/high temperature, or
• Non-regenerative Heat Exchangers high temperature, or
• Reactor Coolant Pumps low flow/high temperature, or
• Loss of Service Water System.

CONTINUOUS USE

NUMBER PROCEDURE TITLE REVISION 21 1-AP-15 LOSS OF COMPONENT COOLING PAGE 20f9 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

   *1. CHECK CC HEAD TANK LEVEL -           Do the following:

STABLE OR INCREASING a) Perform one of the following Attachments to refill the CC Head Tank: D

• ATTACHMENT 4, CONDENSATE MAKEUP TO THE CC HEAD TANK D
• ATTACHMENT 6, SERVICE WATER MAKEUP TO THE CC HEAD TANK b) IE CC Head Tank level is NOT indicated:

D 1) Put CC pumps in PTL (~~ D 2) Locally isolate ruptured equipment. D 3) WHEN CC Head Tank level is restored, THEN RETURN TO Step 2. D c) GO TO Step 8.

2. VERIFY AT LEAST ONE UNIT 1 CC D Start a Unit 1 CC Pump.

PUMP - RUNNING D IF CC Systems are cross-tied and no Unit 1 CC Pump can be started, THEN start both Unit 2 CC Pumps.

NUMBER PROCEDURE TITLE REVISION 21 1-AP-15 LOSS OF COMPONENT COOLING PAGE 3 of9 ACTION! EXPECTED RESPONSE RESPONSE NOT OBTAINED

3. CHECK RUNNING CC PUMP AMPS - Do the following:

STABLE o a) Put the running CC Pump in PTL. o b) Start the standby CC Pump.

                                           !E the standby CC  Pump cannot be started OR amps are NOT stable, THEN put the standby CC Pump in PTL and do the following:

o 1) !E CC Systems are cross-tied and no Unit 1 CC Pump can be started, THEN start both Unit 2 CC Pumps. o 2) IF no CC Pump can be started OR amps are NOT stable, THEN put the affected CC Pump(s) in PTL AND GO TO Step 8.

4. CHECK CC FLOW - NORMAL Do the following:

o a) Check position of CC Trip Valves. o b) Check position of CC Valves using 1-0P-51.1A, VALVE CHECKOFF - COMPONENT COOLING WATER - AUXILIARY BUILDING, FUEL BUILDING, DECONTAMINATION BUILDING, AND MAIN STEAM VALVE HOUSE. o !E flow cannot be restored to normal, THEN GO TO Step 8.

NUMBER PROCEDURE TITLE REVISION 21 1-AP-15 LOSS OF COMPONENT COOLING PAGE 4 of 9 ACTION I EXPECTED RESPONSE RESPONSE NOT OBTAINED

5. LOCALLY CHECK SERVICE WATER D Restore Service Water flow to CC Heat TO CC HEAT EXCHANGER t.Ps - Exchangers using applicable steps of O-OP-49.1, NORMAL SERVICE WATER NORMAL SYSTEM OPERATION.

D !E Service Water is NOT available, THEN initiate O-AP-12, LOSS OF SERVICE WATER, AND GO TO Step 8.

6. PERFORM ATTACHMENT 2 TO RESTORE EQUIPMENT TO NORMAL NOTE: The Limiting Condition for Operation for the CC System is listed in Tech Spec 3.7.19 and

( TRM 3.7.15.

7. RETURN TO PROCEDURE AND STEP IN EFFECT

8. DETERMINE IF CC SYSTEM SHOULD BE SPLIT OUT D a) Check if CC Systems cross-tied D a) GO TO Step 10.

b) Check either of the following D b) GO TO Step 10. conditions - TRUE: D

• Only Unit 1 OR Unit 2 CC System - INTACT AND AVAILABLE OR D
• CDA on Unit 2 - ACTUATED

9. INITIATE ATTACHMENT 5, ALIGNING THE CC SYSTEM FOR SPLIT OPERATIONS, WHILE CONTINUING WITH THIS PROCEDURE

NUMBER PROCEDURE TITLE REVISION 21 1-AP-15 LOSS OF COMPONENT COOLING PAGE 50f9 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

• 10. MONITORRCP Do the following while continuing with this TEMPERATURES: procedure:

o . Motor bearing temperature - o a) GO TO 1-E-0, REACTOR TRIP OR SAFETY LESS THAN 195 0 F INJECTION. o b) WHEN Reactor is tripped, THEN stop affected RCPs. ISOLATE LETDOWN BY CLOSING 0 Close 1-CH-LCV-1460A by placing control switch THE FOLLOWING VALVES: in ISO. a) Letdown Orifice Isolation Valves: 0

• 1-CH-HCV-1200A 0
• 1-CH-HCV-1200B 0
• 1-CH-HCV-1200C b) Letdown Isolation Valves:

0

• 1-CH-LCV-1460A 0
• 1-CH-LCV-1460B

12. CHECK EXCESS LETDOWN - 0 Secure Excess Letdown using 1-0P-8.5, SECURED OPERATION OF EXCESS LETDOWN.

13. CLOSE 1-CH-FCV-1122, CHARGING 0 Close 1-CH-MOV-1289A, Normal Charging Line FLOW CONTROL VALVE Isolation Valve.

14. CLOSE 1-CH-MOV-1380, SEAL 0 Close 1-CH-MOV-1381, Seal Water Return WATER RETURN ISOLATION VALVE Isolation Valve.

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) 22.7 Objective U 11659 List the following information associated with 1-AP-15, "Loss of Component Cooling Water."

• Purpose of the procedure
• Modes of applicability
• Entry conditions
• Possible causes of component cooling water loss
• Means used to monitor reactor coolant pump temperatures 22.7 Content

1. The purpose of AP-15 is to provide guidance to the operator in response to either a complete or partial loss of the CC System.

( 2. This procedure is applicable during all modes of plant operation.

3. AP-15 should be entered when the following conditions exist 3.1. Any of the following alarms are actuated:

3.1.1.1 G-A 1, CC SURGE TK HI-La LEVEL 3.1.2.1 G-B3, CC HX 1A-1 B CC OUTLET La FLOW 3.1.3.1 G-C3, CC HX OUTLET La PRESS 3.1.4.1G-F5, CaMP COOL PP 1AAUTO TRIP 3.1.5.1G-E8, CaMP COOL PP 1B AUTO TRIP, or 3.2. Low flow/high temperature is detected on: 3.2.1.Excess letdown heat exchanger 3.2.2.Reactor coolant pumps. 3.3. High temperature is detected on non-regenerative heat exchanger. 3.4. Loss of the Service Water System has occurred. REACTOR OPERATOR Page 134 of 158 Revision 30, 11/06/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91)

4. Possible causes for a loss of component cooling water include:

4.1. Component Cooling Water System leak. 4.1.1 Verify that level is indicated in the component cooling water head tank. 4.1.2.lf no level is indicated in the head tank, then place the pumps in PTL, isolate the source of leakage, and refill the head tank. 4.2. Failure of a running component cooling water pump. 4.2.1.Start the affected unit's standby component cooling water pump or start the other unit's standby pump. (CC systems are normally cross-tied)

5. One of the major heat loads supplied with component cooling are the reactor coolant pumps.

5.1. The reactor coolant pump temperatures are normally monitored using the plant computer. 5.2. When a loss of component cooling is identified the operator should select "Reactor Coolant Pumps" for display on the computer's monitor. 5.2.1.lf neither computer system is available then the RCP temperatures should be swapped to the recorder. 5.3. If any reactor coolant pump temperature limit is exceeded, the operator is directed to initiate E-O, trip the reactor, turbine, and then the affected RCP. 5.3.1.This is a continuous action and should be initiated whenever a RCP temperature limit is exceeded while this procedure is in effect. 22.8 Objective U 11657 List the following information associated with O-AP-12, "Loss of Service Water."

• Purpose of the procedure
• Modes of applicability
• Entry conditions REACTOR OPERATOR Page 135 of 158 Revision 30, 11/06/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91)

5. Conditions that would require the unit to be shutdown 5.1. If at least one SW supply header is not intact, the operators should trip both reactors.

5.2. If at least one SW supply header is intact and being supplied by a service water pump, then plant operation may continue. 5.3. The operator should also continuously monitor RCP temperature to ensure that the temperature limits are not exceeded. 5.3.1.The RCP temperatures are normally monitored using the plant computer 5.3.1.1. RCP motor bearing ~ 195°F 5.3.1.2. RCP pump bearing ~ 225°F 5.3.1.3. RCP stator ~ 300°F 5.4. If RCP temperature limits are exceeded the affected unit should be tripped first and then the affected RCP. (

6. Alternate cooling supplies to critical service water loads 6.1. Critical service water loads identified in AP-12 include:

6.1.1.Control room chillers 6.1.2.Component cooling water heat exchangers 6.1.3.lnstrument air compressors 6.1.4.Charging pumps 6.2. Most critical Service Water System loads can be supplied from either supply header. 6.2.1.lf one header is unavailable, the other header can usually provide sufficient cooling. 6.3. If no service water is available, then alternate cooling water sources should be aligned where possible. 6.3.1.Control room chillers: 6.3.1.1. If service water is unavailable, bearing cooling water can be aligned as an alternate cooling water source. ( 6.3.2.Charging pumps: REACTOR OPERATOR Page 137 of 158 Revision 30, 11/06/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

26. 026-K2.01 026/MODIFIED/2006-01 AUDITIL/2/ROfNAPS/S/20/200S1 Given the following conditions:

• A large-break LOCA occurred with Unit 1 initially at 100% power.
• A loss of offsite power occurs.
• All equipment functioned as designed EXCEPT that 1J1, 480-Volt Emergency Bus in Rod Drive, deenergized due to an electrical fault.

Based on these plant conditions, which ONE of the following identifies the Quench Spray and Recirc Spray pumps that have power available? A. BOTH Quench Spray pumps and ONLY three Recirc Spray pumps. B~ ONLY one Quench Spray pump and ONLY three Recirc Spray pumps. C. BOTH Quench Spray pumps and ONLY two Recirc Spray pumps. D. ONLY one Quench Spray pump and ONLY two Recirc Spray pumps. Feedback

a. Incorrect. The OS pumps are power from 480v swgr s,o only one will be operating; plausibleAs::'candidate assumes they are 4160v loads.

If

b. Correct. 2 of the six subject pumps (one of the OS pumps and 1 of the ISRS pumps) are powered from this swgr. Thus 1 OS pump and 3 of th RS pumps have power available.

c. Incorrect. First part plausible as described in Distractor A; second part plausible since there are 2 RS pumps on each emergency train.

d. Incorrect. First part is correct; second part plausible since there are 2 RS pumps on each emergency train.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Containment Spray System (CSS) Knowledge of bus power supplies to the following: Containment spray pumps (CFR: 41.7) Tier: 2 Group: 1 Importance Rating: 3.4/3.6 Technical

Reference:

1-0P-26A Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info: (

DOMINION 1-0P-26A North Anna Power Station Revision 44 Page 55 of 140 ( (Page 1 of 1) Attachment 20 BUS/PANELS LOCATED IN ROD DRIVE 1-EE-SS-1 J1, 1J1 480 Volt Emergency Switchgear 1-EE-SS-04 LOCATION: ROD DRIVE ROOM POWER SUPPLY: l-EE-BKR-lSJ8 VIA 4160/480 V XFMR IJl

REFERENCE:

1171S-FE-IAF Breaker Required Ind No. Load Position Verifier Verifier 1411-1 Closed FEEDER FROM ISJ8 1411-2 Racked In l-RS-P-lB INSIDE RS PUMP 1411-4 Racked In l-QS-P-lB, B Quench Spray Pump Circuit Breaker ( 1411-S Racked In I-HV-F-lB, B Cntmt Air Recirc Fan Circuit Breaker l-EP-CB-I0A, 1411-6 Racked In Pressurizer Heater Panel No 1 Backup Group Ckt Bkr f50fk f

DOMINION 1-0P-26A North Anna Power Station Revision 44 Page 56 of 140 (Page 1 of 1) Attachment 21 1-EE-SS-1 H1, 1 H1 480 Volt Emergency Switchgear 1-EE-SS-03 LOCATION: ROD DRIVE ROOM POWER SUPPLY: l-EE-BKR-1SH8 VIA 4160/480 V XFMR IHI

REFERENCE:

1171S-FE-IAF Breaker Required Ind No. Load Position Verifier Verifier l-EE-SS-IH1, 14Hl-l Closed IHI 480V Emergency Switchgear Power Sply CB l-RS-P-IA, 14HI-2 Racked In A Inside Recirc Spray Pump Circuit Breaker Breaker 3 Spare, 14HI-3 Removed or Spare Circuit Breaker Disconnect l-QS-P-IA, 14Hl-4 Racked In A Quench Spray Pump Circuit Breaker I-HV-F-IA, 14Hl-S Racked In A Cntmt Air Recirc Fan Circuit Breaker l-EP-CB-lOD, 14HI-6 Racked In Pressurizer Heater Panel No 4 Backup Group Ckt Bkr l-EE-MCC-IHI-2S, 14HI-7 Closed IHl-2S Motor Control Center Power Sply Ckt Bkr

DOMINION 1-0P-26A North Anna Power Station Revision 44 Page 11 of 140 (Page 1 of 2) Attachment 1 BUS/MCC LOCATED IN EMERGENCY SWITCHGEAR ROOM 1-EE-SW-1H, 4160V Bus 1H LOCATION: EMERG SWGR ROOM POWER SUPPLY: "C" RSS VIA "F" XFER BUS, I-EP-SW-lB, IH EDG

REFERENCE:

11715-FE-ID Breaker Required Ind No. Load Position Verifier Verifier I-EE-SW-IH, 15HI Racked In IH Emergency Bus Power Supply Circuit Breaker I-EE-SW-IH, 15H2 Racked In IH Emer Bus Diesel Gen Power Supply Circuit Bkr I-FW-P-3A, 15H3 Racked In 3A Motor Driven Auxiliary Feedwater Pump Ckt Bkr 1-SW-P-4 15H4 Racked In Auxiliary Service Water Pump Circuit Breaker l-SW-P-IA, 15H5 Racked In A Service Water Pump Circuit Breaker I-CH-P-IA, 15H6 Racked In A Charging Pump Circuit Breaker 15H7 Power from H Bus Racked In I-CH-P-IC, C Charging Pump Circuit Power from J Bus Racked Out Breaker I-EE-SS-IH, IH Emergency Switchgear Power Supply 15H8 Circuit Bkr, AND l-EE-SS-lHl, IHI Emergency Racked In Switchgear Power Supply Circuit Bkr 15H9 LOW HEAD SAF INJ PP l-SI-P-IA Racked In l-RS-P-2A, 15HlO Racked In A Outside Recirc Spray Pump Circuit Breaker l-EE-SW-IH, 15HII Racked In Transfer Bus "F" Power Supply Circuit Breaker I-EE-SW-IH, 15H12 Racked In Emergency Bus IH Stub Bus Circuit Breaker

DOMINION 1-0P-26A North Anna Power Station Revision 44 Page 21 of 140 (Page 1 of 2) Attachment 7 1-EE-SW-1J, 4160V Bus 1J (1-EE-SW-2) LOCATION: EMERGENCY SWITCHGEAR ROOM POWER SUPPLY: A RSS, 2-EP-SW-2B BUS, OR lJ DIESEL

REFERENCE:

11715-FE-ID Breaker Required Ind No. Load Position Verifier Verifier 15J1 Racked In ALT FEED BUS lJ FROM BUS 2B I-EE-SW-lJ, 15J2 Racked In lJ Emer Bus Diesel Gen Power Supply Circuit Bkr I-FW-P-3B, 15J3 Racked In 3B Motor Driven Auxiliary Feedwater Pump Ckt Bkr Breaker J4SPARE, 15J4 Removed or Spare Circuit Breaker Disconnect I-SW-P-lB, B Service Water Pump Circuit Breaker 15J5 Racked In I-CH-P-lB, 15J6 Racked In B Charging Pump Circuit Breaker 15J7 Power from J Bus Racked In I-CH-P-IC, C Charging Pump Circuit Power from H Bus Racked Out Breaker I-EE-SS-lJ, lJ Emergency Switchgear Power Supply 15J8 Circuit Bkr, AND I-EE-SS-lJI, IJ1 Emergency Racked In Switchgear Power Supply Circuit Bkr I-SI-P-lB, 15J9 Racked In B Low Head SI Pump Circuit Breaker I-RS-P-2B, 15J10 Racked In B Outside Recirc Spray Pump Circuit Breaker I-EE-SW-lJ, 15J11 Racked In lJ Emergency Bus Power Supply Circuit Breaker I-EE-SW-lJ, 15J12 Racked In Emergency Bus lJ Stub Bus Circuit Breaker

STUDENT GUIDE FOR QUENCH SPRAY SYSTEM (53) Quench Spray Pumps 4.1 Objective U 5869 Explain the following concepts associated with the quench spray pumps.

• Purpose
• Purpose of the test nozzles
• Purpose of the weight-loaded check valve in the pump discharge line
• How an undervoltage condition affects the starting time of the pumps 4.1 Content

1. The purpose of the OS pumps is to:

( 1.1. Deliver water from the RWST to the spray rings following a CDA 1.2. Deliver RWST water to the suction of the inside recirculation spray (IRS) pumps to ensure adequate NPSH.

2. The purpose of the flow through the test nozzles is to ensure that no particulate material is in the system that will plug the containment spray nozzles.

2.1. The discharge into the RWST is split into two flow paths, one for the major portion of the recirculation flow and the other for passing a small quantity of water through test nozzles that are identical to those used in the spray rings. 2.2. The flow rate through the test nozzles is monitored during periodic testing using flow elements in the recirculation lines, and is compared to previous test results.

3. A weight-loaded check valve in each header ensures that no air leakage into Containment occurs and provides containment isolation.

( REACTOR OPERATOR Page 14 of 21 Revision 5, 09/17/2008

STUDENT GUIDE FOR QUENCH SPRAY SYSTEM (53) 3.1. Because the Quench Spray System headers are filled with air and the containment is maintained at a vacuum during normal plant operation, the possibility exists that atmospheric pressure air leaking into the QS System piping could reach the containment atmosphere.

4. If an undervoltage condition exists on its supply bus, a quench spray pump will:

4.1. Trip if it is already running. 4.2. Not start if an AUTO start signal is present. 4.3. When its respective supply bus under-voltage has cleared for 15 seconds the pump can automatically start as required. 4.2 Objective U 5925 Describe the conditions that would cause the following automatic quench spray pump actions to occur.

• Pump to start
• Motor-operated suction valves QS-MOV-100A and 100B to open
• Motor-operated discharge valves QS-MOV-1 01 A and 101 B to open 4.2 Content

1. The quench spray pumps will start immediately upon receipt of a CDA signal, provided that the following conditions are met:

1.1. The control switch is in the AUTO position. 1.2. No motor overload exists. 1.3. There has not been an undervoltage on the supply bus for at least 15 seconds.

2. Quench spray pump suction valves 1-QS-MOV-1 OOA and 1OOB are normally open.

2.1. They receive an OPEN signal from CDA. 2.2. Can not be manually closed if either a CDA signal is present or the associated QS pump is running. REACTOR OPERATOR Page 15 of 21 Revision 5,09/17/2008

STUDENT GUIDE FOR RECIRCULATION SPRAY SYSTEM (54) ( Inside Recirculation Spray Pumps 2.1 Objective U 6278 List the following information associated with the Unit-1 inside recirculation spray pumps.

• Power supplies
• Designed flow capacity
• Interlocks for starting the pump automatically
• Interlocks for tripping the pump automatically
• Purpose of the time delay associated with the automatic start of the pumps
• Time delay associated with starting the pump following an undervoltage condition
• Conditions that will cause the RS PUMP LOCKOUT, AUTO TRIP, OR TEST annunciator to actuate 2.1 Content

1. The inside recirculation spray pumps have the following power supplies:

1.1. 1-RS-P-1A - "H" 480 VAC Bus 14H1-2 located in Rod Drive. 1.2. 1-RS-P-1 B - "J" 480 VAC Bus 14J1-2 located in Rod Drive.

2. Each inside RS pump is a vertical, two-stage, turbine pump with a capacity of 3300 gpm.

3. With a CDA signal present and 2 of 3 RWST level channels below 60%, the inside recirculation spray pumps will automatically start after a 120-second time delay.

3.1. Control switch is in the AUTO position 3.2. Motor over-current reset 3.3. No undervoltage on the supply bus for the last 20 seconds. ( REACTOR OPERATOR Page 7 of 25 Revision 2, 10/10/2007

STUDENT GUIDE FOR RECIRCULATION SPRAY SYSTEM (54) ( 1.2. It should be noted that if CDA is reset prior to RWST level reaching 60%, the automatic start signal to outside recirculation spray pumps will be canceled. 3.3 Objective U 6239 List the following information associated with the outside recirculation spray pumps.

• Power supplies
• Interlocks for automatically starting the pumps
• Time delay associated with starting the pumps automatically
• Designed flow rate
• Time delay associated with starting the pump following an undervoltage condition
• Motive force used to circulate the seal water
• Source of makeup water to the seal head tank
• Indications available to the control room operator of an abnormal level in the seal head tank 3.3 Content

1. The outside recirculation spray pumps have the following power supplies:

1.1. 1-RS-P-2A - "H"4160 breaker 15H 10. 1.2. 1-RS-P-2B - "J" 4160 breaker 15J10.

2. With a CDA signal present and 2 of 3 RWST level channels below 60%, the outside RS pumps will automatically start, providing all the following conditions are met:

2.1. Control switch is in AUTO 2.2. No phase or ground over current 2.3. No undervoltage on the supply bus for the last 35 seconds. REACTOR OPERATOR Page 14 of 25 Revision 2, 10/10/2007

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

27. 026-K3.02 027INEW//L/3IROINAPSII Given the following conditions:

• A large-break LOCA occurred with Unit 1 initially at 100% power.
• All equipment functions as designed EXCEPT that 1-QS-P-1A, "A" Quench Spray Pump, shaft shears on startup.

Based on this malfunction, which ONE of the following describes the impact on the Containment, and on the Recirculation Spray System? A. Quench Spray will provide 360 0 spray of Containment and BOTH Inside Recirc Spray Pump sumps will receive design flow from Quench Spray. B~ Quench Spray will provide 360 0 spray of Containment and only ONE Inside Recirc Spray Pump sump will receive design flow from Quench Spray. C. Quench Spray will provide 180 0 spray of Containment and BOTH Inside Recirc Spray Pump sumps will receive design flow from Quench Spray. D. Quench Spray will provide 180 0 spray of Containment and only ONE Inside Recirc Spray Pump sump will receive design flow from Quench Spray. Feedback

a. Incorrect but plausible since candidate may assume that flow to recirc sumps is redundant.

b. Correct. Each train is a 360 0 array vice RS which are 180 0 , each as sump is dedicated to its associated train recirc sump.

c. Incorrect but plausible since as mentioned above RS arrays are 1800 and again candidate may assume that recirc sump flow is redundant.

d. Incorrect as discussed above; second part is correct.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Containment Spray System (CSS) Knowledge of the effect that a loss or malfunction of the CSS will have on the following: Recirculation spray system (CFR: 41.7 1 45.6) Tier: 2 Group: 1 Importance Rating: 4.2/4.3 Technical

Reference:

Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info:

Revision 44-Updated Online 11126/08 NAPS UFSAR 6.2-47 temperature rise of the water to approximately 0.5°F per 24-hour period when the refrigeration units are not operating. The RWST also has a connection that supplies water to the ECCS (Section The tank nozzle outlets connecting to the QS subsystem are located within an enclosure formed by a weir and the wall of the tank. The weir is shown on Figure The chemical addition tank has an operating volume of between 4800 and 5500 gallons and is located in close proximity to the RWST. The chemical addition tank and the RWST are connected by a pipe that conveys the sodium hydroxide solution from the bottom of the chemical addition tank through a 6-inch diameter opening to the volume within the weir in the RWST. There it mixes with the borated water flowing to the QS subsystems and flows through two lO-inch diameter openings located symmetrically on either side of the 6-inch inlet. The effect caused by the combination of various flow directions creates turbulence within the weir, which enhances the mixing operation. The mixture is then discharged under turbulent flow conditions to the quench spray pumps where the pump impeller will supply final mixing. The mixing process is not sensitive to any particular flow pattern. Both tanks are adequately vented to permit rapid drawdown. Two parallel redundant motor-operated valves are located in the line between the chemical addition tank and the RWST. The valves are closed during normal unit operation to prevent mixing of the sodium hydroxide solution with the water in the RWST. Five minutes after receipt ( of a containment depressurization actuation (CDA) signal, the motor-operated valves in the line between the RWST and the chemical addition tank open. This delay is to permit the operator to determine if the signal is authentic and to prevent sodium hydroxide injection to the quench sprays if the signal is spurious. As water is pumped out of the RWST, the sodium hydroxide solution flows under its hydrostatic head from the chemical addition tank to the RWST, keeping the liquid levels in the two tanks together once the connecting valves are opened. The height of the chemical addition tank has been chosen so that the column of sodium hydroxide in the chemical addition tank and the column of water in the RWST are in hydrostatic balance after the valves open. When 400,000 gallons of water have been withdrawn from the RWST, the chemical addition tank is empty. Sodium hydroxide addition initiated by a CDA signal cannot be manually terminated unless the CDA signal has been cleared. The chemical addition tank is insulated and, if required, the fluid is recirculated to keep the tank contents at a temperature above the freezing point of the solution. The chemical addition tank has a low-temperature alarm and a low-level alarm. The two electric motor-driven quench spray pumps are capable of supplying 1600 to 2000 gpm each of borated water to separate 360-degree quench spray ring headers located approximately 100 feet above the operating floor in the dome of the containment structure. The quench spray pumps are located in the safeguards area, an enclosure adjacent to the containment structure and the RWST. The pumps have been constructed in accordance with Class II of the

DESIGN QS System B 3.6.6 ( B 3.6 CONTAINMENT SYSTEMS B 3.6.6 Quench Spray (QS) System BASES BACKGROUND The QS System is designed to provide containment atmosphere cooling to limit post accident pressure and temperature in containment to less than the design values. The QS System, operating in conjunction with the Recirculation Spray (RS) System, is designed to cool and depressurize the containment structure to less than 2.0 psig in 1 hour and to subatmospheric pressure within 6 hours following a Design Basis Accident (DBA). Reduction of containment pressure and the iodine removal capability of the spray limit the release of fission product radioactivity from containment to the environment in the event of a DBA. The QS System consists of two separate trains of equal capacity, each capable of meeting the design bases. Each train includes a spray pump, a dedicated spray header, nozzles, valves, and piping. Each train is powered from a separate Engineered Safety Features (ESF) bus. The refueling water storage tank (RWST) supplies borated water to the QS System. The QS System is actuated either automatically by a containment High-High pressure signal or manually. The QS System provides a spray of cold borated water into the upper regions of containment to reduce the containment pressure and temperature during a DBA. Each train of the QS System provides adequate spray coverage to meet the system design requirements for containment heat and iodine fission product removal. The QS System also provides flow to the Inside RS pumps to improve the net positive suction head available. The Chemical Addition System supplies a sodium hydroxide (NaOH) solution into the spray. The resulting alkaline pH of the spray enhances the ability of the spray to scavenge iodine fission products from the containment atmosphere. The NaOH added to the spray also ensures an alkaline pH for the solution recirculated in the containment sump. The alkaline pH of the containment sump water minimizes the evolution of iodine and minimizes the occurrence of chloride and caustic stress corrosion on mechanical systems and components exposed to the fluid. (continued) North Anna Units 1 and 2 B 3.6.6-1 Revision 31

RS System B 3.6.7 ( \ BASES BACKGROUND cooling tank. The casing cooling pumps are considered part (continued) of the outside RS subsystems. Each casing cooling pump is powered from a separate ESF bus. The inside RS subsystem pump NPSH is increased by reducing the temperature of the water at the pump suction. Flow is diverted from the QS system to the suction of the inside RS pump on the same safety train as the quench spray pump supplying the water. The RS System provides a spray of subcooled water into the upper regions of containment to reduce the containment pressure and temperature during a DBA. Upon receipt of a High-High containment pressure signal, the two casing cooling pumps start, the casing cooling discharge valves open, and the RS pump suction and discharge valves receive an open signal to assure the valves are open. Refueling water storage tank (RWST) Level-Low coincident with Containment Pressure-High High provides the automatic start signal for the inside RS and outside RS pumps. Once the coincidence logic is satisfied, the outside RS pumps start immediately and the inside RS pumps start after a 120-second delay. The delay time is sufficient to avoid simultaneous starting of the RS pumps on the same emergency diesel generator. The coincident trip ensures that adequate water inventory is present in the containment sump to meet the RS sump strainer functional requirements following a loss of coolant accident (LOCA). The RS system is not required for steam line break (SLB) mitigation. The RS pumps take suction from the containment sump and discharge through their respective spray coolers to the spray headers and into the containment atmosphere. Heat is transferred from the containment sump water to service water in the spray coolers. The Chemical Addition System supplies a sodium hydroxide (NaOH) solution to the RWST water supplied to the suction of the QS System pumps. The NaOH added to the QS System spray ensures an alkaline pH for the solution recirculated in the containment sump. The resulting alkaline pH of the RS spray (pumped from the sump) enhances the ability of the spray to scavenge iodine fission products from the containment atmosphere. The alkaline pH of the containment sump water minimizes the evolution of iodine and minimizes the occurrence of chloride and caustic stress corrosion on mechanical systems and components exposed to the fluid. (continued) North Anna Units 1 and 2 B 3.6.7-2 Revision 31

STUDENT GUIDE FOR QUENCH SPRAY SYSTEM (53)

• How the containment spray pattern is affected by the loss one quench spray pump 4.4 Content

1. The OS spray rings distribute the OS water around the upper containment area producing the proper spray pattern and atomizing the water to maximize the surface area available for heat transfer and fission product removal from the containment atmosphere.

2. Two different sized nozzles are used in the Ouench Spray System spray rings.

2.1. The smaller nozzles atomize the OS water to maximize the surface area available for heat transfer between the containment atmosphere and the water droplets. 2.2. The larger nozzles ensure the proper spray pattern is obtained.

3. There are two 360 0 OS spray rings, one per OS pump, located in the dome of containment.

3.1. Nozzles are evenly distributed around their circumference to ensure maximum coverage of the containment.

4. The two 360 degree quench spray system spray rings are located next to each other at the top of the containment; the loss of a single quench spray pump still results in a 360 degree spray pattern.

( REACTOR OPERATOR Page 17 of 21 Revision 5, 09/17/2008

STUDENT GUIDE FOR RECIRCULATION SPRAY SYSTEM (54) (

• Purpose of the time delay associated with the automatic start of the pumps
• System that supplies additional cooling water to the suction of the pumps
• Configuration of the cooling line entering inside recirculation spray pumps
• How the non-operating is prevented from introducing air into the suction of the operating pump 2.2 Content

1. The outside recirculation spray pumps will start as soon as they receive the automatic start signal.

1.1. This will allow the outside recirculation spray pumps to: 1.1.1. Fill their piping completely. 1.1.2.Commence spray delivery to the containment thereby enhancing cooling of the containment sump prior to start of the inside recirculation spray pumps. 1.1.3.Stabilization of the containment sump's flow demand prior to start of the inside recirculation spray pumps. 1.2. The inside recirculation pumps will start after a 120-second time delay once they receive an automatic start signal.

2. Each inside recirculation spray pump suction pipe is supplied with cooling water from a portion of the discharge from the corresponding train's quench spray pump.

3. Due to the configuration of the suction strainer, the cooling water from the quench spray pumps is injected into the suction line of each inside recirculation spray pump via a single 4 inch bleed line.

4. As the design basis event progresses, one train of recirculation spray will be placed in standby once containment pressure has been reduced below 13 psia.

4.1. The recirculation spray pump suction strainer configuration provides the potential for injection of air from the standby pump's 4-inch bleed line into the suction of the running pump. 4.2. A spring loaded check valve has been installed in the inside recirculation spray pump bleed lines to prevent this from occurring. REACTOR OPERATOR Page 9 of 25 Revision 2, 10/10/2007

STUDENT GUIDE FOR RECIRCULATION SPRAY SYSTEM (54)

• Purpose of the time delay associated with the automatic start of the pumps
• System that supplies additional cooling water to the suction of the pumps
• Configuration of the cooling line entering inside recirculation spray pumps
• How the non-operating is prevented from introducing air into the suction of the operating pump 2.2 Content

1. The outside recirculation spray pumps will start as soon as they receive the automatic start signal.

1.1. This will allow the outside recirculation spray pumps to: 1.1.1. Fill their piping completely. 1.1.2.Commence spray delivery to the containment thereby enhancing cooling of the containment sump prior to start of the inside recirculation spray pumps. 1.1.3.Stabilization of the containment sump's flow demand prior to start of the inside recirculation spray pumps. 1.2. The inside recirculation pumps will start after a 120-second time delay once they receive an automatic start signal.

2. Each inside recirculation spray pump suction pipe is supplied with cooling water from a portion of the discharge from the corresponding train's quench spray pump.

3. Due to the configuration of the suction strainer, the cooling water from the quench spray pumps is injected into the suction line of each inside recirculation spray pump via a single 4 inch bleed line.

4. As the design basis event progresses, one train of recirculation spray will be placed in standby once containment pressure has been reduced below 13 psia.

4.1. The recirculation spray pump suction strainer configuration provides the potential for injection of air from the standby pump's 4-inch bleed line into the suction of the running pump. 4.2. A spring loaded check valve has been installed in the inside recirculation spray pump bleed lines to prevent this from occurring. REACTOR OPERATOR Page 9 of 25 Revision 2, 10/10/2007

STUDENT GUIDE FOR QUENCH SPRAY SYSTEM (53)

• How the containment spray pattern is affected by the loss one quench spray pump 4.4 Content

1. The OS spray rings distribute the OS water around the upper containment area producing the proper spray pattern and atomizing the water to maximize the surface area available for heat transfer and fission product removal from the containment atmosphere.

2. Two different sized nozzles are used in the Ouench Spray System spray rings.

2.1. The smaller nozzles atomize the OS water to maximize the surface area available for heat transfer between the containment atmosphere and the water droplets. 2.2. The larger nozzles ensure the proper spray pattern is obtained.

3. There are two 360 0 OS spray rings, one per OS pump, located in the dome of containment.

3.1. Nozzles are evenly distributed around their circumference to ensure maximum coverage of the ( containment.

4. The two 360 degree quench spray system spray rings are located next to each other at the top of the containment; the loss of a single quench spray pump still results in a 360 degree spray pattern.

REACTOR OPERATOR Page 17 of 21 Revision 5, 09/17/2008

QUESTIONS REPORT ( for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

28. 027-A4.01 028/MODIFIED/NAPSILI2!RO/NAPSII Which ONE of the following describes the automatic operation of 1-QS-MOV-1 02A, Chemical Addition Tank outlet valve?

A. 1-QS-MOV-102A will open immediately provided BOTH the "A" Quench Spray Pump breaker is closed ANO COA is actuated. B. 1-QS-MOV-102A will open immediately provided EITHER the "A" Quench Spray Pump breaker is closed OR COA is actuated. C. 1-QS-MOV-1 02A will open after a 5-minute time delay provided BOTH the "A" Quench Spray Pump breaker is closed ANO COA is actuated. O~ 1-QS-MOV-102A will open after a 5-minute time delay provided EITHER the "A" Quench Spray Pump breaker is closed OR COA is actuated. Feedback

a. Incorrect. Plausible since candidate may assume that it would only be needed under COA conditions and would require a QS pump running to inject into containment. Candidate may not be aware of the purpose of the time delay.

b. Incorrect. Plausible since candidate may not be aware of the purpose of the time delay. Second part for opening logic is correct.

c. Incorrect. Time delay to prevent undesired Naoh injection is correct but opening logic is incorrect as discussed above.

d. Correct. Time delay to prevent undesired Naoh injection is correct and opening logic is correct.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Containment Iodine Removal System (CIRS) Ability to manually operate andlor monitor in the control room: CIRS controls (CFR: 41.7 1 45.5 to 45.8) Tier: 2 Group: 2 Importance Rating: 3.3/3.3 Technical

Reference:

1-E-O Att. 2 and lesson plan Proposed references to be provided to applicants during examination: None Learning Objective: U5955 Question History: modified from uid 270 additional info:

NUMBER ATTACHMENT TITLE ATTACHMENT 1-E-0 2 VERIFICATION OF REVISION PHASE B ISOLATION PAGE 39 1 of 9 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. VERIFY THE FOLLOWING AUTOMATIC OPERATIONS ON THE "H" SAFEGUARDS PANEL:

o a) Verify Phase B isolation valves (located on o Manually close valves: the lower right corner of the panel) - CLOSED (all green lights lit or check each valve below): DAII green lights lit. TRIP VALVES (TV) CLOSED (GREEN) CC- CC- CC- CC-

               -    105A                 -  102A                104A-1                101A CC-                     CC-                CC-                    CC-
               -    105B                 -  102C             -  104B-1                103A CC-                     CC-                CC-                     IA-
               -    105C                 -  102E                104C-1                102A NOTE: 1-QS-MOV-102A, CHEMICAL ADDITION TANK A OUTLET VALVE, opens following a 5-minute time delay.

o b) Verify Quench Spray - ALIGNED AND o Manually do operations as indicated: RUNNING: RUNNING (RED) OPEN (RED) 1-QS-P-1A 1-QS-MOV-1 01 A 1-QS-MOV-100A 1-QS-MOV-102A (STEP 1 CONTINUED ON NEXT PAGE)

INSTRUCTOR GUIDE FOR QUENCH SPRAY SYSTEM (53) ( 1.4.1.1. h+OH- ---) HIO+r 1.5. The iodine formed in the above reaction is highly soluble, and the HIO readily oxidizes to form 103 - in an oxygenated medium. 1.6. This form is also highly soluble in the spray medium and the reaction is as follows: 1.6.1. HIO + O2 ---) 103 - + H+ 1.7. The iodine is removed from the containment atmosphere with a half-life that is less than 3 minutes. 1.8. The rapid removal rate combined with the depressurization of the containment atmosphere reduces the amount of radioactive iodine that leaks out of the Containment. 1.9. The depressurization of the Containment within the 60-minute limit ensures that personnel at the site boundary will not exceed the Code of Federal Regulation 10 CFR 100 limit of 300 Rem to the thyroid and 25 Rem to the whole body.

2. Minimizes the corrosion effects on components within the containment.

2.1. The actuation of OS with water from the RWST introduces water in the containment sump with a pH of approximately 4.0. 2.2. After the 5-minute delay, NaOH is added to the RWST water increasing the pH [8.5 to 10]. 2.3. The spray water combines with the primary coolant and boric acid from the RWST to form a slightly basic solution in the containment sump. 2.4. This solution, with a pH of about [7.0 to 9.5] helps prevent chloride (CI-) stress corrosion of the RCS components. Topi~3.3 Chemi~alAdditiohtankMOVS 3.3 Objective U 5955 List the following information associated with the refueling water storage tank's chemical addition tank motor-operated outlet valves (OS-MOV-1 02A and 1028).

• Power supply REACTOR OPERATOR Page 13 of 22 Revision 5, 09/17/2008

INSTRUCTOR GUIDE FOR QUENCH SPRAY SYSTEM (53)

• Conditions that will automatically cause the valves to open, including the time delay
• Purpose for the opening time delay 3.3 Content

1. Power for the Chemical Addition Tank discharge MOVs is from the 480 Volt Emergency busses.

1.1. 1-QS-MOV-102A is powered from 1H1-2S B2. 1.2. 1-QS-MOV-102B is powered from 1J1-2S B3.

2. Valves will open automatically, following a 5-minute time delay if either:

2.1. CDA is actuated, or 2.2. The associated train's quench spray pump is started.

3. The 5 minutes allow the operator sufficient time to verify that the CDA signal is valid, and if necessary prevent injection of the chemical addition tank contents.

T epic 3.4 De-energizingChetnical.. "ddition Tank MbVs 3.4 Objective U 5872 Explain why the quench spray chemical addition tank's motor-operated valve must be de-energized before starting a quench spray pump for test purposes. 3.4 Content

1. Prior to starting a Quench Spray pump for testing purposes, the associated chemical addition tank 1-QS-MOV-102A or B must be de-energized.

1.1. This is to prevent the valve from opening automatically 5 minutes after starting the pump. 1.2. Prevents dumping of the chemical addition tank to the RWST. REACTOR OPERATOR Page 14 of 22 Revision 5,09/17/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

29. 027-AK3.02 029INEW/IH/3/ROINAPSII Unit 1 is at 100% power.

The OATC notes that all PRZR heaters are energized, and RCS pressure is 2270 psig and rising. Based on these plant conditions, which ONE of the following identifies the failed channel and includes the plant response if no operator action is taken? A. 1-RC-PT-1444 failed low; 1-RC-PCV-1455C will cycle open and closed S:I 1-RC-PT-1444 failed low; 1-RC-PCV-1456 will cycle open and closed C. 1-RC-PT-1445 failed low; 1-RC-PCV-1456 will cycle open and closed D. 1-RC-PT-1445 failed low; 1-RC-PCV-1455C will cycle open and closed Feedback

a. Correct transmitter but incorrect because the PORV is the one associated with the failed channel and it will not respond.

b. Correct transmitter and since this channel also controls the PRZR spray valves not actions will occur until pressure reaches 2335 psig as seen by the opposite control channel at which time PORV-1456 will cycle to limit the pressure rise.

c. Incorrect transmitter, plausible since candidate must know the features of both of the control channels to positively identify the answer and eliminate distractors; PORV is correct.

d. Plausible as discussed in distractor C; also incorrect PORV.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Pressurizer Pressure Control System (PZR PCS) Malfunction Knowledge of the reasons for the following responses as they apply to the Pressurizer Pressure Control Malfunctions: Verification of alternate transmitter and/or plant computer prior to shifting flow chart transmitters (CFR 41.5,41.10/45.6/45.13) Tier: 1 Group: 1 Importance Rating: 2.9/3.0 Technical

Reference:

1-AP-44 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info:

                                                                 ?RES5URIZER PRESSURE CHAr-mELS TRAIN B       TRAIN A

3. LOCAL CDNiPOL OVERRIDES ALL OTHER SIGNALS. LOCAL OVERRIDE ACTUATES ALARM Irl CONTROL ROOM.

   ~. PRC::SSURE 815T ABL::S P(-4448. P(-4.';<lF AI~D PC-4~5A ARE '::NERGIZE            NUCLEAR STEAM SUPPLY SYSTEM TO AC TUI~ T::".

5. OPErUSHUT I~IDICA TIOH II~ COI"HROL ROO~A.

FUNCTIOCIAL DIAGRAM

5. A LIGHT SHOULD BE P::\OVIDED IH THE ~OIHROL ROOIvI FOR EACH 3i PRESSURIZER PRESSURE LEVEL CONTROL SPRAY VALVE TO INDV,TE WHEI'J IT IS NOT FULLY CLOSED. UNITS 1& 2 VIRGINIA POWER NORTH ANNA POWER STATION

STUDENT GUIDE FOR PRESSURIZER CONTROL AND PROTECTION SYSTEM (74) Integrated Plant Operations 10.1 Objective U 11996 Given a set of plant conditions, evaluate Pressurizer Control and Protection System operations in light of the following issues.

• Effect of a failure, malfunction, or loss of a related system or component on this system
• Effect of a failure, malfunction, or loss of components in this system on related systems
• Expected plant or system response based on pressurizer control and protection component interlocks or design features
• Impact on the technical specifications
• Response if limits or setpoints associated with this system or its components have been exceeded
• Proper operator response to the condition as stated 10.1 Content CONTROL SYSTEM FAILURE ANALYSIS (NOTE: ALL EFFECTS ASSUME NO OPERATOR ACTION IS TAKEN.)

PRESSURIZER PRESSURE CONTROL SYSTEM 1444 HIGH EFFECT: PCV1455C and both spray valves go full open and all heaters will turn off. Pressure drops rapidly until the P-11 interlock (2/3 < 2000 psig) closes the PORV. Pressure continues to drop due to both sprays being open and the reactor trips on a low-pressure signal that is rate-compensated. A low pressure SI will also occur (1780 psig). LOW EFFECT: All heaters on full. Spray valves stay shut. Pressure slowly rises until PCV-REACTOR OPERATOR Page 50 of 52 Revision 1, 05/02/2007

STUDENT GUIDE FOR PRESSURIZER CONTROL AND PROTECTION SYSTEM (74) 1456 opens. Pressure cycles around PORV setpoint (-2335 psig). Note that PCV-1455C is disabled. 1445 HIGH EFFECT: PCV-1456 opens and pressure drops rapidly. PORV will be shut by P-11 interlock (2000 psig). Pressure will cycle around interlock setpoint. Note that the pressure could overshoot and cause a plant trip on low pressure. LOW EFFECT: None. Note that PCV-1456 is disabled. PRESSURIZER LEVEL CONTROL SYSTEM Main Control Channel (Channel section 459 or 461) HIGH EFFECT: Backup heaters turn on and the charging flow is reduced to minimum. Pressurizer level will decrease. At 15% level, letdown isolation occurs, heaters turn off, and the other control channel will generate an alarm. With no letdown, pressurizer level will then rise until a trip occurs on high level (92%). LOW EFFECT: Letdown isolation, heaters off, charging flow increases to maximum. Reactor trip will occur on high PRZR level (92%). Secondary Control Channel (460 or 461) HIGH EFFECT: None. High level alarm will be generated (69.5%). LOW EFFECT: Letdown isolation occurs and the heaters turn off. Pressurizer level will rise slowly causing charging flow to be reduced to minimum (-25 gpm). Reactor will eventually trip on high PRZR level (92%). Tave Circuit Failure HIGH EFFECT: Level reference limited to 100% programmed level. If level is less that REACTOR OPERATOR Page 51 of 52 Revision 1, 05/02/2007

STUDENT GUIDE FOR PRESSURIZER CONTROL AND PROTECTION SYSTEM (74) program, it will be brought to 100% program level (64.5%). LOW EFFECT: Charging flow is reduced until level decreases to O%-programmed level (28.4%). REACTOR OPERATOR Page 52 of 51 Revision 1, 05/02/2007

QUESTIONS REPORT ( for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

30. 028-02.2.44 030INEW/1H/3/ROINAPS//

Given the fol/owing conditions: Unit 1 is at 100% power.

• The Pressurizer Level Channel Defeat Switch is selected to position 461/460.
• Annunciator B-G7, PRZ LO LEV HTRS OFF LETDOWN ISOL, alarms.

The OATC notes the following:

• PRZR level is 66% and slowly increasing.

Demand on 1-RC-LC-1459G, PRZR Level Controller, is approximately 35% and slowly decreasing. Based on these plant conditions, which ONE of the following identifies the failed instrument, and the Immediate Operator Action required by 1-AP-3, Loss of Vital Instrumentation? A'! 1-RC-L/-1460 is failed low; Place 1-CH-FCV-1122, Charging Flow Control valve, in MANUAL and control level at program. B. 1-RC-L/-1460 is failed low; Place Pressurizer Level Channel Defeat Switch in position 459/461, then verify Annunciator B-G7, PRZ LO LEV HTRS OFF LETDOWN ISOL, clears. C. 1-RC-L/-1461 is failed low; Place 1-CH-FCV-1122, Charging Flow Control valve, in MANUAL and control level at program. D. 1-RC-L/-1461 is failed low; Place Pressurizer Level Channel Defeat Switch in position 459/460, then verify Annunciator B-G7, PRZ LO LEV HTRS OFF LETDOWN ISOL, clears. Feedback

a. Correct. If the controlling channel failed low then the master controller output would increase to 100%, it would not be throttling back as indicated; second part is the correct lOA (this is a resent change to the procedure to add this as an IDA).

b. Incorrect. Channel is correct as noted above; second part is incorrect, but plausible as this is a subsequent action of the procedure and ultimately required to correct the condition.

c. Incorrect. Channel is incorrect but plausible since if the candidate does not have detailed systems knowledge they could easily confuse which channel controls and may not be aware of the expected master controller response; second part is correct as discussed in Distractor a.

d. Incorrect. Both parts incorrect but plausible as discussed in Distractors b & c.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Pressurizer (PZR) Level Control Malfunction Ability to interpret control room indications to verify the status and operation of a system, and understand how operator actions and directives affect plant and system conditions. (CFR: 41.5/43.5 145.12) Tier: 1 Group: 2 Importance Rating: 4.2/4.4 Technical

Reference:

1-AP-3 and PRZR level control lesson plan Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info: Resent change to procedure 1-AP-3

NORTH ANNA POWER STATION ABNORMAL PROCEDURE NUMBER PROCEDURE TITLE REVISION 23 1-AP-3 LOSS OF VITAL INSTRUMENTATION (WITH TWO ATTACHMENTS) PAGE 1 of 19 PURPOSE To provide instructions to follow in the event of a loss of vital instrumentation. ENTRY CONDITIONS This procedure is entered when a faulty indication occurs on any of the following vital instrumentation channels:

• Reactor Coolant Flow, or
• Pressurizer Level, or
• Pressurizer Pressure Protection, or
• DELTA TITAVE Protection, or
• Containment Pressure Protection, or
• RWST Level, or
• Steam Generator Level, or
• Turbine Stop Valves Indication, or
• Turbine First Stage Impulse Pressure, or
• Turbine Auto Stop Oil Low Pressure Trip Signal, or
• Ste~m Flo"Y1 or
• Fe~~'Flo~~~~r ..
• St*;*"*;** pt~~sJfe,dr)

     .~ll:diOn $~"I"vice B~~Und~FVoltage,br

• Station Service Bus Underfrequency.

CONTINUOUS USE

NUMBER PROCEDURE TITLE REVISION 23 1-AP-3 LOSS OF VITAL INSTRUMENTATION PAGE 2 of 19 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED 1 ] _ VERIFY REDUNDANT o IF unable to determine Reactor is in a safe INSTRUMENT CHANNEL operating condition, THEN GO TO 1-E-O, INDICATION - NORMAL REACTOR TRIP OR SAFETY INJECTION. 2 ]_ VERIFY STEAM GENERATOR Do the following: LEVEL CONTROLLING CHANNELS - NORMAL: a) Place the associated valves in MANUAL: o

• Steam Flow o
• Main Feed Reg Valves o
• Feed Flow o
• Main Feed Reg Bypass Valves o
• Steam Generator Level Ch III o b) Control Steam Generator level.

o

• Steam Pressure 3 ]_ VERIFY TURBINE FIRST STAGE o IF the controlling channel failed, THEN place PRESSURE INDICATIONS - Control Rod Mode Selector switch in MANUAL.

NORMAL 4 ]_ VERIFY PRESSURIZER LEVEL IF any selected channel failed, THEN do the INDICATIONS - NORMAL following: o a) Place 1-CH-FCV-1122, Charging Flow Control Valve, in MANUAL. o b) Control Pressurizer level at program.

NUMBER PROCEDURE TITLE REVISION 23 1-AP-3 LOSS OF VITAL INSTRUMENTATION PAGE 3 of 19 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

5. VERIFY SYSTEMS AFFECTED BY PRESSURIZER LEVEL CHANNELS-NORMAL o a) Verify operable Pressurizer level a) Do the following:

channels - SELECTED o 1) Select operable Pressurizer level channels for control.

