Text

Initial Written Retake Examination, 2009-301 Draft SRO Written Exam
	ML090710082
Person / Time
Site:	North Anna
Issue date:	02/10/2009
From:	; NRC/RGN-II
To:	;
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QUESTIONS REPORT for 2009 NRC SRO exam Validation 3 copy with SRC formatting - for submittal

76. 003-A2.05 076IMODIFIED/TURKEY POINT 2005 EXIHI3/SROIII Given the following conditions:

Unit 1 is at 100% power.

VCT level is initially 52%

VCT pressure is initially 30 psig.

The OATC notes 1-CH-LCV-1115A, VCT Level Control valve, is in the DIVERT position.

The following conditions exist:

VCT automatic makeup initiates.

1-CH-LC-1112C, VCT Level Controller, indicates 100% demand.

VCT level is stable at 23%.

VCT pressure is stable at 17 psig.

Based on the change in plant conditions, leakoff from the Rep number 2 seal to the standpipe will To mitigate this event, the crew will enter 1-AP-16, Increasing Primary Plant Leakage, and _ _ _ _ '

A. increase; isolate letdown by closing 1-CH-HCV-1200A, B, & C, and 1-CH-LCV-1460A & B.

B. increase; align 1-CH-LCV-1115A to VCT by locally opening breaker 7 on 1-EP-CB-26B.

C. decrease; isolate letdown by closing 1-CH-HCV-1200A, B, & C, and 1-CH-LCV-1460A & B.

D~ decrease; align 1-CH-LCV-1115A to VCT by locally opening breaker 7 on 1-EP-CB-26B.

Feedback

a. Incorrect. Plausible if candidate does not understand the relationship between VCT pressure and # 2 seal; second part it also incorrect, however it is only taken if VCT level is NOT under control or failing the divert valve to the VCT is unsuccessful.

b. Incorrect. First part is incorrect as discussed above; second part is correct.

c. Incorrect. First part is correct. Second part is incorrect as discussed in Distractor a.

d. Correct. First part is correct. Second part is also correct, the LC is operating correctly (100% demand is the controller output that positions the valve to the VCT position) so the action required by 1-AP-16 is to fail the valve to the VCT position by removing power (1-AP-16 Step 3 RNO).

QUESTIONS REPORT for 2009 NRC SRO 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: Effects of VCT pressure on RCP seal leakoff flows (CFR: 41.5 /43.5/45.3 /45/13)

Tier: 2 Group: 1 Importance Rating: 2.5/2.8 Technical

Reference:

1-AP-16 Proposed references to be provided to applicants during examination: None Learning Objective:

Question History: modified from turkey point 2005 NRC exam to make specific for NAPS additional info:

(

'Dominion' NORTH ANNA POWER STATION ABNORMAL PROCEDURE NUMBER PROCEDURE TITLE REVISION 25 1-AP-16 INCREASING PRIMARY PLANT LEAKAGE (WITH FIVE ATTACHMENTS) PAGE 1 of 15 PURPOSE To provide instructions for locating, quantifying, and mitigating increasing primary plant leakage.

ENTRY CONDITIONS This procedure is entered when there is increasing primary plant leakage, as indicated by any of the following:

Increasing charging flow or more frequent VCT makeups,

Decreasing PRZR level due to leakage,

Increasing PRT pressure, temperature, or level not due to normal operations,

Increasing Containment pressure, or temperature, not due to normal operations,

Unexplained increase in RCP Thermal Barrier CC flow or temperature,

Increasing Reactor Vessel Flange Leakoff temperature,

More frequent PDTT pumping or Containment Sump Pump operation,

Increasing area radiation or radiation in systems interfacing with RCS,

'.0 Leak Rate

~, ""

PTresultsincrea$ingjor

" '~'), ,;;. :, "t.':

Unexplainedincrease in AuxiliaryBJjldi~g sump level.

CONTINUOUS USE

NUMBER PROCEDURE TITLE REVISION 25 1-AP-16 INCREASING PRIMARY PLANT LEAKAGE PAGE 2 of 15 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. _ VERIFY UNIT IN MODE 1, 2, OR 3 Do the following:

o

IF RHR is lost, THEN GO TO 1-AP-11, LOSS OFRHR.

o

IF RCS level is decreasing with the Reactor Head installed, THEN GO TO 1-AP-17, SHUTDOWN LOCA.

o

IF Refueling Cavity level decreases in an uncontrolled manner, THEN GO TO 1-AP-52, LOSS OF REFUELING CAVITY LEVEL DURING REFUELING.

2. VERIFY THE FOLLOWING IF PRZR level is decreasing, THEN do the PARAMETERS-UNDER following:

CONTROL OF OPERATOR:

o

PRZR level a) Isolate Letdown by closing the following valves:

o

RCS subcooling based on Core 1) Letdown Orifice Isolation Valves:

Exit TCs o

1-CH-HCV-1200A o

VCTlevel 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) IF PRZR level cannot be maintained in AUTO level control, THEN place 1-CH-FCV-1122 controller in Manual and adjust Charging flow to control PRZR level.

(STEP 2 CONTINUED ON NEXT PAGE)

( NUMBER PROCEDURE TITLE REVISION 25 1-AP-16 INCREASING PRIMARY PLANT LEAKAGE PAGE 3 of 15 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

2. VERIFY THE FOLLOWING PARAMETERS-UNDER CONTROL OF OPERATOR:

(Continued) o c) Start a makeup to the VCT from the blender.