2) Verify the following Annunciators are proper for plant conditions:

o

• Panel B-F8, PRZ LO LEVEL o
• Panel B-G6, PRZ HI LEVEL-BU HTRS ON o
• Panel B-G7, PRZ LO LEV HTRS OFF -

LETDWN ISOL o

• Panel B-G8, PRZ HI LEVEL o b) Verify Emergency Bus backup o b) !E Emergency Bus backup Heaters will NOT Heaters - RESTORED restore, THEN enter Tech Spec 3.4.9.

o c) Verify Letdown - IN SERVICE o c) Restore letdown using Attachment 2, LETDOWN RESTORATION. (STEP 5 CONTINUED ON NEXT PAGE)

                      ~----------------------------:!~,                                                                                                                                                                                                                                                            /

PRESSURIZER PRESSURE CHANNELS o, A~~A ~i6N (I)

                                                                                                                                                                                                                             '    CHARGING PUMP                      ' "

PRESSURIZER LEVEL CHANNELS MEDIAN/HI TAVG P-II ~ FROM STATION --l--(I) .---(1) !---(I) PRESSURIZER LOW PRESSURE 1213) MEDIAN SIGNAL SELECT CIRCUIT -------------------~----.--.-.  : (SHEET 61 (SHEE~ 9) -~-- ... ---~.- ------~ TRAIN B TRAIN A v-- t -------- r i-- ----(I) ADJUSTABLE __ :J,?\: ___ ---. ~£T~gl~~ TAVG

                                                                                                                                                        .Y .           WITH CONTROLLER               I'~ tl                                                 ~

--t-~------~

                                                                                                                                                                                                                                                                                  -~~+--

_,o,t:

                                                                             .--- '**-0                                                               ~ LEVEL                                                                                             "V_
                                                                                                                                                                                                               ~

AUX.F.P. PROGRAM

                                                                             .           STATION                                                                  CONTROLLER

LREF ____ _

ADJUSTABLE LEVEL CHANNEL

                                                                                                                                                                                                           -~:lREF;-

PRESSURE SELECTOR

                                                                                      -~----           -- REFERENCE SETPOINT WITHIN SWITCH (POSiTiON 2
                                                                                          . (p-P REFI     CONTROLLER                                                                                                                                                 NORMALLY r

SELECTED) i (NOTE 4) (NOTE~) . (P-P REF) i  : 1:v -'-------- --------T-~---------------.------- (NOTE 4) (NOTE 4)

                                                                                                                                                                                                                  ~-----(I)
                                                                                                                                                                                                                                                                                                  '{O  s L            :1~S (NOTE 4)                                                                                                                                                                                                                                                          (I)
                                       $s
                                         ~ 1"                    A
                                                                                        +/-s                              414) s

(~~ L A ALL ORIFICE ISOLATiON VALVES CLOSED POWER RELIEF VAL VE CONTROL MODE SELECTOR SWITCH POWER RELiEF VAL VE CONTROL MODE SELECTOR SWITCH [1J ~ (CONTROL BOARD) (CONTROL BOARD> SPRAY SPRAY CONTROLLER CONTROLLER CLOSE ALL ORIFICE ISOLATION VALVES (NOTE 5) L-..c...--'-_..JI (NOTE 3) TO TURN-ON TO VARIABLE i MODULATE I MODULATE i CHARGING ALL BACK-UP HEATER SPRAY SPRAY FLOW HEATERS CONTROL VALVE "I VALVE "2 CONTROL (SHEET 12) SIGNAL PCV-455A PCV-455B (SHEET 12) (NOTE 6) (NOTE 6) NOTES: I. LOGIC OUTPUT OPERATES 2 SOLENOID VENT VALVES IN SERIES TO INTERLOCK THE AIR LINE TO EACH VALVE DIAPHRAGIJ. THE SOL£NIOD VALVES ARE DE-ENERGIZED TO VENT, CAUSING THE MAIN RELIEF VALVE TO CLOSE IN 2 SECONDS.

2. ALL CIRCUITS ON THIS SHEET ARE NOT REDUNDANT.

3. LOCAL CONTROL OVERRIDES ALL OTHER SIGNALS. LOCAL OVERRIDE ACTUATES ALARM IN CONTROL ROOM,

4. PRESSURE BISTABLES PC-~44B, PC-444F AND PC-445A ARE *ENERGIZE NUCLEAR STEAM SUPPLY SYSTEM TO ACTUATE*,

5, OPEN/SHUT INDICATiON IN CONTROL ROOM. FUNCTION.AL DIAGRAM

6. A LIGHT SHOULD BE PROVIDED IN THE CONTROL ROOM FOR EACH PRESSURIZER PRESSURE & LEVEL CONTROL SPRAY VALVE TO INDICATE WHEN IT IS NOT FULLY CLOSED. UNITS 1& 2 VIRGINIA POWER REVISED PEP. OCR 2001-1268 NORTH ANNA POWER STATION THIS O"C SUPERSEDES FlEV IORICINIU..

AEVlSICfiDESCRIPTIOH SIt II 01'16 PC=NOt 12-SEP-2001 06118 PRIOR TO USING FOR DESIGN WORK CHECK OMIS FOR WORK PENDING

STUDENT GUIDE FOR PRESSURIZER CONTROL AND PROTECTION SYSTEM (74) Integrated Plant Operations 10.1 Objective U 11996 Given a set of plant conditions, evaluate Pressurizer Control and Protection System operations in light of the following issues.

• Effect of a failure, malfunction, or loss of a related system or component on this system
• Effect of a failure, malfunction, or loss of components in this system on related systems
• Expected plant or system response based on pressurizer control and protection component interlocks or design features
• Impact on the technical specifications
• Response if limits or setpoints associated with this system or its components have been exceeded
• Proper operator response to the condition as stated 10.1 Content CONTROL SYSTEM FAILURE ANALYSIS (NOTE: ALL EFFECTS ASSUME NO OPERATOR ACTION IS TAKEN.)

PRESSURIZER PRESSURE CONTROL SYSTEM 1444 HIGH EFFECT: PCV1455C and both spray valves go full open and all heaters will turn off. Pressure drops rapidly until the P-11 interlock (2/3 < 2000 psig) closes the PORV. Pressure continues to drop due to both sprays being open and the reactor trips on a low-pressure signal that is rate-compensated. A low pressure SI will also occur (1780 psig). LOW EFFECT: All heaters on full. Spray valves stay shut. Pressure slowly rises until PCV-REACTOR OPERATOR Page 50 of 52 Revision 1, 05/02/2007

STUDENT GUIDE FOR PRESSURIZER CONTROL AND PROTECTION SYSTEM (74) 1456 opens. Pressure cycles around PORV setpoint (-2335 psig). Note that PCV-1455C is disabled. 1445 HIGH EFFECT: PCV-1456 opens and pressure drops rapidly. PORV will be shut by P-11 interlock (2000 psig). Pressure will cycle around interlock setpoint. Note that the pressure could overshoot and cause a plant trip on low pressure. LOW EFFECT: None. Note that PCV-1456 is disabled. PRESSURIZER LEVEL CONTROL SYSTEM /J ..\'1-,) \ \-\ \, \f)~ ~)' C/ Main Control Channel (Channel section 459 ~ HIGH EFFECT: Backup heaters tum on and the charging flow is redt! to minimum. Pressurizer level will decrease. At 15% level, letdown isolatio 0 curs, heaters turn off, and the other control channel will generate an alarm. With n\J~own, pressurizer level will then rise until a trip occurs on high level (~ ~ LOW EFFECT: Letdown isolation, heaters off, crerging flow increases to maXi~. Reactor trip will occur on high PRZR level (92%). I Secondary Control Channel (460 or 461) ~y5W " I ~[

                                                                      'fbll.'t6C'J dwv* A't IN I 5   5:' e c..ov.-CLu.-;v"1 A    c..

HIGH EFFECT: None. High level alarm will be generated (69.5%). -0 LOW EFFECT: Letdown isolation occurs and the heaters turn off. Pressurizer level will rise slowly causing charging flow to be reduced to minimum (-25 gpm). Reactor will eventually trip on high PRZR level (92%). Tave Circuit Failure HIGH EFFECT: Level reference limited to 100% programmed level. If level is less that REACTOR OPERATOR Page 51 of 52 Revision 1, 05/02/2007

STUDENT GUIDE F,OR PRESSURIZER CONTROL AND PROTECTION SYSTEM (74) program, it will be brought to 100% program level (64,5%), LOW EFFECT: Charging flow is reduced until level decreases to O%-programmed level (28.4%), REACTOR OPERATOR Page 52 of 51 Revision 1, 05/02/2007

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal 31 . 029-Al.03 03 1IBANKINAPS/H/2/ROINAPSII Unit 1 is in Mode 6 with core off-load in progress. A containment purge exhaust fan is started by the Backboards Operator. As a result of this action, reactor cavity level will and spent fuel pit level will _ _ _ _ __ A':" increase slightly; decrease slightly B. increase slightly; not be affected C. not be affected; not be affected D. decrease slightly; increase slightly Feedback

a. Correct. Starting the purge fan would lower pressure slightly and thus allow water to sluice from the SFP to the cavity via the canal, the candidate must have detailed knowledge of the procedure and/or refueling process.

b. Incorrect. Plausible since the candidate who does not have detailed systems knowledge may conclude that this would affect level via a source such as cavity purification system and since it is in containment would not relate it back to the SFP.

c. Incorrect. Plausible since the candidate may conclude that a fan would not be significant enough to cause a change in level.

d. Incorrect. Plausible if the candidate reverses the cause and effect relationship this distractor would make sense.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Containment Purge System (CPS) Ability to predict and/or monitor changes in parameters associated with operating the Containment Purge System controls including: Containment pressure, temperature, and humidity (CFR: 41.5/45.5) Tier: 2 Group: 2 Importance Rating: 3.0/3.3 Technical

Reference:

1-0P-21.2 Proposed references to be provided to applicants during examination: None Learning Objective: 50739 Effects of ventilation on pool levels Question History: bank additional info:

DOMINION 1-0P-21.2 North Anna Power Station Revision 30 Page 5 of 15 ( 4.0 PRECAUTIONS AND LIMITATIONS 4.1 Comply with the following guidelines when marking steps NIA:

• IF the conditional requirements of a step do not require the action to be performed, THEN mark the step NIA.
• IF any other step is marked NIA, THEN have the SRO approve the NIA and justify the NIA on the Procedure Cover Sheet.

4.2 WHEN required to be functional by TRM 3.9.5 OR During movement of irradiated fuel assemblies within containment THEN the following Radiation Monitors are OPERABLE per TRM 3.3.7, table 3.3.7-1: (Reference 2.4.5)

• l-RM-RMS-159, Containment Particulate Radiation Monitor
• l-RM-RMS-160, Containment Area Gas Radiation Monitor

(

• l-RM-RMS-162, Manipulator Crane Radiation Monitor 4.3 The reactor containment shall not be purged while the reactor coolant system temperature is > 200°F and containment is sub atmospheric.

4.4 All automatic containment isolation valves in that unit shall be operable or at least one valve in each line shall be closed except in those systems which must be operated during refueling. 4.5 To prevent the possible collapse of purge system duct work, when it is desired to establish atmospheric conditions in the containment, do NOT under any circumstances open l-HV-MOV-lOOB, CONT PURGE SUPPLY VALVE (outside valve) while vacuum is being broken. 4.6 Purges shall go through filter unless written authorization from Health Physics states otherwise. 4.7 Ventilation changes made when the fuel transfer tube is open may cause a pressure differential between Containment and the Fuel Building and result in level changes in the Spent Fuel Pit or Reactor Cavity. (Reference 2.4.1)

STUDENT GUIDE FOR FUEL HANDLING SYSTEM (48)

• Possible affect on core power distribution
• Indications of a core loading error
• Administrative controls which prevent core loading errors 9.5 Content

1. Fuel assemblies loaded into the wrong core location could cause a power distortion that could significantly raise peaking factors.

2. The power distortion resulting from a core loading error would be readily observable with in-core flux monitors.

2.1. Core thermocouples would also indicate any abnormally high coolant enthalpy rise. In-core flux measurements are taken during the startup following the refueling operations.

3. Core loading errors are prevented by administrative procedures implemented during core loading.

3.1. Core mapping is performed following the onload of fuel. 3.2. In the unlikely event that a loading error occurs, the power distribution effects either will be readily detected by the in-core movable detector system or will cause sufficiently small perturbation to be acceptable within the uncertainties allowed between nominal and design power shapes. 9.6 Objective U 9040 Explain the possible effect on spent fuel pit and reactor cavity level due to the following conditions during refueling operations.

• Decreasing the number of containment exhaust fans
• Decreasing the number of fuel building exhaust fans
• Closing the fuel transfer tube isolation valve with the Refueling Purification System aligned to take suction from the reactor cavity and discharge to the spent fuel pit REACTOR OPERATOR Page 50 of 58 Revision 1, 04/11/2007

STUDENT GUIDE FOR FUEL HANDLING SYSTEM (48) 9.6 Content

1. Decreasing the number of containment exhaust fans would cause cavity level to decrease and spent fuel pool level to increase.

2. Decreasing the number of fuel building exhaust fans would cause cavity level to increase and spent fuel pool level to decrease.

3. Closing the fuel transfer tube isolation valve with the Refueling Purification System aligned to take suction from the reactor cavity and discharge to the spent fuel pit would cause cavity level to decrease and spent fuel pool level to increase.

9.7 Objective U 9042 Explain why fuel assemblies should not be stored in the fuel transfer system upenders while in a vertical position. 9.7 Content

1. Fuel is not stored in a vertical upender because a loss of cavity level would result in an increased radiation hazard.

9.8 Objective U 9043 Explain why station personnel must notify security prior to entering the new fuel storage area while fuel is being stored. REACTOR OPERATOR Page 51 of 58 Revision 1, 04/11/2007

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

32. 029-EK2.06032INEWIIL/2/ROINAPS/S/20/200S1 Which ONE of the following describes the actions required by 2-FR-S.1, Response to Nuclear Power Generation/ATWS, Attachment 4 (Remote Reactor Trip) if attempts to locally trip the reactor from the Rod Drive room are unsuccessful?

A. De-energize BOTH 2A1 and 2C2 480-Volt Station Service Busses by opening their respective supply breakers. B. De-energize BOTH 2A1 and 2B2 480-Volt Station Service Busses by opening their respective supply breakers. C~ Open BOTH Rod Drive M-G Set Motor Supply Breakers locally at the 2A 1 and 2C2 480-Volt Station Service Busses. D. Open BOTH Rod Drive M-G Set Motor Supply Breakers locally at the 2A1 and 2B2 480-Volt Station Service Busses. Feedback

a. Incorrect. This will trip the reactor but is NOT lAW the attachment; the candidate who is not knowledgeable of the attachment may default to this distractor.

b. Incorrect. Plausible as discussed in Distractor A; also these busses are the power supplies on Unit 1 (knowledge of Unit differences is also required to answer this test item).

c. Correct. Action and location (power supply) are both correct.

d. Incorrect. Action is correct but locations wrong for Unit 2 as noted above.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Anticipated Transient Without Scram (ATWS) Knowledge of the interrelations between the and the following an ATWS: Breakers, relays, and disconnects (CFR 41.7 / 45.7) Tier: 1 Group: 1 Importance Rating: 2.9/3.1 Technical

Reference:

2-FR-S.1 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info: this question also qualifies as a Unit differences topic for dual unit license

NUMBER ATTACHMENT TITLE ATTACHMENT 2-FR-S.1 4 REMOTE REACTOR TRIP REVISION PAGE 15 1 of 2 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE: Because of M-G Set Flywheel coastdown, Reactor trip may be delayed for approximately one minute following opening of the M-G Set Motor Supply Breakers.

1. LOCALLY TRIP THE REACTOR FROM THE ROD DRIVE ROOM:

a) Do the following:

• Press the TRIP buttons for both Reactor Trip Breakers:

o

• 2-EP-BKR-RTA o
• 2-EP-BKR-RTB
• Press the TRIP buttons for both Bypass Breakers:

o

• 2-EP-BKR-BYA o
• 2-EP-BKR-BYB o
• Put both M-G Set Generator Output Breakers control switches to TRIP o
• Press the TRIP buttons for both M-G Set Generator Output Breakers o
• Put both M-G Set Motor Supply Breakers control switches to TRIP (STEP 1 CONTINUED ON NEXT PAGE)

NUMBER ATTACHMENT TITLE ATTACHMENT 2-FR-S.1 4 REMOTE REACTOR TRIP REVISION PAGE 15 2 of 2 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. LOCALLY TRIP THE REACTOR FROM THE ROD DRIVE ROOM: (Continued) b) Verify at least one of the following conditions - o b) GO TO Step 3.

SATISFIED o

• A" Reactor Trip and Bypass Breakers -

OPEN OR 0

• Both M-G Set Generator Output Breakers - OPEN OR 0
• Both M-G Set Motor Supply Breakers -

OPEN

2. NOTIFY THE CONTROL ROOM OF STATUS OF ROD POWER SUPPLY BREAKERS AND AWAIT FURTHER INSTRUCTIONS

3. LOCALLY TRIP THE REACTOR FROM 307 SWITCHGEAR:

a) Press the Mechanical Trip buttons for both M-G Set Motor Supply Breakers: 0

• 2-EP-BKR-24A1-3, 2-ED-MG-1A Rod Drive M-G Set Motor Supply Breaker 0
• 2-EP-BKR-24C2-12, 2-ED-MG-1B Rod Drive M-G Set Motor Supply Breaker o b) Notify the Control Room of status of rod power supply breakers and await further instructions

                                                - END-

STUDENT GUIDE FOR ROD CONTROL SYSTEM (65) 4.3 Content

1. The automatic synchronizer is designed to automatically parallel the output of the two Motor Generator sets.

2. The input signals supplied to the automatic synchronizer are:

2.1. Voltage 2.2. Phase 2.3. Relative frequency

3. The synchronizer controls the breaker closing time, and will automatically prevent synchronization of the two sets if the relative speed difference is excessive.

3.1. A speed matcher is incorporated in the synchronizer to automatically change the speed of the oncoming generator. 4.4 Objective U 6452 List the following information associated with removing a Rod Control System motor generator set from operation.

• How to place the MG set supply and output breakers in PULL-TO-LOCK (PTL)
• Source of power to each motor generator set
• Location from which the position of the motor generator input breaker is normally controlled
• Type of breaker used as the generator output breaker
• Conditions that will cause a motor generator output breaker to trip open 4.4 Content

1. The MG set supply and output breakers are placed in the PULL-TO-LOCK position by rotating the associated control switch 90° in the counter-clockwise direction and pulling straight out.

REACTOR OPERATOR Page 17 of 64 Revision 3, 11/18/2008

STUDENT GUIDE FOR ROD CONTROL SYSTEM (65) 1.1. The switch pulls out approximately 3/4 inch

2. The source of power to each motor generator set is:

2.1. U-1 ~ Band C station service 480-volt busses 2.2. U-2 ~ A and C station service 480-volt busses

3. The motor generator input breaker is controlled from the MG set control panel, located in the rod drive room.

4. The MG set output breakers are Westinghouse model DB-50 breakers, the same as the reactor trip breakers.

5. The MG set output breaker will trip open on any of the following:

5.1. Over-current 5.2. Reverse current 5.3. Over-voltage REACTOR OPERATOR Page 18 of 64 Revision 3, 11/18/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

33. 032-AK3.02 033/BANKINAPS/L/3IROINAPSII Unit 1 tripped from 100% power 22 minutes ago.

The following plant conditions exist:

• Intermediate Range Channel N-35 indicates 8 x 10- 10 amps and stable.
• Intermediate Range Channel N-36 indicates 1 x 10- 11 amps and stable.
• High voltage is de-energized on BOTH Source Range Channels N-31 & N-32.

1-ES-O.1, Reactor Trip Response, is in effect and the crew is at the step, "Check If Source Range Detectors Should Be Energized." Based on these plant conditions, which ONE of the following identifies the malfunction that has occurred, and the action required by 1-ES-0.1? A-:t N-35 is under-compensated; Manually energize Source Range Detectors using the SOURCE RANGE BLOCK/RESET switches. B. N-35 is over-compensated; Manually energize Source Range Detectors using the SOURCE RANGE BLOCK/RESET switches. C. N-35 is over-compensated; Energize Source Range Detectors by bypassing N-35 and removing the instrument power fuses. D. N-35 is under-compensated; Energize Source Range Detectors by bypassing N-35 and removing the instrument power fuses. Feedback

a. Correct. N-35 exhibits characteristics of being under-compensated; the action provided is correct based on plant conditions and the time from reactor trip.

b. Incorrect. Plausible since candidate may have a misconception regarding the effect/purpose of compensating voltage; second part is correct.

c. Incorrect. Plausible AP-4.2, Loss of intermediate range contains this action but again it is not for this stated purpose and not per ES-O.1 as asked by the question ..

d. Incorrect. First part correct as discussed above; second part plausible if candidate is unaware of the method employed by ES-0.1 to restore source range monitoring.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Loss of Source Range Nuclear Instrumentation Knowledge of the reasons for the following responses as they apply to the Loss of Source Range Nuclear Instrumentation: Guidance contained in EOP for loss of source-range nuclear instrumentation (CFR 41.5,41.10/45.6 145.13) Tier: 1 Group: 2 Importance Rating: 3.7/4.1 Technical

Reference:

1-ES-O.1 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: Bank Associated objective(s): Explain the following concepts concerning the restoration of source-range nuclear instrumentation (SRNI) in 1-ES-O.1, "Reactor Trip Response." Two conditions indicating SRNls should be restored following a reactor trip How SRNls should be restored manually

STUDENT GUIDE FOR EX-CORE NUCLEAR INSTRUMENTATION SYSTEM (62) 1.3. However, it should only be considered an alarm for QPTR in conjunction with 1A-D4, CMPTR ALARM PR TILT ROD DEV/SEQ, 1A-C7, NIS PR UP DET DEV - DEF < 50%, or 1A-C8, Nls PR LWR DET DEV - DEF < 50%.

2. The NIS PR UP DET DEV -DEF < 50% is an expected alarm if reactor power is less than 50%

2.1. If power is greater than 50%, the alarm actuates when anyone of the four upper power range detectors deviates from the average of all upper detectors by more than 2%. 2.2. This alarm indicates a possible rod misalignment and/or flux imbalance.

3. The NIS PR LWR DET DEV -DEF < 50% is an expected alarm if reactor power is below 50%.

3.1. If power is greater than 50%, the alarm actuates when one of the four lower power range detectors deviates from the average of all lower detectors by more than 2%. 3.2. This alarm indicates a possible rod misalignment and/or flux imbalance. 9.3 Objective U 7803 Explain the response of all nuclear instruments following a reactor trip from full power during each of the following conditions.

• Intermediate ranges--overcompensated
• Intermediate ranges--correctly compensated
• Intermediate ranges--undercompensated 9.3 Content

1. When the compensating voltage is set too high (overcompensation), the intermediate range level indication indicates lower than normal at the low end of the range.

REACTOR OPERATOR Page 57 of 86 Revision 3, 12/11/2007

STUDENT GUIDE FOR EX-CORE NUCLEAR INSTRUMENTATION SYSTEM (62) 1.1. Following a reactor trip, the overcompensated intermediate range channel would reach 5 X 10-11 amps sooner than expected. 1.2. As a result, P-6 for the associated train would clear sooner than expected as well.

2. Reliable intermediate range indication in the overlap region between source and intermediate ranges is dependent upon proper adjustment of compensating voltage to the CIC.

2.1. Following a reactor trip, an intermediate range detector with properly adjusted compensating voltage will decrease to 5 X 10- 11 amps in 15 - 20 minutes.

3. Compensating voltage set too low, or loss of compensating voltage (under-compensation), results in insufficient gamma current cancellation 3.1. Following long-term reactor operation, sufficient shutdown gamma levels exist to create a current indication on the intermediate range level meters greater than 10-10 amperes following a reactor trip.

( 3.2. Protection interlock P-6 allows the source range detectors to energize automatically when both intermediate range flux levels are less than 5XlO- 11 amps. 3.3. Following a reactor trip, an under-compensated intermediate range channel will take longer to reach 5 X 10- 11 amps if it reaches the P-6 reset current at all. 3.4. An under-compensated intermediate range detector may prevent automatic reinstatement of source range channels following a reactor trip. 3.5. If the intermediate range channels fail to decrease below 5X1 0- 11 amps following a reactor trip due to under-compensation, the source range channels may be manually reinstated provided interlock P-10 has reset. Topic 9.4 QuCidrant PowerTHf Rafid'(QPTH) 9.4 Objective U 7940 Explain the following concepts associated with Quadrant Power Tilt Ratio (QPTR): REACTOR OPERATOR Page 58 of 86 Revision 3, 12/11/2007

NUMBER PROCEDURE TITLE REVISION 27 1-ES-O.1 REACTOR TRIP RESPONSE PAGE 17 of 21 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

13. CHECK IF SOURCE RANGE DETECTORS SHOULD BE ENERGIZED:

a) Verify both of the following: o a) WHEN both conditions are satisfied OR 20 minutes have elapsed since Reactor o

• Intermediate Range flux - BELOW Trip, THEN do Step 13b, Step 13c and 5.0E-11 AMPS ON N-35 AND N-36 Step 13d.
• P NOT LIT: o Continue with Step 14.

o

• Annunciator Panel "1.:' F-1 o
• Annunciator Panel "1.:' F-2 b) Verify both Source Range Detectors - o b) Manually energize BOTH Source Range ENERGIZED: Detectors using the Source Range Block and Reset switches.

o

• N-31 o
• N-32 o c) Transfer recorder NR-45 to S1 and S2 (N-31 and N-32) o d) Energize the Scaler-Timer using the power toggle switch

NUMBER PROCEDURE TITLE REVISION 7 MALFUNCTION OF NUCLEAR INSTRUMENTATION (INTERMEDIATE 1-AP-4.2 RANGE) PAGE 3 of 11 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE:

• P-6 is lost with both intermediate range instruments failed low.

At 10% power. the source range instruments will automatically re-energize if the actions of Step 6 are not performed .

• Limited plant cooldown or boron dilution is allowed provided the change is accounted for in the calculated Shutdown Margin.

6. REDUCE REACTOR POWER LESS THAN P-6 WITHIN 2 HOURS AS FOLLOWS:

a) Place failed channels of Intermediate Range instrumentation in the following positions:

• N-35 Operation Selector Switch in 1 x 10- 9 position
• N-36 Operation Selector Switch in 1 x 10- 9 position b) Place failed channels of Intermediate Range instrumentation in the following positions:
• N-35 Level Trip Switch in BYPASS position
• N-36 Level Trip Switch in BYPASS position c) Ensure at least one c) Install jumpers in back side of Intermediate Range channel BOTH Source Range channel selected in Step 6a indicates cabinets:

between the following amp values:

• N-31 Jumper between terminals 1 and 2 on terminal board 123
• 8.3 x 10- 10 in 1-EI-CB-36A .
• N-32 Jumper between terminals 1 and 2 on terminal board 223 in 1-EI-CB-36B.
• 1.2 x 10- 9 (STEP 6 CONTINUED ON NEXT PAGE)

VIRGINIA POWER 1-EI-CB-21A ANNUNCIATOR A5 1-AR-A-A5 NORTH ANNA POWER STATION REV. 1

 ~APPROVAL: ON FILE                                        Effective Date:6/20/01

(>>, NIS IR CHI LOSS OF 50% of normal COMP VOLT 1.0 Probable Cause 1.1 Loss of compensating voltage to intermediate range, N-35 detector 2.0 Operator Action 2.1 Refer to alarm light on intermediate range drawer N-35 to confirm alarm. 2.2 IF the alarm is valid, THEN GO TO 1-AP-4.2, Malfunction Of Nuclear Instrumentation (Intermediate Range). 2.3 Notify Instrument Department of Malfunction. 3.0 References 3.1 UFSAR 3.2 1-AP-4.2, Malfunction Of Nuclear Instrumentation (Intermediate Range) 3.3 11715-ESK-10AAK 3.4 Westinghouse NIS Tech manual 3.5 Westinghouse SSP Tech Manual 3.6 Tech Spec 3.3.1.1 (ITS 3.3.1) 4.0 Actuation 4.1 Bistable in intermediate range drawer N-35 (NC-201)

QUESTIONS REPORT ( for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

34. 034-K6.02 034INEW/IH/3/ROIII Core on-load has commenced and Containment Purge is in service on Unit 1.

1-RM-RMS-159, Containment Particulate Radiation Monitor, has just pegged high due to a malfunction of the monitor. Which ONE of the following identifies the automatic actuations that will occur, and the impacts of this failure on fuel movement lAW 1-0P-4.1, Controlling Procedure for Refueling? A'I ONLY Containment Purge Isolation; OPS Manager approval is required to resume fuel movement. B. Containment Purge Isolation AND Control Room Bottle Air Dump; OPS Manager approval is required to resume fuel movement. C. ONLY Containment Purge Isolation; Fuel movement may continue without any additional approvals. D. Containment Purge Isolation AND Control Room Bottle Air Dump; Fuel movement may continue without any additional approvals. Feedback

a. Correct. Pegging high causes a Hi-HI alarm resulting in automatic Containment Ventilation Isolation, but control room bottled air does not automatically dump; second part is correct per 1-0P-4.1, Controlling Procedure for Refueling.

b. Incorrect. Plausible since other monitors related to fuel movement (e.g. fuel pool bridge crane monitor) do initiate bottled air dump; second part is correct.

c. Incorrect. First part is correct as discussed in Distractor a; second part is incorrect but plausible since FSRC in an approval per defense-in-depth of 1-0P-4.1, but only if the subject monitor and two other monitors have are failed are unavailable.

d. Incorrect. First part is incorrect but plausible as discussed in Distractor b; second part is incorrect but plausible as discussed in Distractor c.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Fuel Handling Equipment System (FHES) Knowledge of the effect of a loss or malfunction on the following will have on the Fuel Handling System: Radiation monitoring systems (CFR: 41.7/45.7) Tier: 2 Group: 2 Importance Rating: 2.613.3 Technical

Reference:

1-0P-4.1, 1-AP-5 Att. 5 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: New Additional Info:

( NUMBER PROCEDURE TITLE REVISION 26 1-AP-5 UNIT 1 RADIATION MONITORING SYSTEM PAGE 3 of 5 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. VERIFY THE FOLLOWING FOR THE AFFECTED RADIATION MONITOR(S): (Continued)

INIT RADIATION MONITOR RECORDER ATT. NO. SG STEAMLINE N/A ATTACHMENT 11 1-MS-RM-170, 171,172 TURBINE DRIVEN AFW PUMP EXHAUST N/A ATTACHMENT 11 1-MS-RM-176 PERSONNEL HATCH AREA 1-RM-RR-100 ATTACHMENT 6 1-RM-RMS-161 MANIPULATOR CRANE 1-RM-RR-100 ATTACHMENT 5 1-RM-RMS-162 CONTAINMENT 1-RM-RR-100 ATTACHMENT 7 1-RM-RMS-163 IN-CORE INST AREA 1-RM-RR-100 ATTACHMENT 7 1-RM-RMS-164 SG AND MAIN STEAM N-16 1-MS-RR-193 ATTACHMENT 2 1-MS-RI-190, 191, 192, 193 REACTOR COOLANT LETDOWN RADIATION 1-RM-RR-100 ATTACHMENT 8 MON RATEMETER, 1-CH-RI-128 DISCHARGE TUNNEL 1-RM-RR-100 ATTACHMENT 4 1-SW-RM-130 SG BLOWDOWN 1-RM-RR-100 ATTACHMENT 9 1-SS-RM-124, 122, 123 CONTAINMENT PARTICULATE 1-RM-RR-100 ATTACHMENT 5 1-RM-RMS-159 (STEP 1 CONTINUED ON NEXT PAGE)

( NUMBER ATTACHMENT TITLE ATTACHMENT 1-AP-5 5 CONTAINMENT PARTICULATE, GASEOUS, AND REVISION MANIPULATOR CRANE RADIATION MONITORS PAGE 26 1 of 3 NOTE: 1-RMS-RM-162 is expected to be de-energized in modes 1, 2, 3, 4, and 5.

1. Do the following:

_ a) Have Health Physics determine if Containment gaseous and particulate samples are required. _ b) IF Containment gaseous and particulate samples are required, THEN have Health Physics obtain and analyze Containment gaseous and particulate samples. NOTE: If both containments are lined up for Containment Ventilation, then the Containment Vent Fans will restart when the Unit 1 Ventilation MOVs indicate full closed.

2. IF a Hi-Hi alarm is actuated OR a malfunction is suspected in Mode 5 or 6, THEN verify that Containment ventilation is isolated as indicated below:

0

• 1-HV-F-4A - STOPPED 0
• 1-HV-F-4B - STOPPED 0
• 1-HV-F-5A - STOPPED 0
• 1-HV-F-5B - STOPPED 0
• 1-HV-MOV-100A - CLOSED 0
• 1-HV-MOV-100B - CLOSED 0
• 1-HV-MOV-100C - CLOSED 0
• 1-HV-MOV-100D - CLOSED 0
• 1-HV-MOV-101 - CLOSED 0
• 1-HV-MOV-102 - CLOSED

DOMINION 1-0P-4.1 North Anna Power Station Revision 58 Page 8 of 164 ( To prevent excessive heat load in the Spent Fuel Pool, the following restrictions have been established by NAF and are described in ET NAF-2001-0081, Rev. 0: (Reference 2.3.96)

• Refueling may only be performed on one Unit at a time.
• For back-to-back refuelings, the second refueling may not start until at least 25 days after the previous Unit became subcritical for its refueling.

(Reference 2.3.111) TRM TR 3.3.7 requires that a Condition Report be submitted within 12 hours if radiation monitor l-RM-RMS-159, l-RM-RMS-160, or l-RM-RMS-162 is inoperable during movement of irradiated fuel within containment. An increased level of Station Management authorization is required to perform fuel movement as the "defense-in-depth" is reduced if one or more radiation monitors becomes inoperable. This authorization is obtained in Attachment 2, Core Alterations Checklist.

2.0 REFERENCES

2.1 Source Documents 2.1.1 VRA-90-721, Fuel Assembly Guide Pin Precautions 2.1.2 UFSAR, Section 9.1, Fuel Handling and Storage 2.2 Technical Specifications 2.2.1 TRM TR 3.1.4 2.2.2 Tech Spec SR 3.1.4.3 2.2.3 TRM TR 3.3.7, Table 3.3.7-1, Items I.b and 2.b 2.2.4 Tech Spec 3.4.6 2.2.5 Tech Spec 3.4.7 2.2.6 Tech Spec 3.4.8

DOMINION 1-0P-4.1 North Anna Power Station Revision 58 Page 116 of 164 (Page 3 of 6) Attachment 2 Core Alterations Checklist 7.3 Ensure the following for the Containment Air Recirc Fans:

a. At least one ofthe following fans is in service. Mark any fan not in service N/A:

• I-HV-F-IA, A CNTMT AIR RECIRC FAN
• I-HV-F-IB, B CNTMT AIRRECIRC FAN
• I-HV-F-IC, C CNTMT AIRRECIRC FAN

b. IF any Containment Air Recirc Fan is secured, THEN the corresponding fan discharge damper is closed by either the damper open light being NOT lit or by local position verification.

c. IF any secured fan discharge damper is NOT closed, THEN declare l-RM-RMS-159 and l-RM-RMS-160 inoperable and enter the TRM Actions for TR 3.3.7 and TR 3.9.5.

NOTE: TRM TR 3.3.7 requires that a Condition Report be submitted within 12 hours if radiation monitor l-RM-RMS-159, l-RM-RMS-160, or l-RM-RMS-162 is inoperable during movement of irradiated fuel within containment. An increased level of Station Management authorization is required to perform fuel movement as the "defense-in-depth" is reduced if one or more radiation monitors become inoperable. 7.4 Record the status of the following radiation monitors: l-RM-RMS-159, Containment Particulate Monitor _ Operable _ NOT Operable l-RM-RMS-160, Containment Gaseous Monitor _ Operable _ NOT Operable l-RM-RMS-162, Manipulator Crane Area Monitor _ Operable _ NOT Operable

DOMINION 1-0P-4.1 North Anna Power Station Revision 58 Page 117 of 164 (Page 4 of 6) Attachment 2 Core Alterations Checklist 7.5 IF any radiation monitor listed in Step 7.4 is NOT Operable, THEN obtain appropriate Station Management approval to perform fuel movement:

• IF one ofthe three radiation monitors is NOT Operable, THEN obtain OPS MGR permission from the Operations Manager to perform fuel movement.
• IF two of the three radiation monitors are NOT Operable, THEN obtain DIR-O&M permission from the Director-Operations and Maintenance to perform fuel movement.
• IF all three of the radiation monitors are NOT Operable, THEN obtain FSRC permission from FSRC to perform fuel movement.

7.6 IF any radiation monitor listed in Step 7.4 is NOT Operable, THEN enter in the Action Statement Log to suspend fuel movement and obtain appropriate higher Station Management approval prior to continuing fuel movement if any of the remaining operable radiation monitors become inoperable. 7.7 IF 3 fuel assemblies are in the Reactor Vessel AND Source Range audible indication in Containment is desired, THEN verify the Source Range audio count rate is indicating at least 2 cpm on the Source Range detector adjacent to the fuel. 7.8 Ensure the Equipment hatch is installed and held in place by at least four bolts OR is capable of being installed and held in place by at least four bolts. 7.9 Ensure Emergency Escape Air Lock is installed in the Equipment Hatch or the air lock opening is covered by the Equipment Hatch Temporary Hatch Plate. 7.10 IF installed, THEN ensure both doors in the Emergency Escape Air Lock are closed. (References 2.4.26 and 2.4.27)

STUDENT GUIDE FOR RADIATION MONITORING SYSTEM (46) 2.3. The ion chamber can be modified for a number of applications. It can count gammas, betas, or fast and slow neutrons. 1.6 Objective U 5227 Explain the following concepts as they apply to the radiation monitor detectors.

• Why scintillation detectors are normally used in particulate and liquid process applications
• Why Geiger-Mueller detectors are normally used in area and gaseous applications
• How detectors are shielded from background radiation 1.6 Content

1. Scintillation detectors are normally used in particulate and liquid process applications due to accuracy and reliability of the output (i.e., energy dependent)

2. Geiger-Mueller detectors are normally used in area and gaseous applications.

2.1. Due to their high sensitivity, changes in radiation levels are seen quickly. 2.2. These detectors are not sensitive to changes in temperature or humidity. 2.2.1.Also, these detectors are very rugged compared to other detectors.

3. Detectors are normally shielded from background radiation by lead shields (called pigs).

1.7 Objective U 10705 List the automatic actions that will occur when output signals are generated by the following radiation monitors.

• New fuel storage area (RMS-RM-152)
• Fuel pool bridge area (RMS-RM-153)

REACTOR OPERATOR Page 11 of 58 Revision 4, 09/22/2008

STUDENT GUIDE FOR RADIATION MONITORING SYSTEM (46) (

• Manipulator crane area (RMS-RM-162)
• Clarifier effluent (RM-LW-111)
• Condenser air ejector (SV-RM-121)
• Containment gaseous and particulate (RMS-RM-159 and 160)
• Process Vent (GW-RM-178-1 and 178-3) 1.7 Content

1. New fuel storage area (RMS-RM-152) and fuel pool bridge area (RMS-RM-153) 1.1. On a HI-HI alarm performs the following if the FUEL BUILDING RADIATION INTERLOCK KEY switch is in ENABLE:

1.1.1.After a 2 minute time delay will automatically dump the MCR bottled air, 1.1.2.closes the MCR dampers, and starts the MCR emergency ventilation fans. 1.1.3.(High alarm must be in after the 2 minutes for the action to take place)

2. Clarifier effluent (RM-LW-111) 2.1. On Hi-Hi alarm performs the following:

2.1.1.Shuts PCV-LW-115 2.1.2.Closes clarifier influent valve, 1-LW-FCV-1 00 2.1.3.This causes the SG blowdown pumps to trip.

3. Condenser air ejector (SV-RM-121) 3.1. Hi-Hi rad alarm - automatically diverts effluent from the vent stack to the containment atmosphere.

3.1.1.A Hi-Hi rad alarm with a phase A signal: 3.1.1.1. Isolates aux steam to the air ejectors. (1-AS-FCV-1 OOA and 100B) 3.1.1.2. All air ejector discharge valves close 1-SV-TV-1 02-1, 103 and 102-2

4. Process vent (GW-RM-178-1 and 178-3)

REACTOR OPERATOR Page 12 of 58 Revision 4, 09/22/2008

STUDENT GUIDE FOR RADIATION MONITORING SYSTEM (46) 3.2. A Hi or Hi-Hi alarm signal from GW-RM-178-1 (Process Vent Noble Gas Normal MGPI) automatically performs the following: 3.2.1.Closes FCV-GW-1 01, flow control valve from the waste gas decay tanks. 3.2.2.Closes the containment vacuum pump discharge trip valves. 3.2.3.This in turn trips the vacuum pumps. 3.3. A Hi-Hi alarm signal from GW-RM-178-1 (Process Vent Noble Gas Normal MGPI) will shift the Process Vent sample flow path to GW-RM-178-2 (Process Vent Noble Gas Accident MGPI). 3.3.1.The Hi-Hi alarm signal will "latch-in". 3.3.2.The waste gas decay tank discharge and the containment vacuum pump discharge will be locked out until the Hi-Hi "latch" is relased by the Instrument Department. 3.3.3.After the Hi-Hi alarm condition is cleared, the MGP system is returned to normal range monitoring by the Instrument Department. 3.4. A Hi alarm signal from GW-RM-178-3 (Process Vent Particulate MGPI) automatically performs the following: 3.4.1.Closes FCV-GW-1 01, flow control valve from the waste gas decay tanks. 3.4.2.Closes the containment vacuum pump discharge trip valves. 3.4.3.This in turn trips the vacuum pumps.

5. Containment gaseous and particulate (RMS-RM-159 and 160) and manipulator crane area (RMS-RM-162).

3.5. Hi-Hi alarm signal automatically performs the following: 3.5.1.Trips the purge and exhaust fans and closes the affected units purge supply and exhaust MOVs. 3.5.2.Fans are interlocked with the purge valves as well as the rad monitor. REACTOR OPERATOR Page 13 of 58 Revision 4, 09/22/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

35. 035-A3.02 035INEW//H/3/ROIII Following a trip with condenser steam dumps NOT available, the SG PORV controllers (1-MS-PCV-101A, S, & C) are designed to control RCS T AVE at approximately  ; this is achieved by a controller pot setting of approximately _ _ __

B. 551°F; 7.0 Feedback

a. Correct. this is the temperature corresponding to 1050 psig, the pot setpoint of 5.5 based on the instrument scaling (500-1500 psig) provides this pressure.

b. Incorrect. First part is correct. Second part incorrect but plausible since the candidate who is not familiar with the scaling or normal operating setting may assume a scaling of 0-1500psig and in that case a setting of 7.0 would correlate to 1050 psig.

c. Incorrect. First part incorrect but plausible since candidate may not properly corrrelate the pressure control point for the SG with RCS temperature, pot setting is correct.

d. Incorrect. Both parts incorrect but plausible as discussed in Distractors B & C.

QUESTIONS REPORT ( for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Steam Generator System (S/GS) Ability to monitor automatic operation of the S/G including: MAD valves (CFR: 41.7/45.5) Tier: 2 Group: 2 Importance Rating: 3.7/3.5 Technical

Reference:

1-ES-0.1 and 1-GOP-1.0 CRO turnover Proposed references to be provided to applicants during examination: None Learning Objective: Question History: New Additional Info: NAPS does not have MAD valves per se; discussed with USNRC via telcon on 9/4/2008 based on NAPS SG PORVs providing an equivalent function of MAD valves the intent of the KA is met with this question.

NUMBER PROCEDURE TITLE REVISION 27 1-ES-O.1 REACTOR TRIP RESPONSE PAGE 2 of 21 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

 *1. CHECK RCS AVERAGE TEMPERATURE:

a) Check Temperature Control: a) Do the following:

• STEAM DUMPS - CONTROLLING: IE temperature is less than control value AND decreasing, THEN:

D

• STABLE AT 54JOF D 1) Stop dumping steam.

OR D 2) Verify SG Blowdown Trip Valves are D

• TRENDING TO 54JOF closed.

OR D IE NOT, THEN manually close valves.

• SG PORVs - CONTROLLING:

D 3) Adjust total AFW flow to maintain D

• STABLE AT 551°F greater than 400 gpm (340 gpm with RCPs OFF) until at least one SG OR narrow range level is greater than D
• TRENDING TO 551°F 11%.

4) !Ecooldown continues, THEN close the following:

D

• MSTVs D
• MSTV Bypass Valves D 5) GO TO Step 2.

(STEP 1 CONTINUED ON NEXT PAGE)

1-GOP-1.0 UNIT 1 CRO TURNOVER CHECKLIST (MODES 1-4) REVISION 39 NORTH ANNA POWER STA TlON GENERAL OPERATING PROCEDURE PAGE 1 OF 14 POWER MODE PLANT STATUS Unit 1: Unit 2: Current Reactivity Data: RCS Boron: - - - - - ppm Reactor above the Point Of Adding Heat (POAH) - DNo DYes (if yes, perform daily reactivity calculation using reactivity worksheet or applicable station curves and record control requirements below. Independently verify calculations to include inputs.):

• Gallons of PG required to raise RCS Temperature 10 F: gallons PG IV
• Gallons of Boric Acid required to lower RCS Temperature 10 F: gallons Boric Acid IV Non-Steady State conditions -

DNo DYes (if yes, discuss current conditions below): Most Limiting Action Statement: LCO/A.S. number: _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __

== Description:== Expiration Time _ _ __ Date - - - - - - Special Plant/System DNo DYes (if yes, explain below) Requirements (levels, pump configuration, valve requirements, power levels, etc): Periodic Tests in Progress: DNo DYes (if yes, explain below) Automatic functions DNo DYes (if yes, explain below) disabled/bypassed: Open Procedures: DNo DYes (if yes, explain below) CONTINUOUS USE

DOMINION 1-GOP-1.0 North Anna Power Station Revision 39 Page 4 of 14 NOTE: IF Lowest Tc is less than or equal to 280 0 F, THEN the inoperable Charging Pump normal and alternate discharge header valves may be closed to prevent inadvertent injection. Verify the following MOVs are OPEN or note the reason for being out of position in the remarks section: D l-CH-MOV-1275B D l-CH-MOV-1287A D I-CH-MOV-1269A D l-CH-MOV-1275A D l-CH-MOV-1267B D l-CH-MOV-1287B D l-CH-MOV-1275C D I-CH-MOV-1286C D l-CH-MOV-1269B D l-CH-MOV-1286A D l-CH-MOV-1270A D l-CH-MOV-1287C D l-CH-MOV-1267A D l-CH-MOV-1286B D l-CH-MOV-1270B Record status of the following controllers below. IF controller is in Manual mOT required MFRV Bypass valves) OR Pot Setting is NOT as expected, THEN explain in the remarks section (unless directed otherwise): Pressurizer Controllers l-RC-LCV-1459G DAuto DManual Controller output: l-RC-PCV-1455A DAuto DManual Controller output: Pot Setting: (Expected ~ 5.5) l-RC-PCV-1455B DAuto DManual Controller output: Pot Setting: (Expected ~ 5.5) l-RC-PCV-1444J DAuto DManual Controller output: Pot Setting: (Expected "" 6.7) CVCS Controllers l-CH-FCV-1122 DAuto DManual Controller output: l-CH-FCV-1160 D Verify in Manual with 0% Controller output. Explain differences in Remarks. l-CH-LCV-ll12C DAuto DManual Controller output: Pot Setting: (Expected "" 7.1) l-CH-PCV-1145 DAuto DManual Controller output: Pot Setting: (Expected "" 5.0) l-CC-TCV-I06 DAuto DManual Controller ouput: SG PORV Controllers (Reference Tech Spec 3.7.4) I-MS-PCV-I0IA DAuto DManual Controller output: Pot Setting: (Expected "" 5.5) I-MS-PCV-I0lB DAuto DManual Controller output: Pot Setting: (Expected "" 5.5) I-MS-PCV-I0IC DAuto DManual Controller output: Pot Setting: (Expected ~ 5.5)

STUDENT GUIDE FOR MAIN STEAM SYSTEM (23-A) 2.4 Objective U 4058 List the following information associated with the steam generator power-operated relief valves.

• Purpose
• Number of valves per main steam line
• Normal lift setpoint of each valve
• How to adjust the lift setpoint of each valve
• Rated relieving capacity of each valve 2.4 Content

1. The SG PORVs are used to remove plant sensible heat and core residual heat (decay heat) from the RCS, and provide a means for plant cooldown when the condenser steam dumps are not available.

1.1. Operation of the PORVs limits the undesirable opening of the SG safety valves.

2. Each main steam header is provided with one PORV (MS-PCV-101A!8/C).

3. During normal operation, the lift setpoint of the PORV is approximately 1035 psig.

4. The pressure setpoint at which the valve begins to open is variable (as determined by the associated manual/automatic control station when enabled), but is normally set to begin opening at 1035 pSig, (controller setpoint of 5.5) a pressure below the lowest main steam safety valve lift setpoint.

4.1. The controller is adjusted for automatic operation using the setpoint potentiometer on the manual-auto station for the individual valve. 4.2. Each PORV receives its pressure signal from a steam generator pressure transmitter, 1-MS-PT-101 A, 8, or C. These transmitters have a range of 600 to 1400 psig. 4;3. Each steam generator PORV's controller is adjusted for automatic operation as follows. REACTOR OPERATOR Page 14 of 14 Revision 1, 10/11/2007

STUDENT GUIDE FOR EMERGENCY PROCEDURES (92) 2.17 Content

1. E-O contains a step that requires the operator to verify RCS temperature stable at or trending to 547°F (if controlling on Steam Dumps) or 551°F (if controlling on SG PORVs).

1.1. This step is designed to evaluate decay heat removal capability and excessive cool down conditions.

2. If an excessive cooldown condition exists, E-O first directs the operator to stop dumping steam.

2.1. If cooldown continues, auxiliary feedwater flow should be throttled to 340 gpm until narrow range level in at least one steam generator is greater than 11 % [22%], in order to stop the cooldown. 2.2. Once the operator has stopped dumping steam and throttled back feedwater to the steam generators, continued cool down may be the result of a steam leak. 2.3. Therefore, E-O has the operator manually close the main steam trip valves and bypass valves.

3. Sometimes excessive RCS cooldown may be attributed to safety injection flow and not secondary heat removal.

3.1. In a case such as this, closure of the main steam trip valves would not limit the cooldown. 3.2. Furthermore, closure of the main steam trip valves would remove the option to dump steam to the condenser for RCS cooldown and depressurization later in the event. 3.3. If the cooldown can be attributed to safety injection flow only, the Senior Reactor Operator may exercise the option to not close the main steam trip valves. 2.18 Objective U 12465 Explain the following concepts concerning the checking of pressurizer power-operated relief valves (PORVs) and spray valves in 1-E-0, "Reactor Trip or Safety Injection."

• Basis
• How the operator is directed to address an open PORV

(

• How the operator is directed to address an open pressurizer spray valve REACTOR OPERATOR Page 52 of 187 Revision 19, 11/06/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

36. 039-A2.04036IMODIFIEDINAPS/H/3/ROINAPSII Given the following conditions:

• Unit 1 generator output breaker G-12 has just been closed following a reactor startup.
• All control systems are aligned per startup procedures.

   *   "An train of steam dumps is isolated to repair 1-MS-TCV-140SA, which is de-energized and tagged out.

Main steam line pressure transmitter 1-MS-PT-1464 fails HIGH. Which ONE of the following identifies the ReS temperature response, and the required action? A. RCS temperature increases; Manually insert rods to match TAVE and T REF' B. RCS temperature increases; Verify rods automatically insert to match T AVE and T REF' C. RCS temperature decreases; Close all MSTVs using Appendix R Switch. D~ RCS temperature decreases; Place both Steam Dump Interlock Switches to OFF/RESET. Feedback

a. Incorrect. Plausible since candidate may confuse operation of dumps and conclude that they close because of the malfunction, using rods manually would be a logical response to increasing temperature.

b. Incorrect. Plausible since candidate may confuse operation of dumps and conclude that they close because of the malfunction, similar to above the response of the rod control system would make sense as would the need to verify it.

c. Incorrect. As given half the dumps will open and temperature would decrease and power increase, however while closing the MSTVs would terminate the excess steam demand it is not the action required by the procedure and would only be required if turning off steam dumps did not work.

d. Correct. As given half the dumps will open and temperature would decrease and power increase, 1-AP-38 directs the action to turn,rOfsteam dumps which in..ttre ('h' case will remedy the condition. off I 15

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Main and Reheat Steam System (MRSS) Ability to (a) predict the impacts of the following malfunctions or operations on the MRSS; and (b) based on predictions, use procedures to correct, control, or mitigate the consequences of those malfunctions or operations: Malfunctioning steam dump (CFR: 41.5/43.5/45.3/45.13) Tier: 2 Group: 1 Importance Rating: 3.4/3.7 Technical

Reference:

Steam Dump lesson plan and 1-AP-38 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: Bank (modified to more closely match KA) Associated objective(s):

NORTH ANNA POWER STATION ABNORMAL PROCEDURE NUMBER PROCEDURE TITLE REVISION 14 1-AP-38 EXCESSIVE LOAD INCREASE (WITH TWO ATTACHMENTS) PAGE 1 of 10 PURPOSE To provide instructions to follow in the event of an excessive load increase. ENTRY CONDITIONS This procedure is entered when any of the following conditions exist:

• Rapid increase in Steam Flow, or
• Rapid increase in Main Generator MW Output due to increased Steam addition to the N1~'in Turbine, or cC~l;;'
• Rapid decrease in Main Generator MW Output due to Steam diversion from the Main Tl.I~~ine, or
• Rapid increase in Reactor Power Level, or
• Control Rods stepping OUT in fast speed.

CONTINUOUS USE

NUMBER PROCEDURE TITLE REVISION 14 1-AP-38 EXCESSIVE LOAD INCREASE PAGE 2 of 10 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 1 ]_ VERIFY ALL STEAM DUMP D Place Both Steam Dump Interlock Switches to VALVES - CLOSED OFF/RESET. D

• 1-MS-TCV-140BA D !E any valve does NOT close, THEN locally close using ATTACHMENT 2, STEAM DUMP D
• 1-MS-TCV-140BB INSTRUMENT AIR ISOLATION.

D

• 1-MS-TCV-140BC D
• 1-MS-TCV-140BD D
• 1-MS-TCV-140BE D
• 1-MS-TCV-140BF D
• 1-MS-TCV-140BG D
• 1-MS-TCV-140BH 2 ]_ VERIFY ALL SG PORVs - D Place any OPEN SG PORV controller in MAN and CLOSED shut affected SG PORV.

D

• 1-MS-PCV-101A (A SG)

D

• 1-MS-PCV-101B(BSG)

D

• 1-MS-PCV-101C (C SG)

STUDENT GUIDE FOR STEAM DUMP CONTROL AND PROTECTION SYSTEM (23-8) 1.1. This is known as "hand-jacking" the valves open. 1.5 Objective U 8856 Explain the purpose of the following steam dump control switches.

• MODE SELECTOR switch
• BYPASS INTERLOCK selector switch 1.5 Content

1. The Mode Selector switch determines what signals will open and close the steam dumps.

1.1. In Tave mode, the Steam Dump Control Subsystem compensates for the power mismatch between primary and secondary plant following a load rejection or turbine trip, provided Tave is greater than 547*F. 1.2. In the steam pressure mode of operation, the steam dumps are controlled based on the steam header pressure signal from PT-1464 and the setting of the M/A control station PC-1464B. 1.3 The reset position will reset the sudden load decrease of 10% in 2 minutes signal (C-7).

2. The Bypass Interlock selector switch permits TCV-1408A & B to modulate open when Tave is less than 543*F. (P-12 setpoint) 2.1. Placing the selector switches in BYPASS INTERLOCK resets the low-low Tave interlock allowing the plant to be cooled down in the Steam Pressure Mode.

2.1.1 OFF/RESET will close the steam dumps if open or prevent them from opening if closed. 2.2.1.1. This position is also selected when switching between Tave and steam pressure mode to minimize any switching transients. REACTOR OPERATOR Page 6 of26 Revision 1, 06/05/2007

STUDENT GUIDE FOR STEAM DUMP CONTROL AND PROTECTION SYSTEM (23-8) TopiC:; 6.6 Te rmiha I KnowledgeObjec~ive 6.6 Objective U 12014 Given a set of plant conditions, evaluate Steam Dump Control and Protection System operations in light of the following issues.

• Effect of a failure, malfunction, or loss of a related system or component on this system
• Effect of a failure, malfunction, or loss of components in this system on related systems
• Expected plant or system response based on steam dump component interlocks or design features
• Impact on the technical specifications
• Response if limits or setpoints associated with this system or its components have been exceeded
• Proper operator response to the condition as stated 6.6 Content CONTROL SYSTEM FAILURE ANALYSIS (NOTE: ALL EFFECTS ASSUME NO OPERATOR ACTION IS TAKEN.)

STEAM DUMP CONTROL SYSTEM Median Select Tave TI-40BA HIGH EFFECT: The failure causes a maximum output from both the loss of load and turbine trip controllers. The dumps will not actuate if not armed. If the dumps become armed, the valves will fail full open and cooldown the plant until the low-low Tave interlock (543°) shuts the valves. Due to the excessive steam demand, the plant could trip on overpower or low pressure, or a SI on high steam flow could occur. LOW EFFECT: None, since Tave is auctioneered high. First Stage Pressure (1446) HIGH EFFECT: None, since dumps actuate only when Tave>Tref. Note that steam dumps will REACTOR OPERATOR Page 25 of26 Revision 1, 06/05/2007

STUDENT GUIDE FOR STEAM DUMP CONTROL AND PROTECTION SYSTEM (23-8) I \ not open on a load reject. LOW EFFECT: The loss of load controller will have a maximum output. The dumps will not actuate if not armed. If armed, dumps will attempt to reduce Tave to the no-load value (547") and a trip on overpower or low pressure, or a SI on high steam flow could occur. First Stage Pressure (1447, arming signal) HIGH EFFECT: None. The loss of load arming signal is lost. LOW EFFECT: If the failure occurs at a high enough rate, steam dumps will arm due to C-7 load reject signal. No transient unless a Tave-Tref mismatch, is generated. Steam Pressure (1464) HIGH EFFECT: If in the steam pressure mode, the valves will go full open until the low-low Tave interlock (543°) causes them to close. EFFECT: None. Steam pressure mode of control is disabled. LOW I

                                                      ,              ~

(rtZ-J REACTOR OPERATOR Page 26 of25 Revision 1, 06/05/2007

        ,~,~,                                                                                                                                                                                                            1                                            /~\-,-------,

By TURSI NE I MPUL SE TREF FROM ~ " BY! BY I REDuNDANT CHAMBER PRESSURE (NOTE 4) TURBINE PRESSURE (NOTE 4) MEDIAN/HI i OTHERS r------*-*-------------t---------~-------~---, TAVG FROM REFERENCE MEDiAN SIGNAL lAVG i i INTE~~6~~ ~~t:CTOR ! SWITCH (NOTE 3) I SELECT CIRCUIT (SHEET 'I) INTERNAL SETPOINT STEAM HEADER STEAM LINE PRESSURE I~ , STEAM DUMP CONTROL MODE SELECTOR SWiTCH PRESSURE , 1 LOOP I LOOP 2 lOOP 3 ! p- 12 i [-8 I LQ-LO , i (sJE~VTG 5)  ! TURBINE TRIP (SHEET 15) t12 S + 1 t\3S+ I STEAM HEADER STEAM GENERATOR STEAM GENERATOR STEAM GENERATOR i

                                               "Li   1 TRAIN B RESET (MOMENTARY)

TAVG STEAM PRESS. PRESSURE CONTROLLER l i PRESSURE CONTROLLER t PRESSURE CONTROLLER PRESSURE CONTROLLER 1 1 ' ll(l"'~) K12(1+~) K12(IT~1 K12(1"'~) 1 1 1  :.©

~

~

                                                                                                                                 © ...

1 1 1 ' i 1 i i i i i i i BY: BY i i OTHERS! i 1 i i i

                                                                                                                                                                                                                         !       T~~D~~~~El         T~~D~~~;E2           T~~O~6~~E3 (A                                                                                                                                                                [__ ~~0~r~~L ____~mr"v~~~~ _____~rL~r~~~_~~____:;I-~~~:-

i i i i i NOTES: i STEAM DUMP IS BLOCKED BY BLOCKING AIR TO THE DUMP VALVES i AND VENTING THE DIAPHRAGMS. THE REDUNDANT LOGIC OUTPUT OPERATES 2 SOLENIOD VENT VALVES IN SERIES TO REDUNDANTLY i INTERLOCK THE AIR LINE BETWEEN EACH VALVE DIAPHRAGM AND ITS i ASSOCIATED POSITIONER. THE SOLENOID VALVES ARE DE-ENERGIZED TO i VENT CAUSING THE MAIN DUMP VALVE TO CLOSE IN FIVE SECONDS.

2. CIRCUITRY ON THIS SHEET IS NOT REDUNDANT EXCEPT WHERE INDICATED i REDUNDANT.

i 3. SELECTOR SWITCH WITH THE FOLLOW!NG 3 POSlfIONS: i ON - STEA!"l DUMP IS PERMITTED. BYPASS - TAVG INTERLOCK IS BYPASSED FOR LO~LO. i TAVG SPRING RETURN TO ON POSITlON. i OFF - STEAM DUMP IS NOT PERMITTED AND RESET i i TAVG BYPASS. THE REDUNDANT INTERLOCK SELECTOR 51-1 ITCH CONSISTS OF TWO i --+ CONTROLS ON THE CONTROL BOARD. ONE FOR EACH TRAIN. i i 4. THE TWO ANALOG SIGNAL INPUTS COMING FROM TURBINE PRESSURE MUST i i *----*--0 COME FROM DIFFERENT PRESSURE TAPS TO MEET THE SINGLE i

                                                                                                                                                                                                                       ~

i i i i  !"lODULATE THE DUMP VALVES ACCORDING

5. DELETED.:::  :':. ~

i TO THE FOLLOW I NG SEQUENCES; 6. LIGHTS SHOULD BE PROV IDED IN THE CONTROL ROOM FOR EACH DUMP i I - REDUNDANT VALVE TO INDICATE WHEN THE VALVE IS FULLY CLOSED OR FULLY OPEN. i i  % SIGNAL VALVES MODULATED OPEN OR CLOSED (ZERO TO FULL OPEN)

7. ALL TEMPERATURE BISTABLES ON THIS SHEET AND TURBINE IMPULSE i i (NOTE 6) CHAMBER PRESSURE BISTABLE "PB-447A ARE "ENERGIZE TO ACTUATE".

i i 0-25% 25-50% TCV-408A rCV-408C

                                                                                                                                                                                               & TCV-408B
                                                                                                                                                                                               & TCV~40BD                       HIGHEST EQUIPMENT CLASSIFICATION ON THIS DWG.      IS SAFETY RELATED i                                                             i                                                                                                  50¥75%              TCV-408E   & TCV~408F i                                                                                                 75-100%              TCV- 408G  & TCV- 408H                                   NUCLEAR STEAM SUPPLY SYSTEM i                                                             i                                                                                                                                                                                       FUNCT10NAL D1AGRAMS i                       (NOTE I)                              i (NOTE 6)

STEAM DUMP CONTROL i (NOTE I) i UN [TS 1 & 2 i i i i i i i

               -~;:u~~:~~~-------------------------------J i

._------- VIRGINIA POWER (NOTE 61 REVlSEOPEflDCA q<!'[e57 NORTH ANNA POWER STATION 3 THISDltGstJ'ERSEDESTHEI!EV20AICIHIOL SH 10 OF 16 3 PC=NDL PRIOR TO USING FOR DESIGN wORK CHECK DMIS FOR WORK PENDING

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

37. 040-AA2.04 037/MODIFIEDINAPS-60323/H/3IROINAPS/SI220S1 Given the following conditions:

Unit 1 was operating at 100% power when a Main Steam line break occurred inside containment. 1-E-2, Faulted Steam Generator isolation, has been completed.

• The team transitioned to 1-ES-1.1, SI Termination, and has just completed isolating the BIT and establishing normal charging.

The following plant conditions exist:

• Containment pressure is 19 psia and decreasing.
• Intact SG narrow-range levels are 8% and increasing.

PRZR level is 16% and decreasing. 1-CH-FCV-1122, Charging flow control valve is full open. Based on these plant conditions, which ONE of the following identifies the action required by 1-ES-1.1, SI Termination? A'I Manually start charging pumps and align the BIT; go to 1-E-1, Loss of Reactor or Secondary Coolant. B. Continue in 1-ES-1.1; when Containment pressure is less than 13 psig, then stop Quench Spray Pumps. C. Isolate letdown; if PRZR level continues to decrease, then manually actuate SI. D. Stop feed flow to SGs; if cooldown continues, then close MSTVs and bypass valves. Feedback A. Correct. Based on-this point in the procedure (SI terminated) SI reinitiation criteria of foldout page is met and the action MUST be performed. B. Incorrect. Plausible since candidate may assume that reinitiation criteria is based solely on Core Exit TC's and 13 psig is a procedural requirement for shutting down Quench Spray. C. Incorrect. Plausible and logical, but there is no guidance to actuate SI manually in ES-1.1. D. Incorrect. Plausible and logical since this is an EOP action, however it is prohibitted since NR levels are <11 % because it would create a loss of heat sink and violate the procedure requirement of maintaining> 340 gpm total feed flow.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Steam Line Rupture Ability to determine and interpret the following as they apply to the Steam Line Rupture: Conditions requiring ESFAS initiation (CFR: 43.5/45.13) Tier: Group: Importance Rating: 4.5/4.7 Technical

Reference:

1-ES-1.1 Proposed references to be provided to applicants during examination: None Learning Objective: 60323 Question History: Modified from bank Associated objective(s): Evaluate a set of plant conditions associated with the E-1 series emergency operating procedures in light of the following issues (E-1, ES-1.1, ES-1.2, ES-1.3, ES-1.4, ES-1.5).

• Procedure entry conditions
• Major action categories
• Step bases
• Proper procedure usage

/': .. Dominion' NORTH ANNA POWER STATION EMERGENCY PROCEDURE NUMBER PROCEDURE TITLE REVISION 20 1-ES-1.1 SI TERMINATION PAGE (WITH FOUR ATTACHMENTS) 1 of 24 PURPOSE To provide instructions to terminate SI and stabilize plant conditions. ENTRY CONDITIONS This procedure is entered from:

• 1-E-O, REACTOR TRIP OR SAFETY INJECTION, or
• 1-E-1, LOSS OF REACTOR OR SECONDARY COOLANT, or
• 1-E-2, FAULTED STEAM GENERATOR ISOLATION, or
• 1-FR-H.1, RESPONSE TO LOSS OF SECONDARY HEAT SINK.

CONTINUOUS USE

NUMBER PROCEDURE TITLE REVISION 20 1-ES-1.1 SI TERMINATION PAGE 2 of 24 ACTIONI EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. RESET BOTH TRAINS OF SI D Perform 1-AP-0, RESETTING SI LOCALLY, while continuing with this procedure.

2. STOP ALL BUT ONE CHARGING PUMP AND PUT IN AFTER-STOP G- CHECK RCS PRESSURE - STABLE OR INCREASING D GO TO 1-ES-1.2, POST LOCA COOLDOWN AND DEPRESSURIZATION, STEP 1.

NUMBER PROCEDURE TITLE REVISION 20 1-ES-1.1 SI TERMINATION PAGE 3 of 24 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION: To provide adequate Charging Pump cooling, either the Charging Pump recirc alignment must be established or Charging flow must be maintained at least 60 gpm.

4. ISOLATE BIT:

a) Do the following: a) !E a Low Head SI Pump is aligned to supply Charging Pump suction in the SI

1) Check Low Head SI Pump Suctions Recirculation Mode OR Charging Pump From Containment Sump - Recirc can NOT be manually aligned, CLOSED: THEN do the following:

o

• 1-SI-MOV-1860A o . 1-SI-MOV-1860B o 2) Open 1-CH-MOV-1373, Charging o 1) Verify 1-CH-HCV-1311, Auxiliary Pump Recirc Header Isolation Spray Valve is closed.

Valve

2) Open Normal Charging Line Isolation

3) Open Charging Pump Recirc Valves:

Isolation Valves: o

• 1-CH-HCV-1310 o
• 1-CH-MOV-1275A o
• 1-CH-MOV-1289A o
• 1-CH-MOV-1275B o
• 1-CH-MOV-1289B o
• 1-CH-MOV-1275C o 3) Open 1-CH-FCV-1122 in Manual to establish 60 gpm Charging flow.

4) Close BIT Inlet Isolation Valves:

o . 1-SI-MOV-1867A o

• 1-SI-MOV-1867B (STEP 4 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 20 1-ES-1.1 SI TERMINATION PAGE 4 of 24 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

4. ISOLATE BIT: (Continued)

5) Close BIT Outlet Isolation Valves:

o . 1-SI-MOV-1867C o

• 1-SI-MOV-1867D

6) !E any of the following valves are open, THEN place control power on AND close:

o

• 1-SI-MOV-1836 o
• 1-SI-MOV-1869B

( o

• 1-SI-MOV-1869A o 7) Establish and maintain greater than 60 gpm Charging flow using 1-CH-FCV-1122 in MANUAL.

o 8) GO TO Step 6. b) Close BIT Inlet Isolation Valves: b) Open affected BIT MOV breaker and locally close valve: o

• 1-SI-MOV-1867A o
• 1-EE-BKR-1 H1-2N 01, BIT Inlet o
• 1-SI-MOV-1867B Isolation Valve Circuit Breaker, 1-SI-MOV-1867A o
• 1-EE-BKR-1J1-2N C3, BIT Inlet Isolation Valve Circuit Breaker, 1-SI-MOV-1867B (STEP 4 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 20 1-ES-1.1 SI TERMINATION PAGE 5 of 24 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

4. ISOLATE BIT: (Continued) c) Close BIT Outlet Isolation Valves:

o

• 1-SI-MOV-1867C o
• 1-SI-MOV-1867D d) Verify the following valves - CLOSED: o d) Place control power on AND close valves.

o

• 1-SI-MOV-1836 o
• 1-SI-MOV-1869B o
• 1-SI-MOV-1869A

5. ESTABLISH CHARGING:

o a) Put controller for 1-CH-FCV-1122 in MANUAL and close o b) Verify 1-CH-HCV-1311, Auxiliary Spray o b) Manually close valve. Valve - CLOSED c) Open Normal Charging Line Isolation Valves: o

• 1-CH-HCV-1310 o
• 1-CH-MOV-1289A o
• 1-CH-MOV-1289B o d) Maintain seal injection flow to each RCP between 6 gpm and 8 gpm

(

NUMBER PROCEDURE TITLE REVISION 20 1-ES-1.1 SI TERMINATION PAGE 6 of 24 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

6. CONTROL CHARGING FLOW TO MAINTAIN !E. any isolated SG pressure is decreasing in PRZR LEVEL an uncontrolled manner, THEN do NOT proceed until one of the following conditions is met:

D

• Faulted SG depressurization stops OR D
• PRZR level can be maintained IF SGs are NOT faulted OR PRZR level continues to decrease after faulted SGs are completely depressurized, THEN do the following:

D a) Manually start Charging Pumps and align BIT as necessary. D b) GO TO 1-ES-1.2, POST LOCA COOLDOWN AND DEPRESSURIZATION, STEP 1. 0- CHECK RCS PRESSURE - STABLE OR INCREASING D IF any isolated SG pressure is decreasing in an uncontrolled manner, THEN do NOT proceed until faulted SG depressurization stops.

                                                 !E. SGs are NOT faulted, THEN do the following:

D a) Manually start Charging Pumps and align BIT as necessary. D b) GO TO 1-ES-1.2, POST LOCA COOLDOWN AND DEPRESSURIZATION, STEP 1. (

NUMBER PROCEDURE TITLE REVISION 20 1-ES-1.1 SI TERMINATION PAGE 7 of 24 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

8. CHECK IF LOW-HEAD SI PUMPS SHOULD BE STOPPED:

a) Check Low Head SI Pump Suctions From o a) GO TO Step 9. Containment Sump - CLOSED: o

• 1-SI-MOV-1860A o
• 1-SI-MOV-1860B o b) Stop Low-Head SI pumps and put in AUTO-STANDBY G- VERIFY SI FLOW - NOT REQUIRED:

o a) RCS subcooling based on Core Exit TCs - 0 a) Manually start Charging Pumps and align GREATER THAN 25°F [75°F] BIT as necessary. 0 GO TO 1-E-1, LOSS OF REACTOR OR SECONDARY COOLANT, STEP 1. o b) PRZR level- GREATER THAN 21% [26%] 0 b) Control charging flow to increase PRZR level. o IF PRZR level cannot be increased, THEN manually start Charging Pumps and align BIT as necessary. o GO TO 1-E-1, LOSS OF REACTOR OR SECONDARY COOLANT, STEP 1.

10. RESET CONTAINMENT ISOLATION SIGNALS:

o a) Reset both Trains of Phase A Isolation o b) Reset both Trains of Phase B Isolation, if actuated

NUMBER PROCEDURE TITLE REVISION 20 1-ES-1.1 SI TERMINATION PAGE 8 of 24 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

11. ESTABLISH INSTRUMENT AIR TO CONTAINMENT:

o a) Verify at least one Air Compressor is o a) Start at least one Air Compressor. supplying Instrument Air System b) Verify Containment Instrument Air Trip o b) Manually open valves. Valves - OPEN: o

• 1-IA-TV-102A o
• 1-IA-TV-102B

NUMBER PROCEDURE TITLE REVISION 20 1-ES-1.1 SI TERMINATION PAGE 9 of 24 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

  *12. CHECK QUENCH SPRAY PUMP STATUS:

D a) Quench Spray Pumps - ANY RUNNING D a) !E CDA has NOT actuated, THEN GO TO Step 16. D IF CDA has actuated, THEN GO TO Step 13. b) Check for either of the following conditions: D b) GO TO Step 13. D

• Containment pressure - LESS THAN 13 PSIA OR

(

• Both of the following:

D

• RWST Level - LESS THAN 3%

AND D

• Quench Spray Pump amps -

FLUCTUATING D c) Verify both trains of CDA - RESET D c) Reset both trains of CDA using the spray actuation reset switches. d) Stop Quench Spray Pumps and put in AUTO-STAN 0 BY: D

• 1-QS-P-1A D
• 1-QS-P-1 B (STEP 12 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 20 1-ES-1.1 SI TERMINATION PAGE 15 of 24 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

18. ESTABLISH LETDOWN: D Establish excess letdown using 1-0P-8.5, OPERATION OF EXCESS LETDOWN.

D a) Put 1-CH-PCV-1145 in MANUAL and open to 100% b) Open the following: D

• 1-CH-TV-1204A D
• 1-CH-TV-1204B D
• 1-CH-LCV-1460A D
• 1-CH-LCV-1460B D c) Open 1-CH-FCV-1122 to establish at least 25 gpm charging flow d) Open one of the following Letdown Orifice Valves:

D

• 1-CH-HCV-1200A OR D
• 1-CH-HCV-1200B OR D
• 1-CH-HCV-1200C D e) Adjust 1-CH-PCV-1145 to establish 300 psig letdown pressure and put in AUTO D f) Maintain seal injection flow to each RCP between 6 gpm and 8 gpm

NUMBER PROCEDURE TITLE REVISION 27 1-ES-O.1 REACTOR TRIP RESPONSE PAGE 2 of 21 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

 *1. CHECK RCS AVERAGE TEMPERATURE:

a) Check Temperature Control: a) Do the following:

• STEAM DUMPS - CONTROLLING: IF temperature is less than control value AND decreasing, THEN:

D

• STABLE AT 54JOF D 1) Stop dumping steam.

OR D 2) Verify SG Blowdown Trip Valves are D

• TRENDING TO 54JOF closed.

OR D LE NOT, THEN manually close valves.

• SG PORVs - CONTROLLING:

D 3) Adjust total AFW flow to maintain D

• STABLE AT 551°F greater than 400 gpm (340 gpm with RCPs OFF) until at least one SG OR narrow range level is greater than D
• TRENDING TO 551°F 11%.

4) !£cooldown continues, THEN close the following:

D

• MSTVs D
• MSTV Bypass Valves D 5) GO TO Step 2.

(STEP 1 CONTINUED ON NEXT PAGE)

STUDENT GUIDE FOR EMERGENCY PROCEDURES (92) Safety Injection Termination (1-ES-1.1) 12.1 Objective U 13688 List the following information associated with 1-ES-1.1, "SI Termination."

• Purpose of the procedure
• Modes of applicability
• Entry conditions
• Major action categories
• Conditions that result in leaving the procedure 12.1 Content

1. Under certain conditions, safety injection may no longer be required to maintain RCS inventory.

1.1. This is generally the case for small break primary loss-of-coolant accidents, steam line breaks, or spurious safety injection signals. 1.2. In these cases, the pressurizer will fill solid and result in a loss of RCS pressure control. 1.3. Once the pressurizer has filled solid, RCS pressure will be maintained by cycling of the pressurizer power operated relief valves. 1.4. It is, therefore, important to terminate safety injection when it is no longer needed. 1.5. ES-1.1 SAFETY INJECTION TERMINATION provides guidance to terminate safety injection and stabilize plant conditions. 1.

2. ES-1.1 is applicable in modes 1, 2, and 3.

1.

2. ES-1.1 may be entered from any of the following Emergency Operating Procedures:

2.1. E-O, REACTOR TRIP OR SAFETY INJECTION REACTOR OPERATOR Page 125 of 187 Revision 19, 11/06/2008

STUDENT GUIDE FOR EMERGENCY PROCEDURES (92) 2.2. E-1, LOSS OF REACTOR OR SECONDARY COOLANT 2.3. E-2, FAULTED STEAM GENERATOR ISOLATION 2.4. FR-H.1, RESPONSE TO LOSS OF SECONDARY HEAT SINK 1.

2. The major action categories of ES-1.1 are as follows:

2.1. Sequentially reduce SI flow 2.2. Verify SI flow not required 2.3. Re-align the plant to pre-SI configuration 2.4. Maintain the plant in a stable condition 1.

2. A transition is made out of ES-1.1 to any of the following procedures:

2.1. A transition is made to E-1 LOSS OF REACTOR OR SECONDARY COOLANT if either of the following conditions occur: 2.1.1.Loss of RCS subcooling-RCS subcooling based on core exit thermocouples less than 25°F 2.1.2.Loss of pressurizer level control - Inability to maintain pressurizer level greater than 21 % [26%]. 2.2. A transition is made to ES-1.2 POST LOCA COOLDOWN AND DEPRESSURIZATION if either of the following conditions: 2.2.1.lf RCS pressure continues to decrease after stopping all but one charging pump. OR; 2.2.2.lf SI has been previously terminated, then an attempt should be made to control Pressurizer level and pressure with normal charging, to avoid unnecessary looping back to E-1. 2.2.3.Pressurizer level cannot be controlled using normal charging following BIT isolation. 2.2.4.RCS pressure continues to decrease with high Pressurizer level and normal charging following BIT isolation, this would occur with a SBLOCA in the top of the Pressurizer. 2.3. A transition is made to E-2 FAULTED STEAM GENERATOR ISOLATION in the event that a steam generator becomes faulted. REACTOR OPERATOR Page 126 of 187 Revision 19, 11/06/2008

STUDENT GUIDE FOR EMERGENCYPROCEDURES~~ 2.3.1.lf a faulted Steam Generator has already been isolated but not yet completely depresurrized, then do not proceed with this procedure until depressurization stops, this will prevent an unnecessary transition to ES-1.2. 2.4. OP-1.5, OP-3.2 or ES-O.2A as appropriate after stabilizing plant conditions. 1. 12.2 Objective U 15893 Explain why there is no transition to 1-E-3, "Steam Generator Tube Rupture," on the continuous action page of 1-ES-1.1, "SI Termination," (1-E-3, 1-ES-1.1). 12.2 Content

1. If a steam generator tube leak is identified that can be adequately addressed by 1-AP-24, it is undesirable to unnecessarily safety inject, so transition to 1-E-3 needs to be avoided in that circumstance.

1.1. If the steam generator tube leak degrades to a steam generator tube rupture, then transition is made to 1-E-1, since flow through the SI header is required to maintain pressurizer level and/or RCS subcooling. 1.1.1. The continuous action page of 1-E-1 will then direct the operating crew to 1-E-3. 12.3 Objective U 13433 Explain why the boron injection tank recirculation valves are not opened when the boron injection tank is being isolated (1-ES-1.1). 12.3 Content

1. One of the major actions performed by ES-1.1 is to isolate the boron injection tank and establish normal charging.

REACTOR OPERATOR Page 127 of 187 Revision 19, 11/06/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

38. 041-K2.01 038INEWIIL/2/ROINAPSII Because power is lost to the steam dump arming circuit, Attachment 24, (Unit 1 CRO Loss of Power Actions), of O-AP-10, Loss of Electrical Power, directs the operator to "Check SG PORVs controlling in AUTO or MANUAL due to loss of Steam Dumps" in the event of a loss of _ _ _ _ _ _ _ _ __

A. 120-VAC Vital Bus I-I B. 120-VAC Vital Bus I-II C~ 120-VAC Vital Bus I-III D. 120-VAC Vital Bus I-IV Feedback Distractor Analysis: All are plausible since several instruments and circuits used by steam dumps are fed from the various 120-VAC instrument busses (e.g. PT-1447 from I-IV, a train of control from I-I, etc). The loss of vital bus I-III removes all power from the arming ckt, thus disabling the steam dumps so c. is the correct answer. Although loss of other 120vac busses may have some minor "effect" on steam dumps, it is inconsequential since they do continue to function. This is why the action for controlling on SG PORVs only appears in the RNO for the loss of I-III and not any of the other 3 remaining 120-VAC instrument busses. Notes Steam Dump System (SDS) and urbine Bypass Control Knowledge of bus power supplies to the following: ICS, normal and alternate power supply (CFR: 41.7) Tier: 2 Group: 2 Importance Rating: 2.8/2.9 Technical

Reference:

O-AP-10 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new Associated objective(s): Not a direct KA match per se since ICS is a B&W system; NAPS has SSPS and the question meets the intent since it measures candidates knowledge of how SDS is affected by a loss of a power supply.

NUMBER ATTACHMENT TITLE ATTACHMENT 0-AP-10 24 UNIT 1 CRO LOSS OF POWER ACTIONS REVISION PAGE 60 8 of 11 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

7. CHECK 120-VAC VITAL BUS - ENERGIZED:

(Continued) D c) 1-111- VOLTAGE INDICATED c) Do the following: D 1) !.E unit is in Mode 6, THEN secure Containment Purge using 1-0P-21.2, CONTAINMENT PURGE, because of loss of 1-RM-RMS-159/160 Sample Pump. D 2) Place Containment Air Compressors in AUTO. D 3) Stop 1-RM-RMS-159/160 Sample Pump due to trip valves being closed.

4) Monitor RCPs because of loss of CC flow and CC Head Tank indication:

D

• Motor Bearing Temperature -

LESS THAN 195 0 F D

• Pump Radial Bearing Temperature -

LESS THAN 225 0 F D

• Stator Winding Temperature -

LESS THAN 300 0 F D 5) Check SG PORVs controlling in AUTO or MANUAL due to loss of Steam Dumps. (STEP 7 CONTINUED ON NEXT PAGE)

STUDENT GUIDE FOR STEAM DUMP CONTROL AND PROTECTION SYSTEM (23-8) 6.4 Objective U 10240 With the steam dump mode selector switch in the STEAM PRESSURE position, describe the steam dump response if the main steam header pressure transmitter 1-PT-MS-464 has failed high or low. 6.4 Content

1. With steam dumps in steam-pressure mode and the controller in AUTO, steam dumps will respond to main steam header pressure PT-464 failures as follows.

1.1.lf PT-464 fails high, all eight steam dump valves will open fully. 1.1.1.Depending on initial plant conditions, the resulting steam flow could cause a high steam flow safety injection and steamline isolation. 1.2.lf PT-464 fails low, all eight steam dump valves will close if open, or remain closed if closed. 1.2.1. Lose the capability to automatically control steam header pressure. 1.2.2.The controller can still be operated in MANUAL to position steam dumps. 6.5 Objective U 7693 Explain the effect of a loss of vital bus 1-111 on the Steam Dump Control System. 6.5 Content

1. If vital bus 1-111 is de-energized, the steam dumps cannot be armed due to loss of power to the arming circuit.

REACTOR OPERATOR Page 24 of 26 Revision 1, 06/05/2007

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

39. 051-AG2.4.35 039/NEW/IL/2/RO/NAPS/S/20/200S1 Given the following conditions:

• Unit 1 is at 100% power when the crew notes degrading condenser vacuum.
• The crew has entered 1-AP-14, Low Condenser Vacuum.
• The Turbine Building operator has been dispatched to perform Attachment 2, Turbine Building Corrective Actions.

The Turbine Building operator checks both condenser air ejector loop seal drain lines to condenser, and notes that one loop seal drain line is hot to the touch and the other is cool to the touch. Which ONE of the following identifies the action required in accordance with 1-AP-14? A. Isolate the hot loop seal drain line and secure the associated set of main condenser air ejectors. B~ Isolate the hot loop seal drain line; when at least 15 minutes have elapsed, then slowly reopen the loop seal drain isolation valve. C. Isolate the cool loop seal drain line and secure the associated set of main condenser air ejectors. D. Isolate the cool loop seal drain line; when at least 15 minutes have elapsed, then slowly reopen the loop seal drain isolation valve. Feedback

a. Isolation of the hot loop seal is correct but the candidate who does not understand the function of the loop seal or have detailed knowledge of the procedure may not have that knowledge; the second part is also incorrect but plausible since again the candidate who does not fully understand the system lineup and operation may conclude that this action would make sense.

b. Correct. The hot loop seal drain line indicates the seal is blown and the correct action is to isolate it, allow it to refill, and then place back in service as per AP14 Attachment 2.

c. Incorrect. Again the candidate who does not have detailed knowledge of operation of the air ejector or procedure knowledge may conclude that this is a problem (since most things in the secondary are hot to the touch when operating and in-service; second part also incorrect but plausible as discussed in Distractor a.

d. Incorrect. Plausible as discussed in Distractor c; second part is correct per AP-14, attachemnt 2.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Loss of Condenser Vacuum Knowledge of local auxiliary operator tasks during an emergency and the resultant operational effects. (CFR: 41.10/43.5/45.13) Tier: 1 Group: 2 Importance Rating: 3.8/4.0 Technical

Reference:

1-AP-14 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info:

NUMBER ATTACHMENT TITLE ATTACHMENT 1-AP-14 2 TURBINE BUILDING CORRECTIVE ACTIONS REVISION PAGE 20 1 of 2 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. VERIFY AIR EJECTOR STEAM Adjust steam pressure using:

SUPPLY PRESSURE - BETWEEN 120 AND 140 PSIG 0

• 1-AS-21 for 1-CN-EJ-1 A 0
• 1-AS-29 for 1-CN-EJ-1 B

2. CHECK CONDENSER VACUUM 0 Cycle 1-AS-11, Water Seal Condensate Supply, BREAKER WATER SEAL - FULL until vacuum breaker is full.

3. CHECK CONDENSER AIR Isolate the hot loop seal drain line:

EJECTOR LOOP SEAL DRAIN LINES TO CONDENSER - NOT HOT 0

• 1-VP-21, 1B Air Ejector to 1B Condenser Isol TO TOUCH AS COMPARED TO Valve CONDENSATE PIPING AT AIR EJECTOR CONDENSER 0
• 1-VP-22, 1A Air Ejector to 1B Condenser Isol Valve 0 WHEN at least 15 minutes have passed, THEN slowly open the loop seal drain isolation valves.

4. VERIFY ALL TURBINE GLAND 0 Bypass any gland steam PCVs - indicating less PRESSURES BETWEEN than 1.5 psig.

1.5 AND 5 PSIG

5. _ CLOSE 1-GN-455, NITROGEN INJECTION TO LP TURBINE EXHAUST ISOLVV (LOCATED UNIT 1 TURBINE DOGHOUSE, SOUTHWEST CORNER) 6._ VERIFY 1-BD-PCV-101, SG BD Do the following:

FLASH TK OUTLET TO CONDENSER PRESS CONT VV - 0 a) Shut down High Capacity Blowdown System CLOSED using 1-0P-32.3, HIGH CAPACITY STEAM GENERATOR BLOWDOWN SYSTEM OPERATION. 0 b) Ensure 1-BD-PCV-1 01 is closed. IF NOT, THEN close 1-BD-1014, SG Blowdown Flash Tank To Condenser Isol Vv.

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91)

7. Health Physics will need to evaluate the liquid waste release permit based on the number of running CW pumps to determine if securing liquid waste release is required.

7.1. Liquid waste releases to the CW discharge tunnel may need to be secured because the dilution flow rate changes when CW pump(s) trip.

8. If rupture discs on the LP turbines are NOT intact, condenser pressure will go to atmospheric and the following actions should be performed.

8.1. Air ejectors are providing no useful function, so they are secured. 6.2. When condenser pressure reaches atmospheric, gland steam is secured.

7. If the loss of the circulating water pumps was caused by SI/CDA load shed, then refer to O-AP-47 for instructions on resetting SI/CDA load shed.

21.3 Objective U 11411 List the following information associated with 1-AP-14, "Low Condenser Vacuum."

• Purpose of the procedure
• Modes of applicability
• Entry conditions 21.3 Content

1. 1-AP-14 provides guidance to respond to a partial loss of condenser vacuum.

2. It is applicable in modes 1 through 4.

3. 1-AP-14 is entered if any of the following conditions exist:

REACTOR OPERATOR Page 109 of 158 Revision 30, 11/06/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) 3.1. Decreasing condenser vacuum or generator output 3.2. Condenser vacuum breaker, 1-AS-MOV-100, open 3.3. 1G-F3, TURBINE LO VACUUM PRE-TRIP, lit 3.4. 1G-E1(G1), LP TURB 1A(1B) EXH HOOD HI TEMP, lit 3.5. 1G-F1(H1), LP TURB 1A(B) EXH HOOD HI-HI TEMP, lit 3.6. Transition from 1-AP-13 21.4 Objective U 11412 Explain the purpose of the following high-level action steps associated with 1-AP-14, "Low Condenser Vacuum."

• Lower main turbine load until condenser vacuum is stable, and verify that pressure is 3.5 inches Hg or less.
• Locate and isolate the loss of vacuum.

21.4 Content

1. Turbine load is reduced to stabilize condenser vacuum 1.1. The presence of even a small amount of non-condensable gases dramatically reduces the rate of heat transfer across the condenser tubes.

1.1.1.Non-condensable gas is carried with the steam to the surface of the tubes, where it accumulates. 1.1.2.This gas accumulation significantly reduces conductive heat transfer, since gas is a poor heat transfer medium. 1.1.3.As a result, the overall heat transfer coefficient is drastically reduced. 1.1.4.The saturation temperature and pressure in the condenser is increased and the Rankine cycle efficiency decreases. 1.2. To combat this, the turbine load is immediately reduced. 1.2.1.This lowers the temperature in the condenser by lowering the heat input. REACTOR OPERATOR Page 110 of 158 Revision 30, 11/06/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

40. 054-AK3.04 040INEW//H/3/ROINAPSII Given the following conditions:

• Operators have transitioned to 1-FR-H.1, Response to Loss of Secondary Heat Sink.
• SG wide-range levels are approximately 50% and slowly decreasing.
• Operators are at Step 2 of 1-FR-H.1 and are unable to establish AFW flow to any of the SGs.

Which ONE of the following identifies the action required by 1-FR-H.1 with respect to the Reps? A. Stop all but ONE Rep. B:t Stop all Reps. C. Maintain Reps operating unless support conditions degrade. D. Maintain Reps operating until bleed and feed criteria are met. Feedback

a. Incorrect. Plausible since several EOps have actions to go down to ONE RCP; logical since EOPs prefer RCP operation for normal pressure control.

b. Correct. Action is required to minimize heat input to the RCS and thus prolong the time before bleed and feed criteria are met.

c. Incorrect. Plausible since candidate may assume that there is no urgency to perform the action and as discussed above; RCP operation for forced circulation is also desired.

d. Incorrect. Plausible and logical for reasons noted above; candidate may rationalize that RCP operation is a good thing and they would only be stopped when we get to the point of bleed and feed where subcooling will be lost.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Loss of Main Feedwater (MFW) Knowledge of the reasons for the following responses as they apply to the Loss of Main Feedwater (MFW): Actions contained in EOPs for loss of MFW (CFR 41.5,41.10/45.6/45.13) Tier: 1 Group: 1 Importance Rating: 4.4/4.6 Technical

Reference:

1-FR-H.1 and background document Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new Associated objective(s): Explain the following concepts associated with the plant's response to a loss of secondary heat sink (1-FR-H.1, SOER-86-1). Why reactor coolant pumps are tripped if the minimum auxiliary feedwater flow cannot be established immediately

NUMBER PROCEDURE TITLE REVISION 19 1-FR-H.1 RESPONSE TO LOSS OF SECONDARY HEAT SINK PAGE 3 of 41 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION: If wide range SG level in any two SGs is less than 14% [32%] because of a loss of secondary heat sink, then Step 14 through Step 23 should be performed immediately for RCS bleed and feed.

2. TRY TO ESTABLISH AFW FLOW TO AT LEAST ONE SG:

a) Check SG Blowdown and Sample o a) Manually close valves. Isolation: 0

• SG Blowdown Isolation Valves -

CLOSED 0

• SG Sample Isolation Valves -

CLOSED b) Review Control Room indications to determine cause of AFW failure: 0

• ECST level 0
• AFW Pump power supply 0
• AFW valve alignment 0 c) Start at least one AFW Pump from the c) IF Motor-Driven AFW Pumps cannot be Control Room started because of loss of control power, THEN try to start at least one pump as follows, while continuing with this procedure:

o

• From the Auxiliary Shutdown Panel o
• Using O-MOP-26.11, 4160-VOLT BREAKER LOCAL MANUAL OPERATION (STEP 2 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 19 1-FR-H.1 RESPONSE TO LOSS OF SECONDARY HEAT SINK PAGE 4 of 41 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

2. TRY TO ESTABLISH AFW FLOW TO AT LEAST ONE SG: (Continued)

D d) Check total flow to SGs - GREATER THAN d) Do the following: 340 GPM D 1) Stop ALL RCPs. D 2) Send an Operator to locally restore or realign AFW using 1-AP-22 series procedures. D 3) GO TO Step 3. D e) RETURN TO procedure and step in effect CAUTION: If SI actuates prior to performance or transition to Step 14 through Step 23 for initiation of RCS bleed and feed, then restoration of Feedwater should be re-established by returning to Step 3. 0)- TRY TO ESTABLISH MAIN FEED FLOW TO AT LEAST ONE SG: D a) Verify at least one Condensate Pump - D a) Start at least one Condensate Pump RUNNING using 1-0P-30.1, OPERATION OF CONDENSATE SYSTEM. D IF one pump cannot be started because of loss of control power, THEN initiate 0-MOP-26.11, 4160-VOLT BREAKER LOCAL MANUAL OPERATION. D !E one pump cannot be started, THEN GO TO Step 13. (STEP 3 CONTINUED ON NEXT PAGE)

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95) 5.2. If RCS bleed and feed was initiated, then FR-H.1 is not exited until each of the following conditions exist: 5.2.1.At least one SG N/R level is restored to greater than 11 %, and 5.2.2.Core exit TCs are decreasing, and 5.2.3.Hot leg temperatures are decreasing 7.2 Objective U 11301 Explain the following concepts associated with the plant's response to a loss of secondary heat sink (1-FR-H.1, SOER-86-1).

• Why 1-FR-H.1 should not be used if total auxiliary feedwater flow is less than 340 gpm due to operator action
• Why auxiliary feedwater flow should not be established to a faulted steam generator that has been isolated, unless the steam generator is needed for cooldown
• Why a secondary heat sink is not required if Reactor Coolant System pressure is less than that of the non-faulted steam generators
• Why reactor coolant pumps are tripped if the minimum auxiliary feedwater flow cannot be established immediately
• Why charging pump suction must be aligned to the RWST prior to depressurizing steam generators even if safety injection has not been initiated
• Why steam generators should be maintained within 100 psi of each other during steam generator feed or depressurization 7.2 Content

1. FR-H.1 should not be used if the operator has intentionally reduced AFW flow to less than 340 gpm in accordance with EOP guidance for three faulted steam generators.

1.1. The capability to provide feed flow to the SGs determines whether FR-H.1 must be performed. 1.2. During the performance of certain EOPs (e.g. ECA-2.1, FR-P.1, FR-S.1, and FR-Z.1), it is possible that the SG level is below the N/R and total feed flow is intentionally throttled to less than 340 gpm. 1.2.1.lf this is the case, then FR-H.1 should not be performed. REACTOR OPERATOR Page 47 of 99 Revision 14, 11/06/2008

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95)

2. The operator is cautioned not to feed a faulted S/G that has been isolated unless it is needed for cooldown.

2.1. Reestablishing feed flow to a faulted SG may result in thermal or mechanical shock to the SG tubes that could cause failure of SG tubes. 2.2. Subsequent control of the primary-to-secondary leakage would not be possible until the SG secondary boundary was restored. 2.3. A faulted SG should NOT be used for cool down if there is a non-faulted SG available. 2.4. If a faulted SG is isolated in accordance with E-2, and subsequently the other two SGs become faulted, the first SG should remain isolated unless needed for cooldown. 2.4.1.100 gpm of feedwater flow should be established to each of the other two SGs.

3. Before implementing actions to restore flow to the steam generators, the operator should check if secondary heat sink is required.

3.1. For larger LOCA break sizes, the RCS will depressurize below the intact steam generator pressures. 3.2. The steam generators no longer function as a heat sink, and the core decay heat is removed by the RCS break flow. 3.3. For this range of LOCA break sizes, the secondary heat sink is not required and actions to restore secondary heat sink are not necessary. 3.4. The operator is returned to procedure and step in effect.

4. If AFW cannot be immediately established, all RCPs are tripped.

4.1. RCP operation results in heat addition to the reactor coolant. 4.1.1.Tripping the RCPs eliminates them as a source of heat input to the reactor coolant. 4.1.2.Extends the effectiveness of the remaining water inventory in the SGs (delays SG dryout). 4.1.3.Extends the time at which RCS bleed and feed will be necessary, which provides additional time for the operator to restore feedwater flow to the SGs. REACTOR OPERATOR Page 48 of 99 Revision 14, 11/06/2008

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95) ( 4.2. RCPs running can also reduce the effectiveness of bleed and feed, should it eventually become necessary. 4.2.1.RCP heat input to the RCS will result in increased steam generation, which hinders the depressurization of the RCS during bleed and feed. 4.2.2.The higher RCS pressure produced by RCP operation will result in reduced SI flow and increased inventory loss through the PRZR PORVs.

5. In order to provide adequate negative reactivity insertion for the subsequent RCS cooldown during SG depressurization, boration is initiated from the RWST via normal charging.

6. All intact SGs should be maintained within 100 psi of each other during SG feed and depressurization to prevent steamline differential pressure SI.

6.1. Safety injection results in Main FW isolation. Even if not using MFW (using AFW instead), the SI I results in an unnecessary plant transient that can be avoided. 6.2. Actions to restore feedwater flow should consider SG pressure.

7. If pressure in one intact SG is significantly less than the other two, avoid feeding it, if possible.

7.3 Objective U 11295 Explain the following concepts associated with the plant's response to a loss of secondary heat-removal capability from 100% power (1-FR-H.1, SOER-86-1).

• How Reactor Coolant System pressure, temperature, and inventory are affected, assuming that no operator actions are taken
• How operator actions minimize uncovering and inadequately cooling the core, assuming that secondary heat-removal capability cannot be restored
• Why using the Residual Heat Removal System is most likely not a viable alternative method of removing decay heat REACTOR OPERATOR Page 49 of 99 Revision 14, 11/06/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

41. 055-EK2.04041INEWIIH/3/ROINAPSII Given the following conditions:

• Both units are initially at 100% power.
• 2-SW-P-1B is tagged out, and Service Water is throttled.

A 1055 of both Unit-1 4160-Volt Emergency buses occurs, and power is eventually restored to the 1H Emergency bus from the SBO diesel. Which ONE of the following identifies how the Unit-1 Service Water pumps are operated in accordance with 1-ECA-0.0, Loss of All AC Power? A. 1-SW-P-1A and 1-SW-P-1B control switches are maintained in AUTO during 1-ECA-0.0 recovery actions; 1-SW-P-1A will be started prior to exiting 1-ECA-0.0. B. 1-SW-P-1A and 1-SW-P-1B control switches are maintained in AUTO during recovery actions; 1-SW-P-1A will be started after exiting 1-ECA-0.0. C~ 1-SW-P-1A and 1-SW-P-1 B control switches are placed in PULL-TO-LOCK during recovery actions; 1-SW-P-1A will be started prior to exiting 1-ECA-0.0. D. 1-SW-P-1A and 1-SW-P-1 B control switches are placed in PULL-TO-LOCK during recovery actions; 1-SW-P-1A will be started after exiting 1-ECA-0.0. Feedback

a. Incorrect. Plausible since this is the normal configuration of the subject pumps and candidate may not recognize requirement to place them in PTL; second part is correct.

b. Incorrect. Plausible since this is the normal configuration of the subject pumps and candidate may not recognize requirement to place them in PTL; second part is also incorrect but plausible since most other equipment is started by subsequent recovery procedures, SW is an exception to this rule since it provides the heat sink for other safety related loads.

c. Correct. ECA-O.O place the equipment in PTL to ensure control loading on the emergency power source; second part is also correct as discussed in Distractor b.

d. Incorrect. First part is correct as discussed above; second part is incorrect as discussed in Distractor b.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Loss of Offsite and Onsite Power (Station Blackout) Knowledge of the interrelations between the and the following Station Blackout: Pumps (CFR 41.7 / 45.7) Tier: Group: Importance Rating: plant specific> 2.5 (catalog is blank) Technical

Reference:

1-ECA-O.O Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new Associated objective(s): (

( NUMBER PROCEDURE TITLE REVISION 22 1-ECA-O.O LOSS OF ALL AC POWER PAGE 7 of 22 ACTION! EXPECTED RESPONSE RESPONSE NOT OBTAINED G-- VERIFY POWER TO 1H (1J) 4160-VOLT EMERGENCY BUS - RESTORED: o a) Verify 1H (1J) Emergency Diesel o a) Continue attempts to start 1H (1 J) Generator - RUNNING Emergency Diesel Generator using ATTACHMENT 4, Step 2 before continuing with Step 9b. o IF at least one EDG can NOT be started, THEN GO TO Step 10. o b) Verify 1H (1 J) 4160-Volt Emergency Bus - o b) Continue attempts to energize 1H (1 J) ENERGIZED Emergency Bus using ATTACHMENT 4, Step 3 before continuing with Step 9c. o IF at least one Emergency Bus can NOT be energized, THEN GO TO Step 10. o c) Check 1H (1J) Emergency Bus voltage o c) Place 1H (1J) EDG MOP Defeat switch to and frequency - NORMAL MANUAL and control voltage and frequency within normal range. o IF EDG voltage AND frequency cannot be controlled as required, THEN GO TO Step 10. o d) RETURN TO procedure and step in effect

NUMBER PROCEDURE TITLE REVISION 22 1-ECA-O.O LOSS OF ALL AC POWER PAGE 8 of 22 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION:

• If an SI signal exists or an SI is actuated during this procedure, then SI should be reset to allow manual loading of equipment on a recovered AC Emergency Bus.
• When power is restored to any AC Emergency Bus, then, to facilitate recovery actions, recovery should continue starting with Step 29.

10. PUT THE FOLLOWING EQUIPMENT IN PTL:

o

• All Charging Pumps o
• Both CC Pumps o
• All PRZR Heaters 0
• Both Low-Head SI Pumps 0
• Both Quench Spray Pumps 0
• All Recirc Spray Pumps 0
• Both Service Water Pumps 0
• Auxiliary Service Water Pump 0
• Both Motor-Driven AFW Pumps 0
• All Containment Air Recirc Fans

@_INITIATEATTACHMENT3TOLOCALLY ISOLATE RCP SEALS

NUMBER PROCEDURE TITLE REVISION 22 1-ECA-O.O LOSS OF ALL AC POWER PAGE 19 of 22 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

28. CHECK IF AC EMERGENCY POWER IS RESTORED - AT LEAST ONE AC EMERGENCY BUS ENERGIZED (Continued) e) Check status of boration systems:

D

• BIT temperature greater than 115°F D
• BAST temperature greater than 115°F D
• IF any temperature is less than 115°F, THEN consult TSC or Plant Staff for guidance on methods of diluting Boron concentration or locally draining affected components.

D f) RETURN TO Step 16.

29. MANUALLY CONTROL SG PORVs TO Locally control SG PORVs:

STABILIZE SG PRESSURES D

• 1-MS-PCV-1 01 A D
• 1-MS-PCV-101 B D
• 1-MS-PCV-101C CAUTION: To prevent overloading the power supply, loads put on the energized AC Emergency Bus should not exceed the capacity of the power source.