IF PRZR level OR VCT level cannot be maintained with Letdown isolated and one Charging Pump at maximum charging flow, THEN do the following:

o a) IF PRZR level cannot be maintained, THEN GO TO 1-E-O, REACTOR TRIP OR SAFETY INJECTION, while continuing with this procedure.

b) Shift Charging Pump Suction to RWST as follows:

1) Open Charging Pump suction from RWST MOVs:

o

1-CH-MOV-1115B o

1-CH-MOV-1115D

2) Close Charging Pump suction from VCT MOVs:

o

1-CH-MOV-1115C o

1-CH-MOV-1115E

NUMBER PROCEDURE TITLE REVISION 25 1-AP-16 INCREASING PRIMARY PLANT LEAKAGE PAGE 4 of 15 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

~ ~ (}....,-k\z,. .'1

\ { e,o-tr. 01 vJ"~\~

3._ CHECK 1-CH-LCV-1115A, VCT Align letdown to VCT: (::... ()v \rfDDfu ~,~

LEVEL CONTROL VALVE - NOT DIVERTED D a) Adjust 1-CH-LCV-1112C for VCT Level Control.

D b) IF 1-CH-LCV-1115A, VCT Level Control Valve, will NOT align to VCT, THEN locally open breaker No.7 on 1-EP-CB-26B.

c) IF 1-CH-LCV-1115A, VCT Level Control Valve, does NOT fail to VCT, THEN do the following:

1) Isolate Letdown by closing the following valves:

a. Letdown Orifice Isolation Valves:

D

1-CH-HCV-1200A D

1-CH-HCV-1200B D

1-CH-HCV-1200C

b. Letdown Isolation Valves:

D

1-CH-LCV-1460A D

1-CH-LCV-1460B D 2) Start a makeup to the VCT from the blender.

D 3) Place 1-CH-FCV-1122 in manual and adjust charging flow to less than or equal to VCT makeup flowrate to maintain PRZR level.

D 4) !E. PRZR level is increasing with charging flow secured, THEN place excess letdown in service using 1-0P-8.5, OPERATION OF EXCESS LETDOWN.

D 5) !E. PRZR level is decreasing and cannot be maintained, THEN RETURN TO Step 2.

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

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91)

Topic 16.21.:.AP-16High.. l~vel Acti.Ons 16.2 Objective U 11400 Explain the purpose of the following high-level action steps associated with 1-AP-16, "Increasing Primary Plant Leakage."

Verify that pressurizer level and Reactor Coolant System subcooling are under control of the operator.

Place excess letdown in service if letdown is isolated, charging is minimized, and pressurizer level continues to increase.

Identify and isolate the source of the leakage.

16.2 Content

1. The step to verify that pressurizer level, VCT level and Reactor Coolant System subcooling are under control of the operator is performed to allow the operator to take anticipatory actions 1.1. These anticipatory actions include isolating letdown, increasing charging, starting a VCT makeup, entering 1-E-O if needed, and swapping charging pump suction to the RWST, if necessary.

1.2. A loss of control over PRZR level, VCT level or RCS subcooling indicates a larger leak than the normal control systems can respond to, or that the control systems are not responding appropriately 1.3. In this case, "under control of operator" means PRZR level control in AUTOMATIC.

1.3.1.lf PRZR level is decreasing with LC-1459G/FCV-1122 in AUTOMATIC, then the answer to step two is NO, and the RNO is used to isolate letdown and increase charging flow manually.

2. The step to place excess letdown in service if letdown is isolated, charging is minimized, and pressurizer level continues to increase is performed to prevent PRZR level from increasing to the reactor trip setpoint.

2.1. With normal letdown isolated and charging flow secured, seal injection flow will continue to fill the PRZR.

REACTOR OPERATOR Page 91 of 158 Revision 30, 11/06/2008

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

77. 005-A2.02 077INEW//H/3/SROINAPS/8/20/20081 Unit 1 is in Mode 4 with a heatup in progress following a scheduled refueling outage.

The following plant conditions exist:

RHR is in service.

RCS temperature is 270°F.

Sl accumulator pressures and levels are all at normal operating level and pressure.

Sl accumulator MOVs are all CLOSED.

The Safeguards watchstander reports the following:

The breaker for "8" Sl accumulator MOV is ON.

The breaker for "c" Sl accumulator MOV is OFF.

8ased on these plant conditions, which ONE of the following identifies the action to be taken, and the reason for the action?

A. Place the breaker for "c" Sl accumulator MOV in ON; Sl accumulators are maintained available for Shutdown LOCA mitigation concerns.

B. Place the breaker for "c" Sl accumulator MOV in ON; Sl accumulator MOVs are energized to prepare for the change to Mode 3.

C. Place the breaker for "8" Sl accumulator MOV in OFF; Power is removed from the MOVs to preclude an inadvertent dilution of the RCS.

D'!" Place the breaker for "8" Sl accumulator MOV in OFF; Power is removed from the MOVs for RCS overpressure protection.

Feedback

a. Incorrect. Plausible and would be correct if the Unit were at higher temperature.

b. Incorrect. Plausible since the action is part of the startup sequence but is prohibited at the given temperature.

c. Incorrect. Plausible since boron concentration is not stated and if the assumption was the plant is exiting a refueling outage the candidate who is unaware of the actual requirement may default to this distractor.

d. Correct. This is a procedural and TS requirement since it is given that the Accumlators are at a pressure that requires them to be isolated with power removed from their actuators.

QUESTIONS REPORT

( for 2009 NRC SRO exam Validation 3 copy with SRC formatting - for submittal Notes Residual Heat Removal System (RHRS)

Ability to (a) predict the impacts of the following malfunctions or operations on the RHRS, and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those malfunctions or operations: Pressure transient protection during cold shutdown (CFR: 41.5/43.5/45.3/45.13)

Tier: 2 Group: 1 Importance Rating: 3.5/3.7 Technical

Reference:

Proposed references to be provided to applicants during examination: None Learning Objective:

Question History: new additional info:

- NUCLEAR DESIGN INFORMATION PORTAL-LTOP System 3.4.12 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.12 Low Temperature Overpressure Protection (LTOP) System LCO 3.4.12 An LTOP System shall be OPERABLE with a maximum of one charging pump and one low head safety injection (LHSI) pump capable of injecting into the RCS and the accumulators isolated, with power removed from the isolation valve operators, and one of the following pressure relief capabilities:

a. Two power operated relief valves (PORVs) with lift setting allowable values of:

1. ~ 540 psig when any RCS cold 1eg temperature ~ 280°F; and

2. ~ 375 psig when any RCS cold 1eg temperature ~ 180°F.

b. The RCS depressurized and an RCS vent of ~ 2.07 square inches.

NOTES- - - - - - - - - - - - -

1. Two charging pumps may be made capable of injecting for

~ 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months for pump swapping operations.

2. Accumulator isolation with power removed from the isolation valve operators is only required when accumulator pressure is greater than the PORV lift setting.

APPLICABILITY: MODE 4 when any RCS cold leg temperature is ~ 280°F, MODE 5, MODE 6 when the reactor vessel head is on.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Two LHSI pumps capable A.l Initiate action to Immediately of injecting into the verify a maximum of RCS. one LHSI pump is capable of injecting into the RCS.

North Anna Units 1 and 2 3.4.12-1 Amendments 242/223

- NUCLEAR DESIGN INFORMATION PORTAl-LTOP System 3.4.12 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. Two or more charging B.1 Initiate action to Immediately pumps capable of verify a maximum of injecting into the one charging pump is RCS. capable of injecting into the RCS.

C. --------NOTE--------- C.1 Isolate affected Immediately Only applicable when accumulator.

accumulator pressure is greater than PORV AND

~\~~~::-~:::~~~: ------ -- C.2 Remove power from 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months affected accumulator

~ An accumul ator not isolation valve isolated. operators.

OR Power available to one or more accumulator isolation valve operators.

D. Required Action and 0.1 Increase RCS cold leg 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion temperature to > 280°F.

Time of Condition C not met. OR 0.2 Depressurize affected 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months accumulator to less than PORV lift setting.

E. One required PORV E.1 Restore required PORV 7 days inoperable in MODE 4. to OPERABLE status.

F. One required PORV F.1 Restore required PORV 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months inoperable in MODE 5 to OPERABLE status.

or 6.

North Anna Units 1 and 2 3.4.12-2 Amendments 242/223

- NUCLEAR DESIGN INFORMATION PORTAL-LTOP System B 3.4.12 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.12 Low Temperature Overpressure Protection (LTOP) System BASES BACKGROUND The LTOP System controls RCS pressure at low temperatures so the integrity of the reactor coolant pressure boundary (RCPB) is not compromised by violating the LTOP System design basis pressure and temperature (PIT) limit curve (i.e., 100% of the isothermal PIT limit curve determined to satisfy the requirements of 10 CFR 50, Appendix G, Ref. 1).

The reactor vessel is the limiting RCPB component for demonstrating such protection. This specification provides the maximum allowable actuation logic setpoints for the power operated relief valves (PORVs) and LCO 3.4.3, "RCS Pressure and Temperature (PIT) Limits," provides the maximum RCS pressure for the existing RCS cold leg temperature during cool down, shutdown, and heat up to meet the Reference 1 requirements during the LTOP MODES.

The reactor vessel material is less tough at low temperatures than at normal operating temperature. As the vessel neutron exposure accumulates, the material toughness decreases and becomes less resistant to pressure stress at low temperatures (Ref. 2). RCS pressure, therefore, is maintained low at low temperatures and is increased only as temperature is increased.

The potential for vessel overpressurization is most acute when the RCS is water solid, occurring only while shutdown; a pressure fluctuation can occur more quickly than an operator can react to relieve the condition. Exceeding the RCS PIT limits by a significant amount could cause brittle cracking of the reactor vessel. LCO 3.4.3, "RCS Pressure and Temperature (PIT) Limits," requires administrative control of RCS pressure and temperature during heat up and cool down to prevent exceeding the PIT limits.

This LCO provides RCS overpressure protection by limiting coolant input capability and having adequate pressure relief capacity. Limiting coolant input capability requires all but one low head safety injection (LHSI) pump and one charging pump incapable of injection into the RCS and isolating the accumulators when accumulator pressure is greater than the PORV lift setting. The pressure relief capacity requires either two redundant RCS PORVs or a depressurized RCS and an (continued)

North Anna Units 1 and 2 B 3.4.12-1 Revision 20

- NUCLEAR DESIGN INFORMATION PORTAL-LTOP System B 3.4.12 BASES BACKGROUND RCS vent of sufficient size. One RCS PORV or the open RCS (continued) vent is the overpressure protection device that acts to terminate an increasing pressure event.

With limited coolant input capability, the ability to provide core coolant addition is restricted. The LCO does not require the makeup control system deactivated or the safety injection (SI) actuation circuits blocked. Due to the lower pressures in the LTOP MODES and the expected core decay heat levels, the makeup system can provide adequate flow via the makeup control valve. If conditions require the use of more than one LHSI and charging pump for makeup in the event of loss of inventory, then pumps can be made available through manual actions.

The LTOP System for pressure relief consists of two PORVs with reduced lift settings, or a depressurized RCS and an RCS vent of sufficient size. Two RCS PORVs are required for redundancy. One RCS PORV has adequate relieving capability to keep from overpressurization for the required coolant input capability.