30. VERIFY 480V EMERGENCY BUSSES - D Manually load available 480V Emergency ENERGIZED Busses.

NUMBER PROCEDURE TITLE REVISION 22 1-ECA-O.O LOSS OF ALL AC POWER PAGE 20 of 22 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

31. CHECK 480V EQUIPMENT:

o a) Check Battery Chargers - ENERGIZED a) Put Battery Chargers in service using applicable procedures: o . 1-0P-26.4.1, MAIN STATION BATTERY CHARGERS 1-1 AND HI OPERATION o

• 1-0P-26.4.2, MAIN STATION BATTERY CHARGERS HII AND 1-IV OPERATION o
• 1-0P-26.4.3, MAIN STATION BATTERY CHARGERS 1C-I AND 1C-II

( OPERATION o b) Return previously de-energized DC loads to service as required o c) Check Instrument Air pressure - NORMAL o c) Manually start compressors. OR INCREASING o d) Check Auxiliary Building Central Exhaust o d) Manually start at least one fan. Fan - AT LEAST ONE RUNNING

( NUMBER PROCEDURE TITLE REVISION 22 1-ECA-O.O LOSS OF ALL AC POWER PAGE 21 of 22 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

32. CHECK SERVICE WATER SYSTEM STATUS:

a) Verify at least two of four Service Water D a) Manually start required Service Water Pumps - RUNNING: Pumps. D

• 1-SW-P-1A D
• 1-SW-P-1 B D
• 2-SW-P-1A D
• 2-SW-P-1B D b) Verify at least one Service Water Pump on D b).!.E one Supply Header has NO running each Supply Header - RUNNING SW Pump, THEN align Service Water to both headers using O-AP-12, LOSS OF SERVICE WATER, while continuing with this procedure.

STUDENT GUIDE FOR EMERGENCY CONTINGENCY ACTION PROCEDURES (94)

1. Westinghouse recommends that seal cooling should not be restored following an extended loss of all seal cooling where the seal temperature exceeds 235°F.

1.1. This temperature was chosen as the maximum allowed seal water outlet temperature permitted for any RCP to allow for starting an EDG with seals unisolated. 1.2. Placing all charging pumps in PTL is considered sufficient isolation to allow an EDG to be started.

2. If an EDG is successfully started on this first attempt at power restoration and 1-ECA-0.0 is exited at step 9, the crew is directed to verify that the attachment for isolating seals is complete before starting charging pumps.

1.3 Objective U 13831 Explain why the functional restoration procedures are not implemented during the performance of 1-ECA-0.0. 1.3 Content

1. Functional restoration procedures are not implemented during the performance of 1-ECA-0.0 since they are written on the premise that at least one emergency bus is energized.

1.1. ECA-O.O has priority over all FRs and is written to implicitly monitor and maintain critical safety functions. 1.4 Objective U 13832 Explain the following actions directed in ECA-O.O:

• Resetting of SI signals
• Placing specific equipment in PTL.

( REACTOR OPERATOR Page 70f7 Revision 7, 09/17/2008

STUDENT GUIDE FOR EMERGENCY CONTINGENCY ACTION PROCEDURES (94) ( 1.4 Content

1. A caution before step 9 in ECA-O.O directs that should an SI signal exist or an SI is actuated during performance of the procedure, that the SI be reset to allow the manual loading of equipment on a recovered AC emergency bus.

2. The procedure directs the following equipment to be placed in PTL to allow the equipment to manually start when an emergency bus is recovered:

2.1. Charging pumps 2.2. Low-head SI pumps 2.3. Quench spray pumps 2.4. Inside and outside Recirc Spray pumps 2.5. Service Water pumps 2.6. Component Cooling pumps 2.7. Motor-driven AFW pumps 2.8. PRZR heaters 2.9. Containment air recirc fans. 1.5 Objective U 13833 Explain why seal injection, sealleakoff, and component cooling water are isolated to the reactor coolant pumps during the response to a loss of all AC power. 1.5 Content

1. Seal injection, sealleakoff, and CC to the RCPs are isolated during ECA-O.O to isolate the RCP seals.

1.1.lsolating the RCP seal injection lines prepares the plant for recovery while protecting the RCPs from seal and shaft damage that may occur when a charging/SI pump is started as part of the recovery. REACTOR OPERATOR Page 8 of 8 Revision 7, 09/17/2008

STUDENT GUIDE FOR EMERGENCY CONTINGENCY ACTION PROCEDURES (94) 3.1. If the CDA setpoint has been exceeded, the operator is directed to manually initiate CDA actuation signal, then verify closed or manually close the Phase B isolation valves. 3.1.1.Since the RCPs are not running and the Phase B penetration piping is not pressurized, there is no technical reason for not isolating Phase B valves concurrent with Phase A valve isolation.

4. Core Exit thermocouple temperatures are used to determine if conditions exist which require transition to the SAMGs.

4.1. If core exit thermocouple indicate greater than 1200° F the EOPs should be exited and the SAMGs entered. Topic . 1;g**Se..vice.Water Re.sloralibh** r 1.9 Objective ( U 13836 Explain why the service water pumps are started prior to moving from 1-ECA-0.O to a recovery procedure. 1.9 Content

1. SW pumps are started prior to moving from 1-ECA-0.0 to a recovery procedure to ensure adequate cooling to the CCHXs and charging pumps.

1.1. In the subsequent recovery procedures, various equipment will be started within the power source limitations that will place heat loads on the service water system, therefore a check of the system occurs before a transition. REACTOR OPERATOR Page 13 of 13 Revision 7,09/17/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

42. 056-AG2.4.8 042INEW/1H/3IRO///

Given the following conditions:

• Unit 1 is at 25% power ramping up following a scheduled refueling.
• Annunciator A-G1, CNDSR LO VAC C-9 PERM NOT AVAIL is received.
• The OATC notes that condenser vacuum is 4 in Hg abs and slowly degrading.
• The crew enters 1-AP-14, Low Condenser Vacuum.

Which ONE of the following identifies the action required to mitigate these plant conditions? A. Go to 1-AP-2.2, Fast Load Reduction, reduce load and remove the main generator from service while continuing with 1-AP-14. B. Exit 1-AP-14, go to 1-AP-2.2, Fast Load Reduction, reduce load and remove the main generator from service. C'!'" Trip the reactor and go to 1-E-O, Reactor Trip or Safety Injection, while continuing with 1-AP-14. D. Exit 1-AP-14, trip the reactor and go to 1-E-O, Reactor Trip or Safety Injection. Feedback

a. Incorrect. plausible since this would be the normal course of action at this power level if Condenser dumps were available, however for this scenario with vacuum at 4" abs C-9 persmissive is not satisfied so a reactor trip is required, the procedure 1-AP-14 specifically directs performing E-O while continuing with 1-AP-14.

b. Incorrect. Entry into 1-AP-2.2 is plausible as discussed above; exiting 1-AP-14 is also plausible since the candidate may conclude that 1-AP-2.2 actions are taken to remedy the situation, and thus not see a need to perform 1-AP-14 concurrently.

c. Correct. As previously discussed since Condenser dumps are unavailable a Reactor trip is required, AP-14 directs that is be performed concurrently since those actions may restore condenser vacuum and thus restore Condenser steam dumps which is the prefered method of maintaining hot standby conditions.

d. Incorrect. As discussed in distractor b. exiting 1-AP-14 is plausible; the second part entering E-O is correct.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Loss of Offsite and Onsite Power (Station Blackout) Knowledge of how abnormal operating procedures are used in conjunction with EOPs. (CFR: 41.10/43.5/45.13) Tier: Group: Importance Rating: 3.8/4.5 Technical

Reference:

1-AP-14 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new Associated objective(s):

NUMBER PROCEDURE TITLE REVISION 20 1-AP-14 LOW CONDENSER VACUUM PAGE 2 of 9 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. CHECK TURBINE LOAD CONTROL:

o a) Verify Turbine valve position - OFF o a) Take Turbine off Valve Position Limiter. VALVE POSITION LIMITER o b) Verify Turbine Load Control in o b) Place Turbine Load Control in IMP-IN by IMP-IN. depressing the IMP-IN pushbutton.

2. COMMENCE MANUAL TURBINE LOAD REDUCTION UNTIL CONDENSER VACUUM - STABLE NOTE: ATIACHMENT 3 is provided to aid in estimating boration flowrates during a fast load reduction.

3. INITIATE ONE OF THE FOLLOWING

                                                                                          ,~
                                                                                      ~OV'"'~    ,vv WHILE CONTINUING WITH THIS PROCEDURE:
                                                                            ,},':O V  ~t7JS ~~,
                                                                             "'~ {~          j\

V)~ 0'r tJ~ o

• 1-0P-2.2, UNIT POWER yu-u yr' G

                                                                                        \_~
                                              ~0c.;.L ~y~

OPERATION FROM MODE 1 TO MODE 2 VeP OR (j .e/~ ,,~.J s #

                                                 -0 tA/ cY o

• 1-AP-2.2, FAST LOAD \../ ~ YJ '" L; REDUCTION
• 4. MONITOR CONDENSER o !E Reactor power is less than 30%, THEN GO TO PRESSURE - 3.5 INCHES HG 1-E-0, REACTOR TRIP OR SAFETY INJECTION, ABS OR LESS while continuing with this procedure.

o !E Reactor power is 30% or greater AND Condenser pressure is greater than 5.5 inches, THEN GO TO 1-E-0, REACTOR TRIP OR SAFETY INJECTION, while continuing with this procedure.

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) 1.2.2.Lowering the heat input reduces the delta T between the condenser and the circulating water and brings the temperature closer to the circulating water temperature. 1.2.2.1. This decreases the saturation temperature of the secondary steam. 1.3. The overall effect is an increase in efficiency and more time is available to correct the problems in the field.

2. The most likely causes for a loss of vacuum are checked and corrective actions are initiated to restore vacuum.

21.5 Objective U 9877 ( Determine the appropriate operator action if condenser pressure increases above 3.5 inches as per 1-AP-14, "Low Condenser Vacuum." 21.5 Content

1. If condenser pressure increases above 3.5 inches and reactor power is less than 30%, the operator is directed to enter 1-E-0 while continuing with 1-AP-14.

1.1. If Reactor power is 30% or greater AND condenser pressure is greater than 5.5 inches, the operator is directed to enter 1-E-0 while continuing with 1-AP-14. 21.6 Objective U 11413 List the following information associated with 1-AP-19, "Loss of Bearing Cooling Water."

• Purpose of the procedure
• Modes of applicability
• Entry conditions REACTOR OPERATOR Page 111 of 158 Revision 30, 11/06/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

43. 057-AG2.2.38 043INEWIIL/3/ROINAPSII Given the following conditions:

• Unit 1 is at 100% power.
• Numerous alarms are received, and the OATC determines that a partial loss of Vital AC Bus 1-111 has occurred.
• Unit 1 is stable, and the OATC has identified that several instruments powered from Vital AC Bus 1-111 have been lost.

Which ONE of the following failed instruments requires action within 1 Hour in accordance with Technical Specifications? A"! Pressurizer pressure protection channel III, 1-RC-PT-1457. B. Pressurizer level channel III, 1-RC-LT-1461. C. "B" SG steam flow channel III, 1-MS-FT-1484 D. "A" SG narrow-range level channel III, 1-FW-LT-1476 Feedback

a. Correct. The pressurizer pressure protection channel feed ESFAS permissives which are required by TS to verified in their required state within 1 hour (reference TS Table 3.3.2-1, Function 8, condition J).

b. Incorrect. Plausible since several instument channels have a 1 hour action associated with them, however Pressurizer level is not one of them.

c. Incorrect. Plausible since some secondary instruments (e.g. Turbine first stage pressure) have 1 hour actions associated with them however steam flow is not one of them.

d. Incorrect. Plausible since Hi-HI SG water level is the P-14 permisssive and being a permissive would seam to imply action may be required within 1 hour, but this is not the case.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Loss of Vital AC Electrical Instrument Bus Knowledge of conditions and limitations in the facility license. (CFR: 41.7/41.10/43.1/45.13) Tier: Group: Importance Rating: 3.6/4.5 Technical

Reference:

TS 3.8.7 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: New Associated objective(s): additional information: NAPS Tech Spec action time for loss of vital bus is 2 hrs; since this is greater than 1hr and therefore not required from memory by ROs this was discussed with the Chief Examiner. The use of a vital bus load with a 1 hr TS action time was considered to meet the intent of the KA.

PROCEDURE NO: I'........... REVISION NO: 1-MOP-55.73 NORTH ANNA POWER STATION 7 P-1 PROCEDURE TYPE: UNIT NO: MAINTENANCE OPERATING 1 PROCEDURE TITLE: PRESSURIZER PRESSURE PROTECTION INSTRUMENTATION EOP AP REVISION

SUMMARY

Converted to FrameMaker using Template Rev. 030.

• Incorporated DCP 01-007, Phase 2 PCS Installation and P-250 Removal- Unit 1:
• Added DCP to references as Step 2.3.5.
• Added '(printout only ifP-250 not removed by DCP 01-007), in Step 4.4 and added '(P-250) or actuates (Phase 2 PCS)' in Steps5.2.7, 5.3.7, and 5.4.7.
• Added Phase 2 PCS Computer Point descriptions and designated original point descriptions for P-250 in substeps (a), (b), (c), and (d) of Steps 5.2.7, 5.3.7, and 5.4.7.
• Made ITS changes permanent in Section 2.2 and in Steps 4.1, 4.2, 4.3, 4.4,5.1.1, 5.1.1.b, 5.1.2, 5.1.2.b, and Cautions before Steps 5.2.3, 5.3.3, and 5.4.3. Removed ITS from Review Bar.
• Deleted Step 2.3.4, 1-AP-3.3, Loss of Vital Instrumentation Pressurizer Pressure, which was replaced by this procedure. No need to reference a deleted procedure
• EPAR {P1}: Incorporated Ops Concern 04-0153 to allow performance of section 5.4 in step 5.1.3.

PROCEDURE USED: D Entirely D Partially Note: If used partially, note reasons in remarks. PROBLEMS ENCOUNTERED: D NO DYES Note: If YES, note problems in remarks. REMARKS: (Use back for additional remarks.) SHIFT SUPERVISOR: DATE:

DOMINION 1-MOP-55.73 North Anna Power Station Revision 7 P-1 Page 6 of 25 Init Verif 5.0 INSTRUCTIONS 5.1 P-ll Permissive Check 5.1.1 IF RCS pressure is >2000 psig, THEN do the following in accordance with Tech Spec 3.3.2, Table 3.3.2-1, Engineered Safety Feature Actuation System, Function 8b:

a. Verify annunciator B F -2, PR2 PWR RELIEF VL VS AUTO BLOCK is NOT LIT.

b. IF annunciator B F-2 is LIT, THEN enter Tech Spec 3.3.2, Engineered Safety Feature Actuation System, Condition "J".

5.1.2 IF RCS pressure is <2000 psig, THEN do the following in accordance with Tech Spec 3.3.2, Table 3.3.2-1, Engineered Safety Feature Actuation System, Function 8b:

a. Verify annunciator B F-2, PR2 PWR RELIEF VLVS AUTO BLOCK is LIT.

b. IF annunciator B F-2 is NOT LIT, THEN enter Tech Spec 3.3.2, Engineered Safety Feature Actuation System, Condition "J".

5.1.3 {Pl} IF the conditions of Step 5.1.1.a OR 5.1.2.a are met, THEN complete Section 5.2 or 5.3 or 5.4 as applicable within 72 hours.

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 4 of 4) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE

6. Auxiliary Feedwater

a. Automatic Actuation Logic 1, 2, 3 2 trains G SR 3.3.2.2 NA and Actuation Relays SR 3.3.2.3 SR 3.3.2.5

b. SG Water Level-Low Low 1, 2, 3 3 per SG D SR 3.3.2.1 2 17%

SR 3.3.2.4 SR 3.3.2.8 SR 3.3.2.9

c. Safety Injection Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

d. Loss of Offsite Power 1, 2, 3 1 per bus, F SR 3.3.2.6 2 2184 V 2 buses SR 3.3.2.8 SR 3.3.2.9

e. Trip of all Main Feedwater 1, 2 2 per pump H SR 3.3.2.7 NA Pumps SR 3.3.2.9

7. Automatic Switchover to Containment Sump

a. Automatic Actuation Logic 1, 2, 3, 4 2 trains C SR 3.3.2.2 NA

(, and Actuation Relays SR 3.3.2.3 SR 3.3.2.5

b. RWST Level-Low Low 1, 2, 3, 4 4 SR 3.3.2.1 2 15% and SR 3.3.2.4 S 17%

SR 3.3.2.8 SR 3.3.2.9 Coincident with Safety Refer to Function 1 (Safety Injection) for a11 initiation functions and Injection requirements.

8. ESFAS Interlocks

a. Reactor Trip, P-4 1, 2, 3 per train, F SR 3.3.2.7 NA 2 trains

b. Pressurizer Pressure, P-l1 1, 2, 3 3 J SR 3.3.2.1 S 2010 psig SR 3.3.2.8

c. Tavg-Low Low, P-12 1, 2, 3 1 per loop J SR 3.3.2.1 2 542°F and SR 3.3.2.8 S 545°F North Anna Units 1 and 2 3.3.2-11 Amendments 250/230

                 -  NUCLEAR DESIGN INFORMATION PORTAL-ESFAS Instrumentation 3.3.2 ACTIONS CONDITION                    REQUIRED ACTION           COMPLETION TIME J. One or more channels     J.1      Verify interlock is in   1 hour inoperable.                       required state for existing unit conditi on.

OR J.2.1 Be in MODE 3. 7 hours AND J.2.2 Be in MODE 4. 13 hours SURVEILLANCE REQUIREMENTS - - - - - - - - - - - - - - - - NOTE - - - - - - - - - - - - - - - - Refer to Table 3.3.2-1 to determine which SRs apply for each ESFAS Function. SURVEILLANCE FREQUENCY SR 3.3.2.1 Perform CHANNEL CHECK. 12 hours SR 3.3.2.2 Perform ACTUATION LOGIC TEST. 31 days on a STAGGERED TEST BASIS SR 3.3.2.3 Perform MASTER RELAY TEST. 31 days on a STAGGERED TEST BASIS SR 3.3.2.4 Perform COT 92 days North Anna Units 1 and 2 3.3.2-5 Amendments 231/212

STUDENT GUIDE FOR REACTOR PROTECTION SYSTEM (77 -A) Control and Protection Interlocks (Permissives) 5.1 Objective U 8971 List the following information as it applies to each of the control interlocks (permissives).

• Instruments that supply the signal
• Coincidence and setpoint
• Function(s) provided by the interlock
• Means provided in the control room to determine the status of the interlock 5.1 Content Use graphic SB1211C to explain C's.

5.2 Objective U 8972 List the following information as it applies to each of the protection interlocks (permissives).

• Instruments that supply the signal
• Coincidence and setpoint
• Function(s) provided by the interlock
• Means provided in the control room to determine the status of the interlock 5.2 Content Use graphic SB1211C to explain P's.

REACTOR OPERATOR Page 27 of 49 Revision 2, 05/24/2007

STUDENT GUIDE FOR REACTOR PROTECTION SYSTEM (77 -A) ( 8.9 Content See Improved Technical Specification materials 8.10 Objective U 8988 List the technical specification requirements for the following protection interlocks (permissives) (TS-3.3.2) ..

• Reactor trip P-4
• Pressurizer pressure P-11
• Reactor Coolant System Tavg P-12 8.10 Content See Improved Technical Specification materials.

8.11 Objective U 8990 Explain why at least six minutes must pass prior to attempting to reset the ATWS Mitigation System Actuation Circuit (AM SAC) following a trip from 100% power due to a loss of all feedwater. 8.11 Content

1. AMSAC, by design, is not to be reset until Turbine 1st Stage Pressure has been less than 38% Power for at least 6 minutes.

1.1. The time delay insures AMSAC actuation to limit core voiding if the Rx Protection System fails during a loss of heat sink event. 1.2. If AM SAC has actuated and the operator attempts to reset AMSAC before the 6 minute time delay is complete, then AMSAC will re-actuate when the reset switch is released. 1.3. After the 6 minute time delay, C-20 will clear, AMSAC can be reset and equipment can be realigned. REACTOR OPERATOR Page 45 of 49 Revision 2, 05/24/2007

QUESTIONS REPORT ( for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

44. 059-A1.03 044INEW//L/2/ROINAPSII Which ONE of the following identifies the power level and sequence for securing a Main Feedwater (MFW) pump in accordance with 1-AP-2.2, Fast Load Reduction?

At approximately 55% power, _ _ _ _ _ _ _ ; at approximately 50% power, _ _ _ _ __ A'I open one MFW recirc valve; shutdown one MFW pump. B. shutdown one MFW pump; open one MFW recirc valve. C. close one MFW recirc valve; shutdown one MFW pump. D. shutdown one MFW pump; close one MFW recirc valve. Feedback

a. Correct. the valve is placed hard open to ensure cycling which causes substancial changes in thrust on the shaft do not occur as a result of automatic operation of the valve at flows that are right around setpoint; second part is correct power level per the AP.

b. Incorrect. The order is reversed but plausible since tha candidate who does not have detailed knowledge may conclude that it would make more sense to stop the pump first and then as power (and therefore the demand for feed) is reduced futher to then open the valve.

c. Incorrect. Plausible since candidate who does not have knowledge of the system operation and reasons might conclude that closing a recirc first (thus reducing feed demand) and the shutting down one of the pumps would make sense.

d. Incorrect. Again order is reversed, but would make sense since two pumps are no longer needed one can be shutdown, and with only one running at the given power level recirc wouldn't be needed to prevent pump overheat and there is no longer the concern for the potential of a strong pump to overcome a weak one.

(

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Main Feedwater (MFW) System Ability to predict and/or monitor changes in parameters (to prevent exceeding design limits) associated with operating the MFW controls including: Power level restrictions for operation of MFW pumps and valves. (CFR: 41.5 /45.5) Tier: 2 Group: 1 Importance Rating: 2.7/.9 Technical

Reference:

1-0P-2.1 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: New Associated objective(s):

NUMBER PROCEDURE TITLE REVISION 13 1-AP-2.2 FAST LOAD REDUCTION PAGE 5 of 16 ACTION! EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE: If the fast load reduction is due to loss of 2/3 Main Feedwater Pumps, then the plant may be stabilized at 55% power, if desired, by continuing actions with Step 19.

10. AT APPROXIMATELY 55%

REACTOR POWER, DO THE FOLLOWING: 0 a) Verify two Main Feedwater Pumps - o a) Continue load reduction. WHEN less than 50% IN SERVICE reactor power, THEN GO TO Step 12. 0 b) Verify unisolated MFW Recirc o b) Open valve as required. Valve - OPEN

11. AT LESS THAN OR EQUAL TO 50%

REACTOR POWER, DO THE FOLLOWING: 0 a) Verify two Main Feedwater Pumps - o a) GO TO Step 12. IN SERVICE b) Stop one Main Feedwater Pump, if desired, as follows: 0 1) Place both control switches for standby MFW Pump in PTL 0 2) Close Discharge MOV for MFW Pump to be stopped 0 3) Place both control switches in PTL for MFW Pump to be stopped (STEP 11 CONTINUED ON NEXT PAGE)

STUDENT GUIDE FOR INTEGRATED PLANT OPERATIONS (98) Fast Load Reduction 14.1 Objective U 11591 List the following information associated with 1-AP-2.2, "Fast Load Reduction."

• Purpose of the procedure
• Modes of applicability
• Entry conditions 14.1 Content

1. When the unit is operating at power, situations may arise that require expeditious reduction of reactor power.

1.1. 1-AP-2.2 "Fast Load Reduction" is used to rapidly reduce reactor power in a controlled manner. 1.2. This procedure provides instructions in the event that plant conditions require a continuous load reduction at turbine ramp rates from 2 - 5 % per minute.

2. 1-AP-2.2 is only applicable when the unit is operating in Mode 1.

3. 1-AP-2.2 is entered when a fast load reduction (2 - 5 % per minute) is required as determined by the Unit Supervisor.

14.2 Objective U 5825 Evaluate the following information as it pertains to 1-AP-2.2, "Fast Load Reduction." REACTOR OPERATOR Page 114 of 142 Revision 16,08/20/2008

STUDENT GUIDE FOR INTEGRATED PLANT OPERATIONS (98)

• Operator actions during ramp
• Termination/trip criteria
• Use of alternate power indications during ramp 14.2 Content

1. The 1-AP-2.2 includes the following operator actions:

1.1. Turbine control is transferred to IMP-IN 1.2. Load reduction is initiated in either OPERATOR AUTO or TURBINE MANUAL 1.3. Control Rod Bank D is inserted in Manual until it is either at 200 steps or Tavg starts to decrease 1.4. Operators are directed to control RCS parameters 1.4.1.Additional pressurizer heaters can be energized to maintain RCS pressure 1.4.2.Control rods can be inserted either in AUTO or MANUAL to maintain Tavg within 5 degrees of Tref 1.4.3.Boration of RCS will be required to maintain rods above insertion limits 1.4.4.An attachment is provided to aid in estimating boration flowrates during a fast load reduction 1.4.5.Steam dumps should be monitored for proper operation 1.4.5.1. Dumps may arm at ramp rates close to 5%/minute 1.5. Directions are given for securing equipment as power is reduced. 1.6. If plant conditions no longer require a fast load reduction then the crew is directed to continue the procedure at steps which verify stable plant conditions exist and direct a review of OP-2.2 and associated procedures for TS requirements and completion of long term actions.

2. The ramp should be terminated if the load reduction cannot be controlled 2.1. An attachment gives various criteria for tripping the reactor or turbine, as applicable 2.2. Copies of the attachment are available for distribution to control room personnel 2.2.1.Conservative decision making is emphasized.

2.2.2. The reactor should be tripped and E-O entered if any of the following conditions exist: 2.2.2.1. Tavg > 591 degrees F REACTOR OPERATOR Page 115 of 142 Revision 16,08/20/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

45. 059-K3.03 045IBANKlNAPSlH!3/ROIII Given the following conditions:

Unit 1 is at 70% power.

     *   "8" Main Feedwater (MFW) pump is tagged out.

The "e" MFW pump trips. Which ONE of the following describes the plant response? (Assume no operator action.) A'! MFRVs modulate open, but SG levels continue to decrease. B. MFRVs modulate open and maintain SG levels. C. MFRVs and bypass valves modulate open and maintain SG levels. D. MFRVs and bypass valves fully open, but SG levels continue to decrease. Feedback

a. Correct. Only the MFRVs will modulate since bypasses will be in manual and

( closed at this power level and at 70% power one feed pump will not maintain level.

b. Incorrect. MFRVs will modulate open however as discussed above power level is beyond the capacity of a single feed pump.

c. Incorrect. As noted above this is plausible since the bypass valves have an auto feature however they would normally be in manual at this power level and in any case the single feed pump will not be able to maintain level unless operator action to reduce power is taken.

d. Incorrect. As previously discussed the bypass valve will not open sincethe normal configuration would be manual and closed, plausbile since an auto feature exists and some APs (e.g. AP-4.3 and AP-3) have actions to place the valves in manual which tends to further support them a misconception of them being in auto normally.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Main Feedwater (MFW) System Knowledge of the effect that a 1055 or malfunction of the MFW will have on the following: SIGS (CFR: 41.7 145.6) Tier: 2 Group: 1 Importance Rating: 3.5/3.7 Technical

Reference:

Lesson plan Proposed references to be provided to applicants during examination: None Learning Objective: 6097 Question History: bank Associated objective(s):

NUMBER PROCEDURE TITLE REVISION 4 1-AP-31 LOSS OF MAIN FEEDWATER PAGE 2of7 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 1 ]_ CHECK MFW PUMP STATUS: o a) Reactor Power - GREATER THAN o a) IF at least one MFW Pump is running, THEN 70% GO TO Step 2.IF NO MFW Pumps are running, THEN GO TO 1-E-O, REACTOR TRIP OR SAFETY INJECTION. o b) Two MFW Pumps - RUNNING o b) I.E a second MFW Pump cannot be immediately started, THEN GO TO 1-E-O, REACTOR TRIP OR SAFETY INJECTION. 2 ]_ CHECK MFW SUCTION o Start an additional Condensate Pump. PRESSURE-AT LEAST 300 PSIG

3. CHECK MFW PUMP ISOLATION:

o a) Any MFW Pump - TRIPPED o a) GO TO Step 4. o b) Tripped MFW Pump(s) Discharge b) Isolate tripped pump(s) discharge: MOV-CLOSED o 1) Place one control switch of tripped pump in PTL. o 2) Close associated pump discharge MOV. o 3) IF discharge cannot be closed, THEN locally check pump rotation. IF reverse rotating, THEN de-energize and locally close pump discharge MOV.

STUDENT GUIDE FOR STEAM GENERATOR LEVEL CONTROL AND PROTECTION SYSTEM (26-C) Bypass Valve Control 2.1 Objective U 8816 List the following information as it applies to the feedwater bypass valves.

• Approximate range of power levels during which the valves are used to regulate feedwater flow
• Instruments which supply input signals to the valves' control circuits
• Protection signals which result in automatic closure of the valves
• Position to which the valves fail on loss of instrument air or power
• Position of the valves as the N-44 feed-forward signal varies from 0% to 25%

2.1 Content

1. The bypass feedwater regulating valve are used to control feedwater flow below 25% power.

1.1. The transition from bypass valve control to main feedwater regulating valve (FRV) control begins during unit startup at approximately 15% turbine power. 1.2. The transition from main feedwater regulating valve control to bypass control begins when < 25% power during unit shutdown.

2. The instruments which supply input signals to the bypass valves' control circuits are:

2.1. Selected turbine first stage pressure channel (III or IV) 2.2. Narrow range level channel III for associated SG 2.3. Nuclear Instrument power range channel N-44

3. The Protection signals which result in automatic closure of the bypass valves 3.1. Safety injection (SI) signal (Train A or Train 8) 3.2. Hi-Hi steam generator water level (P-14) (Train A or Train 8)

REACTOR OPERATOR Page 8 of 26 Revision 0, 10/01/2006

STUDENT GUIDE FOR STEAM GENERATOR LEVEL CONTROL AND PROTECTION SYSTEM (26-C) Main Feedwater Regulating Valve Control 3.1 Objective U 8819 List the following information as it applies to the main feedwater regulating valves.

• Approximate range of power levels during which the valves are used to regulate feedwater flow (SOER-84-4)
• Instruments which supply input signals to the valves' control circuits
• Protection signals which result in automatic closure of the valves
• Position to which the valves fail on loss of instrument air or power
• Position to which a valve fails if the valve's position feedback arm falls off 3.1 Content Approximate range of power levels during which the valves are used to regulate feedwater flow 1.1. The main feedwater regulating valves (FRVs) are utilized to control feedwater flow at elevated turbine power levels.

1.2. Transfer of control from the bypass feedwater regulating valves to the main FRVs is begun at approximately 15% and completed by approximately 25%.

2. Instruments which supply input signals to the valves' control circuits 2.1. Selected turbine first stage pressure channel (III or IV) 2.2. Narrow range level channel III for associated SG 2.3. Selected feedwater flow channel (III or IV) for associated SG 2.4. Selected steam flow and steam pressure channel (III or IV) for associated SG

3. Protection signals which result in automatic closure of the valves REACTOR OPERATOR Page 11 of 26 Revision 0, 10101/2006

STUDENT GUIDE FOR MAIN FEEDWATER SYSTEM (26-A) ( Major Components 2.1 Objective U 1835 List the following information associated with the main feedwater pumps.

• Major electrical bus supplying power
• Pump type
• Source of water for the suction of the pumps
• Suction relief valve setpoint 2.1 Content

1. The motors for the main feedwater pumps are powered from the 4160-volt station service busses.

(

2. Each main feedwater pump is a horizontally mounted, single- stage, double suction, vertically split centrifugal pump.

2.1. Each pump is rated 16,250 gpm and is driven by two 4500 HP motors mounted in tandem.

3. Three main feedwater pumps provide the driving force necessary to pump water from the Main Condensate System to the steam generators.

3.1. Normally, two feedwater pumps are running and one pump is maintained in a standby status. 3.2. Control of the feedwater pumps is from the MCR.

4. A relief valve is provided on the suction side of the pump to prevent over-pressurization of the pump and associated piping in the event the pump is isolated.

4.1. The relief valve discharges to the floor of the turbine building basement and relieves at a pressure of 665 psig. REACTOR OPERATOR Page 6 of 33 Revision 3, 10/09/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) 21.12 Content

1. The purpose of AP-31 is to provide guidance in response to a loss of main feedwater in mode 1 or 2.

2. AP-31 is entered when any of the following conditions exist:

2.1. Loss of 1 or 2 main feedwater pumps 2.2. F-A4, MAIN FD PPS DISCH HDR LO PRESS, lit. 2.3. F-A5, MAIN FD PP 1A-1B-1C AUTO TRIP, lit. 2.4. F-B5, MAIN FD PPS LO DIFF PRESS, lit. 2.5 Inadequate main feedwater pump suction pressure 2.B. Inadequate feed flow to more than one S/G as indicated any of the following annunciators 2.B.1.F-C1/C2/C3, STM GEN 1A11B/1C LO LEVEL CH I-II 2.B.2.F-D1/D2/D3, STM GEN 1A11B/1C FW<STM FLOWCH III-IV 2.B.3.F-F1/F2/F3, SG 1A11B/1C LEVEL ERROR

3. Immediate operator actions contained in AP-31 are:

3.1. Check MFW pump status to determine if an immediate reactor trip is required: 3.1.1.lf reactor power is greater than 70% with only one MFW pump running and a second MFW pump cannot be immediately started, the crew enters 1-E-0 to trip the unit. 3.1.2.lf reactor power is less than or equal to 70% and no MFW pumps are running, the crew enters 1-E-0 to trip the unit. 3.2. If a trip is not required then determine if MFW pump suction pressure is at least 300 psig 3.2.1.lf not, start an additional condensate pump. 21.13 Objective U 14377 Explain the purpose of the following high-level action steps associated with 1-AP-31, "Loss of Main Feedwater." REACTOR OPERATOR Page 118 of 158 Revision 30, 11/0B/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91)

• Check for stuck open check valve on unisolated tripped main feedwater pump
• Evaluate reducing turbine load to less than 55% power
• Verify acceptable main feedwater pump performance 21.13 Content If any tripped MFW pump discharge MOV is not closed, then closing the discharge MOV isolates the tripped pump discharge check valve (in case it is stuck open).

If only one MFW pump is running and reactor power is greater than 55%, power must be reduced to less than 55% to ensure adequate MFW flow capability to maintain S/G levels without experiencing pump runout. If MFW motor amps are greater than 550 amps on either motor, or annunciator F-B5, MAIN FD PPS LO DIFF PRESS is lit, the running MFW pump may be experiencing runout conditions and thus be in jeopardy. 1.1. Turbine load must be reduced to reduce the feed flow requirements and protect the running MFW pump. 21.14 Objective U 11421 List the following information associated with 1-AP-38, "Excessive Load Increase."

• Purpose of the procedure
• Modes of applicability
• Entry conditions
• Immediate operator actions REACTOR OPERATOR Page 119 of 158 Revision 30, 11/06/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

46. 061-Kl.07 046/BANKINAPS/L/2IROIII With AFW in service to supply SG feed water, ECST level suddenly begins to decrease rapidly due to a rupture in the tank.

Which ONE of the following identifies the preferred source of alternate makeup water used to supply AFW pump suction? A'! Fire Protection System using motor-driven pump 1-FP-P-1. B. Standby 300,OOO-galion condensate storage tank. C. In-service 300,OOO-galion condensate storage tank. D. Fire Protection System using diesel-driven pump 1-FP-P-2. Feedback

a. Correct. The fire protection system is the source and the motor driven pump is preferred by AP-22.5 since it takes suction on the lake.

b. Incorrect. This is a source but with the ECST not intact AP-22.5 bypasses this option, the candidate who does not have detailed knowledge ofthe procedure may conclude that this would be the first choice and sellect this distractor.

c. Incorrect. This is a source but with the ECST not intact AP-22.5 bypasses this option, the candidate who does not have detailed knowledge ofthe procedure may conclude that this would be the first choice and sellect this distractor.

d. Incorrect. Based on the conditions given the fire protection system is the source, the diesel-driven pump is thus plausible however the diesel-driven pump is the least preferred because of the water chemistry of the service water reservoir

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Auxiliary 1 Emergency Feedwater (AFW) System K1 Knowledge of the physical connections and/or cause effect relationships between the AFW and the following systems: Emergency water source (CFR: 41.2 to 41.9 145.7 to 45.8) Tier: 2 Group: 1 Importance Rating: 3.6/3.8 Technical

Reference:

1-AP-22.5 Proposed references to be provided to applicants during examination: None Learning Objective: 6098 Question History: bank additional info:

NUMBER PROCEDURE TITLE REVISION 6 1-AP-22.5 LOSS OF EMERGENCY CONDENSATE STORAGE TANK 1-CN-TK-1 PAGE 2 of 13 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. CHECK STATUS OF ECST: 0 GO TO Step 4.

0

• ECST - INTACT 0
• Normal makeup supply to ECST

       -AVAILABLE

2. MAKE UP TO ECST USING 1-0P-31.2, STEAM GENERATOR AUXILIARY FEEDWATER SYSTEM

3. RETURN TO PROCEDURE AND STEP IN EFFECT

4. STOP AFW PUMPS:

0 a) Reset both trains of SI 0 b) Reset AMSAC c) Place Motor-Driven AFW Pumps in PTL: 0

• 1-FW-P-3A 0
• 1-FW-P-3B d) Manually close Steam Supply Valves to Turbine-Driven AFW Pump (Terry Turbine):

0

• 1-MS-TV-111A 0
• 1-MS-TV-111B

NUMBER PROCEDURE TITLE REVISION 6 1-AP-22.5 LOSS OF EMERGENCY CONDENSATE STORAGE TANK 1-CN-TK-1 PAGE 3 of 13 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE: The AFW lineup drawings of ATTACHMENT 3 should be retained in the Control Room to provide Control Room personnel with a graphical representation of the AFW lineup.

5. DO ATTACHMENT 3 TO ALIGN AFW PUMPS TO ALTERNATE SUCTION HEADER CAUTION: Sharing/balancing the use of Fire Protection Systems between fire fighting and makeup capability must be considered.

NOTE:

• Because of the chemistry of the Service Water Reservoir, the Fire Main water from the lake is the preferred source of alternate makeup water.
• Because of the poor quality of the alternate makeup sources, adequate time should be scheduled to allow cleanup of the Steam Generators after the alternate source is no longer needed. The Chemistry Department should be contacted for guidance.
• 1-FP-P-2, Diesel-Driven Fire Pump, takes suction on the Service Water Reservoir.

6. DETERMINE IF FIRE PROTECTION D GO TO Step 11 .

SYSTEM SHOULD BE USED TO SUPPLY AFW PUMP SUCTION

NUMBER PROCEDURE TITLE REVISION 6 1-AP-22.5 LOSS OF EMERGENCY CONDENSATE STORAGE TANK 1-CN-TK-1 PAGE 4 of 13 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

7. START 1-FP-P-1, MOTOR-DRIVEN Do the following:

FIRE PUMP a) Locally start either of the Warehouse 5 Fire Pumps: o . 1-FP-P-10, Diesel-Driven Warehouse 5 Fire Pump OR o . 1-FP-P-11, Motor-Driven Warehouse 5 Fire Pump o b) Open 1-FP-246, Cross-tie with Warehouse 5 Fire Pumps (Post Indicator Valve located in the SE corner of the yard). o !E Warehouse 5 Fire Pumps are not available, THEN start 1-FP-P-2, Diesel-Driven Fire Pump.

8. LOCALLY UNLOCK AND OPEN 1-FP-93, UNIT 1 AUX FEED WTR PUMPS FIRE WATER MAKEUP ISOL VV (POST INDICATOR VALVE)

9. LOCALLY UNLOCK AND OPEN 1-FW-175, FIRE MAIN SUPPLY HEADER TO AFW PUMPS ISOLATION VALVE (LOCATED BELOW CARD READER)

10. GO TO STEP 12

STUDENT GUIDE FOR AUXILIARY FEEDWATER SYSTEM (26-8) 2.25 Objective U 5971 Explain the following concepts associated with the auxiliary feedwater pump alternate suction sources.

• Alternate suction source which is normally preferred
• Why one alternate source is preferred over the other
• Function of tell-tale drain valves on the alternate suction lines
• Consequences if the alternate suction source is placed in service without closing the tell-tale drain valves 2.25 Content

                               --_-l AUXIUARY FEEDWATER SYSTEM ALT. SUCTION

1. The fire main from the lake is the preferred alternate source of water to the AFW pumps.

REACTOR OPERATOR Page 55 of 55 Revision 4,07/16/2008

STUDENT GUIDE FOR AUXILIARY FEEDWATER SYSTEM (26-8)

2. Fire main from the lake is the preferred alternate source of water to the AFW pumps rather than the Service Water System or fire main from the service water reservoir because the chemical additives in SW are undesirable in the steam generators.

3. The telltale drain valves on the alternate suction lines ensure leakage through either of the manual isolation valves from FP or SW doesn't contaminate the ECST.

4. If the AFW pump alternate suction header were to be placed in service with the telltale drains open, flooding of the AFWPH would result.

2.26 Objective U 5978 Explain the following concepts associated with flushing the service water and fire water piping that can be used to supply the Auxiliary Feedwater System.

• Purpose
• Frequency in which these lines are required to be flushed
• Types of contamination expected to be flushed 2.26 Content

1. The purpose of flushing the AFW System alternate suction lines is to ensure they are capable of supplying water flow free of debris if needed.

2. The AFW alternate suction lines are flushed every 36 months.

3. The AFW alternate suction lines are flushed to check for sludge, Asiatic clams, or shell debris.

REACTOR OPERATOR Page 56 of 56 Revision 4, 07/16/2008

QUESTIONS REPORT ( for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

47. 061-K6.02 047INEWIIH/3/ROINAPS/S120/200S1 Given the following conditions:

Unit 1 is at 100% power.

• AFW pump 1-FW-P-3A is tagged out for Maintenance.

A loss of offsite power occurs, and all equipment functions as designed EXCEPT the 1J EDG locked out. Based on these plant conditions, which ONE of the following identifies the realignment that will provide flow to all 3 SGs AND also allows the BOP the ability to control AFW flow rate to each SG from the control board? A. Align 1-FW-P-2 to the MOV header. B~ Align 1-FW-P-2 to the HCV header. C. Align 1-FW-P-3B to the MOV header. D. Align 1-FW-P-3B to the HCV header. Feedback

a. Incorrect. The MOV header has no power precluding remote operation from the control room.

b. Correct. 1-FW-P-2 (terry turbine) is the only pump running and since only the HCVs have power they are the only valves that can be controlled remotely.

c. Incorrect. Since 1J EDG is locked out this pump is unavailable; plausible if candidate is unaware of power supply.

d. Incorrect. Plausible first part is incorrect as described in Distractor C; second part is the correct header alignment.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Auxiliary / Emergency Feedwater (AFW) System Knowledge of the effect of a loss or malfunction of the following will have on the AFW components: Pumps (CFR: 41.7/45.7) Tier: 2 Group: 1 Importance Rating: 2.6/2.7 Technical

Reference:

Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info: (

( NUMBER PROCEDURE TITLE REVISION 5 1-AP-22.4 LOSS OF BOTH MOTOR-DRIVEN AFW PUMPS PAGE 2 of 8 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION:* When ECST level decreases to 40%, then 1-AP-22.5, LOSS OF EMERGENCY CONDENSATE STORAGE TANK 1-CN-TK-1, should be initiated to provide an alternate water source to the AFW Pumps.

• To prevent heating of the ECST above 120 0 F, the AFW Pumps should not be run on recirc for extended periods of time.
• To prevent possible degradation to the AFW Pump, the amount of time spent on minimum recirc flow should be minimized.
• To prevent lifting relief valve 1-FW-RV-1 00 when reducing feed flow, any MOV or HCV supplied by the Turbine-Driven AFW Pump should be slowly throttled.
• To prevent lifting relief valve 1-FW-RV-1 00, a discharge flowpath must be available to feed an SG from the Turbine-Driven AFW Pump.

NOTE:

• Normal PRZR spray should be isolated from any RCP that is stopped.
• The C RCP provides the best PRZR spray capability. The A RCP also provides PRZR spray capability.
• If AFW Pumps are lost due to loss of control from the Control Room, then evaluate using 1-AP-20, OPERATION FROM THE AUXILIARY SHUTDOWN PANEL, to start the affected AFW Pumps from the Auxiliary Shutdown Panel.

1. CHECK MAIN FEEDWATER - IN Do the following:

SERVICE D a) Stop all but one RCP. D b) Initiate attempts to restore Main Feedwater.

NUMBER PROCEDURE TITLE REVISION 5 1-AP-22.4 LOSS OF BOTH MOTOR-DRIVEN AFW PUMPS PAGE 3 of 8 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

2. VERIFY TURBINE-DRIVEN AFW Manually start Turbine-Driven AFW Pump:

PUMP - RUNNING o a) Open 1-FW-MOV-100D, TURBINE DRIVEN AFW PUMP TO A SG. b) Put Steam Supply Valves for Turbine Driven AFW Pump in OPEN: o . 1-MS-TV-111A o . 1-MS-TV-111 B

3. CHECK ECST LEVEL - GREATER o Initiate 1-AP-22.5, LOSS OF EMERGENCY THAN 40% CONDENSATE STORAGE TANK 1-CN-TK-1.

NOTE:

• AFW HCVs fail open on loss of semi-vital bus 1A.
• The AFW lineup drawings of ATTACHMENT 3 and ATTACHMENT 4 should be retained in the Control Room to provide Control Room personnel with a graphical representation of the AFW lineup.

4. PERFORM ATTACHMENT 4 TO o Perform ATTACHMENT 3 to align MOV Header for ALIGN HCV HEADER FOR FEEDING feeding all SGs.

ALL SGs o WHEN ATTACHMENT 3 is complete, THEN GO TO Step 7.

• 5. CONTROL AFW FLOW TO MAINTAIN SG NARROW RANGE LEVELS BETWEEN 23% AND 50% USING:

o . 1-FW-HCV-100A for A SG o . 1-FW-HCV-100B for B SG o . 1-FW-HCV-100C for C SG

6. GO TO STEP 8

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) 21.10 Objective U11417 List the following information associated with 1-AP-22.4, "Loss of 80th Motor-Driven AFW Pumps" (SOER-86-1 ).

• Purpose of the procedure
• Modes of applicability
• Entry conditions 21.10 Content

1. 1-AP-22.4 provides guidance to respond to a loss of both motor-driven AFW pumps.

2. This procedure is applicable in modes 1 through 3, and mode 4 when steam generator is relied upon for heat removal.

3. 1-AP-22.4 is entered when AFW flow is required to the 8 and C steam generators and both motor-driven AFW pumps are inoperable.

21.11 Objective U 11418 Explain the purpose of the following high-level action steps associated with 1-AP-22.4, "Loss of 80th Motor-Driven AFW Pumps."

• Verify that main feedwater is in service.
• Check auxiliary feedwater pump status.
• Align auxiliary feedwater for feeding all steam generators.

REACTOR OPERATOR Page 116 of 158 Revision 30, 11/06/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) 21.11 Content

1. If main feedwater is not in service, all but one RCP is stopped and attempts to restore main feedwater are initiated.

1.1. Stopping the RCPs helps reduce the heat input into the RCS.

2. The turbine-driven AFW pump is started (if it's not running) to prepare for aligning it to feed all S/Gs.

2.1. 1-FW-MOV-100D is opened prior to starting to ensure a flow path and prevent lifting the discharge relief valve.

1. Either the HCV or the MOV header is selected for alignment to feed the steam generators.

1.1. AFW header selection may be dependent on emergency bus power availability. 1.1.1. The AFW HCVs will fail open on a loss of semi-vital bus 1A (loss of 1H emergency bus). 1.1.2. The AFW MOVs will not have power (fail "as is") on a loss of 1J emergency bus. 3.2. AFW flow is controlled to maintain S/G N/R levels between 23% and 50% until normal AFW alignment can be established. 3.2.1.0nce normal alignment is possible, S/G N/R levels are raised to between 45% and 50% which allows the re-alignment to take place without jeopardizing the available heat sink. 21.12 Objective U 14561 List the following information associated with 1-AP-31, "Loss of Main Feedwater."

• Purpose of the procedure
• Modes of applicability
• Entry conditions
• Immediate operator actions REACTOR OPERATOR Page 117 of 158 Revision 30, 11/06/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

48. 062-AAl.07 048INEWIIH/3IROIII The NORMAL source of cooling water for charging pumps is the _ _ _ _ _ _ ; in the event of a loss of the normal source, alternate cooling is aligned from the _ _ _ _ _ __

A. Service Water System; Component Cooling System 8:0" Service Water System; Fire Protection System C. Component Cooling System; PG Water System D. Component Cooling System; Fire Protection System Feedback

a. Incorrect. First part is correct. Second part is incorrect but plausible since CC is required by Tech Specs and cools many different loads, candidate who does not have detailed systems knowledge may conclude that CC would be logical and default to this distractor.

b. Correct. First part is correct; second part is also correct as O-AP-12 provides the option of using fire system or PG system to align backup cooling. Incorrect.

c. First part incorrect as discussed in Distractor a; second part is correct as 0-AP-12 provides the option of using fire system or PG system to align backup cooling.

d. First part incorrect as discussed in Distractor a; second part is correct as 0-AP-12 provides the option of using fire system or PG system to align backup cooling.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Loss of Nuclear Service Water Ability to operate and / or monitor the following as they apply to the Loss of Nuclear Service Water (SWS): Flow rates to the components and systems that are serviced by the SWS; interactions among the components (CFR 41.7 / 45.5 / 45.6) Tier: 1 Group: 1 Importance Rating: 2.9/3.0 Technical

Reference:

O-AP-12 Proposed references to be provided to applicants during examination: None ~ Learning Objective: Question History: new additional info: (

NUMBER PROCEDURE TITLE REVISION 33 O-AP-12 LOSS OF SERVICE WATER PAGE 12 of 15 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION: To keep Charging in service, the Charging Pumps should be cycled to prevent overheating until a cooling source is restored. CAUTION: Sharing / balancing the use of Fire Protection Systems between fire fighting and makeup capability must be considered.

17. ALIGN ALTERNATE COOLING TO CHARGING PUMPS USING EITHER OF THE FOLLOWING:

o

• Fire Protection System - AVAILABLE
• Do the following, as applicable:

o

• Perform ATTACHMENT 3, Cooling o
• Isolate the ruptured portion of the Fire Charging Pumps With Fire Protection Header.

Protection o

• Align Fire Protection using ATTACHMENT 3, Cooling Charging Pumps With Fire Protection.

o

• Align a fire truck with suction from lake to an intact hose house.

o

• STUDENT GUIDE FOR CHEMICAL AND VOLUME CONTROL SYSTEM (41) 5.1 Content 5.2 Objective U 348 List the following information associated with the charging pumps.
• Source of cooling supplied to the pumps and speed increasers
• Start limitations for the pump motor (1-0P-8.1)
• Maximum pump suction temperature (1-0P-8.1)
• Power supply to each charging pump
• Means available in the control room to determine abnormal alignment of the power supply breakers 5.2 Content

1. Normally, lubricating oil, and speed increaser oil are all cooled by the Service Water System.

2. The following charging pump motor starting limits must be observed (1-0P-8.1):

2.1. Two consecutive starts with a cold motor. 2.2. One consecutive start with a hot motor. 2.3. Subsequent starts with motor running between starts, 15 minutes apart. 2.4. Subsequent starts with motor idle between starts, 60 minutes apart.

3. The maximum charging pump suction temperature allowed by 1-0P-8.1 is 130°F, to ensure NPSH is maintained.

3.1. Since there is no temperature indication for this in the control room we assume VCT temperature is equivalent to the charging pump suction.

4. The charging pumps are powered from the 4160-volt emergency buses as follows:

4.1. CH-P-1A from bus 1H 4.2. CH-P-18 from bus 1J REACTOR OPERATOR Page 53 of 86 Revision 10, 08/20/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91)

5. Conditions that would require the unit to be shutdown 5.1. If at least one SW supply header is not intact, the operators should trip both reactors.

5.2. If at least one SW supply header is intact and being supplied by a service water pump, then plant operation may continue. 5.3. The operator should also continuously monitor RCP temperature to ensure that the temperature limits are not exceeded. 5.3.1.The RCP temperatures are normally monitored using the plant computer 5.3.1.1. RCP motor bearing::;; 195°F 5.3.1.2. RCP pump bearing::;; 225°F 5.3.1.3. RCP stator::;; 300°F 5.4. If RCP temperature limits are exceeded the affected unit should be tripped first and then the affected RCP.