PORV Requirements As designed for the LTOP System, each PORV is signaled to open if the RCS pressure exceeds a limit determined by the LTOP actuation logic. The LTOP actuation logic monitors both RCS temperature and RCS pressure and determines when a condition is not acceptable. The wide range RCS temperature indications are auctioneered to select the lowest temperature signal.

The lowest temperature signal is passed to a comparator circuit which determines the pressure limit for that temperature. The pressure limit is then compared with the indicated RCS pressure from a wide range pressure channel.

If the indicated pressure meets or exceeds the calculated value, the PORVs are signaled to open.

The PORV setpoints are staggered so only one valve opens to stop a low temperature overpressure transient. If the opening of the first valve does not prevent a further increase in pressure, a second valve will open at its higher pressure setpoint to stop the transient. Having the setpoints of both valves within the limits in the LCO ensures that the LTOP System design basis PIT limit curve will not be exceeded in any analyzed event.

(continued)

North Anna Units 1 and 2 B 3.4.12-2 Revision 0

LTOP System B 3.4.12 BASES BACKGROUND PORV Requirements (continued)

When a PORV is opened in an increasing pressure transient, the release of coolant will cause the pressure increase to slow and reverse. As the PORV releases coolant, the RCS pressure decreases until a reset pressure is reached and the valve is signaled to close. The pressure continues to decrease below the reset pressure as the valve closes.

RCS Vent Requirements Once the RCS is depressurized, a vent exposed to the containment atmosphere will maintain the RCS within the LTOP design basis PIT limit curve in an RCS overpressure transient, if the relieving requirements of the transient do not exceed the capabilities of the vent. Thus, the vent path must be capable of relieving the flow resulting from the limiting LTOP mass or heat input transient, and maintaining pressure below the LTOP System design basis PIT limit curve.

The required vent capacity may be provided by one or more vent paths.

For an RCS vent to meet the flow capacity requirement, it

( requires either removing a pressurizer safety valve, or blocking open a PORV and opening its block valve, or similarly establishing a vent by opening an RCS vent valve.

The vent path(s) must be above the level of reactor coolant, so as not to drain the RCS when open.

APPLICABLE Safety analyses (Ref. 3) demonstrate that the reactor vessel SAFETY ANALYSES is adequately protected against exceeding the LTOP System design basis PIT limit curve (i.e., 100% of the isothermal PIT limit curve determined to satisfy the requirements of 10 CFR 50, Appendix G, Ref. 1). In MODES 1,2, and 3, and in MODE 4 with RCS cold leg temperature exceeding 280°F, the pressurizer safety valves will prevent RCS pressure from exceeding the Reference 1 limits. At 280°F and below, overpressure prevention falls to two OPERABLE RCS PORVs or to a depressurized RCS and a sufficient sized RCS vent. Each of these means has a limited overpressure relief capability.

The RCS cold leg temperature below which LTOP protection must be provided increases as the reactor vessel material toughness decreases due to neutron embrittlement. Each time the PIT curves are revised, the LTOP System must be (continued)

North Anna Units 1 and 2 B 3.4.12-3 Revision 26

- NUClEAB DESIGN INFORMATION PORTAL-LTOP System B 3.4.12 BASES APPLICABLE re-evaluated to ensure its functional requirements can still SAFETY ANALYSES be met using the PORV method or the depressurized and vented (continued) RCS condition.

The LCO contains the acceptance limits that define the LTOP requirements. Any change to the RCS must be evaluated against the Reference 3 analyses to determine the impact of the change on the LTOP acceptance limits.

Transients that are capable of overpressurizing the RCS are categorized as either mass or heat input transients, examples of which follow:

Mass Input Type Transients

a. Inadvertent safety injection; or

b. Charging/letdown flow mismatch.

Heat Input Type Transients

a. Reactor coolant pump (RCP) startup with temperature asymmetry between the RCS and steam generators.

The following are required during the LTOP MODES to ensure that mass and heat input transients do not occur, which either of the LTOP overpressure protection means cannot handle:

a. Rendering all but one LHSI pump and one charging pump incapable of injection;

b. Deactivating the accumulator discharge isolation valves in their closed positions when accumulator pressure is greater than the PORV lift setting; and

c. Disallowing start of an RCP if secondary temperature is more than 50°F above primary temperature in anyone loop.

LCO 3.4.6, "RCS Loops-MODE 4," and LCO 3.4.7, "RCS Loops-MODE 5, Loops Fill ed, provi de thi s protecti on.

II The Reference 3 analyses demonstrate that either one PORV or the depressurized RCS and RCS vent can maintain RCS pressure below limits when only one LHSI pump and one charging pump are actuated. Thus, the LCO allows only one LHSI pump and one charging pump OPERABLE during the LTOP MODES. The (continued)

North Anna Units 1 and 2 B 3.4.12-4 Revision 0

- NUCLEAR DESIGN INFORMATION PORTAL-LTOP System B 3.4.12 BASES APPLICABLE Heat Input Type Transients (continued)

SAFETY ANALYSES Reference 3 analyses do not explicitly model actuation of the LHSI pump, since the RCS pressurization resulting from inadvertent safety injection by a single charging pump against a water-solid RCS would not be made more severe by such actuation. Since the LTOP analyses assume that the accumulators do not cause a mass addition transient, when RCS temperature is low, the LCO also requires the accumulators to be isolated when accumulator pressure is greater than the PORV lift setting. The isolated accumulators must have their discharge valves closed and the valve power supply breakers fixed in their open positions.

Fracture mechanics analyses established the temperature of LTOP Applicability at 280°F.

The consequences of a small break loss of coolant accident (LOCA) in LTOP MODE 4 conform to 10 CFR 50.46 (Ref. 4),

requirements by having a maximum of one LHSI pump and one charging pump OPERABLE.

PORV Performance The fracture mechanics analyses show that the vessel is protected when the PORVs are set to open at or below the allowable values shown in the LCO. The setpoint allowable values are derived by analyses that model the performance of the LTOP System, assuming the limiting LTOP transient of one charging pump injecting into the RCS. These analyses consider pressure overshoot beyond the PORV opening and closing, resulting from signal processing and valve stroke times. The PORV setpoints at or below the derived value ensure the RCS pressure at the reactor vessel beltline will not exceed the LTOP design PIT limit curve.

The PORV setpoint allowable values are evaluated when the PIT limits are modified. The PIT limits are periodically modified as the reactor vessel material toughness decreases due to neutron embrittlement caused by neutron irradiation.

Revised limits are determined using neutron fluence projections and the results of examinations of the reactor vessel material irradiation surveillance specimens. The Bases for LCO 3.4.3 discuss these examinations.

The PORVs are considered active components. Thus, the failure of one PORV is assumed to represent the worst case, single active failure.

North Anna Units 1 and 2 B 3.4.12-5 Revision 20

LTOP System B 3.4.12 BASES APPLICABLE RCS Vent Performance SAFETY ANALYSES (continued) With the RCS depressurized, analyses show a vent size of 2.07 square inches is capable of mitigating the allowed LTOP overpressure transient. (A vent size of 2.07 square inches is the equivalent relief capacity of one PORV.) The capacity of a vent this size is greater than the flow of the limiting transient for the LTOP configuration, one LHSI pump and one charging pump OPERABLE, maintaining RCS pressure less than the LTOP design basis PIT limit curve.

The RCS vent size is re-evaluated for compliance each time the PIT limit curves are revised based on the results of the vessel material surveillance.

The RCS vent is passive and is not subject to active failure.

The LTOP System satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO This LCO requires that the LTOP System is OPERABLE. The LTOP System is OPERABLE when the minimum coolant input and pressure relief capabilities are OPERABLE. Violation of this LCO could lead to the loss of low temperature overpressure mitigation and violation of the LTOP System design basis PIT limit curve (i .e., 100% of the isothermal PIT limit curve determined to satisfy the requirements of 10 CFR 50, Appendix G, Ref. 1) as a result of an operational transient.

To limit the coolant input capability, the LCO requires a maximum of one LHSI pump and one charging pump capable of injecting into the RCS and all accumulator discharge isolation valves closed with power removed from the isolation valve operator, when accumulator pressure is greater than the PORV lift setting.

The LCO is modified by two Notes. Note 1 allows two charging pumps to be made capable of injection for ~ 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months during pump swap operations. One hour provides sufficient time to safely complete the actual transfer and to complete the administrative controls and Surveillance requirements associated with the swap. The intent is to minimize the actual time that more than one charging pump is physically capable of injection.

(continued)

North Anna Units 1 and 2 B 3.4.12-6 Revision 20

LTOP System B 3.4.12 BASES LCO Note 2 states that accumulator isolation is only required (continued) when the accumulator pressure is more than the PORV lift setting. This Note permits the accumulator discharge isolation valves to be open if the accumulator cannot challenge the LTOP limits.

The elements of the LCO that provide low temperature overpressure mitigation through pressure relief are:

a. Two OPERABLE PORVs; or A PORV is OPERABLE for LTOP when its block valve is open, its lift setpoint is set to the limits provided in the LCO and testing proves its ability to open at this setpoint, and backup nitrogen motive power is available to the PORVs and their control circuits.

b. A depressurized RCS and an RCS vent.

An RCS vent is OPERABLE when open with an area of

~ 2.07 square inches.

Each of these methods of overpressure prevention is capable of mitigating the limiting LTOP transient.

APPLI CAB I LlTY This LCO is applicable in MODE 4 when any RCS cold leg temperature is ~ 280°F, in MODE 5, and in MODE 6 when the reactor vessel head is on. The pressurizer safety valves provide overpressure protection that meets the Reference 1 PIT limits above 280°F. When the reactor vessel head is off, overpressurization cannot occur.

LCO 3.4.3 provides the operational PIT limits for all MODES.

LCO 3.4.10, "Pressurizer Safety Valves," requires the OPERABILITY of the pressurizer safety valves that provide overpressure protection during MODES I, 2, and 3, and MODE 4 above 280°F.

Low temperature overpressure prevention is most critical during shutdown when the RCS is water solid, and a mass or heat input transient can cause a very rapid increase in RCS pressure when little or no time allows operator action to mitigate the event.

North Anna Units 1 and 2 B 3.4.12-7 Revision 20

STUDENT GUIDE FOR REACTOR COOLANT SYSTEM (38) 10.3 Objective U 3588 List the following technical specification information associated with the Reactor Coolant System.

System leakage detection systems which must be operable in modes 1 through 4 (TS-3.4.15)

Maximum allowed system pressure (TS-2.1.2)

Minimum system flow rate (TRM-3.1.4, TRM-3.4.7, TS-3.9.5, TS-3.9.6) 10.3 Content

1. The following leakage detection systems are required by TS-3.4.15 to be operable in modes 1 through 4:

1.1. Containment atmosphere particulate or gaseous radioactivity monitor.

1.2. Containment sump level or discharge flow measurement system.

1.2.1.A plant computer program automatically monitors sump in-leakage.

1.2.2.A sump level indicator is also acceptable.