6. Alternate cooling supplies to critical service water loads 6.1. Critical service water loads identified in AP-12 include:

6.1.1.Control room chillers 6.1.2.Component cooling water heat exchangers 6.1.3.lnstrument air compressors 6.1.4.Charging pumps 6.2. Most critical Service Water System loads can be supplied from either supply header. 6.2.1.lf one header is unavailable, the other header can usually provide sufficient cooling. 6.3. If no service water is available, then alternate cooling water sources should be aligned where possible. 6.3.1.Control room chillers: 6.3.1.1. If service water is unavailable, bearing cooling water can be aligned as an alternate cooling water source. 6.3.2.Charging pumps: REACTOR OPERATOR Page 137 of 158 Revision 30, 11/06/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) 6.3.2.1. If service water is unavailable Primary Grade Water or Fire Protection System water can be aligned as an alternate cooling water source. 6.3.3.To minimize the Component Cooling Water System heat load, common loads should be secured. 22.9 Objective U 11660 List the following information associated with 1-AP-18, "Increasing Containment Pressure."

• Purpose of the procedure
• Modes of applicability
• Entry conditions
• How the desired containment partial pressure is determined
• Possible causes of containment pressure increase 22.9 Content

1. 1-AP-18, Increasing Containment Pressure, provides guidance to the operator when an unexpected increase of containment pressure occurs.

2. At North Anna, a vacuum is maintained in the containment structures whenever the RCS average temperature is greater than 200°F: therefore, this procedure is applicable in modes 1, 2, 3, and 4.

3. 1-AP-18 is entered when containment partial pressure is;:;: .25 psi above the containment partial pressure setpoint.

4. The required vacuum to be maintained is determined based on the temperature of the Service Water System (refer to TS figure 3.6.1).

( REACTOR OPERATOR Page 138 of 158 Revision 30, 11/06/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

49. 062-Kl.04 049IBANKINAPSIHI2IRO///

Given the following conditions:

• Unit 1 is at 50% power.
• 15F3, "F" Transfer Bus Supply to 1H Bus, is tagged out for breaker maintenance.
• The 1H 4160-Volt Emergency bus is powered from the 1B Station Service Bus.

While checking neutral bus volts, the OATe inadvertently takes breaker 15B2, Station Service Transformer Supply to 1B Station Service Bus, to TRIP. As a result of this action, final status of the 1B Station Service Bus will be _ _ _ _ " and the final status of the 1H 4160-Volt Emergency bus will be _ _ __ A'! de-energized; energized B. energized; energized C. energized; de-energized D. de-energized; de-energized Feedback

a. Correct. The auto transfer to RSST will not occur since 15B2 was manually opened; second part is also correct ,bus UV will open all required breakers and the 1H EDG will pick up the Emergency bus.

b. Incorrect. Plausible since there is an auto transfer feature to RSSTs however it will not occur if the breaker is manually opened.

c. Incorrect. First part incorrect but plausible as discussed above; similarly since this is an abnormal configuration the candidate who does not have detailed systems knowledge may conclude that the logic necessary for breaker interlock and edg start and load are met and thus conclude that this distactor is correct.

d. Incorrect. First part is correct as explained in distractor a; second part incorrect as discussed in distractor c.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes AC. Electrical Distribution Knowledge of the physical connections and/or causeeffect relationships between the ac distribution system and the following systems: Off-site power sources (CFR: 41.2 to 41.9) Tier: 2 Group: 1 Importance Rating: 3.7/4.2 Technical

Reference:

Proposed references to be provided to applicants during examination: None Learning Objective: 3820 Question History: bank additional info:

                                /""""'"

STUDEN". ,dUIDE FOR BASIC ELECTRICAL DISTRIBUTION SYSTEM (18) Figure 2 e} 8RO\WI

                                                                                                - F'RA;';SFERSlf.>
                                                 ~:~IJ::-~,_,
                                             '1- 'lfJ ~~ Wi'-~jt
                                           ';~"I ctF I~=t~
                                             )
                                           ~~~
                                                    )     )

For Information Only L::J l1li ~ Revised 5/25/95 NORTH ANNA POWER STATION ELECTRICAL POWER DISTRIBUTION

STUDENT GUIDE FOR BASIC ELECTRICAL DISTRIBUTION SYSTEM (18) Top}c2.12 4t60c~V()ltBU$iFeeder Breaker AyfomaticClosure Signals 2.12 Objective U 7384 List the conditions that will cause the following breakers to close automatically.

• 15A 1, B1, and C 1
• 15G10 2.12 Content Refer to 11715-FE-21 G and 21 H.

1. 15A 1 (15B1, 15C1) station service bus alternate feeder breaker will close automatically if all of the following conditions exist:

1.1. 15A 1 (15B1, 15C1) control switch in the AFTER TRIP position. 1.2. 15A2 (15B2, 15C2) open with control switch in the AFTER CLOSE position. 1.3. No 86 lockout on 15A2 (15B2, 15C2). 1.4. No A (B, C) RSST pilot wire differential. 1.5. No A (B, C) RSST lockout. 1.6. Either feeder breaker for A (B, C) RSST closed. (A.)-, (, \ 1.7. No undervoltage upstream of A (B, C) RSST. d-e~~~e, 1.8. No 86 lockout on 15A 1 (15B1, 15C1). Refer to 11715-FE-21K.

2. 15G10 1G-2G bus crosstie breaker will close automatically if all of the following conditions exist:

2.1. 15G10 control switch in the AFTER TRIP position. 2.2. NORMAL-DEFEAT switch in the NORMAL position. 2.3. 15G1 (25G1) in the AFTER CLOSE position, 25G1 (15G1) open, and bus 2G (1G) under-voltage condition. 2.4. No 86 lockout on either 15G 1 or 25G 1 . REACTOR OPERATOR Page 27 of 46 Revision 7, 10109/2008

STUDENT GUIDE FOR EMERGENCY DIESEL GENERATOR ELECTRICAL & CONTROL (55-C) Diesel Control Circuit Topic 3. fAutt>. StaftSvvitchAlign l1lents 3.1 Objective U 6298 Identify the conditions that will automatically start a diesel generator when each of the following switch alignments exist (SOER-83-1).

• Mode selector switch in AUTO REMOTE
• Mode selector switch in MAN REMOTE
• Mode selector switch in MAN LOCAL
• CRE switch in EMERG
• Control room isolation switch in ISOL 3.1 Content

1. With the mode selector switch in the AUTO REMOTE position the EDG starts automatically if the start circuits receive any of the following:

1.1. Safety injection signal 1.2. 4 kV bus 1H degraded voltage signal, 1.3. 4 kV bus 1H undervoltage signal, or 1.4. Improper 4 kV bus 1H breaker lineup signal.

2. In the MANUAL REMOTE position all emergency starts are functional.

3. In the MAUAL LOCAL position there are no auto starts available.

4. All emergency starts will function when the CRE switch is in EMERG.

5. The control room isolation switch has no affect on auto-start signals.

REACTOR OPERATOR Page 12 of 12 Revision 2, 11/20/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

50. 063-A3.01 050INEWIIH/3/ROINAPSII A Loss of All AC has just occurred on Unit 1.

Five minutes have elapsed, and a source of power has not yet been restored. The operator should expect the voltage on all four (4) of the 125-Volt DC Busses to be _ _ _ _ __ their pre-event values. Over time, vital DC bus 1-1 voltage would be expected to drop _ _ _ _ __ as compared to vital DC bus 1-11 voltage. A. approximately the same as ; at approximately the same rate B. approximately the same as ; at a slower rate C. approximately 10 volts l.ower than; at approximately the same rate D~ approximately 10 volts lower than; at a slower rate Feedback

a. Incorrect. Plausible since it would not be illogical to conclude that the battery would maintain voltage about the same; second part also incorrect but plausible since the candidate who doesn't have detailed systems knowledge may

( conclude that there is no difference between busses.

b. Incorrect. Plausible as discussed above; second part is correct, DC busses I-II and I-IV carry turbine DC oil pumps which will deplete their respective batteries at a faster rate as compared to DC busses I-I and I-III.

c. Incorrect. First part is correct, initially when the charger is lost and battery picks up load it will drop roughly 6 volts as seen on the meters on the vertical board; second part incorrect but plausible as discussed in Distractor a.

d. Correct. As noted above bus voltage will drop to approximately 125 VDC (from the initial value of approximately 130 vdc when the charger was carrying the bus); second part is also correct since bus I-I does not have turbine oil pumps on it like bus I-II its battery will deplete at a slower rate.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes D.C. Electrical Distribution Ability to monitor automatic operation of the DC electrical system, including: Meters, annunciators, dials, recorders, and indicating lights (CFR: 41.7 /45.5) Tier: 2 Group: 1 Importance Rating: 2.7/3.1 Technical

Reference:

Proposed references to be provided to applicants during examination: None Learning Objective: Question History: additional info:

STUDENT GUIDE FOR VITAL AND EMERGENCY ELECTRICAL DISTRIBUTION SYSTEM (35) 1.2. II and IV are located in the ESGR (II and IV on the floor)

2. There are 60 cells per DC bus.

3. The designed amperage and time-duration ratings of the batteries supplying the DC busses is 2 hours

4. The minimum or final cell voltage for the station batteries is 1.75 volts.

4.1. Total battery minimum voltage is 105 VDC.

5. The typical terminal voltage for each battery cell ranges from 2.17 to 2.25 volts.

6. The major loads on each DC vital bus are:

6.1. Vital DC bus H. 6.1.1.Associated vital AC bus inverter. 6.1.2.Hotel-train breaker control power. 6.1.3.Main Control Board DC SOV Panel, 1-EP-CB-26A 6.1.4."C" Station Service 4160 breaker control power. 6.2. Vital DC bus 1-11. 6.2.1.Associated vital AC bus inverter. 6.2.2.1-TM-P-5, Emergency Turbine Oil Pump 6.2.3."B" Station Service 4160 breaker control power. 6.3. Vital DC bus HII. 6.3.1.Associated vital AC bus inverter. 6.3.2.Computer Inverter 6.3.3.Juliet-train breaker control power. 6.3.4.Main Control Board DC SOV Panel, 1-EP-CB-26B 6.3.5."A" Station Service 4160 breaker control power. 6.4. Vital DC bus 1-IV. REACTOR OPERATOR Page 7 of 36 Revision 4, 07/31/2008

STUDENT GUIDE FOR VITAL AND EMERGENCY ELECTRICAL DISTRIBUTION SYSTEM (35) 6.4.1 .Associated vital AC bus inverter 6.4.2.1-GM-P-8, Air-Side Seal Oil Backup Pump.

7. The following indications are available to the control room operator for determining an abnormality in the battery room:

7.1. Smoke detectors are located in the battery rooms. 7.1.1.ln the event of a fire, annunciator D-C8, SMOKE DET SYS SMOKE INDICATION TROUBLE will alarm. 7.1.2. The alarming battery room can be identified by observing the SMOKE or TROUBLE alarm lights for the battery rooms, which are located at the bottom of the respective unit's fire protection panel. 7.2. A low ventilation flow would be identified by annunciator D-G6, BATTERY RM EXHAUST FAN NO FLOW. 7.2.1.The affected battery room can be identified by observing the red low-flow lights located at the bottom of the respective unit's ventilation panel. Topic 1.5 Response**.of .*OCSUS*.*.tol.t)S$ .dfl3atteryCharg~r (SER-3-99) 1.5 Objective U 3280 Describe the response of the station DC bus voltage during an extended period of operation without a battery charger in service (SER-3-99). 1.5 Content

1. Without a battery charger in service the battery will initially supply all loads with only a very slow drop in voltage.

REACTOR OPERATOR Page 8 of 36 Revision 4, 07/31/2008

STUDENT GUIDE FOR VITAL AND EMERGENCY ELECTRICAL DISTRIBUTION SYSTEM (3S) 1.1. However during an extended period of time without a battery charger, (for example: during the loss of power to the 480-volt bus that supplies the charger) voltage will drop faster as discharge time increases. 1.2. This is because the limiting factor for battery capacity is individual cell voltage. 1.3. As total battery voltage drops individual cell reversal can occur on a weaker cell. 1.4. Cell reversal is a condition where the reversed cell goes from being a contributor to battery output to being a load on the battery. 1.5. This additional load on the battery, combined with the fact that fewer good battery cells are now actually supplying the load, causes the total battery voltage to drop even faster than before. 1.6. The further battery voltage drops, the more chances that another cell will reverse, which causes battery voltage to drop even faster ... etc. Tqpi6<1 .. 6120-vOllACStatic*.lnverters 1.6 Objective U 5511 List the following information associated with the 120-volt AC static inverters.

• Purpose
• Color designations associated with each vital AC bus
• Source of power supplied to each inverter
• Normal output voltage
• Kilovolt-ampere rating for vital bus 1-2, 1-3, and 1-4
• Kilovolt-ampere rating for vital bus 1-1
• Why vital bus 1-1 's kilovolt-ampere rating is higher than the rating of the other inverters
• Normal output frequency
• Cooling medium for the inverter
• Indications available to the control room operator for determining if an inverter cooling fan is malfunctioning REACTOR OPERATOR Page 9 of 36 Revision 4, 07/31/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) 1.1. These actions reduce the rate of pressurizer level increase, since normal letdown and excess letdown capability has been lost.

2. The use of seal injection flow control valve 1-CH-HCV-1186 is preferred over the seal injection throttle valves because it is much quicker than dispatching an operator to locally throttle and is a more efficient use of available manpower.

6.7 Objective U 10792 Describe and explain the actions required to be taken in response to an extended loss of power to a 125 VDC station battery charger. (1-MOP-6.70, 1-MOP-6.71, SER-3-99). 6.7 Content

1. Certain actions are required to be taken in response to an extended loss of power to a 125 VDC station battery charger:

1.1. Without a battery charger in service the battery will initially supply all loads with only a very slow drop in voltage. 1.2. During an extended period of time without a battery charger, (for example: during the loss of power to the 480-volt bus that supplies the charger) voltage will drop faster as discharge time increases. 1.2.1.This is because the limiting factor for battery capacity is individual cell voltage. 1.2.2.As total battery voltage drops individual cell reversal can occur on a weaker cell. 1.2.2.1. Cell reversal is a condition where the reversed cell goes from being a contributor to battery output to being a load on the battery. 1.2.3.This additional load on the battery, combined with the fact that fewer good battery cells are now actually supplying the load, causes the total battery voltage to drop even faster than before. REACTOR OPERATOR Page 38 of 158 Revision 30, 11/06/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) 1.2.4. The further battery voltage drops, the more chances that another cell will reverse, which causes battery voltage to drop even faster. .. etc. 1.3. A loss of the DC bus will cause a loss of the associated vital bus, which can complicate control of the plant and recovery from the event. 1.4. Extremely low voltage on the DC bus can complicate control of the plant. 1.4.1.This is because control power for several safety-related breakers is provided via DC control power. 1.4.2.To ensure that sufficient DC voltage will be available to operate required circuit breakers, actions must be taken to minimize the load on the DC bus. 1.5. If, for example, power is lost to the 1J 4160-volt bus 1-MOP-6.71 directs: 1.5.1.lf the bus is not expected to be restored within 30 minutes, or if the bus is dead for 30 minutes, then deenergize the computer inverter. 1.5.2.lf the bus is not expected to be restored within 4 hours 1.5.3.Within one hour of bus loss stop the DC-powered air side seal oil pump 1.5.4.Within two hours of buss loss deenergize vital bus 1-111 and the 1-111 inverter. 1.6. In another example, if power is lost to the 1H 4160-volt bus 1-MOP-6.70 directs: 1.6.1.lf an emergency bus feeder will be closed within 4 hours, then to ensure sufficient DC control power is available, deenergize vital bus 1-1 and the 1-1 inverter within 2 hours of bus loss. 1.6.2.lf an emergency bus feeder will not be closed within 4 hours, then to conserve battery power, deenergize vital bus 1-1 and the 1-1 inverter within 3 hours of bus loss. 6.8 Objective U 11550 Explain the following concepts as they apply to restoring automatic trip valves following the restoration of vital bus voltage (1-MOP-26.60).

• Why the containment sump pump discharge valve's CLOSE push-button must be depressed REACTOR OPERATOR Page 39 of 158 Revision 30, 11/06/2008

                                                                      /

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

51. 063-K4.02 051IBANKINAPS/L/2JROINAPSII Which ONE of the following methods ensures that only one DC bus at a time is supplied from the swing charger?

A'! Key-operated interlock mechanism on each swing charger supply breaker to the DC bus. ' B. Automatictrip signal for simultaneously closed swing charger output breakers:-' C. Dedicated plug-in type swing charger output breaker. c D. Electrical interlock on the swing charger6utput breaker. Feedback

a. Correct. Key interlock provides administrative control.

b. Incorrect. Plausible since some breakers (e.g. RT BYP bkrs) have this feature.

c. Incorrect. Plausible since some systems (e.g. 4160v swgr) have this feature ..

d. Incorrect. Plausible as discussed above since electrical interlocks are a common feature of several systems.

Notes D.C. Electrical Distribution Knowledge of DC electrical system design feature(s) and/or interlock(s) which provide for the following: Breaker interlocks, permissives, bypasses and cross-ties (CFR: 41.7) Tier: 2 Group: 1 Importance Rating: 2.9/3.2 Technical

Reference:

Proposed references to be provided to applicants during examination: None Learning Objective: Question History: bank additional info:

DOMINION 1-0P-26.4.3 North Anna Power Station Revision 13 Page 6 of 45 4.2 The Main Station Batteries should NOT remain in operation longer than necessary without a battery charger in service to the batteries. 4.3 The Main Station Battery Chargers must NOT be paralleled with the swing battery chargers. 4.4 WHEN inserting or removing Hathaway Cabinet Annunciator patch cords, THEN the following guidelines apply:

• Grasp the patch cord by the plastic covering on the plug and NOT by the cord.
• Remove patch cord plug from or insert the patch cord plug into the designated socket by pulling or pushing the plug very slowly, while maintaining a 90 degree angle to the socket board. This will limit the possibility of arcing, which could seriously damage the power supply to the board.

4.5 The following applies to the term recently irradiated fuel: 4.5.1 Recently irradiated fuel is defined in the bases of the following Tech Specs as fuel that has occupied part of a critical reactor core within the previous 100 hours:

• Tech Spec 3.7.15, Fuel Building Ventilation System (FBVS)
• Tech Spec 3.9.4, Containment Penetrations

DOMINION 1-0P-26.4.3 North Anna Power Station Revision 13 Page 9 of 45 5.0 INSTRUCTIONS 5.1 Placing 01-BY-C-03, Swing Battery Charger lC-I, in Service on 01-BY-B-Ol, Battery 1-1 5 .1.1 Verify Initial Condition is satisfied. 5.1.2 Review Precautions and Limitations. CAUTION Placing 01-BY-C-03, Swing Battery Charger 1C-I, in service may cause 1-VB-INV-Ol, Vital Bus Distribution Panel 1-1 Inverter, to swap to its voltage regulating transformer. (Reference 2.4.8) 5.1.3 Obtain the Kirk Interlock key for Swing Battery Charger 1C-I from the Administrative Key Locker. 5.1.4 IF Battery charger 1C-I annunciator alarm was defeated, THEN establish communications with the Unit 1 CRO and notify the Unit 1 CRO that Panel H C-3, BATTERY CHGR 1C-I TROUBLE, will light while performing this subsection. 5.1.5 IF Battery charger 1C-I annunciator alarm was defeated, THEN enable the Panel H C-3, BATTERY CHGR 1C-I TROUBLE, annunciator as follows:

a. Unlock and open 1-EI-CB-21, Hathaway Cabinet.

STUDENT GUIDE FOR VITAL AND EMERGENCY ELECTRICAL DISTRIBUTION SYSTEM (35)

4. During normal operation, the battery output voltage is ~ 132 volts

5. During an equalizer battery charge, the battery output voltage is ~ 139.8 volts

6. During normal operation, battery charger 1-1 (2-1) have an approximate current output of 105 amps.

6.1. Battery chargers 1-11, 1-111, and 1-IV have an approximately current output of 60 amps. 6.2. The nominal 100% current is 225 amps (100%).

7. The maximum current flow is 275 amps (110%).

1.2 Objective U 5510 Explain how the Kirk interlock ensures that only one DC bus is supplied from the swing battery charger at one time (SOER-81-15). 1.2 Content

1. A single key is used for two locking mechanisms, that can't be removed unless the breaker is open.

1.1. This ensures that only one DC bus is supplied from the swing battery charger at one time. 1.3 Objective U 4745 List the following information associated with the 120-volt DC bus breaker panels (SOER-81-15). REACTOR OPERATOR Page 5 of 36 Revision 4, 07/31/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

52. 064-A4.04052/BANK/NAPS/L/2/ROINAPSII When the emergency diesel generator air compressors are swapped to the Lister diesels, the Lister

_ _ _ _ , and air bank pressure is maintained by loading and unloading of the air compressor. A'!' runs continuously; the automatic B. runs continuously; manual C. is manually started when air pressure drops; the automatic D. is manually started when air pressure drops; manual Feedback

a. Correct. There are no auto start features with the lister so it runs continuously and does have pressure switches for loading and unloading automatically.

b. Incorrect. First part is correct as discussed above, second part is incorrect but plausible since manual action is required to place it in service and start it, the candidate who does not have detailed systems knowledge may conclude that maintaining pressure is also a manual function.

c. Incorrect. Plausible since it would be possible to operate this way, but it is not in accordance with the procedure; second part is corrrect.

d. Incorrect. First part plausible but incorrect as noted above; second part also incorrect as discussed in distractor b.

Notes Emergency Diesel Generators (ED/G) Ability to manually operate and/or monitor in the control room: Remote operation of the air compressor switch (different modes) (CFR: 41.7 / 45.5 to 45.8) Tier: 2 Group: 1 Importance Rating: 3.2/3.2 Technical

Reference:

lesson plan Proposed references to be provided to applicants during examination: None Learning Objective: 3273 Question History: new additional info:

DOMINION 1-0P-6.7 North Anna Power Station Revision 11 Page 10 of 22 5.2 Placing The EDG Air System In Service Using The Lister Diesel As The Prime Mover 5.2.1 Verify Initial Conditions are satisfied. 5.2.2 Review Precautions and Limitations. 5.2.3 Obtain the Lister diesel handcrank. 5.2.4 IF the drive belts are not connected to the Lister diesel, THEN do the following:

a. Ensure the Lister diesel DECOMPRESSION lever is in the UNLOAD position.

b. Ensure the Lister diesel ENGINE CONTROL lever is in the OFF position.

c. Ensure the applicable control switch for its associated compressor electric motor, is in OFF:

• l-EG-C-IHA, l-EE-BKR-IHI-IA Bl
• l-EG-C-IHB, l-EE-BKR-1HI-IA B2
• l-EG-C-llA, l-EE-BKR-IJ1-1A Bl
• 1-EG-C-llB, 1-EE-BKR-IJ1-1A B2

DOMINION 1-0P-6.7 North Anna Power Station Revision 11 Page 11 of 22

d. Danger Tag open the supply breaker for the applicable electric motor:

• 1-EG-C-1HA, 1-EE-BKR-1H1-1A B1
• 1-EG-C-1HB, 1-EE-BKR-1H1-1A B2
• 1-EG-C-lJA, 1-EE-BKR-1J1-1A B1
• 1-EG-C-lJB, 1-EE-BKR-1J1-1A B2 NOTE: During emergency situations, an operator can make the belt changeover.

e. Contact the Mechanical Maintenance department to make the belt change over by skill of the craft. IF an operator is to make belt changeover, THEN do the following (N/A the rest of this step if mechanics change belt):

1. IF required, THEN loosen the foundation adjusting bolts:

• Lister diesel (3/4" wrench)
• electric motor (9116" wrench)

2. Swap the belts to the Lister diesel.

NOTE: The Lister diesel has jacking bolts for adjustment of belt tension.

3. IF required, THEN adjust belt tension until snug.

4. Verify proper alignment between the drive unit and the compressor.

5. IF required, THEN tighten the foundation adjusting bolts for the

( Lister diesel.

DOMINION 1-0P-6.7 North Anna Power Station Revision 11 Page 12 of 22 5.2.5 Ensure the Lister diesel DECOMPRESSION lever is in the UNLOAD position. 5.2.6 Ensure the ENGINE CONTROL lever is in the ON position. CAUTION IF the applicable compressor auto-unloading mechanism isolation valve is not opened, THEN the Lister diesel will run unloaded and the air receiver will not be pressed-up. (Reference 2.4.2) NOTE: The auto-unloading mechanism, on the compressor, will maintain approximately 240 psig air pressure with the Lister diesel running continuously. 5.2.7 Open the applicable compressor auto-unloading mechanism isolation valve.

• I-EB-47, IHA Press Switch To IHA Air Compressor Isol Valve
• I-EB-79, IHB Press Switch To IHB Air Compressor Isol Valve
• I-EB-59, lJA Press Switch To lJA Air Compressor Isol Valve
• l-EB-98, lJB Press Switch To lJB Air Compressor Isol Valve 5.2.8 Slide handcrank onto the Lister diesel shaft and rotate in the clockwise direction to ensure ratchet mechanism is operating properly. The diesel shaft should not tum.

(

DOMINION 1-0P-6.7 North Anna Power Station Revision 11 Page 13 of 22 5.2.9 Perform the following steps in quick sequence to start the Lister diesel:

a. Rotate the handcrank in the counter-clockwise direction to rotate the diesel.

b. Remove the handcrank AND place the DECOMPRESSION lever to LOAD.

5.2.10 IF the Lister diesel will not start, THEN do the following:

a. Have the Mechanical Maintenance Department remove the fuel line vent plugs one at a time to vent any entrapped air in the system.

b. Ensure all vent plugs are installed and REPEAT Steps 5.2.8 and 5.2.9.

IF the Lister diesel will not start, THEN submit a Work Request to repair the engine. 5.2.11 WHEN it is desired to stop the Lister diesel, THEN do the following:

a. Ensure the Lister diesel ENGINE CONTROL lever is in the OFF position.

b. Ensure the Lister diesel DECOMPRESSION lever is in the UNLOAD position.

5.2.12 Close the applicable compressor auto-unloading mechanism isolation valve.

• l-EB-47, IHA Press Switch To IHA Air Compressor Isol Valve
• l-EB-79, IHB Press Switch To IHB Air Compressor Isol Valve
• l-EB-59, lJA Press Switch To lJA Air Compressor Isol Valve
• l-EB-98, IJB Press Switch To IJB Air Compressor Isol Valve

DOMINION 1-0P-6.7 North Anna Power Station Revision 11 Page 14 of 22 5.2.13 IF the electric motor will be returned to service as the prime mover, THEN GO TO Section 5.1, Placing The EDG Air System In Service Using The Electric Motor As The Prime Mover. Completed by: _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ Date: - - - -

When the emergency diesel generator air compressors are swapped to the Lister diesels, the Lister , and air bank pressure is maintained by _ _ _ _ _ loading and unloading of the air compressor. A. runs continuously; the automatic B. runs continuously; manual C. is manually started when air pressure drops; the automatic D. is manually started when air pressure drops; manual Answer: A

               'questipn1; jnf:o;~' l~'%'$,\:~\,;"~.:,,;v*=!iil;,,,,;:: ~~:')'!:'t,>, . ,;,~;,~:;",' .' . ..::;j ,;,   :
                                                                                                                  ."..... "~~'::'   i' Question Type:                     Multiple Choice Status:                            Active Always select on test?             No Authorized for practice?           No Points:                            1.00 Time to Complete:                  0 Difficulty:                        0.00
                        ~' i..t          \ ' ,;' S System ID:                         26656

( User-Defined ID: 3273 Cross Reference Number:

                                                                                                                              "~ ,~'i  '

Topic: 3273 : NO TOPIC Num Field 1: Num Field 2: Text Field: 064-A4.04 Comments: Associated objective(s): Explain how the diesel generator air bank pressure is maintained in the following modes of operation.

• Lister drive
• Electric drive VA NAPS OPS Page: 1 of 1 18 August 2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

53. 065-AA2.01 053INEWIIH/3IROINAPSII Unit 1 is at 100% power.

After receiving annunciator J-E8, INSTRUMENT AIR LOW PRESS, operators entered 1-AP-28, Loss of Instrument Air. The BOP notes Instrument Air pressure has decreased to . 1-AP-28 directs the crew to trip the reactor and close Main Steam Trip Valves. These actions are taken primarily to _ _ _ __ A'! 68 psig ; prevent an undesired automatic Safety Injection. B. 68 psig ; prevent an uncontrolled RCS cooldown. C. 88 psig ; prevent an undesired automatic Safety Injection. D. 88 psig ; prevent an uncontrolled RCS cooldown. Feedback

a. Correct. AP-28 has a continuous action to trip the reactor if pressure is less than 70 psig and the main steam trip valves fail closed on a loss of instrument air, thus if one drifted into the steam flow and closed a safety injection on high steam flow low

( SG pressure on the other 2 generators could result.

b. Incorrect. First part is correct as discussed above, second part is incorrect but plausible if the candidate does not fully understand the implications of the loss of instrument ait as relates to the main steam trip valves they may conclude that the concern is for over cooling due to secondary valves failing open resulting in colder feedwater etc. the fact that preocedures do direct closing MSTVs in the event of excessive cooldown (e.g. ES-O.1) futher reinforces this misconception.

c. Incorrect. Plausible since this pressure is well below the normal value and below 94 psig which is an action point in the procedure for taking actions such as bypassing the instrument air dryers; second part is correct as discussed in Distractor a.

d. Incorrect. First part incorrect but plausible as discussed above; second part also incorrect but plausible as discussed in Distractor b.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Loss of Instrument Air Ability to determine and interpret the following as they apply to the Loss of Instrument Air: Cause and effect of low-pressure instrument air alarm (CFR: 43.5 /45.13) Tier: Group: Importance Rating: 2.9/3.2 Technical

Reference:

1-AP-28 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info:

NUMBER PROCEDURE TITLE REVISION 30 1-AP-28 LOSS OF INSTRUMENT AIR PAGE 3 of 25 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

 *2. CHECK INSTRUMENT AIR PRESSURE OUTSIDE CONTAINMENT:

D a) Instrument Air pressure - LESS D a) Monitor IA pressure. !.E IA pressure decreases THAN 70 PSIG to less than 70 psig, THEN RETURN TO Step 2b. D GO TO Step 3. D b) Check Reactor - TRIPPED D b) GO TO 1-E-0, REACTOR TRIP OR SAFETY INJECTION, while continuing with this procedure. ( c) Close Main Steam Trip Valves and c) !.E the Main Steam Trip Valves will not close, Bypass Valves: THEN close the Main Steam NRVs and NRV Bypass Valves: D

• 1-MS-TV-1 01 A D
• 1-MS-NRV-101A D
• 1-MS-TV-1018 D
• 1-MS-NRV-101B D
• 1-MS-TV-101C D
• 1-MS-NRV-101C D
• 1-MS-TV-113A D
• 1-MS-NRV-103A D
• 1-MS-TV-113B D
• 1-MS-NRV-103B D
• 1-MS-TV-113C D
• 1-MS-NRV-103C D d) Verify RCS is NOT solid d) Place the following equipment in PTL:

D

• RCPs D
• Charging Pumps D
• PRZR Heaters D e) GO TO Step 15

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) 4.1.1. 1-RMS-RM-152 - New Fuel Area radiation monitor. 4.1.2. 1-RMS-RM-153 - SFP Bridge Crane radiation monitor.

5. Any fuel handling or core alterations that are in progress should be stopped until the Spent Fuel Pit System has been restored to normal.

5.1. Ensure that fuel assemblies are placed in a safe location and the location clearly documented.

6. If SFP level decreases below the SFP cooling pump suction weirs, normal SFP cooling would be lost.

7. Maintenance activities or a system rupture or misalignment could be a possible source of leakage from the RCS or SFP.

8. Manager Nuclear Operations or Operations Manager on Call permission is required to fill the spent fuel pool using the Fire Protection System.

9. It is approximately 10 hours before the spent fuel pool temperature would reach 200°F if worst-case conditions existed.

10. Alternate spent fuel pool cooling methods are:

10.1. Bleed and feed the SFP using the Reactor Purification System. 10.2. Align service water through the SFP heat exchangers. 22.11 Objective U 11662 List the following information associated with 1-AP-28, "Loss of Instrument Air" (SOER-88-1).

• Purpose of the procedure REACTOR OPERATOR Page 141 of158 Revision 30, 11/06/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91)

• Modes of applicability
• Entry conditions
• Immediate operator actions
• Actions required if instrument air pressure decreases below 70 psig
• Possible causes of a loss of instrument air
• Means used to determine whether the instrument air leak is inside or outside of the containment 22.11 Content

1. 1-AP-28 provides guidance to the operator for recovering from a loss of IA condition.

2. Pneumatic control valves are used in almost all systems throughout the station therefore this procedure is applicable in all modes.

3. 1-AP-28 is entered when any of the following conditions exist:

3.1. Rupture of Instrument Air System piping 3.2. Instrument air compressor failure 3.3. Transition from other plant procedures.

4. There is one immediate operator action for 1-AP-28, to "START ALL AVAILABLE AIR COMPRESSORS."

5. If instrument air pressure decreases below 70 psig the procedure directs the operator to trip the reactor and go to 1-E-0 while continuing with this procedure.

5.1. The main steam trip valves are closed because sufficient air pressure may not exist to hold each valve out of the steam flow causing the valve to close. 5.1.1. Closure of one trip valve with the others open could result in actuation of a safety injection signal. REACTOR OPERATOR Page 142 of 158 Revision 30, 11/06/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

54. 067-AK1.01 054INEWIIL/3/ROINAPS/S120/200S1 If an oil fire occurs in the North Fuel Oil Pump House, a _ _ _ _ _ _ _ _ will actuate to suppress the fire; the fire is classified as a _ _ _ _ _ __

A. pre-action sprinkler system; Class B fire B. pre-action sprinkler system; Class A fire C~ high-pressure CO 2 system; Class B fire D. high-pressure CO 2 system; Class A fire Feedback

a. Incorrect. Plausible since water is commonly used for equipment that contains oil (e.g. transformers) and has the potential for spreading rapidly. Second part is correct.

b. Incorrect. Plausible since water is commonly used for equipment that contains oil (e.g. transformers) and has the potential for spreading rapidly. Second part is also incorrect.

c. Correct. This is the correct suppression system. Second part is also correct.

d. Incorrect. This is the correct suppression system. Second part is incorrect as this is the classification for an electrical fire.

Notes Plant fire on site Knowledge of the operational implications of the following concepts as they apply to Plant Fire on Site: Fire classifications, by type (CFR 41.8 / 41.10 / 45.3) Tier: 1 Group: 2 Importance Rating: 2.9/3.9 Technical

Reference:

Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info:

STUDENT GUIDE FOR FIRE PROTECTION SYSTEM (6) ( 1.2. The 17-ton system protects non-safety-related equipment. 1.2.1.The 17-ton system also provides for purging of hydrogen in the main generators. 1.3. The 6-ton low-pressure system protects safety-related equipment.

2. The high-pressure carbon dioxide system has CO 2 compressed and stored in cylinders.

2.1. The high Pressure CO 2 is provided solely for the Fuel Oil Pump House.

3. Halon 1301 is a chemical compound that interferes with the chemistry of a fire.

3.1. Halon has advantages over carbon dioxide: it can be used in spaces which must remain occupied since, in low concentrations, it does not present a serious health risk to humans. 3.2. A Halon 1301 system is provided for the following areas: 3.2.1.Main Control Room 3.2.2.Emergency Switchgear Rooms 3.2.3.Simulator Room 3.2.4.Security Alarm Station 3.2.5.Central Alarm Station Topic: 1.3 Fire Barriers 1.3 Objective U 6766 State the following information associated with fire protection.

• Four types of fire barriers
• Length of time for which a fire barrier is designed to withstand a fire 1.3 Content

1. There are four types of fire barriers utilized in the different plant areas at NAPS.

NON-LICENSED OPERATOR Page 5 of 70 Revision 10, 06/18/2008

STUDENT GUIDE FOR FIRE PROTECTION SYSTEM (6) High-pressure Carbon Dioxide System 3.1 Objective U 6776 Explain the following concepts associated with the High-pressure Carbon Dioxide System.

• How the fuel oil pump house heat detectors actuate the system's discharge
• How the system is manually locked out 3.1 Content

1. The Fuel Oil Pump House CO 2 system operation is mechanical.

1.1. A heat detector triggers the release of nitrogen from a pilot bottle. 1.2. The nitrogen in turn releases CO 2 from two bottles. ( 1.3. High pressure in the discharge header causes the remaining bottle on the header to discharge.

2. A 90 quick-throw valve provides a mechanical lockout for each fuel oil pump room high-pressure 0

system. 2.1.lt is located in the CO 2 bottle enclosure outside of the fuel oil pump house. 3.2 Objective U 6637 Explain the following concepts associated with the High-pressure Carbon Dioxide System.

• How manual actuation of the nitrogen pilot bottles causes the system to discharge
• How manual actuation of the system is accomplished if the pilot bottles are depressurized
• How each bank can be backed up by the other bank NON-LICENSED OPERATOR Page 18 of 70 Revision 10, 06/18/2008

STUDENT GUIDE FOR FIRE PROTECTION SYSTEM (6) Topic3.3High-preSsurE!Ce>2SysteOl i lnfofrn tion a 3.3 Objective U 6638 List the following information associated with the High-pressure Carbon Dioxide System.

• Areas to which the system discharges
• Effect on system operability if the control power fuses were removed
• Number of carbon dioxide bottles in each bank 3.3 Content

1. The system discharges is the fuel oil pump house (south and north).

2. Removal of the control power fuses for the High Pressure Carbon Dioxide System will not affect its ability to automatically discharge.

2.1. It will prevent the system from turning off the fuel oil building's fan and disable any remote alarms.

3. There are 3 carbon dioxide bottles in each bank.

NON-LICENSED OPERATOR Page 20 of 70 Revision 10, 06/18/2008

DOMINION VPAP-2401 REVISION 29 PAGE 11 OF 131 3.2.21 Plant Issue (Deviation) S-2003-5254, Appendix R Emergency Switchgear Room Fire 3.2.22 Audit Finding 07-04-02NS 4.0 DEFINITIONS 4.1 Aerosol A material which is dispensed from its container as a mist spray or foam by a propellant under pressure. If the contents are flammable then the U. S. Federal Hazardous Substance labeling Act requires the container to be labeled "FLAMMABLE." 4.2 Alternate Shutdown or Dedicated Shutdown The use of safety-related equipment or Appendix R equipment from either unit to achieve and maintain stable safe shutdown using Fire Contingency Action (FCA) procedures. 4.3 Approved Determined to be acceptable for use by a national recognized testing laboratory, a regulatory authority, an engineering evaluation, or other authority having jurisdiction. 4.4 Class of Fire A classification system used that segregates the fires by the types of material on fire. 4.4.1 Class A Fires Fire involving ordinary combustible materials such as wood, paper, cloth, some rubber and plastics. 4.4.2 Class B Fires Fires involving flammable and combustible liquids, gases, greases, and similar materials, and some flammable rubber and plastic materials. 4.4.3 Class C Fires Fires involving energized electrical equipment. 4.4.4 Class D Fires Fires involving combustible metals such as magnesium, titanium, zirconium, sodium, lithium, and potassium. 4.5 Combustible Liquid Liquids with flash points at or above 100°F (e.g., diesel fuel, lubricating oil).

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

55. 073-K3.01 055IBANKINAPS/L/2/ROIII Which ONE of the following components is automatically affected by a high alarm on 1-GW-RI-178-1, MGP Process Vent Radiation Monitor?

A'! Containment Vacuum Pump Discharge Valves B. Low Level Liquid Waste Tank Vents C. Boron Recovery Tank Vents D. Containment Purge Exhaust Valves Feedback

a. Correct. Actuation of alarm results in trip valves closing and pumps tripping to isolate potential source of release from this pathway.

b. Incorrect. Plausible since these valves are required to be closed by the AP but these are MANUAL actions, not automatic actions.

c. Incorrect. Plausible as discussed in Distractor b.

d. Incorrect. Plausible since several RMs will automatically close these valves but this RM is not one of them.

Notes Process Radiation Monitoring (PRM) System Knowledge of the effect that a loss or malfunction of the PRM system will have on the following: Radioactive effluent releases (CFR: 41.7 / 45.6) Tier: 2 Group: 1 Importance Rating: 3.6/4.2 Technical

Reference:

O-AP-5.2 Proposed references to be provided to applicants during examination: None Learning Objective: 5679 Question History: bank additional info:

NUMBER ATTACHMENT TITLE ATTACHMENT O-AP-S.2 3 1-GW-RI-178-1, 2 OR 3, MGP PROCESS VENT RAD MONITOR REVISION PAGE 19 1 of S NOTE: The MGP Remote Display Unit indicating a fault will buzz with an audible alarm. Pressing the BLUE Select/Acknowledge key on the display unit will silence the audible alarm.

1. Check any MGP Process Vent Radiation Monitor(s) in alarm:

o

• 1-GW-RI-178-3, Process Vent RM Particulate - alert or high o
• 1-GW-RI-178-1, Process Vent RM Noble Gas Normal- alert, high or H/H o
• 1-GW-RI-178-2, Process Vent RM Noble Gas Accident - alert or high

2. IF at least one of the following conditions is met, THEN GO TO Step 4:

o

• 1-GW-RI-178-3, is in alarm and the Operate light is LIT.

o

• 1-GW-RI-178-1, is in alarm and the Operate light is LIT.

o

• 1-GW-RI-178-2, is in alarm; and 1-GW-RI-178-3, is in standby and the Test light is LIT; and 1-GW-RI-178-1, is in standby and the Test light is LIT.

3. IF a MGP Process Vent Radiation Monitor(s) Operate Light is NOT LIT, THEN GO TO Step 6.

4. Check Radiation Reading on alarming MGP Process Vent Radiation Monitor(s) as applicable:

a) Screen display using the channel keys:

• 1-GW-RI-178-3, Process Vent RM Particulate channels:

o

• A Part-Rei mci/sec o
• B Part-Act mci/cc
• 1-GW-RI-178-1, Process Vent RM Noble Gas Normal channels:

o

• A NG-Rel-L mci/sec o
• B NG-Act-L mci/cc
• 1-GW-RI-178-2, Process Vent RM Noble Gas Accident channels:

o

• A NG-Rel-H mci/sec o
• B NG-Act-H mci/cc o b) 1-RM-RR-178, Process Vent RM Activity and Release Rate recorder

NUMBER ATTACHMENT TITLE ATTACHMENT O-AP-5.2 3 1-GW-RI-178-1, 2 OR 3, MGP PROCESS VENT RAD MONITOR REVISION PAGE 19 2 of 5

5. IF the abnormality of the Radiation Monitor was NOT caused by an obvious malfunction, THEN do the following for the MGP Process Vent Radiation Monitor(s) in alarm:

a) Inform the Health Physics Shift Supervisor of the following:

• Date and time the monitor alarmed and which channels are alarming
• Process Vent flow rate (1-GW-FI-108)

NOTE: The analysis should be completed immediately due to time limits for event classification in EPIP-1.01, EMERGENCY MANAGER CONTROLLING PROCEDURE. b) Request a sample and survey of the affected area. c) IE a Hi alarm has actuated on 1-GW-RI-178-3 OR 1-GW-RI-178-1, THEN verify the following: D

• 1-GW-TV-102A - CLOSED D
• 1-GW-TV-102B - CLOSED D
• 1-GW-FCV-101 - CLOSED D
• 1-CV-P-3A, Unit 1 Containment Vacuum Pump A - STOPPED D
• 1-CV-P-3B, Unit 1 Containment Vacuum Pump B - STOPPED D
• 2-CV-P-3A, Unit 2 Containment Vacuum Pump A - STOPPED D
• 2-CV-P-3B, Unit 2 Containment Vacuum Pump B - STOPPED

_ d) Ensure the following trip valves are closed, as directed by the SRO, to stop potential radioactive sources to the Process Vent System: D

• 1-GW-TV-106, Equipment Vents D
• 1-GW-TV-113, Liquid Waste Tank Vents D
• 1-GW-TV-114, Boron Recovery Tank Vents e) Do the following to determine if the release has exceeded allowable limits:

1) Evaluate sample results, dose projections, and meter readings and compare to the limits in EPIP-1.01, EAL Table, Tab E to determine the need to implement EPIPs.

2) IF EPIP implementation is NOT required, THEN initiate notifications specified in VPAP-2802, NOTIFICATIONS AND REPORT.

NUMBER ATTACHMENT TITLE ATTACHMENT 0-AP-5.2 3 1-GW-RI-178-1, 2 OR 3, MGP PROCESS VENT RAD MONITOR REVISION PAGE 19 3 of 5 NOTE:

• IF Hi alarm is lit on 1-GW-RI-178-1 or 1-GW-RI-178-3, THEN WGDT discharge and Containment Vacuum pumps will be locked out until the Hi alarm(s) clear.
• A Hi Hi (H/H) alarm on 1-GW-RI-178-1 will swap monitoring to 1-GW-RI-178-2, Process Vent RM Noble Gas Accident. The WGDT discharge and Containment Vacuum pumps will be locked out until the Hi Hi latch is released by the Instrument Department. The MGP system is returned to normal range monitoring by the Instrument Department.
• IF power was lost to the MGP Radiation Monitor unit, THEN observe the following:
• When power is restored, then the MGP system will startup in accident mode.
• After a loss of power, the MGP system should automatically return to operable normal range monitoring approximately 20 minutes following power restoration.
• A burned out operating light bulb at the MGP skid should not render the radiation monitor inoperable. The MGP display will indicate the affected bulb.

6. Do the following for the affected MGP Process Vent Radiation Monitor(s):

_ a) Check for any Faults indicated at bottom of screen display. _ b) Have the Instrument Department check the MGP Radiation Monitor(s) for operability and repair as applicable. _ c) IF a FLOW FAULT is indicated on 1-GW-RI-178-1, THEN have the Instrument Department inspect the filter paper for discoloration and boron particles using 0-GIP-9.0, MGP PARTICULATE FILTER ASSEMBLY REPLACEMENT. _ d) IF a Hi Hi (H/H) alarm has swapped monitoring to the 1-GW-RI-178-2, Process Vent RM Noble Gas Accident Rad Monitor, AND 1-GW-RI-178-1 and 1-GW-RI-178-2 are reading normal, THEN with Health Physics concurrence, do the following:

1) Have the Instrument Department reset the Hi Hi alarm AND restore the MGP system to normal range monitoring.

2) Reset the "latch in" logic to reset the Hi Hi alarm:

a. On the PCS homepage, select "P&ID MENU".

b. On the PIDMENU screen, select "RM - Radiation Monitoring".

c. On the 1RM1 screen, select "Reset Rad Monitor Latches".

d. On the RMRESET screen, select "RESET PROCESS VENT LATCH".

(STEP 6 CONTINUED ON NEXT PAGE)

DOMINION O-OP-23.3 North Anna Power Station Revision 6 Page 11 of 21 5.1.13 Open the following valves at Waste Disposal Panel in Control Room:

• I-GW-TV-106, EQUIP VENT TO GW REGEN HX
• I-GW-TV-l13, LW TK VENT TO GW REGEN HX
• I-GW-TV-114, BRT VENT TO GW REGEN HX
• I-GW-TV-1 02A, CONT VAC PUMP DISCH TO GW REGEN HX
• I-GW-TV-I02B, CONT VAC PUMP DISCH TO GW REGEN HX Completed by: _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ Date: - - - -

STUDENT GUIDE FOR RADIATION MONITORING SYSTEM (46) 2.3. The ion chamber can be modified for a number of applications. It can count gammas, betas, or fast and slow neutrons. 1.6 Objective U 5227 Explain the following concepts as they apply to the radiation monitor detectors.

• Why scintillation detectors are normally used in particulate and liquid process applications
• Why Geiger-Mueller detectors are normally used in area and gaseous applications
• How detectors are shielded from background radiation 1.6 Content

1. Scintillation detectors are normally used in particulate and liquid process applications due to accuracy

( and reliability of the output (i.e., energy dependent)

2. Geiger-Mueller detectors are normally used in area and gaseous applications.

2.1. Due to their high sensitivity, changes in radiation levels are seen quickly. 2.2. These detectors are not sensitive to changes in temperature or humidity. 2.2.1.Also, these detectors are very rugged compared to other detectors.

3. Detectors are normally shielded from background radiation by lead shields (called pigs).

1.7 Objective U 10705 List the automatic actions that will occur when output signals are generated by the following radiation monitors.

• New fuel storage area (RMS-RM-152)

(

• Fuel pool bridge area (RMS-RM-153)

REACTOR OPERATOR Page 11 of 58 Revision 4, 09/22/2008

STUDENT GUIDE FOR RADIATION MONITORING SYSTEM (46)

• Manipulator crane area (RMS-RM-162)
• Clarifier effluent (RM-LW-111)
• Condenser air ejector (SV-RM-121)
• Containment gaseous and particulate (RMS-RM-159 and 160)
• Process Vent (GW-RM-178-1 and 178-3) 1.7 Content

1. New fuel storage area (RMS-RM-152) and fuel pool bridge area (RMS-RM-153) 1.1. On a HI-HI alarm performs the following if the FUEL BUILDING RADIATION INTERLOCK KEY switch is in ENABLE:

1.1.1 .After a 2 minute time delay will automatically dump the MCR bottled air, 1.1.2.closes the MCR dampers, and starts the MCR emergency ventilation fans. 1.1.3.(High alarm must be in after the 2 minutes for the action to take place)

2. Clarifier effluent (RM-LW-111) 2.1. On Hi-Hi alarm performs the following:

2.1.1.Shuts PCV-LW-115 2.1.2.Closes clarifier influent valve, 1-LW-FCV-100 2.1.3. This causes the SG blowdown pumps to trip.

3. Condenser air ejector (SV-RM-121) 3.1. Hi-Hi rad alarm - automatically diverts effluent from the vent stack to the containment atmosphere.

3.1.1.A Hi-Hi rad alarm with a phase A signal: 3.1.1.1. Isolates aux steam to the air ejectors. (1-AS-FCV-1 OOA and 100B) 3.1.1.2. All air ejector discharge valves close 1-SV-TV-1 02-1, 103 and 102-2

4. Process vent (GW-RM-178-1 and 178-3)

REACTOR OPERATOR Page 12 of 58 Revision 4, 09/22/2008

STUDENT GUIDE FOR RADIATION MONITORING SYSTEM (46) 3.2. A Hi or Hi-Hi alarm signal from GW-RM-178-1 (Process Vent Noble Gas Normal MGPI) automatically performs the following: 3.2.1.Closes FCV-GW-1 01, flow control valve from the waste gas decay tanks. 3.2.2.Closes the containment vacuum pump discharge trip valves. 3.2.3.This in turn trips the vacuum pumps. 3.3. A Hi-Hi alarm signal from GW-RM-178-1 (Process Vent Noble Gas Normal MGPI) will shift the Process Vent sample flow path to GW-RM-178-2 (Process Vent Noble Gas Accident MGPI). 3.3.1.The Hi-Hi alarm signal will "latch-in". 3.3.2.The waste gas decay tank discharge and the containment vacuum pump discharge will be locked out until the Hi-Hi "latch" is relased by the Instrument Department. 3.3.3.After the Hi-Hi alarm condition is cleared, the MGP system is returned to normal range monitoring by the Instrument Department. 3.4. A Hi alarm signal from GW-RM-178-3 (Process Vent Particulate MGPI) automatically performs the ( following: 3.4.1.Closes FCV-GW-1 01, flow control valve from the waste gas decay tanks. 3.4.2.Closes the containment vacuum pump discharge trip valves. 3.4.3.This in turn trips the vacuum pumps.

5. Containment gaseous and particulate (RMS-RM-159 and 160) and manipulator crane area (RMS-RM-162).

3.5. Hi-Hi alarm signal automatically performs the following: 3.5.1.Trips the purge and exhaust fans and closes the affected units purge supply and exhaust MOVs. 3.5.2.Fans are interlocked with the purge valves as well as the rad monitor. REACTOR OPERATOR Page 13 of 58 Revision 4, 09/22/2008

QUESTIONS REPORT ( for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

56. 075-K4.01 056INEWIIH/3IROIII Both units are at 100% power.

Breaker 15G1 0, 1G/2G bus crosstie, will automatically close if power is lost to the _ _ _ _ _ _ _ ' A. "A" RSST provided lake level is greater than 251 feet B. "A" RSST provided lake level is less than 251 feet C. "C" RSST provided lake level is greater than 251 feet D'!" "C" RSST provided lake level is less than 251 feet Feedback

a. Incorrect. Plausible if candidate is unaware of the purpose of the feature or the requirement to defeat it contained in 0-AP-40.

b. Incorrect. Plausible as discussed in distractor a.

c. Incorrect. The loss of C RSST is part of the logic, however the feature is required to be defeated by 0-AP-40 for the given lake level.

d. Correct. For the stated condition the automatic closure will occur and maintain CW pumps running (maintain Heat Sink) on the affected Unit.

Notes Circulating Water System Knowledge of circulating water system design feature(s) and interlock(s) which provide for the following: Heat sink (CFR: 41.7) Tier: 2 Group: 2 Importance Rating: 2.5/2.8 Technical

Reference:

0-AP-40 and basic electrical lesson plan Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info:

'D .. OmlnlOItI! NORTH ANNA POWER STATION PROCEDURE NO: REVISION NO: 1-0P-48.2 33 PROCEDURE TYPE: UNIT NO: OPERATING PROCEDURE 1 PROCEDURE TITLE: OPERATION OF CIRCULATING WATER SYSTEM REVISION

SUMMARY

• FrameMaker Template Rev. 030 .
• Made the following changes for DCP 04-016, CW Pump Elbow VP Level Switch Removal/NAPS / 1&2:
• Deleted "CIRCULATING WATER PUMP DISCHARGE ELBOW FULLY PRIMED" from the start logic description in P&L 4.2.3 and from Note before old Step 5.5.3,5.6.6, and 5.7.6.
• Deleted existing Steps 5.5.6, 5.6.7, and 5.7.7 and replaced with new Steps 5.5.6, 5.6.7, and 5.7.7 to determine "Minimum Vacuum", verify the appropriate Circ Water Pump Discharge Elbow is primed, as indicated by the listed pressure indicator vacuum reading being above the Minimum Vacuum, and IF the applicable Circ Water Pump Discharge Elbow is not primed, THEN prime the elbow using 1-0P-48.6, Circulating Water Pumps Elbow Vacuum Priming.
• Added a new Attachment 3, Vacuum Required.
• Added new Reference 2.3.38 of the DCP.
• Added information to Synopsis.
• Deleted Reference 2.4.2 addressing drain valves and changed Step 4.18 to delete SOV information due to manual valve replacement.

PROBLEMS ENCOUNTERED: o NO DYES Note: If YES, note problems in remarks. REMARKS: (Use back for additional remarks.) SRO: DATE: CONTINUOUS USE

DOMINION 1-0P-48.2 North Anna Power Station Revision 33 Page 12 of 111 4.7 The Dam Operator MUST be notified to prepare for possible reservoir level change before starting or stopping Circulating Water Pumps (9-872-3531). 4.8 The IG/2G BUS FAST TRANSFER 15GI0 switch MUST be in DEFEAT any time lake level is ;;::: 251 ft. elevation OR the IG AND 2G buses are NOT being supplied by their normal source of power. 4.9 Limit switches in the Circulating Water Pump Discharge MOV Motors prevent throttling the Circulating Water Pump Discharge MOVs until the MOVs are at least 45° open (approximately 50% Control Room indication). 4.10 Time delays in the Circulating Water Pump Discharge MOV Motors prevent throttling the Circulating Water Pump Discharge MOVs until the Circulating Water Pump Motors have been energized for 5 minutes. 4.11 Normal Circulating Water Pump amperage for Circulating Water Pumps with unthrottled Discharge MOVs is between 290 and 310 amps. 4.12 Normal Circulating Water Pump amperage for Circulating Water Pumps with throttled Discharge MOVs is between 290 and 342 amps. 4.13 Communications shall be established with an Operator at the Circulating Water Pump Discharge MOV s to monitor valve travel and position when throttling the MOVs. 4.14 To prevent the potential for intake tunnel overpressurization, the keylock switches for any Water Box should NOT be in defeat unless:

• The number of running Circulating Water Pumps is less than the number of inservice Water Boxes.
• The Water Box for a running Circulating Water Pump is NOT aligned for service.
• The Water Box for the Circulating Water Pump that will be started is NOT aligned for service.

NUMBER ATTACHMENT TITLE ATTACHMENT 0-AP-10 2 LOSS OF ELECTRICAL POWER DIAGNOSTIC REVISION PAGE 60 2 of?

         "8"                                                              "C" R.s.s.                                                          R.S.S.

15G10 25G1 (1-MOP-26.80) (2-MOP-26.80) 2G 12G1-1NA3 I (Attachment 4) 2G1-1N I 2G1-18 I 25G-9

                                                           ~ 24G2-15
                                                       ~
                                                             ..Drawing No* KM392 4160V G BUSSES

VIRGINIA POWER 1-EI-CB-21H ANNUNCIATOR G7 1-AR-H-G7 NORTH ANNA POWER STATION REV. 0 APPROVAL: ON FILE Effective Date:05/09/97 4KV BUSSES 1G-2G TIE CLOSED 1.0 Probable Cause 1.1 Loss of "B" or "C" RSS transformer 1.2 Fault on "E" or "F" transfer bus 1.3 1G and 2G Buses crosstied 2.0 Operator Action 2.1 Verify 15G10 closed. 2.2 Verify voltage on 1G and 2G buses. 2.3 Monitor amps on RSS Transformer carrying "G" buses. 2.4 IF 15G10 auto closed, THEN notify Electrical Department. 3.0 References 3.1 LSK-22-10C 3.2 LSK-22-10D 3.3 11715-FE-21K 4.0 Actuation 4.1 52A contact on 15G10

STUDENT GUIDE FOR CIRCULATING WATER SYSTEM (12) 10.3 Objective U 7492 List the conditions which require the "G" bus fast transfer switch to be placed in the DEFEAT position. 10.3 Content

1. If lake level is greater than 251 feet or any G bus not on it's normal source of power, the "G" bus fast transfer switch must be placed in the DEFEAT position.

1.1. Potential tunnel pressure surge could occur due to re-energization of the bus. 10.4 Objective U 5184 Explain the effect that removing a condenser water box from service will have on the following controls and indications.

• Hotwell low-level alarm
• Hotwell high-level alarm
• Indicated hotweillevel
• Hotwell makeup valve position
• Hotwell high-level divert valve position 10.4 Content

1. When removing a condenser water box from service, the pressure in that side of the condenser will be slightly higher than the other side.

1.1. This will cause the hotwell level in the higher pressure side to drop and cause the hotwell level in the lower pressure side to increase. 1.2. The condenser level controls are provided on the 8 condenser and the alarms are on the A condenser. REACTOR OPERATOR Page 29 of 35 Revision 5, 07/15/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

57. 076-K4.0 1 057/MODIFIEDINAPS/H/3/ROINAPSI/

Given the following conditions:

• Both units are at 100% power.
• 1-SW-P-1A and 2-SW-P-1A are running.
• Unit 1 experiences a large-break LOCA.

Service Water flow to the CCHXs isolates _ _ __ A. on Unit 1 ONLY, and 3 Service Water pumps will be running. B. on BOTH units, and 3 Service Water pumps will be running. C~ on Unit 1 ONLY, and 4 Service Water pumps will be running. D. on BOTH units, and 4 Service Water pumps will be running. Feedback

a. Incorrect. First part is correct; second part incorrect but plausible since the candidate who does not have detailed knowledge oft he interaction of the ESFAS system and the service water system may conclude that only the accident unit pumps receive and start signal and thus sellect this distractor.

b. Incorrect. First part incorrect but plausbile sincethe CC system has no accident mitigation function, and because of the heat disipation capability of the CC system service water could be isolated for a period of time and then reestablished; second part incorrect but plausible as discussed above.

c. Correct. First part is correct, for the valves only the accident unit gets a close signal; second part also correct, for the pumps both units get a start signal so 4 will be running.

d. Incorrect. First part incorrect but plausible as discussed in Distractor b; second part is corrrect as discussed in Distractor c.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Service Water System (SWS) Knowledge of SWS design feature(s) and/or interlock(s) which provide for the following: Conditions initiating automatic closure of closed cooling water auxiliary building header supply and return valves (CFR: 41/7) Tier: 2 Group: 1 Importance Rating: 2.5/2.9 Technical

Reference:

1-E-1 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: Modified additional info:

NUMBER ATTACHMENT TITLE ATTACHMENT 1-E-O 4 EQUIPMENT VERIFICATION REVISION PAGE 39 2 of 4 ACTION! EXPECTED RESPONSE RESPONSE NOT OBTAINED

4. VERIFY SI PUMPS - RUNNING: o Manually start pumps.

o

• Two Charging Pumps - RUNNING AND o
• Both Low-Head SI Pumps - RUNNING

5. VERIFY FOUR SERVICE WATER PUMPS - o Manually start pumps.

RUNNING o IF less than 4 Service Water Pumps are running, THEN ensure Unit 2 Operator initiates O-AP-47, UNIT OPERATION DURING OPPOSITE UNIT EMERGENCY.

• 6. CHECK IF MAIN STEAMLINES SHOULD BE ISOLATED:

a) Check the following: o a) RETURN this Attachment to SRO for continued monitoring. o

• Annunciator Panel "D" E LIT OR o
• Containment pressure - HAS EXCEEDED 18 PSIA o b) Verify MSTVs and Bypass Valves - CLOSED o b) Manually close valves.

NUMBER ATTACHMENT TITLE ATTACHMENT 1-E-O 2 VERIFICATION OF PHASE B ISOLATION REVISION PAGE 39 2 of 9 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. VERIFY THE FOLLOWING AUTOMATIC OPERATIONS ON THE "H" SAFEGUARDS PANEL: (Continued) o c) Verify Service Water - ISOLATED TO o Manually close valve:

CC HEAT EXCHANGERS: CLOSED (GREEN) 1-SW-MOV-108A ( o d) Verify Service Water - ALIGNED TO RECIRC o Manually open valves: SPRAY HEAT EXCHANGERS (all red lights lit or check each valve below): DAII red lights lit. OPEN (RED) OPEN (RED) OPEN (RED) OPEN (RED) 1-SW-MOV-103A 1-SW-MOV-103D 1-SW-MOV-104A 1-SW-MOV-104D 1-SW-MOV-1 01 A 1-SW-MOV-1 01 C 1-SW-MOV-105A 1-SW-MOV-105C o e) Verify Casing Cooling - ALIGNED AND o Manually do operations as indicated: RUNNING: RUNNING (RED) OPEN (RED) OPEN (RED) 1-RS-P-3A 1-RS-MOV-100A 1-RS-MOV-101B

NUMBER ATTACHMENT TITLE ATTACHMENT 1-E-0 2 VERIFICATION OF PHASE B ISOLATION REVISION PAGE 39 5 of 9 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

4. VERIFY THE FOLLOWING AUTOMATIC OPERATIONS ON THE "J" SAFEGUARDS PANEL: (Continued) o c) Verify Service Water - ISOLATED TO o Manually close valve:

CC HEAT EXCHANGERS: CLOSED (GREEN) 1-SW-MOV-108B o d) Verify Service Water - ALIGNED TO RECIRC o Manually open valves: SPRAY HEAT EXCHANGERS (all red lights lit or check each valve below): DAII red lights lit. OPEN (RED) OPEN (RED) OPEN (RED) OPEN (RED) 1-SW-MOV-103B 1-SW-MOV-103C 1-SW-MOV-104B 1-SW-MOV-104C 1-SW-MOV-1 01 B 1-SW-MOV-101O 1-SW-MOV-105B 1-SW-MOV-105D o e) Verify Casing Cooling - ALIGNED AND o Manually do operations as indicated: RUNNING: RUNNING (RED) OPEN (RED) OPEN (RED) 1-RS-P-3B 1-RS-MOV-100B 1-RS-MOV-101A

STUDENT GUIDE FOR SERVICE WATER SYSTEM (13) 2.1. The relief valve is set to lift when service water supply pressure reaches 150 psig.

3. Maximum allowed differential pressure across the service water side of a component cooling heat exchanger (CCHX) is as follows:

3.1. With two CCHXs in-service on a service water header, maximum differential pressure across the service water side of each CCHX is 25 psid. 3.2. With only one CCHX in-service on a service water header, the maximum differential pressure across the service water side of the CCHX is dependent on service water pump alignment on that header, as follows: 3.2.1.With one service water pump in-service and another service water pump in automatic on that header, the differential pressure for the in-service CCHX must be less than 20 psid. 3.2.2.With only one service water pump operable in-service on the header (no other pump in automatic on that header), the maximum differential pressure for the in-service CCHX is 25 psid.

4. The service water supply header to each unit's component cooling heat exchangers have two motor operated valve installed.

4.1. They serve to isolate service water flow to the accident unit's component cooling heat exchangers during a Design Basis Accident. 4.2. This action ensures sufficient service water flow will be available to the accident unit's recirculation spray heat exchangers following a large break loss of coolant accident. 4.3. Unit 1 component cooling heat exchanger service water supply motor operated valves are 1-SW-MOV-108A and 108B. 4.4. Unit 2 component cooling heat exchanger service water supply motor operated valves are 2-SW-MOV-208A and 208B. REACTOR OPERATOR Page 22 of46 Revision 7,07/16/2008

STUDENT GUIDE FOR SERVICE WATER SYSTEM (13)

5. A series arrangement was chosen for the installation of component cooling heat exchanger service water supply motor operated valves.

5.1. This arrangement ensures that service water will be isolated to the accident unit's component cooling heat exchangers in the event of single train actuation.

6. A Containment Depressurization Actuation on Unit 1 will automatically close 1-SW-MOV-1 08A and 108B.

6.1. A Containment Depressurization Actuation on Unit 2 will automatically close 2-SW-MOV-208A and 208B. 7.

8. The Service Water System is subject to radioactive contamination by component cooling water system at the heat exchangers.

8.1. As such, the service water exiting the component cooling heat exchangers is continuously monitored for radioactivity. 8.2. 1-SW-RM-107 receives service samples from two sampling pumps. 8.3. 1-SW-P-9A is normally aligned to sample service water return header 3 at the outlet of the four component cooling heat exchangers. 8.4. 1-SW-P-9B is normally aligned for sampling service water return header 4. TQpJc.~ *. 2SWTl1rottling 3.2 Objective U 7692 Explain the following concepts concerning "throttled" operation of the Service Water System.

• Why service water throttling is required
• List the three conditions that allow throttling the service water outlet valves from the component cooling heat exchangers
• Two technical specification conditions requiring throttling
• Normal condition (throttled or un-throttled) of the Service Water System REACTOR OPERATOR Page 23 of46 Revision 7,07/16/2008

STUDENT GUIDE FOR SERVICE WATER SYSTEM (13)

2. Under normal operating conditions, it is desirable that the spray valves in use be powered off the same bus as the running service water pumps.

2.1. Two spray arrays are capable of removing 100% of the heat load from one unit during normal operation. 2.2. With both units in operation, a total of four spray arrays are required.

3. All eight of the service water spray valves will open automatically following receipt of a safety injection signal from either unit.

3.1. There is a 15-second time delay associated with the opening of the service water spray valves on a safety injection signal. 3.2. This 15 seconds provides a 5-second time period from the automatic start of the four service water pumps, following restoration of voltage on the emergency buses after an assumed loss of offsite power. 3.3. The 5-second delay prevents possible pump run-out by ensuring all four service water pumps have developed sufficient discharge pressure. 3.4. It should be noted that a safety injection signal from either unit's train "A" or "B" will open the service water spray valves.

4. A minimum of four spray arrays is desired for Design Basis Accident conditions.

4.1. This equates to either two spray arrays per return header or four spray arrays on a single return header. 4.2. As such, the system can operate with only one service water header in service and still have 100% heat removal capability for a Design Basis Accident.

5. During the winter months, the potential exists for freezing of service water spray arrays.

5.1. The spray arrays have drain lines that will drain down isolated spray arrays and thereby prevent freezing. 5.2. If these drain lines are plugged, the associated spray arrays must be drained down manually. REACTOR OPERATOR Page 13 of46 Revision 7, 07/16/2008

STUDENT GUIDE FOR SERVICE WATER SYSTEM (13) 3.2. The normal alignment of the service water pump discharge is as follows: 3.2.1.1-SW-P-1A feeds "A" header 3.2.2.1-SW-P-18 feeds "8" header 3.2.3.2-SW-P-1A feeds "8" header 3.2.4.2-SW-P-18 feeds "A" header

4. The service water pumps may either be controlled locally or remotely.

4.1. The remote control switches are mounted on the "H" and "J" safeguards panels. 4.2. A local control switch is provided on each of the associated 4160 VAC supply breakers located in the Emergency Switchgear Room. 4.2.1.These local control switches satisfy the requirements of Appendix-R.

5. A two-position transfer switch (LOCAL-REMOTE) is located on each service water pump 4160 VAC circuit breaker cabinet.

5.1. This switch allows control of the service water pump to be manually transferred from the control room to the Emergency Switchgear Room. 5.2. When the switch is placed in the "LOCAL" position, the control circuit in the control room will isolate and the local control circuit at the associated breaker will be enabled. 5.3. Control of the breaker can be restored to the control room by turning the transfer switch to the "REMOTE" position.

6. Anyone of the following signals will automatically start the service water pumps:

6.1. Safety injection from either unit will start all four SW pumps 6.1.1. The SI signal is train specific 6.1.1.1. Unit 1 "A" train SI starts the "A" and "8" SW pumps on unit 1, and the "A" SW pump on unit 2. 6.1.1.2. Unit 1 "8" train SI starts the "A" and "8" SW pumps on unit 1, and the "8" SW pump on unit 2. REACTOR OPERATOR Page 16 of 46 Revision 7, 07116/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

58. 077-AAl.03 058INEW//L/3IROINAPSII Unit 1 is at 100% power with approximately 960 MW and 100 MVAR OUT.

The OATe notes the following conditions:

• Sustained Generator output voltage increasE[>
• MVAR sustained increase consistent with Generator output voltag~
• MW stable.

Which ONE of the following identifies the required operator actions based on these plant conditions? A. Maintain Voltage Regulator in AUTO and adjust voltage using Base Adjust; Maintain less than 200 MVAR OUT. B. Maintain Voltage Regulator in AUTO and adjust voltage using Base Adjust; Maintain less than 200 MVAR IN. C. Place Voltage Regulator control switch in OFF and adjust voltage using Base Adjust; Maintain less than 200 MVAR OUT. D!' Place Voltage Regulator control switch in OFF and adjust voltage using Base Adjust; Maintain less than 200 MVAR IN. Feedback

a. Incorrect. First part is incorrect but plausible since the action would be correct if the cause were grid disturbances; second part also incorrect but plausible since candidate may conclude that zeroing vars is the conservative course of action.

b. Incorrect. First part is incorrect as discussed above; second part is the correct subsequent action of the AP.

c. Incorrect. First part is the correct action for the AP in effect; Second part is incorrect but plausible as discussed in distractor a.

d. Correct. First part is the correct action and required by AP-26; second part is also correct as it is a required subsequent step of the AP.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Generator Voltage and Electric Grid Disturbances Ability to operate and/or monitor the following as they apply to Generator Voltage and Electric Grid Disturbances: Voltage regulator controls (CFR: 41.5 and 41.10 /45.5,45.7, and 45.8 ) Tier: 1 Group: 1 Importance Rating: 3.8/3.7 Technical

Reference:

1-AP-26 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info: (

NUMBER PROCEDURE TITLE REVISION 9 1-AP-26 FAILURE OF MAIN GENERATOR VOLTAGE REGULATOR HIGH PAGE 20f3 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION: IF unsure of conditions, THEN leave the Voltage Regulator in Auto. JIShrb-£.-foV 1 1_ CHECK GENERATOR STATUS: Do the following: o

• Sustained Generator output o
• Contact System Operator voltage increase o
• Return to procedure and step in effect AND o
• MVAR sustained increase consistent with Generator output voltage AND o
• MW stable 2 1_ TURN VOLTAGE REGULATOR CONTROL SWITCH TO OFF 3 1_ ADJUST GENERATOR VOLTAGE Do the following:

USING THE VOLTAGE REGULATOR BASE ADJUST o a) IF Reactor power is greater than or equal to SWITCH: 30%, THEN GO TO 1-E-0, REACTOR TRIP OR SAFETY INJECTION. o

• GENERATOR OUTPUT VOLTAGE- NORMAL RANGE o b) IF Reactor power is less than 30%, THEN Trip Turbine and GO TO 1-AP-2.1, TURBINE TRIP o
• MVARs - NOT greater than WITHOUT REACTOR TRIP REQUIRED.

200 MVARs IN

4. NOTIFY SYSTEM OPERATOR THAT VOLTAGE REGULATOR IS IN BASE CONTROL

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) Voltage Regulator Failure 7.1 Objective U 11419 List the following information associated with 1-AP-26, "Failure of Main Generator Voltage Regulator High."

• Purpose of the procedure
• Modes of applicability
• Entry conditions
• Immediate operator actions 7.1 Content

1. The purpose of AP-26, "Loss of Main Generator Voltage Control" is to provide guidance to respond to

( main generator overexcitation.

2. AP-26 is applicable in modes 1 and 2.

3. AP-26 is entered when any of the following conditions exist:

3.1. Annunciator 1K-B4, EXCITER FIELD FORCING is lit. 3.2. Annunciator 1K-C1, OVEREXCITATION is lit. 3.3. Operator discretion.

4. A note cautions the operator to leave the voltage regulator in AUTO if unsure of conditions; the AP then directs the crew to take the following actions:

4.1. Check generator status to ensure that the voltage regulator has failed, and a load swing on the grid did NOT cause the overexcitation (if it did, the operator contacts the system operator and exits the AP). 4.2. Turn the voltage regulator OFF. REACTOR OPERATOR Page 41 of 158 Revision 30, 11/06/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) 4.3. Adjust voltage using the BASE ADJUST switch until generator output voltage is in the normal range and MVARs are :0; 200 IN. 4.3.1. If unable to adjust voltage using BASE ADJUST: 4.3.1.1. If reactor power ~ 30% go to E-O. 4.3.1.2. If reactor power is < 30% go to 1-AP-2.1. 7.2 Objective U 11420 Explain the purpose of the following high-level action steps associated with 1-AP-26, "Failure of Main Generator Voltage Regulator High." (

• Verify the validity of the overexcited condition.
• Adjust the voltage regulator.

7.2 Content

1. The crew determines if the overexcited condition is valid to prevent making the situation worse.

1.1. If the voltage regulator is functioning properly, and the condition is due to a perturbation on the grid (MW swing), then the best course of action is to leave the voltage regulator in automatic and allow it to control voltage. 1.2. Protective features in the voltage control system are designed to cause actuations that prevent generator damage due to overexcitation, but they function best if the voltage regulator is in automatic control.

2. An attempt is made to adjust generator output voltage using BASE ADJUST, if possible.

2.1. If unable to adjust voltage, the unit is tripped to prevent generator damage due to overexcitation. REACTOR OPERATOR Page 42 of 158 Revision 30, 11/06/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

59. 078-K2.02 059/MODIFIEDINAPS/L/2IROINAPS//

The Service Air Compressors are powered from their respective unit's _ _ _ _ _ _ _ _ and the Instrument Air Compressors are powered from their repective unit's _ _ _ _ _ _ _ __ A'! "B" 480-Volt Station Service Bus; "H" 480-Volt Emergency Bus B. "B" 480-Volt Station Service Bus; "'J" 480-Volt Emergency Bus C. "G" 480v Station Service Bus; "H" 480-Volt Emergency Bus D. "G" 480-Volt Station Service Bus; "J" 480-Volt Emergency Bus Feedback

a. Correct. Power supplies are correct.

b. Incorrect. power supplies for SACs is correct, however power supplies for lACs is incorrect but plausible since each unit has a containment instrument air compressor powered from 'J' train and candidate may confuse this.

c. Incorrect. Plausible since the units have an auto transfer feature for the 'G' busses making them more reliable, since SACs are the normal source of Instrument air, the candidate who is not knowledgable of compressor power supplies may consider 'G' bus a logical choice from the reliability standpoint and thus sellect this distractor; pwer supply for lACs is correct.

d. Incorrect. Both parts incorrect but plausible as discussed above.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Instrument Air System (lAS) Knowledge of bus power supplies to the following: Emergency air compressor (CFR: 41.7) Tier: 2 Group: 1 Importance Rating: 3.3/3.5 Technical

Reference:

Station Load list Proposed references to be provided to applicants during examination: none Learning Objective: Question History: modified (two questions combined to provide more depth) additional info: NAPS does not have a specific 'emergency' air compressor, however the instrument air compressors are powered from the emergency busses where as the service air compressors that normally run to supply the system come from station service. Knowledge of the specific emergency bus is important since for loss of offsite power events the operator must be aware of the importance of having at least one 'H' bus energized to supply instrument air (a loss of instrument air would complicate recovery actions).

DOMINION 1-0P-26A North Anna Power Station Revision 44 Page 54 of 140 (Page 5 of 5) Attachment 19 1-EE-MCC-1 H1-2S, 1 H1-2S Motor Control Center 1-EP-MC-20 LOCATION: CABLE VAULT POWER SUPPLY: I-EE-BKR-14HI-7

REFERENCE:

11715-FE-IQ Breaker Required Ind No. Load Position Verifier Verifier I-HV-F-40A, M4 On Safeguards Area Exhaust Fan Circuit Breaker I-EP-CB-4IAN, Heat Trace Distribution Panel Circuit Cold Weather On Breaker, AND N2L I-EP-CB-4IBN Heat Trace Distribution Circuit Breaker Hot Weather Off Hot Weather I-EP-CB-14N, N2R On Heat Trace Distribution Panel Ckt Bkr l-CH-P-ICl, N3 On IC Charging Pump Aux Oil Pump Circuit Breaker I-SW-P-5, N4 On Rad Monitor Sample Pump Circuit Breaker PI l-IA-C-l AUX BLDG INSTR AIR COMP On MODE 1-4 Off REC-29, 480 V oIt Power Receptacle P2L Circuit Breaker MODE 5 &6 On ** l-IC-DRIV-ID, P2R On Incore Instrumentation Drive Assembly Ckt Bkr l-CH-P-IAl, P3 On Aux Oil Pump For l-CH-P-IA Ckt Bkr P4 On l-RM-P-159A & B Sample Pump Feed

• • IF breaker is on with the Unit in Mode 5 or 6, THEN have the SRO enter into the Action Statement Status Log to open the Breaker prior to entering Mode 4. (Reference 2.1.2)

DOMINION 2-0P-26A North Anna Power Station Revision 42 Page 51 of 156 (Page 3 of 4) Attachment 19 2-EE-MCC-2H1-2S LOCATION: CABLE VAULT POWER SUPPLY: 2-EE-BKR-24H-3

REFERENCE:

I2050-FE-IN Breaker Required Ind No. Load Position Verifier Verifier 2-CH-MOV-2380, HI On Seal Water Return Inside Isol Circuit Breaker 2-RC-MOV-2595, H2 Locked Off C Reactor Cool Loop Cold Leg Isol Valve Ckt Bkr 2-RC-MOV-2592, H3 Locked Off B Reactor Cool Loop Hot Leg Isol Valve Ckt Bkr 2-RS-MOV-20lB, H4 On B Casing Cooling Pump Discharge Isol Valve CB 2-RC-MOV-2593, J1 Locked Off B Reactor Cool Loop Cold Leg Isol Valve Ckt Bkr 2-HC-HC-I, J2L On Unit 2 Hydrogen Recombiner Circuit Bkr I-EP-CB-129, J2R On Alt Feed To I-HC-H2A-IOI Ckt Bkr J3L Spare, J3L Off Spare Circuit Breaker 2-EP-CB-84AI, J3R On Quench Spray Area Motor Heater Cabinet Ckt Bkr I-HV-F-75B, J4 On Auxiliary Building Appendix "R" Fan Ckt Bkr 2-IA-C-I, KI On Instrument Air Cprsr I Circuit Breaker 2-IC-DRIV-ID, K2L On Incore Instrumentation Drive Assembly Ckt Bkr K2R Off Spare 2-DA-P-IA, K3 On IA Safeguards Area Sump Pump Circuit Breaker

VIRGINIA POWER l-AR-24 NORTH ANNA POWER STATION REVISION 6 WINDOW 1 PAGE 1 OF 1 VOLTAGE ON 1.0 PROBABLE CAUSE This is a status light indicating that Breaker 14B2-16, power supply to I-SA-C-l is racked to connect and closed. 2.0 OPERATOR ACTION None

3.0 REFERENCES

• Atlas Copco Instruction Manual
• DCP 89-04B
• 11715-TESK-SA-2 (Unit 1 Instrument Loop Book, page SA-006) 4.0 ACTUATION lLT relay

VIRGINIA POWER 2-AR-l4 NORTH ANNA POWER STATION REVISION 7 WINDOWl PAGE 1 OF 1 VOLTAGE ON 1.0 PROBABLE CAUSE This is a status light indicating that Breaker 24Bl-3, power supply to 2-SA-C-l is racked to connect and closed. 2.0 OPERATOR ACTION None

3.0 REFERENCES

• Atlas Copco Instruction Manual
• DCP 89-04B
• l2050-TESK-SA-2 (Unit 2 Instrument Loop Book, page SA-005) 4.0 ACTUATION lLT relay

STUDENT GUIDE FOR COMPRESSED AIR SYSTEM (17) 2.3 Objective U 4272 List the following information associated with the instrument air compressors.

• Source of air to suction of the compressors
• Pressure at which the compressor loads and unloads with its control switch in HAND
• Pressure at which the compressor loads and unloads with its control switch in AUTO
• Pressure for automatically starting a compressor with its control switch in AUTO
• Source of electrical power
• Type of cooling for the control cabinet
• Parameters monitored from control cabinet
• Annunciators on the compressor alarm panel
• Interlocks which will trip the compressor automatically 2.3 Content

1. A common suction header supplies both Instrument Air Compressors.

1.1. The supply air is drawn through two suction filter muffler assemblies located on the fourth floor of the Auxiliary Building.

2. The Instrument Air Compressors loads at 103 psig decreasing and unloads at 109 psig increasing with its control switch in HAND.

3. The Instrument Air Compressor loads at 98 psig decreasing and unloads at 106 psig increasing with its control switch in AUTO.

4. The pressure for automatically starting an Instrument Air Compressor with its control switch in AUTO is 98 psig.

5. The source of electrical power for the instrument air compressors is as follows:

REACTOR OPERATOR Page 11 of 35 Revision 5, 10109/2008

STUDENT GUIDE FOR COMPRESSED AIR SYSTEM (17) ( 5.1. 1-IA-C-1 is supplied by 1H 1-2S 5.2. 2-IA-C-1 is supplied by 2H 1-2S

6. Instrument air cabinet cooling 6.1. IA compressor cabinet cooling from a motor driven fan 6.2. Control cabinet uses vortex cooling. Cooling air is taken off the Instrument Air header via a 3lB-inch line.

6.2.1.The air passes through a TCV and dumps into the cabinet. 6.2.2.Cooling air then flows over components and out bottom.

7. The instrument air compressors have local indications.

7.1. Air Temperature LP Outlet (1-IA-TIS-1 01) alarms locally at 425°F increasing, tripping the compressor. 7.2. Air Temperature HP Outlet (1-IA-TIS-1 02) alarms locally at 425°F increasing, tripping the compressor. 7.3. Air Temperature HP Inlet (1-IA-TIS-1 03) alarms locally at 145°F increasing, tripping the compressor. 7.4. Oil Temperature (1-IA-TIS-1 04) alarms locally at 175°F increasing, tripping the compressor trip. 7.5. Oil Pressure (1-IA-PI-125) 7.6. Discharge Pressure (1-IA-PI-126) 7.7. Inter-cooler Pressure (1-IA-PI-127) 7.B. Filter Indicator (1-IA-PI-12B) 7.9. Water Temperature Compressor (1-IA-TI-1 07) 7.10. Water Temperature Aftercooler (1-IA-TI-1 OB) 7.11. Air Temperature Outlet (1-IA-TI-1 09) B. The instrument air compressor alarm panel has the following alarms:(AIi

• are compressor trips)

B.1. Compressor Not Ready alarm. ( B.1.1 .Auto trips not reset or Stop Pushbutton depressed. REACTOR OPERATOR Page 12 of 35 Revision 5, 10109/200B

STUDENT GUIDE FOR COMPRESSED AIR SYSTEM (17) 3.1.2.Unloads at 111 psig increasing 3.2. In AUTO the compressor starts based on system pressure. 3.2.1. Loads at 98 psig decreasing 3.2.2. Unloads at 106 psig increasing 3.2.3.lf unloaded for 20 min compressor will stop 3.2.4.lf pressure then falls the 98 psig compressor will start

4. The power supply breaker for the Service Air Compressor is located in 307' switch-gear.

4.1. This breaker must be closed for the compressor to be in operation or standby. 4.2. A local contactor at the compressor will operate to control the operation based on control room switch positions.

5. After an under-voltage condition the following will occur when Service Air Compressors are re-energized:

5.1. All local annunciators will be illuminated 5.2. The local "Reset" pushbutton must be depressed to clear all trouble lights and allow the compressor to start. 5.3. When alarms are cleared, the compressor will respond depending on system pressure and mode selected. REACTOR OPERATOR Page 25 of 35 Revision 5, 10109/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

60. I03-Al.OI 060IMODIFIEDINAPS/H/3IRO///

If Chilled Water to Containment is lost, the indicated containment partial air pressure will _ _ __ and the digital containment partial air pressure indicators are _ _ _ _ _ _ ' A"!' decrease; inoperable B. decrease ; operable C. increase; inoperable D. increase; operable Feedback

a. Correct. The loss of cooling flow will cause the decrease; second part is also correct the indicators are not considered accurate and thus are declared inoperable per 1-AP-35 until cooling water flow is reestablished.

b. Incorrect. First part is correct; second part incorrect but plausible since the candidate who does not have detailed knowledge of the procedure would likely not see any reason to declare the indicators inoperable solely because chilled water flow is interupted to the fan coolers, and thus sellect this distractor.

c. Incorrect. First part incorrect but plausible since the candidate who lacks detailed systems knowledge could easily reverse the cause and effect relationship and thus sellect this distractor; second part is correct.

d. Incorrect. First part incorrect but plausible as discussed in Distractor c; second part also incorrect but plausible as discussed in Distractor b.

NUMBER PROCEDURE TITLE REVISION 17 1-AP-35 LOSS OF CONTAINMENT AIR RECIRCULATION COOLING PAGE 2 of 8 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE: The loss of Containment Air Partial Pressure indicator(s) does NOT necessarily mean non-compliance with Tech Spec 3.6.4.

1. DECLARE THE DIGITAL CONTAINMENT PARTIAL AIR PRESSURE INDICATORS INOPERABLE:

o

• 1-LM-PI-101A-1 o
• 1-LM-PI-101B-1 2._ INITIATE ATTACHMENT 2, CALCULATION OF CONTAINMENT AIR PARTIAL PRESSURE, WHILE CONTINUING WITH THIS PROCEDURE NOTE: Because of Environmental Qualification concerns relating to equipment life expectancy, Containment Average Air temperature should be kept less than 105 of.

3. CHECK CONTAINMENT AVERAGE AIR TEMPERATURE:

o a) Less than 115 of o a) Enter Action Statement of Technical Specification 3.6.5. o b) Less than 105 of o b) Notify Engineering Department.

STUDENT GUIDE FOR PRIMARY VENTILATION SYSTEM (47) 1.7 Objective U 4598 Explain how the containment air partial pressure indication is affected by changing the alignment of the containment air recirculation fans and/or cooling water. 1.7 Content

1. The saturation temperature used for deriving the saturation pressure for use in the air partial pressure calculation is sensed between the air cooler and the recirc fan.

1.1. If the cooling water flow to the air coolers is reduced or isolated then the sensed temperature will increase. 1.2. This will cause the indicated Tsat to increase; therefore, the indicated Psat will increase which will cause the partial pressure to read lower than actual. 1.3. The same effect will occur if all recirc air fans trip. 1.4. If only one fan trips there should not be a large change, since the Tsat is sensed at all three fans and the lowest of the three temperatures is used. 1.8 Objective U 4483 List the following information as it applies to the containment dome recirculation fans.

• Areas upon which the fans draw suction
• Location to which the fans' discharge is directed 1.8 Content

1. The Containment dome recirculation air fans HV-F-92A, -92B, and -92C are located on the operating floor/deck of the Containment Structure (291 foot elevation).

1.1. The fans take suction on the cooler air in the lower level (RCP motor cube/loop rooms). REACTOR OPERATOR Page 10 of 65 Revision 3, 07/24/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Containment System Knowledge of system set points, interlocks and automatic actions associated with EOP entry conditions. (CFR: 41.7/45.7/45.8) Tier: 2 Group: 1 Importance Rating: 4.5/4.6 Technical

Reference:

1-F-O Proposed references to be provided to applicants during examination: none Learning Objective: Question History: new additional info:

NUMBER ATTACHMENT TITLE ATTACHMENT 1-F-O 5 CONTAINMENT REVISION PAGE 7 1 of 1 GO TO 1-FR-Z.1

                                                                                                                                          ~    GOTO IIIIII11111!I11111 I11III I11III I11III I11IIII11III ~ 1-FR-Z.1 AT LEAST ONE CONTAINMENT         NO       QUENCH               NO PRESSURE                     SPRAY PUMP LESS THAN 60 PSIA  YES       RUNNING WITH DISCHARGE MOVOPEN Y  GO TO 1-FR-Z.1 CONTAINMENT        NO PRESSURE LESS THAN 28 PSIA      YES IlIIII  I11III   IIIIIIIlIIIIIIIII 1IIII1lIIII1IIIII!1IIIII1IIIII!

GO TO 1-FR-Z.2 III III CONTAINMENT SUMP NO LEVEL LESS THAN 11 FEET 0 INCHES YES GO TO Y 1-FR-Z.3 NO CONTAINMENT RADIATION LESS THAN 2 RlHR YES r;l W GOTO 1-FR-ZA y.eP1r CONTAINMENT PRESSURE LESS THAN 14.5 PSIY CSF SAT

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95) 1.5 Objective U 12706 List the plant conditions that result in reaching an orange path terminus for each of the following critical safety functions (1-F-O).

• Subcriticality
• Core cooling
• Integrity
• Containment 1.5 Content

1. The Subcriticality orange path condition is:

1.1. Intermediate Range startup rate positive (with power range less than 5%) [gamma-metrics WR power increasing]

2. The Core Cooling orange path condition is:

2.1. All of the following: 2.1.1.RCS subcooling :s; 25°F [75°F] 2.1.2.No RCP running 2.1.3.Core exit TICs ~ 700°F (but less than 1200) 2.1.4.RVLlS full range greater than 48% OR 2.2. All of the following: 2.2.1.RCS subcooling :S;25°F [75°F] 2.2.2.No RCP running 2.2.3.Core exit TICs less than 700°F 2.2.4.RVLlS full range :s; 48% OR 2.3. All of the following: REACTOR OPERATOR Page 11 of 99 Revision 14, 11/06/2008

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95) 2.3.1.Core exit T/Cs less than 1200°F 2.3.2.RCS subcooling ~25°F [75°F] 2.3.3.At least one RCP running 2.3.4.RVLlS dynamic range as follows: 2.3.4.1. ~ 65% (3 RCPs) 2.3.4.2. ~ 41 % (2 RCPs) 2.3.4.3. ~ 30% (1 RCP)

3. The Integrity orange path condition is:

3.1. Either of the following sets of conditions: 3.1.1.Temperature decrease in any RCS cold leg ~ 100°F in the last 60 minutes, all RCS pressure/cold leg temperature points to the right of limit A, but at least one RCS cold leg temperature ~ 285°F. 3.1.2.Temperature decrease in all RCS cold legs less than 100°F in the last 60 minutes, any RCS cold leg temperature ~ 285°F, and RCS pressure ~ 535 psig.

4. The Containment orange path condition is:

4.1. Either of the following: 4.1.1.Containment pressure ~ 28 psia (but less than 60 psia) and no Quench Spray pump running. OR 4.1.2.Containment sump level ~ 11 feet 0 inches. 1.6 Objective U 13017 Explain the actions required if each of the following is encountered when monitoring the critical safety function status trees (1-F-0). REACTOR OPERATOR Page 12 of 99 Revision 14, 11/06/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

62. G2.1.28RO 062/BANKINAPS/H/3/ROINAPS/l Both units are at 100% power with no equipment out of service (except as noted below).

Which ONE of the following events would initiate an automatic start of the SBO diesel? A"! With "C" RSST out of service, a loss of 34.5 KV bus #4 occurs. B. With "B" RSST out of service, a loss of 34.5 KV bus #4 occurs. C. Spurious trip of breaker 15F1, "F" transfer bus supply. D. With "A" RSST out of service, a loss of 34.5 KV bus #4 occurs. Feedback

a. Correct. Both transfer busses to a unit emergency busses must lose power to start the S80, given 'C' RSST (normal feed to F xfer bus which feeds 2J emergency bus) lossing bus 4 would take out B RSST and thus E xfer bus which feeds 2H so both unit 2 normal supplies are lost and the SBO start logic is made up.

b. Incorrect. Plausible since the electrical distribution system is complicated and easily confused, moreover there are off-normal alignments that are possible that would make this distractor correct, so the candidate must have detailed knowledge of the normal alignment as well as the knowledge of the SBO start logic to eliminate this distractor. For this distractor only 2H bus does not have its normal feed so start logic is not made up.

c. Incorrect. Plausible as discussed above. In this case a bus on each unit losses normal feed so two are lost but again it is not two lost on THE SAME unit which is needed to make up start logic.

d. Incorrect. Plausible as discussed above, again this is a case where two busses are lost but it is one on each unit so start logic isn't satisfied.

QUESTIONS REPORT ( for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes 2.1.28 Knowledge of the purpose and function of major system components and controls. (CFR: 41.7) Tier: 3 Importance Rating: 4.1/4.1 Technical

Reference:

SSO lesson plan Proposed references to be provided to applicants during examination: None Learning Objective: 6539 Question History: bank additional info:

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For Informalion,Only Revised 512:5195 NORTH ANNA POWER STATION ELECTRICAL POWER DISTRIBUTION

STUDENT GUIDE FOR STATION BLACKOUT DIESEL GENERATOR SYSTEM (55-B) 2.10 Objective U 10786 State the interlock conditions required to automatically start the station blackout diesel generator. 2.10 Content

1. An under voltage condition on both transfer busses associated with either unit will cause the station blackout diesel generator to automatically start and sequence.

1.1. The under voltage condition must be sensed by two-out-of-two under voltage relays on both of the units transfer busses. 1.1.1.2/2 UV relays on "D" transfer bus and 2/2 UV relays on "F" transfer bus OR; 1.1.2.2/2 UV relays on "E" transfer bus and 2/2 UV relays on "F" transfer bus 2.11 Objective U 10907 State the interlock conditions that would cause the station blackout diesel generator to shut down automatically. 2.11 Content

1. The following conditions will cause an automatic shutdown of the SSO diesel generator:

1.1. Low lube oil pressure 1.1.1.Less than 15.2 psig when engine speed is greater than 170 rpm AND less than 650 rpm 1.1.2. Less than 37.7 psig when engine speed is greater than 650 rpm 1.2. Engine over-speed 1.2.1.1017 rpm by magnetic pickup/speed switch 1.2.2.1035 rpm by over-speed controller. 1.3. High crankcase pressure (greater than 4 inches H20 positive pressure) 1.4. Loss Of Jacket Water (less than 2 psig) REACTOR OPERATOR Page 24 of 57 Revision 0, 1% 1/2006

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

63. G2.1.4RO 063IMODIFIEDINAPS/L/2IROINAPSII In order to maintain an active license, a Reactor Operator must stand a MINIMUM of __ 12-hour shifts per calendar quarter.

A. 4 B. 7 C~ 5 D. 8 Feedback

a. Incorrect. since more than 40 hours is stood and that sounds like a reasonable minimum time.

b. Incorrect. plausible as discussed in Distractor A this would be slightly greater than 80 hours and is reasonable considering the 90 day time frame.

c. Correct. First part is the minimum for maintaining the License active.

d. Incorrect. Plausible as discussed above.

Notes Conduct of operations Knowledge of individual licensed operator responsibilities related to shift staffing, such as medical requirements, "no-solo" operation, maintenance of active license status, 10CFR55, etc. (CFR: 41.10 143.2) Tier: 3 Importance Rating: 3.3/3.8 Technical

Reference:

admin procedure and activation paperwork from LORP Proposed references to be provided to applicants during examination: None Learning Objective: Question History: modified additional info: combines to test items one for activation one for reactivation

DOMINION VPAP-2702 REVISION 16 PAGE 6 OF 38 4.5 "Active" License A license whose holder has completed the mandatory number of shifts (five 12-hour or seven 8-hour shifts) assigned to an operating crew and performing licensed duties during the previous calendar quarter, OR A license that has been reactivated by the holder meeting criteria as specified in 6.6.4. 4.6 "Inactive" License A license whose holder has not completed the requirements for maintaining an active license. 4.7 Academic Review Board A board consisting of the Initial license class lead instructor, Manager Nuclear Operations, Assistant Manager Nuclear Operations or Supervisor Nuclear Shift Operations, Director of Engineering (for direct SROs from Engineering), Supervisor Nuclear Training - Initial Operations, and the Manager Nuclear Training that meets to consider license class issues relative to meeting program requirements. 5.0 RESPONSIBILITIES ( 5.1 Site Vice President The Site Vice President is responsible for: 5.1.1 Approving retention of non-licensed operators. 5.1.2 Authorizing candidate entry into license class. 5.1.3 Authorizing candidates to take NRC examinations. 5.1.4 Concurring in termination of licenses by the Manager Nuclear Operations. 5.1.5 Authorizing return of individuals, previously removed due to a significant medical reason, to licensed duties. 5.1.6 Approving removal of candidates from initial license class who do not meet program requirements. 5.2 Plant Manager (Nuclear) The Plant Manager (Nuclear) is responsible for: 5.2.1 Recommending License Class candidates. 5.2.2 Recommending candidates to take NRC examinations.

STUDENT GUIDE FOR ADMINISTRATIVE PROCEDURES (100)

• If the code does not match or if the NRC questions the operator's identity, then hang up immediately and call back to the NRC without using a code.

1. 1.51 Objective U 13586 Explain the requirements associated with the following activities as they apply to reactor operator training and licensing (VPAP-2702).

• Individual licensee obligations in the event of physical or mental incapacitation
• Licensee re-activation following inactive status 1.51 Content

2. Individual Licensee Obligations o Individual licensed Reactor Operators and Senior Reactor Operators shall be subject to the conditions generically specified in 10 CFR 55.53, Conditions of Licenses, and the conditions specified, either generically or specifically, on the individual's license.

o Additionally, each licensed individual shall report promptly to his/her supervisor, or the Manger Nuclear Operations, any physical or mental conditions that might be considered incapacitating with respect to 10 CFR 55.25, Incapacitation because of Disability or Illness.

3. An individual license will be designated in an inactive status if he/she has not met the minimum requirements of seven 8-hour or five-12 hour shifts per calendar quarter. Prior to a license being re-activated, the following actions must be completed:

o The licensee must complete the re-activation on-shift requirements. o The Site Vice President shall authorize resumption of licensed activities following certification of completion of applicable requirements. o The following individuals shall be informed of the authorization to return to licensed duties:

• Manager Nuclear Operations
• Manager Nuclear Training REACTOR OPERATOR Page 53 of 106 Revision 16, 09/19/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

64. G2.2.l5RO 064INEWIIH/3IROINAPSII Given the following conditions:

• Unit 1 is at 100% power.
• Annunciator B-H2, PRZ POWER RELIEF LINE HI TEMP is received.

During the next 1 hour, PRT level increases from 72% to 76%.

• ReS Leakage prior to the event was 0.5 gpm Identified, and 0.3 gpm Unidentified.

Based on the above conditions, which ONE of the following describes the Technical Specification implications of the leaking PORV? (Reference provided) A"! Res Operational Leakage remains within Technical Specification Limits. B. The limit for Identified Leakage has been exceeded. C. The limit for Pressure Boundary Leakage has been exceeded. D. The limit for ReS Pressure Isolation Valve (PIV) Leakage has been exceeded. Feedback

a. Correct. Inleakage from the PORV is approximately 6.7 gpm this is defined as IDENTIFIED LEAKAGE by TS, TS 3.4.13 limit for identified leakage is 10 gpm

                           =

so 6.7+0.5 7.2 which is less than 10.

b. Incorrect. Plausible since candidate may mis-read curve, not recall the limit for identified leakage, or make a calculatonal error.

c. Incorrect. Plasuible as discussed above and also candidate may not have detailed knowledge of TS definitions and erroneously default to this distractor.

d. Incorrect. Plausible as discussed above, and again if the candidate does not realize that a PORV is NOT classified as aRCS PIV they may erroneously sellect this distractor.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Equipment Control Ability to determine the expected plant configuration using design and I configuration control documentation, such as drawings, line-ups, tag-outs, etc. I (CFR: 41.10/43.3/45.13) Tier: 3 Importance Rating: 3.9/4.3 Technical

Reference:

PRT curve and TS and TS basis Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info: (

                   -  NUCLEAR DESIGN INFORMATION PORTAL-RCS Operational LEAKAGE 3.4.13 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.13 RCS Operational LEAKAGE LCO 3.4.13          RCS operational LEAKAGE shall be limited to:      ~

a. No pressure boundary LEAKAGE;"""'-

J..; S~c.- J _.. {-vY- ___ J. s;V __c-.

b. 1 gpm unidentified LEAKAGE;

c. 10 gpm identified LEAKAGE; r;-~/ d. 150 gallons per day primary to secondary LEAKAGE through anyone steam generator (SG).

APPLICABILITY: MODES 1, 2, 3, and 4. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. RCS operational A.l Reduce LEAKAGE to 4 hours LEAKAGE not within withi n 1imits. limits for reasons other than pressure boundary LEAKAGE or primary to secondary LEAKAGE. B. Required Action and B.l Be in MODE 3. 6 hours associated Completion Time of Condition A AND not met. B.2 Be in MODE 5. 36 hours OR Pressure boundary LEAKAGE exists.

    -OR Primary to secondary LEAKAGE not within 1imi t.

North Anna Units 1 and 2 3.4.13-1 Amendments 248/228

                       -  NUCLEAR DESIGN INFORMATION PORTAL-RCS Operational LEAKAGE 3.4.13 SURVEILLANCE REQUIREMENTS SURVEILLANCE                           FREQUENCY SR 3.4.13.1    -------------------NOTES-------------------

1. Not required to be performed until 12 hours after establishment of steady state operation.

2. Not applicable to primary to secondary LEAKAGE.

Verify RCS operational LEAKAGE is within 72 hours limits by performance of RCS water inventory balance. SR 3.4.13.2 -------------------NOTE-------------------- Not required to be performed until 12 hours after establishment of steady state operation. Verify primary to secondary LEAKAGE is 72 hours

               ~ 150 gallons per day through anyone SG.

North Anna Units 1 and 2 3.4.13-2 Amendments 248/228

DESIGN Ii\!FOAIliU\TIOf\I 1',,""'<137 ft. RCS PIV Leakage 3.4.14 ( 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.14 ReS Pressure Isolation Valve (PIV) Leakage ~ ~~~~ LCO 3.4.14 Leakage from each RCS PIV required to be tested shall be within limit. APPLICABILITY: MODES 1, 2, and 3, MODE 4, except any required valves in the residual heat removal (RHR) flow path when in, or during the transition to or from, the RHR mode of operation. ACTIONS

 - - - - - - - - - - - - - - - - NOTES - - - - - - - - - - - - - - - -

1. Separate Condition entry is allowed for each flow path.

2. Enter applicable Conditions and Required Actions for systems made inoperable by an inoperable PIV.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more flow paths A.1 Restore RCS PIV 4 hours with leakage from one leakage to within or more required RCS 1i mi t. PIVs not within limit. B. Required Action and B.1 Be in MODE 3. 6 hours associated Completion Time for Condition A AND not met. B.2 Be in MODE 5. 36 hours North Anna Units 1 and 2 3.4.14-1 Amendments 231/212

                       - NUCLEAR DESIGN INFORMATION PORTAL-RCS PIV Leakage 3.4.14 SURVEILLANCE REQUIREMENTS SURVEILLANCE                            FREQUENCY SR 3.4.14.1    -------------------NOTES-------------------

1. Not required to be performed in MODES 3 and 4.

2. Not required to be performed on any RCS PIVs required to be tested located in the RHR flow path when in the shutdown cooling mode of operation.

3. RCS PIVs actuated during the performance of this Surveillance are not required to be tested more than once if a repetitive testing loop cannot be avoided.