2. RCS pressure is limited by TS-2.1.2 to a maximum of 2735 psig in modes 1 - 5.

3. Minimum RCS system flow rate is >1= 295,000 gpm.

10.4 Objective U 3528 Explain the following concepts associated with Reactor Coolant System Technical Specifications.

Why the loop stop valve must be maintained open and deenergized in modes 1, 2, 3 & 4 (TS-3.4.17)

Why a reactor coolant pump may not be started with Reactor Coolant System (RCS) cold-leg temperatures::; 280°F unless the secondary temperature of the steam generators is < 50°F above each of the RCS cold-leg temperatures (TS 3.4.6 Bases)

SHIFT TECHNICAL ADVISOR Page 105 of 111 Revision 8, 10109/2008

STUDENT GUIDE FOR REACTOR COOLANT SYSTEM (38)

Why only one charging pump and low-head safety injection pump may be operable when the Reactor Coolant System is::;; 280°F (TS-3.4.12 Bases) 10.4 Content

1. TS-3.4.17 bases for maintaining loop stop valve breakers open with power removed in modes 1,2,3 & 4 is to prevent inadvertent closure of a loop stop valve during unit operation.

1.1. This ensures all reactor coolant loops remain in operation and maintains the DNBR above the design limit during all normal operations and anticipated transients.

2. A reactor coolant pump may not be started when one or more RCS cold-leg temperatures is ::; 280°F unless the secondary temperature of the steam generators is < 50°F above each of the RCS cold-leg temperatures.

2.1. These restrictions ensure that the energy addition caused by starting the RCP does not cause RCS overpressurization.

3. Only one charging pump and low-head safety injection pump may be operable when one or more RCS cold-leg temperatures is::; 280°F.

3.1. This ensures that a mass addition overpressure transient can be relieved by the operation of a single PRZR PORV.

10.5 Objective U 10498 Explain the Reactor Coolant System technical specification bases for the limits on primary coolant specific activity (TS-3.4.16).

10.5 Content Refer to ITS-3.4.16.

SHIFT TECHNICAL ADVISOR Page 106 of 111 Revision 8, 10/09/2008

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

78. 005-AG2.2.40 078INEW//L/3/SROINAPS/8/20/20081 Given the following conditions:

Unit 1 was initially at 100% power and stable.

A spurious turbine runback occurred.

The unit has been stabilized at approximately 82% power.

The crew has determined that Control Bank 'D' is below the rod insertion limits.

In accordance with Technical Specifications, the crew must verify Shutdown Margin to be within the limits provided in the COLR , and restore control bank(s) to within limits _ _ __

A'! within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months ; within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months B. within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months ; within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months C. within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months ; within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months D. within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months ; within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Feedback

a. Correct. Times correct per TS.

b. Incorrect. Plausible since action times would seem reasonable and having rods below the insertion limits implies a sense of urgency.

c. Incorrect. Plausible since both actions having the same time frame would not be illogical and numerous spec have multiple actions with the same completion time.

d. Incorrect. Plausible since 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months is for the RIL not the SDM verification and this could easily be confused; again 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is a common time in TS (e. g. RCS leakage) and the candidate who is not familiar with this particular spec may default to this distractor.

QUESTIONS REPORT for 2009 NRC SRO exam Validation 3 copy with SRC formatting - for submittal Notes Inoperable/Stuck Control Rod Ability to apply Technical Specifications for a system.

(CFR: 41.10/43.2/43.5/45.3)

Tier: 1 Group: 2 Importance Rating: 3.4/4.7 Technical

Reference:

TS Proposed references to be provided to applicants during examination: None Learning Objective:

Question History: New additional info:

Control Bank Insertion Limits 3.1.6 3.1 REACTIVITY CONTROL SYSTEMS 3.1.6 Control Bank Insertion Limits LCO 3.1.6 Control banks shall be within the insertion, sequence, and overlap limits specified in the COLR.

APPLICABILITY: MODE 1, MODE 2 with keff ;: : 1. O.

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

This LCO is not applicable while performing SR 3.1.4.2.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Control bank sequence A.1.1 Verify SDM to be 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or overlap limits not within the limits met. provided in the COLR.

-OR A.1.2 Initiate boration to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months restore SDM to within 1 imit.

AND A.2 Restore control bank 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months sequence and overlap to within limits.

B. Control bank insertion B.1.1 Verify SDM to be 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months limits not met for within the limits reasons other than provided in the COLR.

Condition C.

OR B.1. 2 Initiate boration to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months restore SDM to within 1 imit.

AND (continued)

North Anna Units 1 and 2 3.1.6-1 Amendments 231/212

Control Bank Insertion Limits 3.1.6 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.2 Restore control 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months bank(s) to within 1 imits.

C. Control bank A, B, C.1 Verify SDM to be Once per or C inserted within the limits 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

~ 18 steps below the provided in the COLR.

insertion limit and immovable. AND AND

- C.2 Restore the control 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months bank to withi n Each control and insertion limit.

shutdown rod within limits of LCO 3.1.4.

AND Each shutdown bank within the insertion limits of LCO 3.1.5.

D. Required Action and D.1 Be in MODE 2 with 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Keff < 1. O.

Time not met.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1. 6.1 Verify estimated critical control bank Withi n 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months position is within the insertion limits prior to specified in the COLR. achieving criti ca 1ity North Anna Units 1 and 2 3.1.6-2 Amendments 231/212

STUDENT GUIDE FOR ROD CONTROL SYSTEM (65) 3.4. PIA converter feeds the rod position recorders in the MCR for rod position (GREEN PEN) and RIL (RED PEN) is fed from median/high select 11T.

4. An automatic/manual switch is also provided with associated up and down pushbuttons for manually changing the display on the digital indicator.

4.1. The indicator is changed manually during rod alignment procedures.

tOpig.1i.2¢ontrol ~QCI*lns.e'rtibn* Limits 11.2 Objective U 6540 List the following information associated with the control rod insertion limits.