Verify leakage from each RCS PIV required In accordance to be tested is equivalent to s 0.5 gpm per with the nominal inch of valve size up to a maximum Inservice of 5 gpm at an RCS pressure ~ 2215 psig and Testing s 2255 psig. Program, and 18 months AND Pri or to enteri ng MODE 2 whenever the unit has been in MODE 5 for 7 days or more, if 1eakage tes t i ng has not been performed in the previ ous 9 months AND Wi thi n 24 hours fo 11 owi ng valve actuation due to automat i c or manual action or flow through the valve North Anna Units 1 and 2 3.4.14-2 Amendments 231/212

VIRGINIA POWER I-SC-S.ll NORTH ANNA POWER STATION REVISION 1 fVO £6 ~ -rht~ tJ PAGE 1 OF7 ft--G v",.kx~Ge f9 V'ovTc1-ed Pressurizer Relief Tank l-RC-TK-2 Volume Versus Indicated Level 120 9532 Gallona at 99.5% lndicatior I-100 if t IJ"

                                                                                                     ~

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IJ J " 223 Gallonut 0 % Indicatiol o J "'1111111111. I I o 1000 2000 3000 4000 SOOO 6000 7000 8000 9000 10000 Gallons APPROVED BY: CHAIRMAN, STATION NUCLEAR SAFETY AND OPERATING COMMITIEE

. VIRGINIA POWER .1-SC-5.1l NORTH ANNA POWER STATION REVISION 1 PAGE 2 OF 7 PRESSURIZER RELIEF TANK 1-RC-TK-2 VOLUME VERSUS INDICATED LEVEL NOTE:

• Level transmitter reference leg Calibration temperature is 70°F with density 62.305 lbmlff.
• Actual tank water temperature is 85°F With a density of 62.112 Ibmlre.
• The transmitter will no longer increase with increasing level after 99.5 percent indication.

EQUIVALENT INDICATED HOOF VOLUME LEVEL (%) (GALLONS) 0.0 223.19 0.5 247.91 1.0 273.50 1.5 299.93 2.0 327.17 2.5 355.20 3.0 383.99 3.5 413.51 4.0 443.76 4.5 474.71 5.0 506.34 5.5 538.64 6.0 571.58 6.5 605.16 7.0 639.36 7.5 674.17 8.0 709.56 8.5 745.53 9.0 782.06 9.5 819.15 10.0 856.78 10.5 894.93 11.0 933.60

                        *11.5                                                 972.78 12.0                                               1012.45 APPROVED BY:                                                                              DATE:~lXl./$l..

CHAIRMAN, STATION NUCLEAR SAFETY AND OPERATING COMMITI'EE

VIRGiNIA POWER 'I-SC-5.11 NORTH ANNA POWER STATION REVISION 1 PAGE 3 OF7 PRESSURIZER RELIEF TANK l-RC-TK-2 VOLUME VERSUS INDICATED LEVEL EQUIVALENT INDICATED HOOF VOLUME LEVEL (%) (GALLONS) 12.5 1052.61

                   ,13.0                        1093.25 13.5                         1134.35 14.0                         1175.91
                  ,14.5                         1217.91 15.0                         1260.35 15.5                         1303.22 16.0                         1346.51 16.5                         1390.22 17.0                         1434.32 17.5                         1478.82 18.0                         1523.71 18.5                         1568.98
                 , 19.0                         1614.61 19.5                         1660.62 20.0                         1706.97 20.5                         1753.68
                  '21.0                         1800.72 21.5                         1848.11 22.0                         1895.81 22.5                         1943.84, 23.0                         1992.18 23.5                         2040:'82 24.0                         2089.77 24.5                         2139.00 25.0                         2188.53 25.5                         2238.33 26.0                         2288.40 26.5                         2338.74 27.0                         2389.34 27.5                         2440.20 28.0                         2491.30 28.5                         2542.64 29.0                         2594.22 29.5                         2646.02,

 . VIRGINIA POWER            .                                         1-SC-5.U NORTH ANNA POWER STATION                                          REVISION 1 PAGE 4 OF 7

( PRESSURIZER RELIEF TANK 1-RC-TK-2 VOLUME VERSUS INDICATED LEVEL EQUIVALENT INDICATED HOOP VOLUME LEVEL (%) (GALLONS) 30.0 2698.05 30.5 2750.30 31.0 2802.75

                     . 31.5                         2855.42 32.0                        2908.28 .

32.5 2961.33 33.0 3014.57 33.5 3068.00

                       .34.0                        3121.60 34.5                        3175.37 35.0                        3229.30 35.5                        3283.40 36.0                        3337.64 36.5                        3392.04 37.0                        3446.58 37.5                        3501.25 38.0                        3556.06 38.5                        3610.99 39.0                        3666.04 39.5                        3721.21 40.0                        3776.49 40.5                        3831.87 41.0                        3887.35 41.5                        3942.92 42.0                        3998.58 42.5                        4054.33 43.0                        4110.15 43.5                        4166.05 44.0                        4222.00 44.5                        4278.03 45.0                        4334.11 45.5                        4390.24 46.0                        4446.41 46.5                        4502 ..63 47.0                        4558.89

VIRGINIA POWER I-SC-5.1l NORTH ANNA POWER STATION REVISION 1 PAGE 5 OF7 PRESSURIZER RELIEF TANK l-RC-TK-2 VOLUME VERSUS INDICATED LEVEL EQUIVALENT INDICATED HOoP VOLUME LEVEL (%) (GALLONS) 47.5 4615.17 48.0 4671.48 48.5 4727.80 49.0 4784.15 49.5* . 4840.50 50.0 4896.85 50.5 4953.20 51.0 5009.55 51.5 5065.89 52.0 5122.21 52.5 5178.51 53.0 5234.78 53.5 5291.02 ( 54.0 5347.22 54.5 5403.37

                   *55.0                          5459.49 55.5                          5515.54 56.0                          5571.54 56.5                          5627.48 57.0                          5683.33 57.5                          5739.13 58.0                          5794.84 58.5                          5850.46 59.0                          5906.00 59.5                          5961.43 60.0                          6016.78 60.5                          6072.00 61.0                          6127.12 61.5                          6182.13 62.0                          6237.00 62.5                          6291.76 63.0                          6346.37 63.5                          6400.85 64.0                          6455.18 64.5                          6509.36

, . . VIRGINIA POWER I-SC-5.11 NORmANNA POWER STATION REVISION 1 PAGE 6 OF 7

             . PRESSURIZER RELIEF TANK l-RC-TK-2 VOLUME VERSUS INDICATED LEVEL EQIDVALENT INDICATED                      . llO oP VOLUME LEVEL (%)                                 (GALLONS) 65.0                               6563.39 65.5                               6617.26 66.0                               6670.95 66.5                               6724.48 .

67.0 6777.82 67.5 6830.99 68.0 6883.96 68.5 6936.74 69.0 6989.31 69.5 7041.68 70.0 7093.83 70.5 7145.77 71.0 . 7197.48 71.5 7248.~*.*.J 72.0 i. 7300.20'"

                                                             ~-~,--~- -,~ ~ .-"

72.5 7351.19 73.0 7401.94 73.5 7452.43 74.0 . 7502.66 74.5 7552.62 75.0 7602.30 75.5 7651.70 76.0 (~700 . 8V 76.5 7749.63 77.0 7798.15 77.5 7846.36 78.0 7894.25 78.5 7941.81 79.0 7989.05 79.5 8035.95 80.0 8082.51 80.5 8128.71 81.0 8174.56 81.5 8220.05 82.0 8265.15

VIRGINIA POWER I-SC-5.H NORTH ANNA POWER STATION REVISION 1 PAGE 7 OP 7 PRESSURIzER RELffiP TANK l-RC-TK-2 VOLUME VERSUS INDICATED LEVEL EQUIVALENT INDICATED HOOP VOLUME LEVEL erg> (GALLONS> 82.5 8309.87 83.0 8354.21 83.5 8398.14 ' 84.0 8441.66 84.5 8484.78 85.0 8527.47 85.5 8569.72 86.0 , 8611.55 86.5 ' 8652.90 87.0 8693.80 87.S 8734.24 88.0 8774.20 88.5 8813.66 89.0 8852.62 89.5 8891.07

 ,                 90.0                           8929.00 90.5                           8966.40 91.0                           9003.26 91.5                           9039.55 92.0                           9075.27 92.5                           9110.42 93.0                           9144.96 93.5                           9178.90 94.0                           9212.21 94.5                           9244.88 95.0                           9276.90 95.5                           9308.24 96.0                           9338.89 96.5                           9368.84 97.0                           9398.05 97.5                           9426.52 98.0                           9454.21 98.5                           9481.11
                  '99.0                           9507.18 99.5                           9532.40

STUDENT GUIDE FOR REACTOR COOLANT SYSTEM (38) Technical Specifications 10.1 Objective U 3526 List the following technical specification limits associated with the Reactor Coolant System.

• System leakage (TS-3.4.13)
• Primary-to-secondary leakage in modes 1 and 2 (TRM-3.4.4, SG Monitoring Prog.)
• Dissolved oxygen, chloride, and fluoride in the Reactor Coolant System (TRM-3.4.1) 10.1 Content

1. RCS leakage is limited by TS-3.4.13 to the following values in modes 1 - 4:

1.1. No pressure boundary leakage 1.2. 1 gpm unidentified leakage. 1.3. 10 gpm identified leakage 1.4. 150 gallons per day primary to secondary leakage through anyone steam generators (SGs)

2. Primary-to-secondary leakage is limited by TRM-3.4.4 to the following value in modes 1 and 2:

2.1. Total leakage from all SGs of 5 gpd.

3. Dissolved oxygen, chloride, and fluoride in the Reactor Coolant System is limited by TRM-3.4.1 to the following values:

3.1. Dissolved oxygen S. 0.10 ppm (steady state) and S. 1.00 ppm (transient). 3.2. Note that the dissolved oxygen limit is not applicable with T AVG S. 250 "F. 3.3. Chloride S. 0.15 ppm (steady state) and S. 1.50 ppm (transient). 3.4. Fluoride S. 0.15 ppm (steady state) and S. 1.50 ppm (transient). 3.5. Note: The chloride and fluoride analyses are not required when the RCS is drained below the ( reactor vessel nozzle and the internals or head is in place. SHIFT TECHNICAL ADVISOR Page 103 of 111 Revision 8, 10109/2008

STUDENT GUIDE FOR REACTOR COOLANT SYSTEM (38) ( 10.2 Objective U 3527 Define the following technical specification terms associated with the Reactor Coolant System (ITS Definitions).

• Identified leakage
• Unidentified leakage
• Pressure boundary leakage 10.2 Content

1. Identified leakage shall be:

1.1. Leakage such as that from pump seals or valve packing (except reactor coolant pump seal water injection or leakoff) that is captured and conducted to collection systems or a sump or collecting tank. 1.2. Leakage into the containment atmosphere from sources that are both specifically located and known either not to interfere with the operation of leakage detection systems or not to be pressure boundary leakage. 1.3. Reactor Coolant System leakage through a steam generator to the Secondary System 1.4. TS bases state that the 10 gpm limit provides allowance for a limited amount of leakage from known sources whose presence will not interfere with the detection of unidentified leakage by the leakage detection systems.

2. Unidentified leakage shall be all leakage (except RCP seal water injection or leakoff) that is not identified leakage.

3. Pressure boundary leakage shall be leakage (except steam generator tube leakage) through a non-( isolable fault in a Reactor Coolant System component body, pipe wall, or vessel wall.

SHIFT TECHNICAL ADVISOR Page 104 of 111 Revision 8, 10109/2008

QUESTIONS REPORT ( for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

65. 02.2.43 065INEWIIL/3/ROINAPSII The status of annunciator patch cords is checked on a basis using O-GOP-2.7, Annunciator Patchcord Control, and the is used to track the total number of disabled annunciators.

A. quarterly; Central Reporting System B~ quarterly; Operations Aggregate Impact Report C. weekly; Central Reporting System D. weekly; Operations Aggregate Impact Report Feedback

a. Incorrect. First part is correct, this is a quarterly surveillance; second part is incorrect but plausible since some individual items (like the case where a tagout removes a patchcord) could be found by a report querry, but ops aggregate impact report is the controlling document that lists and tracks the status of the collective disabled annunciators for each unit.

b. Correct. First part correct as discussed above; second part also correct as the

( procedure Operations Aggregrate Impact delineates the requirements for tracking of disabled annunciators.

c. Incorrect. First part is plausible since annunciator status is important and performing this on a weekly basis would not create any undue burden, thus the candidate who does not have detailed knowledge of the surveillance frequency may default to this distractor; second part incorrect but plausible as discussed in distractor a.

d. Incorrect. First part incorrect as discussed in distractor c; second part is correct as discussed in distractor b.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Equipment Control Knowledge of the process used to track inoperable alarms. (CFR: 41.10 / 43.5 / 45.13) Tier: 3 Importance Rating: 3.0/3.3 Technical

Reference:

gop-2.7 and admin procedure ops aggregrate impact Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info:

I'c...... PROCEDURE NO: O-GOP-2.7 REVISION NO: NORTH ANNA POWER STATION 2 PROCEDURE TYPE: UNIT NO: GENERAL OPERATING PROCEDURE 1&2 PROCEDURE TITLE: ANNUNCIATOR PATCHCORD CONTROL REVISION

SUMMARY

• Converted to Framemaker using Template Rev. 030 .
• Incorporated OP 03-0507, which deleted Step 5.2.6 as this step no longer provides any added value.

This step was initiated by NIT to ensure the program was working properly.

• Changed Shift Supervisor to SRO in Step 4.1
• Added Attachment titles in Note before Steps 5.1.3 and 5.2.2.

PROBLEMS ENCOUNTERED: D NO DYES Note: If YES. note problems in remarks. REMARKS: (Use back for additional remarks.) SRO: DATE:

DOMINION O-GOP-2.7 North Anna Power Station Revision 2 Page 4 of 11 4.0 PRECAUTIONS AND LIMITATIONS 4.1 Comply with the following guidelines when marking steps N/A:

• IF the conditional requirements of a step do not require the action to be performed, THEN mark the step NIA.
• IF any other step is marked NIA, THEN have the SRO (or designee) approve the N/A and justify the N/A on the Procedure Routing Sheet.

4.2 This procedure should be performed at least once every quarter.

Nuclear Fleet Guidance and Reference Document

Title:

Operations Aggregate Impact Document Number Revision Number Effective Date and OP-AA-1700 o Approvals On File Revision Summary New document that provides guidance in the use of a single index that measures the degree to which plant conditions affect, or could affect, the performance of Operators on shift. The Operations Aggregate Impact (OAI) is a weighted indicator that is used by site personnel to assist in the prioritization of work planning and scheduling. The OAI is comprised of operatorworkarounds, burdens, distractions, control room deficiencies, unplanned lit and disabled annunciators, and temporary modifications. This document supersedes:

• 0-GOP-5.3.1 (NAPS)
• OC-35 and OC-81 (SPS)
• NAD 12.07 (KPS)
• Portions of MP-14-0PS-GDL400 (MPS)

Functional Area Manager: Manager Nuclear Operations

DOMINION OP-AA-1700 REVISION 0 PAGE 5 OF 6 ATTACHMENT 1 (Page 1 of 1) Operations Aggregate Impact Calculation

1. Operator Workarounds The total number of deficiencies that require operators to take compensatory action to comply with abnormal or emergency procedures during an accident or transient.

2. Operator Burdens The total number of deficiencies that require operators to take significant compensatory action during normal operations.

3. Operator Distractions The total number of deficiencies that require operators to take minor action during normal operations.

4. Control Room Panel Deficiencies The total number of control room panel deficiencies.

5. Unplanned Lit Annunciators The total number of lit control room annunciators.

6. Disabled Annunciators The total number of disabled control room annunciators.

7. Temporary Modifications The total number of temporary modifications that can be corrected non-outage, are older than 12 weeks, and are not procedurally controlled.

8. Other The number of any other conditions that are deemed to have a negative impact on shift operations (e.g., impairments requiring a fire watch or flood watch).

NOTE: The following items are in order of decreasing impact. In order to avoid "double-counting" only the first deficiency should be applied. 1 x 5= 2 x 2= 3 x 1= 4 x 1= 5 x 1= 6 x 1= 7 x 1= 8 x 1= TOTAL (T)=_ OAI = 100 - T =

STUDENT GUIDE FOR ANNUNCIATOR AND EVENT RECORDER SYSTEM (69) c 3.2 Objective U 7844 Explain the following concepts concerning the defeating of Hathaway annunciators.

• Purpose of defeating an annunciator
• Conditions that must be met in order to allow defeating an annunciator
• Approved methods of reconfiguring an annunciator in alarm that is not providing useful information
• How the operator is alerted to a reconfigured annunciator 3.2 Content

1. A control room annunciator may be reconfigured for short time periods under certain conditions.

1.1. A control room annunciator, whose current alarming condition provides no useful information to the control room operator, should be reconfigured to avoid unnecessary distractions. 1.2. This philosophy is in keeping with the "Blackboard Concept", which was implemented to maintain the absolute minimum number of lit annunciators possible in the control room. 1.3. The operator is to aggressively pursue clearing of annunciators to minimize distractions. (I.e.: fill or pump tanks to clear level alarms, adjust flows or pressures to clear temperature and pressure alarms, etc.)

2. In order to defeat an annunciator, the annunciator must be lit AND 2.1. Provides no useful information to the control room operator, AND 2.2. The condition is NOT associated with a Technical SpeCification LCO, AND 2.3. The condition causing the annunciator is clearly understood, and the condition cannot be promptly corrected by normal adjustments, plant maintenance, or a maintenance operating procedure (MOP) 2.4. Is alarming due to the system or equipment serving the annunciator being out of service.

c 3. Approved methods for reconfiguring are as follows: REACTOR OPERATOR Page 9 of 11 Revision 0, 10101/2006

STUDENT GUIDE FOR ANNUNCIATOR AND EVENT RECORDER SYSTEM (69) 3.1. System/equipment serving the annunciator out of service: 3.1.1.The annunciator may be defeated by pulling the patch cord, (and installing a shorting plug if required), until the system/equipment is returned to service. 3.2. Alarm is valid, but not expected to change frequently: 3.2.1.The annunciator logic may be reversed such that the annunciator will not light for the alarmed condition, but will relight if the alarmed condition changes. 3.3. Equipment serving the annunciator or annunciator logic itself malfunctioning: 3.3.1.Annunciator may be defeated (as in #1 above) until corrective maintenance can be completed. 3.4. Temporary change in the process parameters serving the annunciator: 3.4.1.Example: a valve leaking by causes temperature to be stable, at a value slightly higher than the alarm setpoint. 3.4.2.The alarm setpoints for the annunciator may be temporarily changed until corrective maintenance or system modification can be performed to allow the process parameters to be returned to the design values. 3.5. Defeating of annunciators as described in #1 above should be placed in the procedures for removing the system/equipment from service, and restoring the annunciator to normal status should be placed in the procedures for placing the system/equipment in service. 3.6. In instances where procedures do not exist for removing the system/equipment form service, the defeating and restoring of the annunciator should be incorporated into the tagging process.

4. In ALL cases, the status of the defeated annunciator should be noted in the NODLAN computer's Virginia Power Annunciator Response System (VPARS).

4.1. This will ensure that when the VPARS is used to respond to an alarm, the operator will automatically be reminded of the annunciator's temporary reconfiguration. Demonstrate to class how to use VPARS to view the status of an annunciator. This will require a PC (with access to the network) and a projector & screen. REACTOR OPERATOR Page 10 of 11 Revision 0, 10/01/2006

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

66. G2.3.l5 066IMODIFIEDINAPS/L/3IROINAPSII The SG N-16 Radiation Monitors are required by Technical Requirements in , and can not be declared operable until reactor power is at least _ _ .

A. Modes 1, 2, and 3; 5% B. Modes 1, 2, and 3 ; 25% C. Modes 1 &2; 5% D!' Modes 1 & 2 ; 25% Feedback

a. Incorrect. Plausible since this spec requires several different monitors and contingencies for montitoring. It is just as likely to have a SGTL in Mode 3 as it is in mode 2, and most instrumentation specs are 1-3 which further reenforces the plausibility.

b. Incorrect. Plausible for Modes as discussed above. Power level in this case is correct.

c. Incorrect. Modes required is correct. Power level incorrect but plausible as discussed in Distractor a.

d. Correct. Modes required is correct and per the TRM basis power level must be at least 25% before RCS N-16 activity is sufficient for the monitor to be functional to meet TRM requirements.

Notes Knowledge of radiation monitoring systems, such as fixed radiation monitors and alarms, portable survey instruments, personnel monitoring equipment, etc. (CFR: 41.12/43.4 / 45.9) Tier: 3 Importance Rating: 2.9/3.1 Technical

Reference:

trm 3.4.5 and basis Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info: Ro rating is 2.2 but this is an sro only question (SRO has a 3.2 value).

                  -  NUCLEAR DESIGN INFORMATION PORTAL-Primary to Secondary Leakage Detection Systems 3.4.5 3.4 REACTOR COOLANT SYSTEM 3.4.5     Primary to Secondary Leakage Detection Systems TR 3.4.5           The following primary to secondary leakage detection systems shall be FUNCTIONAL:

a. One of the following continuous readout Radiation Monitoring Systems:

The N-16 radiation monitoring system on each steam 1ine, or The N-16 radiation monitoring system on the main steam header, or The condenser air ejector exhaust radiation monitor; and

b. The capability to obtain and analyze one of the following:

Condenser air ejector exhaust grab sample, or Liquid sample from the secondary system and from the Reactor Coolant System. APPLICABILITY: MODES 1 and 2. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Required continuous A.l Obtain and analyze In accordance readout radiation grab samples. with monitor nonfunctional. Table 3.4.5-1 AND A.2 Restore required As soon as monitoring system to practical FUNCTIONAL. NAPS TRM 3.4.5-1 Rev 62, 05/03/07

NUGLEJ~\.R Primary to Secondary Leakage Detection Systems B 3.4.5 B 3.4 REACTOR COOLANT SYSTEM B 3.4.5 Primary to Secondary Leakage Detection Systems BASES Primary to secondary leak monitoring is an important defense-in-depth measure to assure steam generator (SG) tube integrity. SG tube integrity is assured through the Reactor Coolant System (RCS) Operational Leakage and SG Tube Integrity Technical Specifications of 3.4, as well as the SG Program requirements of 5.5. NEI 97-06 and its referenced EPRI Guidelines are the documents that define the SG Program referred to in the TS. Specifically, the PWR Primary to Secondary Leak Guidelines (the Guidelines) define the program required by TS 5.5.8.e, "A Steam Generator Program shall be established and implemented" with "provisions for monitoring operational primary to secondary LEAKAGE." Primary to secondary leak monitoring is one aspect of a programmatic, performance-based approach to ensuring SG tube integrity. A radiation monitor can be considered FUNCTIONAL if it is directly correlated to gpd leakage, can be monitored and will produce an alarm in the main control room, and can detect leak rates greater than 30 gpd at existing RCS activity levels. RCS activity levels existing during plant startup may not be adequate to support the required 30 gpd detection capability. One continuous radiation monitoring system consists of the N-16 continuous readout and alarm radiation monitors on each steam line. The second system consists of the N-16 continuous readout and alarm radiation monitor on the main steam header. The third system consists of the condenser air ejector exhaust continuous readout and alarm radiation monitor. The condenser air ejector exhaust monitor is correlated to gpd leakage by PCS or procedurally controlled hand calculation. Secondary system - any secondary system sample that is mixed with the SGs during normal operation - any individual SG sample, condensate system sample, feedwater system sample, main steam sample, or heater drain sample. Condition A, No Continuous Radiation Monitor FUNCTIONAL: A condition where there is no continuous radiation monitoring system sensitive to leak rates greater than 30 gpd and correlated to gpd for continuous on-line monitoring of primary to secondary leakage. This condition requires increased use of grab samples or other monitoring systems to ensure that a primary to secondary leakage event does not occur without rapid detection and response. Note that this condition will exist during plant startup until RCS activity increases to an adequate level to support the required 30 gpd detection capability. RCS N-16 activity will be sufficient to support FUNCTIONALITY of the N-16 systems with reactor power at or above 25%. RCS Ar-41 activity is expected to be sufficient to support FUNCTIONALITY of the condenser air ejector exhaust system shortly after 30% power is reached. A grab sampling program that is based on the NAPS TRM B 3.4.5-1 Rev 62, 05/03/07

                          --- NUCLEAR DE8lGN II\lFOfUII,6,'T'ION Primary to Secondary Leakage Detection Systems B 3.4.5 BASES guidance of Reference 2, Section 3.4 for grab sampling during startup until the radiation monitors can adequately quantify leakage is implemented by Chemistry procedures.

Condition B, Action Level 2: A condition where there is no continuous readout indication of leakage and the leak rate was indicating an increasing trend at the time the continuous readout indication was lost. It is mandatory that the unit be shut down in a planned manner within the allowed Completion Time if the radiation monitor can not be restored. Grab samples are taken at an increased frequency to monitor leakage while in this condition. Condition C, Action Level 3 Condition 2: A condition that suggests the leak is undesireably large with no continuous readout indication of leakage and it is mandatory that the unit be promptly shut down. To avoid unnecessary plant shutdown, Action Level 3 leakage should be qualitatively confirmed prior to declaration. Confirmation time should be kept to a minimum. Precise duplication of leak rates, as indicated by the monitors, is not required. Conditions D and E, No FUNCTIONAL Primary to Secondary Leakage Monitoring Capability: These conditions are not addressed by Reference 2. The potential for these conditions to exist was identified by NAPS-SA-06-38. The 4 hour allowed Completion Time of Condition D is consistent with the most conservative grab sampling requirement of Table 3.4.5-1, while Condition E allows adequate ( time to perform a controlled shutdown if capability is not restored. Together, Ie these requirements implement a conservative operating philosophy as approved by Station Management. Periodic grab sample results are used to provide current correlations between monitor response and leak rate in gpd. This concept is important in an integrated leak rate program since grab sample results are time-consuming and cannot provide timely data if degradation is rapidly progressing. This TR includes requirements for calculating leak rates from grab samples, but the importance of relying on continuous readings from system radiation monitors should be understood. Air ejector exhaust radiation monitoring instrumentation testing is performed in accordance with VPAP-2103N.

References:

1. NEI 97-06, Steam Generator Program Guidelines, Revision 2.

2. PWR Primary-To-Secondary Leak Guidelines - Revision 3, EPRI, Palo Alto, CA:

2004. 1008219. NAPS TRM B 3.4.5-2 Rev 62, 05/03/07

DOMINION 1-0P-2.1 North Anna Power Station Revision 89 Page 43 of 90

e. IF a steam generator tube leak is indicated by radiation monitors showing increasing activity or are in alarm, THEN initiate 1-AP-24, Steam Generator Tube Leak.

5.2.42 WHEN Reactor power is between 25 and 30 percent, THEN do the following:

a. Have STA start 1-PT-46.3A, Primary to Secondary Leak Rate Determination.

b. Record the following data:

• Percent Reactor Power: _____ percent

                                   * "D" Bank:                   _____ steps

• N35: _____ amps
• N36: _____ amps NOTE: With reactor power at or above 25%, RCS N-16 activity is sufficient to support operability of the N -16 radiation monitors, as described in TRM 3.4.5 Bases.

c. IF the N-16 Radiation Monitors were previously declared inoperable due to power less than 25%, AND the N-16 Radiation Monitors are currently indicating primary to secondary leakage in gallons per day (gpd), THEN declare the N-16 Radiation Monitors operable.

5.2.43 Continue to raise Reactor power by raising Main Turbine power. 5.2.44 Place the Reheat Steam System in service using 1-0P-28.3, Startup of the Moisture Separator Reheaters.

STUDENT GUIDE FOR RADIATION MONITORING SYSTEM (46) ( 2.2.1. Alert - 5 gallons/day greater than baseline (from Process Unit) 2.2.2. High - 30 gallons/day greater than baseline (from Process Unit) 2.2.3. High-High -100 gallons/day (fixed setpoint) (from MS-RR-193) 2.3. Associated light will be lit (alert, high, high/high) for whichever alarm is in. 9.4 Objective U 5264 Explain the following concepts concerning the N-16 radiation monitors.

• Relationship between indicated reactor power and N-16 radiation monitor reading
• Why the N-16 main steam radiation monitor's indication is invalid below 25% reactor power
• How steam generator tube leakage can be trended at reactor power levels of < 25% using the N-16 radiation monitors 9.4 Content

1. N-16 Monitors on the individual steam lines are the best indication, and track very well during transients.

1.1. These monitors are not sensitive to RCS activity or air ejector flow rates. 1.2. However they have a tendency to indicate slightly conservative at low powers (less than 50%). 1.3. A conservative power correction factor is built into the N-16 monitors therefore they will tend to indicate a higher SG leak rate at reduced power.

2. Indication of primary-to-secondary leakrate in gallons/day is valid only at reactor power levels greater than 25%.

2.1. At less than 25% power, there is insufficient neutron flux in the core for activation of Oxygen-16 to N-16. 2.2. Therefore, N-16 levels are so low as to make primary-to-secondary leak detection by this method impossible. REACTOR OPERATOR Page 52 of 58 Revision 4, 09/22/2008

STUDENT GUIDE FOR RADIATION MONITORING SYSTEM (46) Technical Specifications 10.1 Objective U 5301 List the area and process radiation monitors required by technical specifications or technical requirements to be operable during unit operation in the following conditions.

• Modes 1 through 3
• Irradiated fuel in the storage pool
• Fuel in the storage pool or building 10.1 Content

1. Review TS-3.3.3

2. Review TRM-3.3.7

3. Review TRM-3.3.7 10.2 Objective U 10706 Given that a radiation monitoring instrument has become inoperable, determine which TS-3.4.6.4 requirements apply.

10.2 Content

1. If both the N-16 radiation monitoring system on each steam line and the N-16 radiation monitoring system on the main steam header are INOPERABLE, increase the frequency of the condenser air ejector grab sample required by Specification 4.4.6.3b to at least once during each 4 hour interval and return at least one of the systems to operation within seven days or reduce power to less than 50%

( within the next four hours. REACTOR OPERATOR Page 54 of 58 Revision 4, 09/2212008

STUDENT GUIDE FOR RADIATION MONITORING SYSTEM (46)

2. If the condenser air ejector exhaust continuous readout and alarm radiation monitor is INOPERABLE, provided at least one of the N-16 monitoring systems is OPERABLE, increase the frequency of the condenser air ejector grab sample required by Specification 4.4.6.3b to at least once during each 4 hour interval and return the system to operation within seven days or reduce power to less than 50% within the next four hours.

3. If the capability to obtain and analyze a condenser air ejector grab sample is lost, provided at least one of the N-16 monitoring systems is OPERABLE and the condenser air ejector exhaust continuous readout and alarm radiation monitor is OPERABLE, restore the capability within seven days or reduce power to less than 50% within four hours.

4. If both N-16 monitoring systems are INOPERABLE and either the condenser air ejector exhaust continuous readout and alarm radiation monitor is INOPERABLE or the capability to obtain and analyze a condenser air ejector exhaust grab sample is lost, reduce power to less than 50% within the next 90 minutes.

5. If the condenser air ejector exhaust continuous readout and alarm radiation monitor is INOPERABLE and the capability to obtain and analyze a condenser air ejector exhaust grab sample is lost, reduce power to less than 50% within the next 90 minutes.

6. If the capability to obtain and analyze a liquid sample from each steam generator and the RCS is lost, increase the frequency of performance of the RCS water inventory balance in TS-4.4.6.2.1 d to once every 24 hours.

REACTOR OPERATOR Page 55 of 58 Revision 4, 09/22/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

67. G2.3 ARO 067IBANKINAPS/L/3IROINAPS//

In accordance with VPAP-2101 , Radiation Protection Program, Radiation Worker Annual Administrative Dose Limits for Total Effective Dose Equivalent (TEDE) are rem/calendar year at the worker's home site. A. 1 B~ 2 C. 3 D. 4 Feedback A. Incorrect. Plausible since 1 is a limit, but this is associated with 1 per each year of age. B. Correct. 2 at any given site not to exceed 3 cumulative without an extension. C. Incorrect. Plausible since 3 is the limit for all sites. D. Incorrect. Plausible since 4 is less than the 10CFR20 limit of 5 rem/year. Notes Radiation Control Knowledge of radiation exposure limits under normal or emergency conditions. (CFR: 41.12/43.4/45.10) Tier: 3 Importance Rating: 3.2/3.7 Technical

Reference:

VPAP-21 01 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: bank additional info:

DOMINION VPAP-2101 REVISION 32 PAGE 33 OF 109 6.3.3 Administrative Dose Limits NOTE: Dose limits in Step 6.3.3 do not apply to a Declared Pregnant Woman or an Expected Pregnant Woman. Declared Pregnant Woman administrative dose control is addressed in Step 6.3.5 and Expected Pregnant Woman dose control is addressed in Step 6.3.6. NOTE: Dose limits in Step 6.3.3 are implemented by controls specified in Step 6.3.4. Administrative dose limits are established to minimize the potential for exceeding federal limits. If a worker exceeds an administrative dose limit without exceeding a 10 CFR 20 or Technical Specifications (TS) limit, the event shall not be considered a violation of either 10 CFR 20 or TS. Exceeding administrative limits shall require a radiological incident investigation and a Condition Report in accordance with PI-AA-200, Corrective Action. Investigation results shall be used to determine reportability and shall become Station records.

a. Radiation Worker Annual Administrative Dose Limits Type Radiation Worker Annllal AdnIinistrative Dose Limits Total Effective Dose Equivalent (TED E) 2.0 rem/calendar year at the worker's home site Total Effective Dose Equivalent (TED E) 3.0 rem/calendar year from all licensees

b. System Worker Annual Administrative Dose Limits System Worker Annual Administrative Dose Limits Total Effective Dose Equivalent (TED E) 0.750 rem/calendar year per Dominion nuclear site (can be concurrently badged at Dominion sites)

STUDENT GUIDE FOR ADMINISTRATIVE PROCEDURES (100) 1.44 Content

1. The Shift Manager (SM) is responsible for:

1.1. Assuming duties of WCT during non-business hours (off-hours), based on emerging plant conditions. 1.2. Aligning plant systems, as required, to support Work Order task activities. 1.3. Reviewing and authorizing Work Orders on permanent plant structures, equipment, and components, including urgent authorizations and pre-authorizing PM Work Orders, ensuring the following: 1.3.1.Equipment is prepared for maintenance 1.3.2.Equipment is tagged, if designated, by the Work Order 1.3.3. Post Maintenance Testing (PMT) can occur. 1.4. Performing PRA Risk Analysis for emergent plant condition changes.

2. Originator (Station Personnel) 2.1. The Originator is responsible for:

2.1.1.lnitiating work in CRS and in accordance with guidelines in this procedure and applicable site procedures, when an equipment deficiency is identified or other work is requested at the station. [eMs 5.1.4 and 5.1.5] 2.1.2.Verifying in the work control system or corrective action system that requested work has not already been identified. 1.45 Objective U 13583 List the following information associated with the radiation protection program (VPAP-21 01).

• 1O-CFR-20 dose limits
• Administrative dose limits REACTOR OPERATOR Page 49 of 106 Revision 16, 09/19/2008

STUDENT GUIDE FOR ADMINISTRATIVE PROCEDURES (100) 1.45 Content See VPAP-21 01. 1.46 Objective U 13584 Define the following terms associated with the off-site dose calculation manual (VPAP-2103N).

• Gaseous radwaste treatment system
• Ventilation exhaust treatment system 1.46 Content

1. Gaseous Radwaste Treatment System 1.1. A system that reduces radioactive gaseous effluents by collecting primary coolant system offgases from the primary system and providing delay or holdup to reduce total radioactivity prior to release to the environment.

1.2. The system comprises 1.2.1. the waste gas decay tanks, 1.2.2.regenerative heat exchanger, 1.2.3.waste gas charcoal filters, 1.2.4.process vent blowers, 1.2.5.waste gas surge tanks, and 1.2.6.waste gas diaphragm compressor.

2. Ventilation Exhaust Treatment System 2.1. A system that reduces gaseous radioiodine or radioactive material in particulate form in effluents by passing ventilation or vent exhaust gases through charcoal adsorbers and High Efficiency Particulate Air (HEPA) filters to remove iodines and particulates from a gaseous exhaust stream prior to release to the environment (such a system is not considered to have any effect on noble gas effluents).

REACTOR OPERATOR Page 50 of 106 Revision 16,09/19/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

68. G2.3.5RO 068INEW//L/2IROINAPSII Unit 1 is at 100% power.

1-SV-RM-121, Condenser Air Ejector Radiation Monitor, spikes high resulting in a Hi alarm AND a Hi-Hi alarm on the drawer, and then indication returns to normal. Based on the above, which ONE of the following describes the response of 1-SV-RM-121, Condenser Air Ejector Radiation Monitor? A'!' The Hi alarm clears when the indication returns to normal; the Hi-Hi alarm remains in and must be reset by the operator. B. The Hi alarm clears when the indication returns to normal; the Hi-Hi alarm remains in and must be reset by I&C. C. The Hi-Hi alarm clears when the indication returns to normal; the Hi alarm remains in and must be reset by the operator. D. The Hi-Hi alarm clears when the indication returns to normal; the Hi alarm remains in and must be reset by I&C. Feedback

a. Correct. The Hi alarm does not seal in; the hi-hi alarm must be reset by taking the operations selector switch to reset.

b. Incorrect. The Hi alarm does not seal in; the hi-hi alarm must be reset by taking the operations selector switch to reset, this is plausible since the MGPls do require I&C to reset them and the candidate may confuse the two.

c. Incorrect. This is opposite of how they operate but the candidate who is not knowledgeable of the system could easily confuse which alarm seals in and which clears on its own.

d. Incorrect. Plausible as described above and also as discussed in Distractor b.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Radiation Control Ability to use radiation monitoring systems, such as fixed radiation monitors and I alarms, portable survey instruments, personnel monitoring equipment, etc. I (CFR: 41.11/41.12/43.4/45.9) Tier: 3 Importance Rating: 2.9/2.9 Technical

Reference:

radiation monitoring lesson plan Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info:

VIRGINIA POWER 1-EI-CB-21K ANNUNCIATOR D4 1-AR-K-D4 NORTH ANNA POWER STATION REV. 1 (-"PPROVAL: ON FILE Effective Date:04-19-02

~"" .

RAD MONITOR SYST HI-HI RAD LEVEL 1.0 Probable Cause 1.1 High-High radiation alarm on a Unit 1 or common radiation monitor 1.2 Failure of alarm relay 74C 2.0 Operator Action WARNING: IF a LOCA has occured, THEN the area dose rates will increase significantly once the changeover to Recirculation Mode has occurred. (Reference 3.6) ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 2.1 VERIFY NO ALARMS ON UNIT 1 OR IMMEDIATELY notify Health COMMON RADIATION MONITORS. Physics. Initiate 1-AP-5, Unit 1 Radiation Monitoring System, or O-AP-5.1, Common Radiation Monitoring System. 2.2 VERIFY NO RADIATION MONITORS Notify Instrument department. HAVE FAILED. Refer to Tech Spec 3.3.3.1 (ITS 3.4.15, TRM 3.3.7) and VPAP-2103, Offsite Dose Calculation Manual. 3.0 References 3.1 11715-ESK-10AAW, 11W 3.2 Stone and Webster drawing 11715/12050-1.21-67 3.3 Instrument Loop 11715-RM-016 3.4 Tech Spec 3.3.3.1 (ITS 3.4.15, TRM 3.3.7) (Radiation Monitoring) 3.5 VPAP-2103, Offsite Dose Calculation Manual 3.6 CTS Item 02-94-2229-060, Service Water System Operational Performance Assessment Items 140 and 143 4.0 Actuation 4.1 74HHC, high-high radiation alarm relay 4.2 K101 contacts, from all Unit 1 and common radiation monitors

VIRGINIA POWER 1-EI-CB-21K ANNUNCIATOR D2 1-AR-K-D2 NORTH ANNA POWER STATION REV. 2 PPROVAL: ON FILE Effective Date:04-12-02 RAD MONITOR SYSTEM HI RAD LEVEL 1.0 Probable Cause 1.1 High radiation alarm on a Unit 1 or common radiation monitor 1.2 Failure of alarm relay 74-HC 2.0 Operator Action WARNING: IF a LOCA has occurred, THEN the area dose rates will increase significantly once the changeover to Recirculation Mode has occurred. (Reference 3.6) ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 2.1 VERIFY NO ALARMS LOCKED IN OR IMMEDIATELY notify Health Physics. ALARMING REPEATEDLY ON UNIT 1 Initiate 1-AP-5, Unit 1 Radiation OR COMMON RADIATION MONITORS. Monitoring System, or 0-AP-5.1, Common Radiation Monitoring System. 2.2 VERIFY NO RADIATION MONITORS Notify Instrument department. HAVE FAILED. Refer to Tech Spec 3.3.3.1 (ITS 3.4.15, TRM 3.3.7) and VPAP-2103, Offsite Dose Calculation Manual. 3.0 References 3.1 11715-ESK-10AAW, 11W, and 11X 3.2 Stone and Webster drawing 11715/12050-1.21-67 3.3 Instrument Loop 11715-RM1011 3.4 Tech Spec 3.3.3.1 (ITS 3.4.15, TRM 3.3.7) (Radiation Monitoring) 3.5 VPAP-2103, Offsite Dose Calculation Manual 3.6 CTS Item 02-94-2229-060, Service Water System Operational Performance Assessment Item 140 4.0 Actuation 4.1 74-HC, radiation high alarm relay 4.2 K102 contacts, from all Unit 1 and common radiation monitors

NUMBER PROCEDURE TITLE REVISION 26 1-AP-5 UNIT 1 RADIATION MONITORING SYSTEM PAGE 4 of 5 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. VERIFY THE FOLLOWING FOR THE AFFECTED RADIATION MONITOR(S): (Continued)

INIT RADIATION MONITOR RECORDER ATT. NO. CONTAINMENT GASEOUS 1-RM-RR-100 ATTACHMENT 5 1-RM-RMS-160 CONDENSER AIR EJECTOR 1-RM-RR-100 ATTACHMENT 3 1-SV-RM-121 RECIRC SPRAY HX SERVICE WATER OUTLET 1-RM-RR-100 ATTACHMENT 10 1-RM-SW-124, 125, 126, 127 CONTAINMENT HIGH RANGE 1-RM-RR-165 ATTACHMENT 11 1-RM-RMS-165, 166 1-RM-RR-166 2._ LOCALLY VERIFY 1-SS-RM-125, o Initiate ATTACHMENT 9. HIGH CAPACITY SG BLOWDOWN RAD MONITOR AS REQUIRED: o

• Indication - NORMAL o
• History trends - NORMAL o
• Switch positions - NORMAL o
• Alarms - NOT LIT

STUDENT GUIDE FOR RADIATION MONITORING SYSTEM (46) Process and Area Radiation Monitors 'r()pic2~1*SV\litch.* . Ptisltions .* for'J\lestil1gijouse HadlatiOI1*Mol'litors 2.1 Objective U 5228 Explain the functions performed by each position of the following Westinghouse radiation monitor control switches.

• Operation selector switch
• Range selector switch 2.1 Content

1. Operation selector switch 1.1. OPERATE - Places the radiation monitor in service 1.2. RESET - Resets the Hi-Hi alarm on the face of cabinet and resets the detector reading.

1.3. CHECK SOURCE - Utilized to check detector for response to radiation. (checks drawer and detector) 1.3.1 .Relay places known source in front of detector 1.3.2.May result in actuation of a Hi or Hi-HI alarm and the automatic actions associated with the radiation monitor 1.4. LEVEL CAL 1 - Detector and part of circuit given constant output which results in a level on the meter (bottom of scale). 1.4.1.Should read about 1 x 10-4 R/hr. 1.5. PULSE CAL - Inserts a known signal value high enough to bring in the Hi and Hi-Hi alarm on the drawer.

2. Range selector switch 2.1. Wide (top scale) 2.2. Narrow (middle scale)

REACTOR OPERATOR Page 14 of 58 Revision 4, 09/22/2008

STUDENT GUIDE FOR RADIATION MONITORING SYSTEM (46)

• High radiation level
• High-high radiation level 2.3 Content

1. Instrument power fuse is blown 1.1. Drawer dead (no power on light, meter at zero) 1.2. Annunciator K-D3, Rad Monitor System Failure Test 1.3. Annunciator K-D4, Rad Monitor Sys Hi-Hi Rad Level 1.4. Note: K-D4 comes in and not K-D2 (Hi-Rad) because of the contact setup in the drawer circuitry.

1.5. Automatic control functions would occur if that monitor has any (except for MCR bottled air dump this needs the Hi-rad in addition to the Hi-Hi rad for actuation to occur)

2. Control power fuse is blown

( 2.1. Loss of control power may be a very subtle failure. 2.2. The symptoms that you receive would be from auxiliary items such as a pump not running on a process monitor and/or the resultant annunciator from a component changing state in the plant and being traced back to its probable cause. 2.3. The control power fuses are concealed inside locked bays. 2.3.1. The only access is from the rear of the radiation monitoring panels. 2.4. The observable indications for the drawer (front of panels) mayor may not appear normal. 2.5. There is not a consistent number of sets of control power fuses for each locked bay. 2.5.1.There may be 1,2, or 3 sets of control power fuses for a bay. 2.5.2.This is based on the electrical load within that bay. 2.5.3.This has changed over time from the original design as radiation monitor DCPs (design change packages) have been completed. 2.5.4.For a blown fuse, all of the monitors that are fed from that set of control power fuses which have automatic control functions, would be actuated. REACTOR OPERATOR Page 16 of 58 Revision 4, 09/22/2008

STUDENT GUIDE FOR RADIATION MONITORING SYSTEM (46)

3. Operation selector switch in any position except OPERATE 3.1. Annunciator K-D3, RAD MONITOR SYSTEM FAILURE TEST will alarm.

4. High radiation level 4.1. The associated drawers HIGH ALARM light will illuminate, and the RAD MONITOR SYSTEM HI RAD LEVEL (1 K-D2) annunciator will alarm.

5. High-high radiation level 5.1. The associated drawers Hi-Hi ALARM light will illuminate and Annunciator K-D4, RAD MONITOR SYS HI-HI RAD LEVEL will alarm.

5.2. Additionally, the HIGH ALARM should also actuate, and any auto function associated should initiate. 5.3. If possible, redundant radiation monitors should be used to validate that radiation level has increased TopiC 2.4 Loss

• and Bestoration'<'ofPower- 'We$ting h6use .

2.4 Objective U 5297 Explain how the Westinghouse radiation monitors are affected by a loss of power followed by restoration of power. 2.4 Content

1. Drawer will energize (power on light lit, meter has a reading) 1.1. Hi-Hi alarm light lit on drawer until reset by placing the OPERATOR SELECTOR switch from "Operate" to "Reset" and back to "Operate".

1.2. K-D3 and K-D4 will not clear until all of the effected drawers have been reset. 1.3. Crew must also deal with any items that changed state as a result of automatic control functions. REACTOR OPERATOR Page 17 of 58 Revision 4, 09/22/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

69. G2.4.20 069INEW//L/3/ROIII 1-FR-H.1, Response to Loss of Secondary Heat Sink, is in effect.

When attempting to establish SG feed flow from the Condensate System, there is a NOTE prior to the step "Initiate depressurization of all SGs to less than 610 psig by dumping steam to condenser at maximum rate." This NOTE states that each Main Steamline flow should be kept less than 1.0E6 LBM/HR. The purpose of this NOTE is to remind the operator that exceeding 1.0E6 LBM/HR may result in A. RCS cooldown rate in excess of Technical Specification limits. B. a challenge to the PTS status tree. C. inadvertant Steamline DP Safety Injection. O~ undesired Main Steam line Isolation. Feedback

a. Incorrect. Plausible since most EOPs limit C/O to the TS 100 degree/hr.

b. Incorrect. Plausible since most EOPs try to avoid intentionally causing a challenge to CSF trees.

c. Incorrect. Plausible since depending on plant conditions this would be a concern and has the potential to complicate recovery, however this is not the reason for the caution.

d. Correct. MSLI signal is not blockable.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Emergency Procedures / Plan Knowledge of the operational implications of EOP warnings, cautions, and notes. (CFR: 41.10 /43.5 /45.13) Tier: 3 Importance Rating: 3.8/4.3 Technical

Reference:

1-FR-H.1 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info:

NUMBER PROCEDURE TITLE REVISION 19 1-FR-H.1 RESPONSE TO LOSS OF SECONDARY HEAT SINK PAGE 16 of 41 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE: To prevent an undesired Main Steamline Isolation, each Main Steamline flow should be kept less than 1.0E6 LBM/HR.

8. INITIATE DEPRESSURIZATION OF ALL SGs TO LESS THAN 610 PSIG BY DUMPING STEAM TO CONDENSER AT MAXIMUM RATE:

o a) Verify Condenser Steam Dumps - a) Manually or locally depressurize SGs AVAILABLE using: o

• SG PORVs OR o
• Decay Heat Release Valve using ATTACHMENT 6, USING DECAY HEAT RELEASE VALVE FOR COOLDOWN.

o IF depressurization is initiated, THEN GO TO Step 9. o IF unable to depressurize SGs, THEN GO TO Step 13. (STEP 8 CONTINUED ON NEXT PAGE)

STEP DESCRIPTION TABLE FOR FR-H.l Step 7 - NOTE NOTE: After the low steamline pressure SI signal is blocked, main steamline isolation will occur if the high steam pressure rate setpoint is exceeded. PURPOSE: To alert the operator to the potential for inadvertent steamline isolation during the subsequent steam generator depressurization. BASIS: An automatic protection feature is provided to close the main steamline isolation valves when the steam pressure rate signal is exceeded. In the following step, the operator is instructed to dump steam from the intact steam generators which may result in exceeding the rate setpoint. Therefore, this note is intended to alert the operator of this possibility. ACTIONS: N/A INSTRUMENTATION: MSIV position indication CONTROL/EQUIPMENT: Atmospheric steam dump valve controls KNOWLEDGE: The rapid cool down should be continued using the atmospheric steam dumps if MSIV closure occurs. PLANT-SPECIFIC INFORMATION: The note may be written to warn the operator not to exceed a certain cool down rate to prevent MSIV closure. FR-H.l Background 82 HP-Rev. 2, 4/30/2005 HFRHIBG.doc

STUDENT GUIDE FOR EMERGENCY PROCEDURES (92) T.opic13.51-ES-1 ..2CoOldown(; qidelines 13.5 Objective U 12205 Explain the following concepts associated with initiating Reactor Coolant System cooldown during a post-LOCA cooldown and depressurization (1-ES-1.2).

• Why main steam line flow should be kept less than 1.0 x 106 LBM/HR
• Why a Reactor Coolant System cooldown is required
• Why the cool down rate is limited to 100°FIhr How to determine the Reactor Coolant System temperature to be used as the starting point for establishing a 1OO°F/hr cool down rate 13.5 Content

1. If condenser steam dumps are used for RCS cooldown during the performance of ES-1.2, the operator is cautioned to maintain steam flow less than 1.0 x 106 Ibm/hr.

1.1. Maintaining steam flow rate below this maximum value precludes undesirable main steam line isolation.

2. ARCS cooldown is performed in order to reduce the need for supporting plant systems required for heat removal.

2.1. ES-1.2 was written under the premise that RCS depressurization must be initiated in order to terminate RCS break flow. 2.2. RCS subcooling will be reduced significantly following depressurization. 2.3. In order to restore and maintain adequate RCS subcooling, once cooldown has been initiated it should be continued.

3. The cooldown rate is limited to 1OO°F/hr in order to preclude unnecessary entry into the Integrity Functional Restoration Guideline.

3.1. Entry into FR-P.1 is undesirable since it would take actions to terminate RCS cooldown that would defeat the actions taken in ES-1.2 to expeditiously terminate RCS break flow. REACTOR OPERATOR Page 134 of 187 Revision 19, 11/06/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

70. G2.4.37070IMODIFIEDINAPS/L/2IROINAPSII Once the TSC is fully operational, the relief Station Emergency Manager will assume all of the following responsibilities from the on-shift SEM EXCEPT _ _ _ __

A. authorizing notification to state and local governments. B. classifying the emergency (escalation/de-escalation). C. making protective action recommendations (PAR). D~ authorizing deviations to procedures pursuant to 10 CFR 50.54x. Feedback

a. Incorrect. Plausible since there are several lines of control with varying responsibilities once the emergency organization is activated, and the candidate who lacks detailed knowledge of various roles/responsibilities of the ERO at different stages of the accident may default to this distractor.

b. Incorrect. Plasusible as discussed above, moreover the on-shift SEM makes initial classification and again the candidate without detailed knowledge may assume that this responsibility always resides in the control room.

c. Incorrect. Plausible as discussed in distractor b.

d. Correct. This is always an on-shift funtion.

Notes Knowledge of the lines of authority during implementation of the emergency plan. (CFR: 41.10 / 45.13) Tier: 3 Importance Rating: 3.0/4.1 Technical

Reference:

EPIP-3.02 Proposed references to be provided to applicants during examination: None Learning Objective: 6171 Question History: bank additional info:

NUMBER PROCEDURE TITLE REVISION EPI P-l. 01 EMERGENCY MANAGER CONTROLLING PROCEDURE 43 PAGE 6 of 7 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED _ _' _ 5 CHECK TSC - ACTIVATED If TSC NOT activated. THEN do the following: a) Have STA report to the Control Room. b) Notify Manager Nuclear Operations or Operations Manager On Call. c) Consider having Radiological Assessment Director report to the Control Room. d) WHEN relief SEM arrives, THEN perform turnover using EPIP-I.OI, Attachment 2. Turnover Checklist. 6 IMPLEMENT EPIP FOR EMERGENCY CLASSIFICATION IN EFFECT:

• Notif1cat1on of Unusual Event -

GO TO EPIP-I.02, RESPONSE TO NOTIFICATION OF UNUSUAL EVENT

• Alert -

GO TO EPIP-I.03. RESPONSE TO ALERT

• Site Area Emergency -

GO TO EPIP-I.04, RESPONSE TO SITE AREA EMERGENCY

• General Emergency -

GO TO EPIP-I.05, RESPONSE TO GENERAL EMERGENCY

NUMBER ATTACHMENT TITLE REVISION EPIP-l.OI TURNOVER CHECKLIST 43 ATTACHMENT PAGE 2 1 of 1 Conduct a turnover between the onshift and relief SEM in accordance with the following checklist. Use placekeeping aid at left of item. "_ _ ", to track completion.

1. Determine the status of primary responder notification.

2. Determine the status of "Report of Emergency to State and Local Governments," EPIP-2.0I. Attachment 2. Get completed copies if available.

3. Determine status of the "Report of Radiological Conditions to the State," [PIP-2.01. Attachment 3. Get completed copy if available.

4. Determine status of Emergency Notification System (ENS) communications and completion status of NRC Event Notification Worksheet (EPIP-2.02 Attachment 1).

5. Review classification and initial PAR status.

6. Review present plant conditions and status. Get copy of Critical Safety Functions form. '

7. Review status of station firewatches and re-establish if conditions allow.

8. Determine readiness of TSC for activation.

9. After all information is obtained. transfer location to TSC.

IE the TSC is functional, THEN the State and Local Communicator in the Control Room will relocate to TSC with the SEM. IE the TSC is NOT functional. THEN the responsibilities may be transferred to relief in another facility, e.g. LEOF/CEOF. lb. Call the Control Room and assess any changes that may have occurred

            'during transition to the TSC.

11: When sufficient personnel are available. the relief SEM is to assume the following responsibilities from the onshift Station Emergency Manager:

a. Reclassification.

b. Protective Action Recommendations until LEOF activated.

c. Notifications (i.e., state, local. & NRC). Upon LEOF activation.

transfer notification responsibilities except for the NRC ENS.

d. Site evacuat,ion authorization.

e. Emergency exposure authorization.

f. Command/control of onsite response.

12. Formally relieve the Interim SEM and assume control in the TSC.

Announce name and facility activation status to facility.

STUDENT GUIDE FOR EMERGENCY PLAN IMPLEMENTING PROCEDURES (90) 2.2.1.For a dual-unit transient, the Shift Manager will perform all the functions of the EPIP Coordinator. 2.2.2. For a single-unit transient, the opposite unit's Unit Supervisor will act as EPIP Coordinator. 1.2 Objective U 13697 List the following information associated with the Operations Department's response during an emergency.

• Responsibilities of the station emergency manager that cannot be delegated to another individual
• Factors to consider when selecting personnel to receive emergency exposure 1.2 Content

1. The following SEM responsibilities cannot be delegated to another individual:

1.1. Classification of the event. 1.2. Notification of offsite authorities. 1.3. Recommendation of protective measures. 1.4. Authorization of emergency exposure limits.

2. The following factors must be considered when selecting a volunteer to receive emergency exposure: )

2.1. Personnel should be volunteers or professional rescue personnel (fire fighters, first aid and rescue personnel). 2.2. Volunteers should be in good physical health. 2.3. Volunteers should be familiar with the consequences of exposure. 2.4. Declared pregnant workers shall not be used. 2.5. The following criteria are preferable, though not mandatory: 2.5.1 Women capable of reproduction should not be used. 2.5.2 Volunteers should be above 45 years of age. SENIOR REACTOR OPERATOR Page 4 of 12 Revision 3, 05/22/2007

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

71. G2.4.45RO 0711MODIFIEDINAPSIH!3IROINAPS/NES - 2004 Operators are responding to a large-break LOCA with a loss of offsite power.

The team is implementing 1-E-1, Loss of Reactor or Secondary Coolant. The OATC reports that the following alarms have just been received:

• F-E8, AFW SUPPLY 20 MIN WATER REMAINING;)

J-A2, RWST LO LEVEL0

• H-H1, EMER DIESEL GEN #1 H DIFFERENTt>

J-F5, LHSI PP 1B LO OR OL TRI~) Based on these alarms, the crew will _ _ _ _ _ _ _ _ _ _ _ _ __ A. verify LHSI pump suction has transferred to containment sump and continue in 1-E-1, Loss of Reactor or Secondary Coolant. B. perform 1-AP-22.5, Loss of Emergency Condensate Storage Tank 1-CN-TK-1, in order to preclude implementing 1-FR-H.1, Loss of Secondary Heat Sink. C. transition to 1-ES-1.3, Transfer to Cold Leg Recirculation, then return to 1-E-1, Loss of Reactor or Secondary Coolant. D~ transition to 1-ES-1.3, Transfer to Cold Leg Recirculation, then transition to 1-ECA-1.1, Loss of Emergency Coolant Recirculation. Feedback

a. Incorrect. Plausible since auto-transfer is a design feature, however ES-1.3 is still required to be performed in order to verify proper system and support system alignment.

b. Incorrect. Plausible since there is a CAP item for this, but it is not required till level in the tank is 40% (alarm is at 46%).

c. Incorrect. Plausible since the transition is required and when leaving ES-1.3 the operator would normally return to E-1, however in this case the flowpath is to ECA-1.1.

d. Correct. Transition to ES-1.3 is required and because of the given conditions ES-1.3 will direct the operator to transition to ECA-1.1.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Emergency Procedures 1 Plan Ability to prioritize and interpret the significance of each annunciator or alarm. (CFR: 41.10/43.5 145.3/45.12) Tier: 3 Importance Rating: 4.1/4.3 Technical

Reference:

ES-1.3, E-1 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: NRC exam from 3 Exams ago additional info: modified 1 alarm in stem

VIRGINIA POWER 1-EI-CB-21J ANNUNCIATOR A2 1-AR-J-A2 NORTH ANNA POWER STATION REV. 0 ~PPROVAL: ON FILE Effective Date:06/13/97 RWST LO RWST < 22.8% LEVEL 1.0 Probable Cause 1.1 Failure of 1-QS-LT-100A or 100B or 1-QS-LAL-100A-3 or 100B-3 1.2 CDA in progress 1.3 Filling Reactor Cavity during refueling 1.4 Rupture of RP system piping while aligned to RWST 2.0 Operator Action 2.1 Verify RWST level. 2.2 IF CDA in progress, THEN GO TO 1-ES-1.3, Transfer To Cold Leg Recirc. 2.3 IF filling Reactor Cavity using LHSI Pump, THEN ensure SI Recirc Mode Reset pushbuttons, Train A and Train B, have been depressed, to prevent swapover of LHSI Pump suction to the Containment Sump. 2.4 IF borating or filling the RWST AND level begins to decrease, THEN secure fill lineup through RP system, UNTIL RP system is verified intact. 2.5 If level is NOT low, THEN submit Work Request on level transmitter. 3.0 References 3.1 11715-LSK-29-5B 3.2 NAPS Instrumentation Manual page QS003 and QS004 3.3 Loop Diagram 1-L-QS100A 3.4 EWR 89-571 3.5 DCP 90-13, Steam Generator Replacement 3.6 ET CE-96-014, Rev 0, Mode 5 & 6 Compensatory Measures Recommended for Problem Reported in Deviation Report No. N-96-0278 4.0 Actuations 4.1 1-QS-LSL-100A-2 and 1-QS-LAS-100B-2 RWST low level alarm switches. Feed signals to 1-QS-LAL-100A-3 and 1-QS-LAL-100B-3

NUMBER PROCEDURE TITLE REVISION 21 1-ES-1.3 TRANSFER TO COLD LEG RECIRCULATION PAGE 6 of 9 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION: Charging and Low-Head Pumps taking suction from the RWST must be stopped when RWST level decreases to 8%.

8. ALIGN SI SYSTEM FOR COLD LEG o Manually align valves in sequence as RECIRCULATION: necessary.

a) Verify Low-Head SI Pump - AUTO IE at least one flow path from the ALIGNMENT: Containment Sump to the RCS cannot be established OR maintained, THEN do the

1) Low-Head SI Pump Discharge following:

( Valves to Charging Pumps - OPEN: o

• Initiate ATTACHMENT 2, PRIMARY o
• 1-SI-MOV-1863A PLANT VENTILATION ALIGNMENT o
• 1-SI-MOV-1863B o
• GO TO 1-ECA-1.1, LOSS OF EMERGENCY COOLANT RECIRCULATION, STEP 1.

2) Low-Head SI Pump Recirc Valves -

CLOSED: o

• 1-SI-MOV-1885A o
• 1-SI-MOV-1885C o
• 1-SI-MOV-1885B o
• 1-SI-MOV-1885D (STEP 8 CONTINUED ON NEXT PAGE)

A Domlnloft" NORTH ANNA POWER STATION EMERGENCY CONTINGENCY ACTION NUMBER PROCEDURE TITLE REVISION 15 1-ECA-1.1 LOSS OF EMERGENCY COOLANT RECIRCULATION PAGE (WITH TWO ATTACHMENTS) 1 of 34 PURPOSE To provide instructions to attempt to restore emergency coolant recirculation capability, to delay RWST depletion by adding makeup and reducing outflow, and to depressurize the RCS to minimize break flow. ENTRY CONDITIONS This procedure is entered from:

• 1-E-1, LOSS OF REACTOR OR SECONDARY COOLANT,
• 1-ES-1.3, TRANSFER TO COLD LEG RECIRCULATION, or
• 1-ECA-1.2, LOCA OUTSIDE CONTAINMENT.

CONTINUOUS USE

STUDENT GUIDE FOR EMERGENCY CONTINGENCY ACTION PROCEDURES (94) Loss of Emergency Coolant Recirculation (1-ECA-1.1) TopicSj1. ECA-1~.lh1formCitibn 5.1 Objective U 13839 List the following information associated with 1-ECA-1.1, "Loss of Emergency Coolant Recirculation."

• Purpose of the procedure
• Modes of applicability
• Entry conditions
• Major action categories
• Conditions that result in leaving the procedure 5.1 Content

1. ECA-1.1 provides guidance for operators to attempt to restore emergency coolant recirculation capability, while reducing RWST depletion and break flow.

1.1. The objective of the loss of Emergency Coolant Recirculation guideline is threefold: 1.1.1. Continue attempts to restore emergency coolant recirculation capability 1.1.2. Delay the depletion of the RWST by adding makeup fluid and reducing outflow 1.1.3. Depressurize the RCS to minimize break flow and cause SI accumulator injection

2. ECA-1.1 is applicable in Modes 1 through 3, and assumes RHR is not in service.

3. The loss of emergency coolant recirculation (ECR) is defined as the inability to inject fluid from the sump to the RCS using low-head SI pumps.

3.1. Symptoms of a loss of ECR include: 3.1.1. Failure to open sump recirculation valves 3.1.2.Failure to start low-head SI pumps REACTOR OPERATOR Page 20 of 20 Revision 7, 09/17/2008 .

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

72. WE04-EK3.2 OnINEW/1H/3IROINAPS//

Operators have entered 1-ECA-1.2, LOCA Outside Containment. 1-ECA-1.2 will have the operator isolate cold leg injection piping from _ _ _ _ _ _ , and if RCS pressure is INCREASING AFTER the isolation, the crew will transition to _ _ _ _ _ _ __ A. High-Head SI pumps; 1-E-1, Loss of Reactor or Secondary Coolant. B. High-Head SI pumps; 1-ECA-1.1, Loss of Emergency Coolant Recirculation. C. Low-Head SI pumps; 1-ECA-1.1, Loss of Emergency Coolant Recirculation. D~ Low-Head SI pumps; 1-E-1, Loss of Reactor or Secondary Coolant. Feedback

a. Incorrect. Plausible since this seems like the more likely source and an alternate hot leg path is available and could be used without interupting flow to the core, however it is not a procedural option; second part correct since the RCS is most likely intact now the operator is sent to E-1 to perform any subsequent diagnostic, and if this were the only problem would check for and meet SI termination in E-1.

b. Incorrect. First part incorrect but plausible as discussed above; second part incorrect but plausible since the candidate who does not have detailed knowledge of the EOP network would most likely conclude that ECA-1.1 will deal with plant conditions.

c. Incorrect. First part is correct this portion of low-head piping outside containment is isolated as the likely source from back leakage of check valves in the cold leg injection lines; second part is incorrect but plausible as discussed in distractor b and would be true if RCS pressure were decreasing as checked in ECA-1.2 Step 2c.

d. Correct. First part correct, after verifing proper system alignment in Step 1 of ECA-1.2, Steps 2a & 2b will isolate this flowpath; second part also correct Step 2c of ECA-1.2 will check RCS pressure, since it is increasing the conclusion is leakage is isolated and inventory is no longer being lost so the EOP network uses E-1 to complete recovery actions.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes LOCA Outside Containment Knowledge of the reasons for the following responses as they apply to the (LOCA Outside Containment): Normal, abnormal and emergency operating procedures associated with (LOCA Outside Containment). (CFR: 41.5 141.10, 45.6, 45.13) Tier: 1 Group: 1 Importance Rating: 3.4/4.0 Technical

Reference:

1-ECA-1.2 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info: knowledge of the reason is implicit in being able to sellect the correct response.

NUMBER PROCEDURE TITLE REVISION 6 1-ECA-1.2 LOCA OUTSIDE CONTAINMENT PAGE 2of4 ACTION I EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. VERIFY PROPER VALVE ALIGNMENT:

a) Low-Head SI Pumps Hot Leg Injection 0 a) Manually close valves. Valves - CLOSED: 0 !E valves cannot be closed, THEN locally 0

• 1-SI-MOV-1890A close valves.

0

• 1-SI-MOV-1890B b) SI Accumulator Sample Isolation Valves- 0 b) Manually close valves.

CLOSED: IF valves cannot be closed, THEN close 0

• 1-SI-HCV-1850B the following Containment Isolation Trip Valves:

0

• 1-SI-HCV-1850D 0
• 1-SI-TV-1842 0
• 1-SI-HCV-1850F 0
• 1-SI-TV-1859 0
• 1-SI-HCV-1850A 0
• 1-SI-HCV-1850C 0
• 1-SI-HCV-1850E

NUMBER PROCEDURE TITLE REVISION 6 1-ECA-1.2 LOCA OUTSIDE CONTAINMENT PAGE 3 of4 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED Q- ISOLATE COLD LEG INJECTION PIPING: a) Close the following Low-Head SI Pump o a) Locally close valves. Cold Leg Injection Valves: o . 1-SI-MOV-1890C o . 1-SI-MOV-1890D b) Close the following Low-Head SI Pump Db) Locally close valves. Discharge Valves: o . 1-SI-MOV-1864A o . 1-SI-MOV-1864B o c) Check RCS pressure - INCREASING c) Do the following:

1) Verify Low-Head SI Pump Cold Leg Injection Valves closed:

o . 1-SI-MOV-1890C o . 1-SI-MOV-1890D o IF both valves are NOT closed, THEN GO TO 1-ECA-1.1, LOSS OF EMERGENCY COOLANT RECIRCULATION, STEP 1. (STEP 2 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 6 1-ECA-1.2 LOCA OUTSIDE CONTAINMENT PAGE 4of4 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

2. ISOLATE COLD LEG INJECTION PIPING:

(Continued)

2) Open the following valves:

a. Low-Head SI Pump Discharge Valves:

o . 1-SI-MOV-1864A o . 1-SI-MOV-1864B

b. Low-Head SI Pump Cold Leg Injection Valves:

o . 1-SI-MOV-1890C o . 1-SI-MOV-1890D o 3) GO TO 1-ECA-1.1, LOSS OF EMERGENCY COOLANT RECIRCULATION, STEP 1. 3._ GO TO 1-E-1, LOSS OF REACTOR OR SECONDARY COOLANT, STEP 1

                                        - END-

STUDENT GUIDE FOR EMERGENCY CONTINGENCY ACTION PROCEDURES (94) LOCA Outside Containment (1-ECA-1.2) 6.1 Objective U 13841 List the following information associated with 1-ECA-1.2, "LOCA Outside Containment."

• Purpose of the procedure
• Modes of applicability
• Entry conditions
• Major action categories
• Conditions that result in leaving the procedure 6.1 Content

1. ECA-1.2 provides recovery/restoration guidelines for operators to use following a LOCA outside containment. This procedure is written to identify and isolate the break.

2. ECA-1.2 is applicable in modes 1 through 3.

3. ECA-1.2 is entered from E-O, "Reactor Trip or Safety Injection," based on a loss of RCS inventory outside containment as indicated by any of the following:

3.1. Safeguards sump level 3.2. Auxiliary building sump levels 3.3. Safeguards (vent stack 8) and auxiliary building radiation. 3.4. ECA-1.2 is also entered via E-1, "Loss of Reactor or Secondary Coolant," based on safeguards and auxiliary building radiation.

4. The major action categories are:

REACTOR OPERATOR Page 28 of 28 Revision 7,09/17/2008

STUDENT GUIDE FOR EMERGENCY CONTINGENCY ACTION PROCEDURES (94) 4.1. Verify proper valve alignment. 4.1.1.Directs the operator to verify all normally closed valves are in the proper position. 4.2. Identify and isolate break. 4.2.1. Operators attempt to locate and isolate the break by sequentially closing valves for each penetration into the containment. 4.3. Check if break is isolated. 4.3.1.RCS pressure is monitored to determine if the break is isolated. 4.3.2.Subsequent follow on action is determined based on the success of break isolation.

5. A transition from ECA-1.2 is based on the success of isolating the break.

5.1.lf the break has been isolated, the operator is directed to go to E-1, "Loss of Reactor or Secondary Coolant." 5.2. If the break cannot be isolated, a transition is made to ECA-1.1, "Loss of Emergency Coolant Recirculation. " 6.2 Objective U 4170 List the two interfaces between the LHSI system and the RCS where an inter-system LOCA can occur. 6.2 Content

1. The most probable source of a Design Basis LOCA outside containment are the interfaces between the LHSI system and the RCS:

1.1. Upstream of the isolation valves (MOV-1890A, B, C, and D) the piping class changes to low pressure piping. 1.1.1.Therefore, this piping can be a source of a LOCA outside containment 1.2. LHSI Pump Cold Leg Injection (most viable area) REACTOR OPERATOR Page 29 of29 Revision 7,09/17/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

73. WE05-EK2.1 073IMODIFIEDINAPSIHI3IROINAPS//

Unit 1 tripped from 100% power, and a loss of secondary heat sink occurred. The following plant conditions exist:

• The crew is currently in 1-FR-H.1, Response to Loss of Secondary Heat Sink.
• Bleed and feed has been established.
• A Main Steam line break occurs inside containment and CDA actuates, but only one Quench Spray pump started.
• RCS cold-leg temperatures have decreased to 26S o F.

Based on these conditions, which ONE of the following identifies the correct operator response? A'! Reset CDA, reset Phase 'B', and place instrument air back in service to PORVs. B. Transition to 1-FR-Z.1, Response to High Containment Pressure. C. Transition to 1-FR-P.1, Response to Imminent Pressurized Thermal Shock Condition. D. Verify proper alignment of equipment using 1-E-O, Reactor Trip or Safety Injection. Feedback

a. Correct. There is caution prior to Step 22 (the step that establishes the bleed path) that specifically delineates these requirements. The concern is maintaining the RCS bleed path.

b. Incorrect. Plausible since a DBA steam break occurred however Z path is a lower priority.

c. Incorrrect. Plausible since criteria is met but P.1 is lower priority.

d. Incorrect. Plausible since these actions are required by the procedure and the candidate who does not have detailed knowledge of H.1 may default to this answer.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Loss of Secondary Heat Sink Knowledge of the interrelations between the (Loss of Secondary Heat Sink) and the following: Components, and functions of control and safety systems, including instrumentation, signals, interlocks, failure modes, and automatic and manual features. (CFR: 41.7/45.7) Tier: 1 Group: 1 Importance Rating: 3.7/3.9 Technical

Reference:

1-FR-H.1 Proposed references to be provided to applicants during examination: None Learning Objective: 6604 Question History: modified additional info:

NUMBER PROCEDURE TITLE REVISION 19 1-FR-H.1 RESPONSE TO LOSS OF SECONDARY HEAT SINK PAGE 24 of 41 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

18. RESET BOTH TRAINS OF SI

19. RESET BOTH TRAINS OF PHASE A ISOLATION

20. RESET BOTH TRAINS OF PHASE B ISOLATION IF NECESSARY

21. ESTABLISH INSTRUMENT AIR TO CONTAINMENT:

o a) Verify at least one Air Compressor is o a) Start at least one Air Compressor. supplying Instrument Air System b) Verify Containment Instrument Air Trip o b) Manually open valves. Valves - OPEN: o

• 1-IA-TV-102A o
• 1-IA-TV-102B

NUMBER PROCEDURE TITLE REVISION 19 1-FR-H.1 RESPONSE TO LOSS OF SECONDARY HEAT SINK PAGE 25 of 41 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION: If a CDA occurs after initiation of bleed and feed, then CDA should be reset and Step 20 through Step 23 should be repeated to verify RCS bleed path.

22. ESTABLISH RCS BLEED PATH:

a) Check power to PRZR PORV Block Valves a) Locally restore power to PRZR PORV

           - AVAILABLE:                                            Block Valves:

0

• 1-RC-MOV-1536 0
• 1-EE-BKR-1H1-2S-F3 (1-RC-MOV-1536) PRZR PORV 0
• 1-RC-MOV-1535 Isolation Valve 0
• 1-EE-BKR-1J1-2S-F2 (1-RC-MOV-1535) PRZR PORV Isolation Valve b) Check PRZR PORV Block Valves - BOTH 0 b) Open valves.

OPEN: 0

• 1-RC-MOV-1536 0
• 1-RC-MOV-1535 c) Open both PRZR PORVs: 0 c) Try to open PORVs by placing NOT PROTECTION key switch to OPEN.

0

• 1-RC-PCV-1456 0
• 1-RC-PCV-1455C

NUMBER PROCEDURE TITLE REVISION 19 1-FR-H.1 RESPONSE TO LOSS OF SECONDARY HEAT SINK PAGE 26 of 41 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

23. VERIFY ADEQUATE RCS BLEED PATH BY Do the following:

VERIFYING THE FOLLOWING VALVES - OPEN: a) Open the following Reactor Vent Valves: 0

• 1-RC-MOV-1536, PRZR PORV 0
• 1-RC-SOV-101A-2 BLOCK VALVE 0
• 1-RC-SOV-1 01 B-2 0
• 1-RC-MOV-1535, PRZR PORV BLOCK VALVE 0
• 1-RC-SOV-101A-1 0
• 1-RC-PCV-1456, PRZR PORV 0
• 1-RC-SOV-1 01 B-1 0
• 1-RC-PCV-1455C, PRZR PORV b) Open the following PRZR Vent Valves:

0

• 1-RC-SOV-1 02A-2 o
• 1-RC-SOV-102B-2 o
• 1-RC-SOV-102A-1 o
• 1-RC-SOV-102B-1 c) Do the following while continuing with Step 24:

1) Align one of the following low-pressure water sources to feed SGs using ATTACHMENT 3, ALIGNING ALTERNATE AFW SUCTION:

o

• Fire Protection System OR o . Service Water System (STEP 23 CONTINUED ON NEXT PAGE)

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95) 7.8 Objective U 11255 Explain the following concepts associated with Reactor Coolant System bleed and feed in response to a loss of secondary heat sink (1-FR-H.1).

• Why bleed and feed must be initiated promptly when a loss of secondary heat removal capability is imminent (SOER-86-1)
• How the continuous action pertaining to cold-leg recirculation transfer is addressed if refueling water storage tank level decreases below the value requiring transfer to cold-leg recirculation while Reactor Coolant System bleed and feed is being established (SOER-86-1)
• How a containment depressurization actuation would affect the expected Reactor Coolant System bleed path 7.8 Content

1. Bleed and feed must be initiated promptly when a loss of secondary heat removal capability is imminent to:

1.1. Prevent or minimize uncovering the core. 1.2. Prevent inadequate core cooling.

2. Per the Continuous Action Page, if RWST level decreases below the value requiring transfer to cold-leg recirculation while RCS bleed and feed is being established, the operator should complete the actions necessary to establish RCS bleed and feed, THEN immediately transition to ES-1.3 to transfer to cold-leg recirculation.

3. If a CDA occurs after initiation of RCS bleed and feed, the resulting containment isolation Phase B will isolate Instrument Air to containment.

3.1. Nitrogen flasks will backup instrument air for a limited time. 3.2. In order to restore the capability to open PRZR PORVs with IA and re-establish the expected RCS bleed path, CDA must be reset, and the applicable steps must be performed again. REACTOR OPERATOR Page 56 of 99 Revision 14, 11/06/2008

QUESTIONS REPORT ( for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

74. WE08-EA2.2 074INEWINAPSIHI3IROINAPS//

Unit 1 was operating at 100% power when a LOCA occurred. The crew has just transitioned from 1-E-1, Loss of Reactor or Secondary Coolant, to 1-FR-P.1, Response to Imminent Pressurized Thermal Shock Condition. The following plant conditions exist:

• Containment pressure is 15 psia and is slowly trending down.
• All RCPs are stopped.
• RVLlS Full Range is reading 100%.
• RCS subcooling based on Core Exit TCs is 105°F.
• RCS pressure is 850 psig.

Based on these plant conditions, which ONE of the following identifies the actions the crew will perform in accordance with 1-FR-P.1, and the reason for these actions? A'! Remain in 1-FR-P.1, terminate SI and depressurize to minimize subcooling in order to limit pressure stress on the vessel. B. Exit 1-FR-P.1 and return to procedure step in effect, pressure is too low for PTS to be a concern. C. Exit 1-FR-P.1 and go to 1-ES-1.1, SI Termination, SI must be terminated promptly to mitigate the PTS condition. D. Remain in 1-FR-P.1, leave SI in service and determine soak requirements in order to minimize thermal stresses during subsequent recovery actions. Feedback

a. Correct. Subcooling is adequate (since we are not adverse) so P.1 will terminate SI this allows for subsequent actions that minimize RCS subcooling (depressurize).

b. Incorrect. Plausible since P.1 will do this upon entry, and the candidate who does not have detailed knowledge of the procedure may assume that since pressure is significantly reduced that this would be logical.

c. Incorrect. Plausible since criteria is met, most EOP procedures transition to ES-1.1 in order to terminate SI and the candidate who does not have detailed knowledge of P.1 may default to this distractor based on past practice on the majority of scenarios that the transition to ES-1.1 is made.

d. Incorrect. Candidate who does not have detailed knowledge of P.1 may not be sure that termination criteria is met, thus they would like choose the distractor since it may appear to them that it is a more conservative approach, the discussion of soak is correct but again it would not be correct to leave SI in service when termination criteria are satisfied.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes Pressurized Thermal Shock Ability to determine and interpret the following as they apply to the (Pressurized Thermal Shock): Adherence to appropriate procedures and operation within the limitations in the facility's license and amendments. (CFR: 43.5/45.13) Tier: 1 Group: 2 Importance Rating: 3.514.1 Technical

Reference:

1-FR-P.1 Proposed references to be provided to applicants during examination: None Learning Objective: Question History: new additional info:

NORTH ANNA POWER STATION FUNCTION RESTORATION PROCEDURE NUMBER PROCEDURE TITLE REVISION 17 1-FR-P.1 RESPONSE TO IMMINENT PRESSURIZED THERMAL SHOCK CONDITION PAGE 1 of 20 (WITH TWO ATTACHMENTS) PURPOSE To provide instructions to avoid or limit thermal shock or pressurized thermal shock to the Reactor Vessel, or to avoid or limit overpressure conditions at low temperature. ENTRY CONDITIONS This procedure is entered from:

• Red or Orange terminus of the INTEGRITY CSF STATUS TREE.

CONTINUOUS USE

NUMBER PROCEDURE TITLE REVISION 17 1-FR-P.1 RESPONSE TO IMMINENT PRESSURIZED THERMAL SHOCK CONDITION PAGE 2 of 20 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION:

• 1-FR-H.1, RESPONSE TO LOSS OF SECONDARY HEAT SINK, should be initiated only if a total feed flow capability of 340 gpm is not available at any time during this procedure.
• When the ECST level decreases to 40%, then 1-AP-22.5, LOSS OF EMERGENCY CONDENSATE STORAGE TANK 1-CN-TK-1, should be initiated to provide an alternate water source to the AFW Pumps.

NOTE: Setpoints in brackets [ ] are for adverse Containment atmosphere (20 psia Containment pressure or Containment Radiation has reached or exceeded 1.0E5 R/hr or 70% on High Range Recorder). CD- CHECK RCS PRESSURE - GREATER THAN 225 PSIG [450 PSIG] o IF either Low-Head SI Pump flow is greater than 1000 gpm, THEN RETURN TO procedure and step in effect. o IF NOT, THEN continue with Step 2.

NUMBER PROCEDURE TITLE REVISION 17 1-FR-P.1 RESPONSE TO IMMINENT PRESSURIZED THERMAL SHOCK CONDITION PAGE 3 of 20 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION: If the turbine-driven AFW pump is the only available source of feed flow, steam supply to the turbine-driven AFW pump must be maintained from at least one SG. NOTE: A faulted SG is any SG that is depressurizing in an uncontrolled manner or is completely depressurized.

2. CHECK COLD LEG TEMPERATURES- Try to stop RCS cooldown:

STABLE OR INCREASING o a) Close SG PORVs. o b) Close Condenser Steam Dump Valves. o c) IF RHR System is in service, THEN stop any cooldown from RHR System. o d) Maintain total feed flow greater than 340 gpm until narrow range level is greater than 11 % [22%] in at least one non-faulted SG. (STEP 2 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 17 1-FR-P.1 RESPONSE TO IMMINENT PRESSURIZED THERMAL SHOCK CONDITION PAGE 4 of 20 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

2. CHECK COLD LEG TEMPERATURES -

STABLE OR INCREASING (Continued) e) Minimize cooldown from faulted SGs: o 1) Verify MSTVs and Bypass Valves are closed for each faulted SG. o IF NOT, THEN manually close faulted SGs MSTVs and Bypass Valves.

2) Locally close faulted SGs Steam Supply Valves to the Turbine-Driven AFW Pump:

o

• 1-MS-18, A Steam Line to AFW Pump Isolation Valve o
• 1-MS-57, B Steam Line to AFW Pump Isolation Valve o
• 1-MS-95, C Steam Line to AFW Pump Isolation Valve o 3) IF all SGs are faulted, THEN control feed flow at 100 gpm to each SG.

o 4) IF any SG is NOT faulted, THEN isolate all feedwater to faulted SGs unless necessary for RCS temperature control. o IF a faulted SG is needed for RCS temperature control, THEN control feed flow at 100 gpm to that SG.

NUMBER PROCEDURE TITLE REVISION 17 1-FR-P.1 RESPONSE TO IMMINENT PRESSURIZED THERMAL SHOCK CONDITION PAGE 5 of 20 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

3. CHECK PRZR PORV BLOCK VALVES:

a) Check power to PRZR PORV Block Valves a) Locally restore power to PRZR PORV

        - AVAILABLE:                                 Block Valves:

o

• 1-RC-MOV-1536 o
• 1-EE-BKR-1 H1-2S-F3 (1-RC-MOV-1536) PRZR PORV o
• 1-RC-MOV-1535 Isolation Valve o
• 1-EE-BKR-1 J 1-2S-F2 (1-RC-MOV-1535) PRZR PORV Isolation Valve b) Check PRZR PORV Block Valves - AT o b) Open at least one Block Valve unless LEAST ONE OPEN: both are closed to isolate open or faulty PRZR PORVs.

o

• 1-RC-MOV-1536 (1-RC-PCV-1455C) o
• 1-RC-MOV-1535 (1-RC-PCV-1456)

NUMBER PROCEDURE TITLE REVISION 17 1-FR-P.1 RESPONSE TO IMMINENT PRESSURIZED THERMAL SHOCK CONDITION PAGE 6 of 20 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION: To minimize loss of RCS inventory, if any PRZR PORV opens because of high PRZR pressure, then Step 4 should be repeated after RCS pressure decreases to less than 2335 psig.

4. CHECK IF PRZR PORVs SHOULD BE CLOSED:

a) Check the following: D a) Verify at least one PRZR PORV is open. D

• PRZR pressure - LESS THAN D IF NOT, THEN manually open at least 2335 PSIG one PRZR PORV.

OR D WHEN pressure is less than *setpoint, THEN do Step 4b. D

• RCS pressure - LESS THAN NDT SETPOINT IF NDT PROTECTION D Continue with Step 5.

SYSTEM IS IN SERVICE D b) PRZR PORVs - CLOSED D b) Manually close PORV. D IF any valve cannot be closed, THEN manually close its Block Valve.

~      CHECK IF SIIS IN SERVICE:                        D   GO TO Step 13.

D

• SI flow - INDICATED OR D
• Low-Head SI Pumps - ANY RUNNING

NUMBER PROCEDURE TITLE REVISION 17 1-FR-P.1 RESPONSE TO IMMINENT PRESSURIZED THERMAL SHOCK CONDITION PAGE 7 of 20 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED 0_ CHECK IF 51 CAN BE TERMINATED: Do the following: D

• RCS subcooling based on Core Exit D a) IF RCS subcooling based on Core Exit TCs - GREATER THAN 75°F [125°F] TCs is greater than 25°F [75°F] AND no RCP is running, THEN start one RCP D
• Check RVLlS indication - GREATER using 1-0P-5.2, REACTOR COOLANT THAN OR EQUAL TO VALUE IN PUMP STARTUP AND SHUTDOWN.

TABLE: D b) GO TO Step 26. NO. RVUS INDICATION RCPs RUNNING FULL RANGE DYNAMIC RANGE 0 67% 1 36% 2 51% 3 83%

7. RESET BOTH TRAINS OF SI

8. RESET ISOLATION SIGNALS:

D a) Reset both Trains of Phase A Isolation D b) Reset both Trains of Phase B Isolation, if actuated

NUMBER PROCEDURE TITLE REVISION 17 1-FR-P.1 RESPONSE TO IMMINENT PRESSURIZED THERMAL SHOCK CONDITION PAGE 8 of 20 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

9. ESTABLISH INSTRUMENT AIR TO CONTAINMENT:

0 a) Verify at least one Air Compressor is o a) Start at least one Air Compressor. supplying Instrument Air System b) Verify Containment Instrument Air Trip o b) Manually open valves. Valves - OPEN: 0

• 1-IA-TV-1 02A 0
• 1-IA-TV-1 02B

10. STOP SI PUMPS:

0 a) Stop all but one Charging pump and put in AFTER-STOP b) Check Low Head SI Pump Suctions From o b) GO TO Step 11. Containment Sump - CLOSED: 0

• 1-SI-MOV-1860A 0
• 1-SI-MOV-1860B 0 c) Stop Low-Head SI pumps and put in AUTO-STANDBY

NUMBER PROCEDURE TITLE REVISION 17 RESPONSETOIMMINENTPRESSUR~EDTHERMALSHOCK 1-FR-P.1 PAGE CONDITION 19 of 20 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

23. CHECK PRZR LEVEL-LESSTHAN o Control charging and letdown as required.

82% [62%] o lE required, THEN establish excess letdown using 1-0P-8.5, OPERATION OF EXCESS LETDOWN.

24. ENERGIZE PRZR HEATERS AND OPERATE o IF normal spray is NOT available AND NORMAL SPRAY AS REQUIRED TO letdown is in service, THEN use Auxiliary MAINTAIN PRZR PRESSURE - STABLE Spray.

o lE letdown is NOT in service, THEN use one PRZR PORV. _ VERIFY ADEQUATE RCS DEPRESSURIZATION: o Depressurize RCS using normal spray. ( IF normal spray is NOT available AND letdown is in service, THEN use Auxiliary o

• RCS subcooling based on Core Exit Spray and RETURN TO Step 17b.

TCs - LESS THAN 35°F [85°F] OR o IF Auxiliary Spray is NOT available, THEN RETURN TO Step 17a. o

• RCS pressure - LESS THAN 125 PSIG [200 PSIG]

CAUTION: If a soak period is required, then RCS temperature should be maintained stable and pressure should not be increased for 1 hour. Cooldown is then permitted after the 1 hour soak.

  ~

6 - DETERMINE IF RCS TEMPERATURE SOAK IS REQUIRED:

                                                        ~'\ ~

LA' .".:. ~. J-uf o a) Cooldown rate in Cold Legs - GREATER 0 a) GO TO Step 27. THAN 100°F IN ANY 60 MINUTE PERIOD (STEP 26 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 17 1-FR-P.1 RESPONSE TO IMMINENT PRESSURIZED THERMAL SHOCK CONDITION PAGE 20 of 20 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

26. DETERMINE IF RCS TEMPERATURE SOAK IS REQUIRED: (Continued) b) Do the following:

0 1) Record start of soak time:

2) Maintain the following for 1 hour:

0

• RCS temperature - STABLE 0
• RCS pressure - STABLE OR DECREASING 0 3) Perform actions of other guidelines in effect that do not cool down or raise RCS pressure until the RCS temperature soak has been completed 0 4) Record end of soak time:

0 5) Maintain RCS pressure and Cold Leg temperatures within the limits of ATTACHMENT 1 0 6) Maintain cooldown rate in Cold Legs at less than 50°F in any 60 minute period

27. RETURN TO PROCEDURE AND STEP IN EFFECT

                                              - END-

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95)

2. Establishing RCS pressure as low as possible minimizes the pressure stress on the reactor pressure vessel.

2.1. Depressurization may have been stopped due to high PRZR level prior to reaching minimum subcooling. 2.2. If minimum subcooling is not already established, this step instructs the operator to depressurize. 12.5 Objective U 13012 Explain the following concepts associated with terminating safety injection in accordance with 1-FR-P.1, "Response to Imminent Pressurized Thermal Shock Condition."

• How termination of safety injection flow may decrease the likelihood of pressurized thermal shock occurring
• Why charging flow may need to be established prior to securing safety injection flow 12.5 Content

1. Terminating cold SI flow to the RCS will reduce the thermal stress on the reactor vessel.

1.1. Also, SI flow could act to cause an RCS pressure increase and to prevent RCS depressurization. 1.2. Minimization of pressure is a desirable action to reduce pressure stress on the vessel. 1.3. Termination of SI flow will reduce the possibility of overfilling the PRZR, with the attendant rapid increase in RCS pressure (due to a solid water condition in the RCS).

2. If the LHSI pumps are supplying the charging pumps (containment suction valves open) then the LHSI recirc valves are closed.

2.1. Minimum flow is established for LHSI operation via normal charging. 2.2. If the charging pump recirc path cannot be established, then regardless of LHSI status, a minimum of 60 gpm of charging flow must be established to provide minimum flow for the charging pumps. REACTOR OPERATOR Page 78 of 99 Revision 14, 11/06/2008

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal

75. WE14-EA1.3 075IMODIFIEDINAPSIHI4IROINAPS//

Given the following conditions:

• Unit 1 has experienced a LOCA.
• After establishing Cold Leg Recirculation, operators observed indication of sump blockage.
• The crew has just transitioned to 1-ECA-1.1, Loss of Emergency Recirculation Capability.

The STA reports an ORANGE path on Containment Pressure. Based on these plant conditions, which ONE of the following identifies the crew response, and the reason for their response? A'I Remain in 1-ECA-1.1; FRPs are not implemented until specifically directed by 1-ECA-1.1. B. Remain in 1-ECA-1.1; 1-FR-Z.1 is not to be performed as long as 1-ECA-1.1 is in effect. C. Immediately transition to 1-FR-Z.1 and operate Containment Depressurization Systems as directed, then return to 1-ECA-1.1; precludes a Red Path on the Containment status tree. D. Immediately transition to 1-FR-Z.1; Verify Phase A Isolation and Steamline Isolation, then return to 1-ECA-1.1; precludes a Red Path on the Containment status tree. Feedback

a. Correct. ECA-1.1 delays FRP implementation because of plant conditions since assessing and responding to core cooling concerns caused by sump blockage takes presidence.

b. Incorrect. Plausible because candidate may relate the fact that ECA-1.1 is used to determine what systems to operate; however FR-Z.1 is still performed when ECA-1.1 allows FRPs to be implemented.

c. Incorrect. Plausible since normally this would be the correct course of action and in general execution of severe challenge procedures is designed to prevent an extreme challenge.

d. Incorrect. This is in fact how Z.1 is implemented according the notes, however as noted above it is NOT immediately entered.

QUESTIONS REPORT for 2009 NRC RO exam Validation 3 copy with SRC formatting - for submittal Notes High Containment Pressure EA 1. Ability to operate and / or monitor the following as they apply to the (High Containment Pressure): Desired operating results during abnormal and emergency situations. (CFR: 41.7 /45.5 /45.6) Tier: 1 Group: 2 Importance Rating: 3.3/3.8 Technical

Reference:

1-FR-Z.1 and background Document Proposed references to be provided to applicants during examination: None Learning Objective: Question History: modified additional info: (

NORTH ANNA POWER STATION EMERGENCY CONTINGENCY ACTION NUMBER PROCEDURE TITLE REVISION 15 1-ECA-1.1 LOSS OF EMERGENCY COOLANT RECIRCULATION PAGE (WITH TWO ATTACHMENTS) 1 of 34 PURPOSE To provide instructions to attempt to restore emergency coolant recirculation capability, to delay RWST depletion by adding makeup and reducing outflow, and to depressurize the RCS to minimize break flow. ENTRY CONDITIONS This procedure is entered from:

• 1-E-1, LOSS OF REACTOR OR SECONDARY COOLANT,
• 1-ES-1.3, TRANSFER TO COLD LEG RECIRCULATION, or
• 1-ECA-1.2, LOCA OUTSIDE CONTAINMENT.

CONTINUOUS USE

NUMBER PROCEDURE TITLE REVISION 15 1-ECA-1.1 LOSS OF EMERGENCY COOLANT RECIRCULATION PAGE 2 of 34 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION:

• If emergency coolant recirculation capability is restored to at least one train during this procedure, then further recovery actions should continue by returning to the procedure and step in effect.
• If the suction source is lost to any SI Pump or Recirc Spray Pump, then the pump should be stopped.

O,,,,0'I,J*;v-./' NOTE:

• IF Containment Sump Blockage has occurred, THEN FRs should NOT be implemented until directed in this procedure.
• ATTACHMENT 2, MINIMUM SI FLOW RATE VERSUS TIME AFTER TRIP, provides adequate injection flow required.
• Setpoints in brackets [ ] are for adverse Containment atmosphere (20 psia Containment pressure or Containment Radiation has reached or exceeded 1.0E5 Rlhr or 70% on High Range Recorder).

1. CHECK EMERGENCY COOLANT Try to restore at least one train of RECIRCULATION EQUIPMENT - Emergency Coolant Recirculation AVAILABLE: Equipment:

o

• Low-Head SI Pumps o
• Local operations o
• Low-Head SI Pump Suction Valves from o
• Electrical restoration Containment o
• Equipment repair

2. RESET BOTH TRAINS OF SI IF NECESSARY

3. PUSH BOTH SI RECIRC MODE RESET BUTTONS

 *4. CHECK RWST LEVEL - GREATER THAN                      o   Implement FRs as applicable.

8% o GO TO Step 30.

NUMBER PROCEDURE TITLE REVISION 9 1-FR-Z.1 RESPONSE TO HIGH CONTAINMENT PRESSURE PAGE 2 of7 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. VERIFY PHASE A ISOLATION VALVES- D IF flow path is NOT necessary, THEN close CLOSED valves.

CAUTION: If 1-ECA-1.1, LOSS OF EMERGENCY COOLANT RECIRCULATION, is in effect, then, to preserve RWST inventory, Step 2 through Step 5 of this procedure should not be performed. (E- CHECK IF CDA IS REQUIRED: D a) Containment pressure - HAS EXCEEDED D a) RETURN TO procedure and step in 28 PSIA effect. b) Do the following: D 1) Manually actuate CDA D 2) Verify CC Pumps - TRIPPED 2) Stop CC Pumps: D

• 1-CC-P-1A D
• 1-CC-P-1B D 3) Stop all RCPs D 4) Verify Phase B Isolation Valves - D 4) Manually close valves.

CLOSED

NUMBER PROCEDURE TITLE REVISION 9 1-FR-Z.1 RESPONSE TO HIGH CONTAINMENT PRESSURE PAGE 3 of 7 ACTIONI EXPECTED RESPONSE RESPONSE NOT OBTAINED

3. VERIFY PROPER OPERATION OF CONTAINMENT QUENCH SPRAY SYSTEMS:

a) Verify QS Pump Discharge MOVs - OPEN: D a) Manually open valves. D

• 1-QS-MOV-101A D
• 1-QS-MOV-1 01 B b) Verify QS Pumps - RUNNING: D b) Manually start pumps.

D

• 1-QS-P-1A D
• 1-QS-P-1 B

4. VERIFY PROPER SERVICE WATER SYSTEM OPERATION:

D a) At least four Service Water Pumps - D a) Manually start pumps. RUNNING b) Verify Service Water Supply to CC Heat D b) Manually close valves. Exchangers - CLOSED: D

• 1-SW-MOV-108A D
• 1-SW-MOV-108B (STEP 4 CONTINUED ON NEXT PAGE)

(

( NUMBER PROCEDURE TITLE REVISION 9 1-FR-Z.1 RESPONSE TO HIGH CONTAINMENT PRESSURE PAGE 4 of 7 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

4. VERIFY PROPER SERVICE WATER SYSTEM OPERATION: (Continued) c) Verify Recirc Spray Heat Exchanger c) Manually open valves:

Service Water flow - INDICATED:

                                                         "H"TRAIN "H"TRAIN D

• 1-SW-MOV-103A D
• 1-SW-FI-100A, RECIR SP HX A SW FLOW D
• 1-SW-MOV-101A D
• 1-SW-FI-100D, D
• 1-SW-MOV-103D RECIR SP HX 0 SW FLOW D
• 1-SW-MOV-101C "J'" TRAIN D
• 1-SW-MOV-104A D
• 1-SW-FI-100B, D
• 1-SW-MOV-105A RECIR SP HX B SW FLOW D
• 1-SW-MOV-104D D
• 1-SW-FI-100C, RECIR SP HX C SW FLOW D
• 1-SW-MOV-105C "J"'TRAIN D
• 1-SW-MOV-103B D
• 1-SW-MOV-1 01 B D
• 1-SW-MOV-103C D
• 1-SW-MOV-1 01 0 D
• 1-SW-MOV-104B D
• 1-SW-MOV-105B D
• 1-SW-MOV-104C D
• 1-SW-MOV-105D

NUMBER PROCEDURE TITLE REVISION 9 1-FR-Z.1 RESPONSE TO HIGH CONTAINMENT PRESSURE PAGE 5 of 7 ACTIONI EXPECTED RESPONSE RESPONSE NOT OBTAINED

5. VERIFY PROPER OPERATION OF CONTAINMENT RECIRC SPRAY SYSTEMS:

a) Verify Casing Cooling Pump Isolation o a) Manually open valves. Valves - OPEN:

           "H"TRAIN o

• 1-RS-MOV-100A o
• 1-RS-MOV-1 01 B "J"TRAIN o
• 1-RS-MOV-100B o
• 1-RS-MOV-101A b) Verify the following pumps - RUNNING: o b) Manually start pumps.

           "H"TRAIN o

• 1-RS-P-3A "J" TRAIN o
• 1-RS-P-3B o c) Verify Recirc Spray Sump level - o c) WHEN Recirc Spray Sump is greater GREATER THAN 4 FT 10 IN than 4 ft 10 in, THEN perform Step 5.d through Step 5.f.

o Continue with Step 6. (STEP 5 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 9 1-FR-Z.1 RESPONSE TO HIGH CONTAINMENT PRESSURE PAGE 6 of 7 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

5. VERIFY PROPER OPERATION OF CONTAINMENT RECIRC SPRAY SYSTEMS: (Continued) d) Verify Recirc Spray Pump Isolation Valves - o d) Manually open valves.

OPEN:

        "H"TRAIN o

• 1-RS-MOV-155A o
• 1-RS-MOV-156A "J" TRAIN o . 1-RS-MOV-155B o
• 1-RS-MOV-156B e) Verify the following pumps - RUNNING: e) Do the following:

        "H"TRAIN

• Manually start ORS pumps:

o

• 1-RS-P-1A (2 minute time delay) o
• 1-RS-P-2A o
• 1-RS-P-2A o
• 1-RS-P-2B "J"TRAIN
• Manually start IRS pumps following time delay:

o

• 1-RS-P-1 B (2 minute time delay) o . 1-RS-P-1A o
• 1-RS-P-2B o . 1-RS-P-1 B f) Start the following sample pumps on the Unit 1 Radiation Monitoring Panel:

o

• 1-SW-P-5 o
• 1-SW-P-8 o
• 1-SW-P-6 o
• 1-SW-P-7

NUMBER PROCEDURE TITLE REVISION 9 1-FR-Z.1 RESPONSE TO HIGH CONTAINMENT PRESSURE PAGE 70f7 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

6. VERIFY MSTVs AND BYPASS VALVES - o Manually close valves.

CLOSED o IF valves cannot be closed, THEN manually close SG Non-Return Valves and SG NRV Bypass Valves. CAUTION:

• At least one SG should be kept available for RCS cooldown to maintain secondary heat sink.
• If all SGs are faulted, then at least 100 gpm feed flow should be maintained to each SG.

7. CHECK IF FEED FLOW SHOULD BE ISOLATED TO ANY SG:

a) Check pressures in all SGs: o a) GO TO Step 8. 0

• Any SG pressure decreasing in an uncontrolled manner OR 0
• Any SG completely depressurized b) Isolate feed flow to affected SGs:

0

• Main Feedwater 0
• AFW

8. RETURN TO PROCEDURE AND STEP IN EFFECT

                                                   - END-

STUDENT GUIDE FOR EMERGENCY CONTINGENCY ACTION PROCEDURES (94) 5.8 Objective U 5829 Explain how ECA-1.1 is used when containment sump blockage occurs during recirculation mode, including use of FRs. 5.8 Content The Continuous Action Page (CAP) of ES-1.3 remains in effect during sump recirculation. This CAP directs operators to an attachment of ES-1.3, "Containment Sump Blockage." Attachment will sequentially secure the HHSI and LHSI pumps as necessary until one LHSI pump is running. If indications for the running LHSI pump are returned to normal, then the crew must evaluate if one HHSI pump can be started. If sump blockage is still indicated, the remaining LHSI pump is secured and the crew should attempt to establish an alternate water source (Charging pump cross-tie, affected unit's RWST, or unaffected unit's RWST) , align primary plant ventilation, and initiate ECA-1.1. ECA-1.1 contains a caution that reminds operators to stop any SI or Recirc Spray pump that loses suction. ECA-1.1 contains a note saying that if containment sump blockage has occurred that FRs should not be implemented until directed by the procedure. RWST level is checked> 3% If RWSR level is sufficient, but no low-heads are running due to containment sump blockage then operators are directed to: Align the suction of the charging pumps to the RWST Start a charging pump Verify adequate flow Open Chemical Addition Tank outlet valves Implement FRs as applicable. REACTOR OPERATOR Page 26 of 26 Revision 7, 09/17/2008}}