Purpose

Input signals

(

Effect on the insertion limit of reactor power increases or decreases

Conditions which wi" cause the LOW/LOW-LOW INSERTION LIMIT annunciator to actuate 11.2 Content

1. The purpose of the control rod insertion limits is to:

1.1. Ensure adequate shutdown margin following a reactor trip.

1.2. Provide a limit on the maximum inserted positive reactivity during a rod ejection accident.

2. Ensure nuclear peaking factors remain acceptable.

3. The input signal is from median/high select ,6.T.

4. As power increases, rod insertion limits increase.

4.1. Conversely, as power decreases, rod insertion limits decrease.

REACTOR OPERATOR Page 42 of 64 Revision 3, 11/18/2008

STUDENT GUIDE FOR ROD CONTROL SYSTEM (65)

5. The ROD BANK A lOW/lOW-lOW LIMIT alarm (1A-H1) first alarms when the bank is 10 steps above the low-low limit and then again when at the insertion limit.

5.1. The alarm may indicate a reactivity control system malfunction, or require the operator to borate the RCS.

5.2. When the low-low limit alarm is received, the operator is required to borate at least 10 gpm to restore the rods to within insertion limits.

11.3 Objective U 10178 Describe the response of the following rod position indication annunciators if the operator mistakenly depresses the STARTUP RESET push-buttons while the unit is at power.

ROD BANK lO/lO-lO LIMIT

RPI ROD BOT ROD DROP

CMPTR ALARM ROD DEV/SEQ 11.3 Content

1. If the STARTUP RESET push buttons were depressed with the unit at power, the following would occur:

1.1. ROD BANK lO/lO-lO LIMIT annunciators would alarm - since the rod position signal to the recorders goes to ZERO.

1.2. RPI ROD BOT ROD DROP annunciator is disabled for control banks B, C, and 0, since the PIA converter signal to the rod bottom bypass bistable indicates less than 35 steps.

1.3. CMPTR ALARM ROD DEV/SEQ annunciator will alarm since all the IRPls will be greater than 10 steps from the supervisory data logger.

REACTOR OPERATOR Page 43 of 64 Revision 3, 11/18/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91) 2.2 Objective U 11023 Explain the following concepts associated with 1-AP-1.1, "Continuous Uncontrolled Rod Motion."

Action required if rod insertion limits are exceeded

Action required if the lowest loop Tavg is less than 541°F

How to determine the programmed T ref for a given plant condition Action required if Reactor Coolant System Tavg stabilizes above or below T ref

Action required if Reactor Coolant System Tavg cannot be returned to program by withdrawing or inserting control rods manually 2.2 Content

1. If rods are below the 10-10 insertion limit the following actions are required:

1.1. Verify shutdown margin within limits within one hour or 1.2. Initiate a boration to restore shutdown margin within limits within one hour, and 1.3. Restore rods to above the insertion limits of TS-3.1.6 (COLR) within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months by withdrawing control rods or decreasing turbine load.

2. If the lowest loop Tavg is less than 541°F the crew is required to restore Tavg to greater than 541°F or reduce power to mode 2 with Keff less than 1.0 within 30 minutes.

3. To determine T ref for a given plant condition, a graph of programmed T ref is included as an attachmElnt to AP-1.1.

3.1. The graph shows T ref versus reactor power with an allowable band for Tavg of +/- 1.5°F.

4. Following the termination of continuous uncontrolled rod motion, actions must be taken to match Tavg and Tref.

REACTOR OPERATOR Page 9 of 158 Revision 30, 11/06/2008

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

79. 008-G2.2.38SRO 079/MODIFIEDINAPS/L/3/SROINAPSII Both units are at 100% power.

The Technical Specification LCO for the Component Cooling Water (CC) System requires _ _ _ _ to be operable. The basis for this requirement is to ensure that _ _ _ _ _ _ __

A'! 3 CC subsystems; one unit can be cooled down rapidly while the other unit is maintained at full power B. 3 CC subsystems; both units can be cooled down rapidly in the event of an Appendix R fire C. 4 CC subsystems; one unit can be cooled down rapidly while the other unit is maintained at full power D. 4 CC subsystems; both units can be cooled down rapidly in the event of an Appendix R fire Feedback

a. Correct. Number of required subsystems is correct and this is the Bases for the LCO requirement ofTS 3.7.19.

b. Incorrect. Number of required subsystems is correct; second part incorrect but plausible since an appendix R scenario could be applicable to both units and the candidate may conclude that this is a logical sellection based on a limited volume of ECST inventory.

c. Incorrect. Number of required subsystems is incorrect but plausible since this is the total number of CC subsystems and typically anytime a component is unavailable there is an action associated with it, an example of this is the service water LCO that requires all 4 pumps and both loops in order to not be in an action; second part is the correct basis.

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 SRO exam Validation 3 copy with SRC formatting - for submittal Notes Component Cooling Water Knowledge of conditions and limitations in the facility license.

(CFR: 41.7 /41.10/43.1 /45.13)

Tier: 2 Group: 1 Importance Rating: 3.6/4.5 Technical

Reference:

TS 3.7.19 & TS Basis Proposed references to be provided to applicants during examination: None Learning Objective:

Question History: modified additional info:

CC System 3.7.19 3.7 PLANT SYSTEMS 3.7.19 Component Cooling Water (CC) System LCO 3.7.19 Three CC subsystems shall be OPERABLE.

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

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One required CC A.1 Restore required CC 7 days subsystem inoperable. subsystem to OPERABLE status.

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A AND not met.

B.2 Be in MODE 5. 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months C. Two required CC C.1 Be in MODE 4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months subsystems inoperable.

AND C.2 Initiate actions to be 13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months in MODE 5.

D. No CC water available 0.1 Be in MODE 4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to supply the residual heat removal heat AND exchangers.

0.2 Implement an alternate Immediately means of decay heat removal.

AND 0.3 Initiate actions to be Immediately in MODE 5.

North Anna Units 1 and 2 3.7.19-1 Amendments 231/212

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 cool down 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 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months 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

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

1.4. However, temperatures should normally be maintained at 135°F or less.

TopiC***S.9IS *llaSesfor*CCSystern *. Operability

in.M ode 1 -4(ITS-3.7.1*~1 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.ls 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 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months during plant cooldown, based on:

REACTOR OPERATOR Page 35 of 37 Revision 2, OS/23/2007

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

80. 016-G2.4.6 080INEW/1H/3/SROINAPS//

Given the following conditions:

Unit 1 tripped from 100% power due to a small-break LOCA.

RCS temperature is stable at approximately 500°F.

All SG pressures are stable at approximately 670 psig.

Containment pressure is 21 psia and increasing 1 psia every 30 minutes.

CDA has not actuated.

Operators have transitioned from 1-E-O, Reactor Trip or Safety Injection, to 1-E-1, Loss of Reactor or Secondary Coolant.

Based on these plant conditions, which ONE of the following identifies the action(s) required by 1-E-1?

A. Start Outside Recirc Spray pumps and inject the Chemical Addition Tank.

B. Start Outside Recirc Spray pumps, but DO NOT inject the Chemical Addition Tank.

C~ Start Quench Spray pumps and inject the Chemical Addition Tank.

D. Start Quench Spray pumps, but DO NOT inject the Chemical Addition Tank.

Feedback

a. Incorrect. First part is plausible since containment pressure is on a slowly increasing trend candidate and recirc spray will control containment pressure, but it is not the procedure strategy; second part is correct.

b. Incorrect. First part is incorrect but plausible as discussed in Distractor A; second part is also incorrect but plausible since candidate may assume that actions are only needed for CNTMT pressure control and disregard the additional action that is required for Iodine control.

c. Correct. These actions are both required by 1-E-1 for the given event (SBLOCA), based on the conditions provided and taken for Iodine control purposes.

d. Incorrect. First part correct. Second part is incorrect but plausible since candidate may assume that actions are only needed for CNTMT pressure control and disregard the additional action that is required for Iodine control.

QUESTIONS REPORT for 2009 NRC SRO exam Validation 3 copy with SRC formatting - for submittal Notes Non-Nuclear Instrumentation Knowledge of EOP mitigation strategies.

(CFR: 41.10/43.5/45.13)

Tier: 2 Group: 2 Importance Rating: 3.7/4.7 Technical

Reference:

1-E-1 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 7 of 27 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

7. CHECK IF QUENCH SPRAY IS REQUIRED:

a) Verify ALL of the following: D a) GO TO Step 8.

D

Quench Spray Pumps - NOT RUNNING D

Containment pressure - HAS EXCEEDED 20 PSIA D

Containment pressure - GREATER THAN 13 PSIA D

All SG pressures stable or under operator control D

Chemical Addition Tank level -

GREATER THAN 23%

D b) Manually start Quench Spray:

1) Open the following valves: D 1) Locally open valve.

D

1-QS-MOV-101A D

1-QS-MOV-101B

2) Start the following pumps:

D

1-QS-P-1A D

1-QS-P-1B (STEP 7 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 23 1-E-1 LOSS OF REACTOR OR SECONDARY COOLANT PAGE 8 of 27 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

7. CHECK IF QUENCH SPRAY IS REQUIRED: (Continued)

3) Open Chemical Addition Tank 0 3) Locally open valves.

Outlet Valves:

0

1-QS-MOV-102A 0

1-QS-MOV-102B c) Stop ALL CRDM fans:

0

1-HV-F-37A and 1-HV-F-37D 0

1-HV-F-37B and 1-HV-F-37E 0

1-HV-F-37C and 1-HV-F-37F

8. CHECK QUENCH SPRAY PUMP STATUS:

0 a) Quench Spray Pumps - ANY RUNNING 0 a) !E. CDA has NOT actuated, THEN GO TO Step 12.

0 !E. CDA has actuated, THEN GO TO Step 9.

b) Check for either of the following conditions: 0 b) GO TO Step 9.

0

RWST Level - LESS THAN 3%

AND 0

Quench Spray Pump amps -

FLUCTUATING 0 c) Perform ATTACHMENT 3, TERMINATION OF QUENCH SPRAY

NUMBER PROCEDURE TITLE REVISION 9

1-FR-Z.1 RESPONSE TO HIGH CONTAINMENT PRESSURE PAGE 60f7 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 y§ e) Verify the following pumps - RUNNING: ~ e) Do the following:

"H"TRAIN >t

Manually start ORS pumps:

o

1-RS-P-1A (2 minute time delay) \~ Do

1-RS-P-2A o

1-RS-P-2A \j

1-RS-P-2B "J"TRAIN

Manually start IRS pumps following time delay:

0

1-RS-P-1 B (2 minute time delay) 0

1-RS-P-1A 0

1-RS-P-2B 0

1-RS-P-1B f) Start the following sample pumps on the Unit 1 Radiation Monitoring Panel:

0

1-SW-P-5 0

1-SW-P-8 0

1-SW-P-6 0

1-SW-P-7

NUMBER PROCEDURE TITLE REVISION 5

1-FR-ZA RESPONSE TO CONTAINMENT POSITIVE PRESSURE PAGE 7 of 9 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED 9, CHECK RECIRC SPRAY SUMP LEVEL - o GO TO Step 15.

GREATER THAN 4 FT 10 IN:

0

1-RS-Ll-151A 0

1-RS-Ll-151B

10. VERIFY ALL CRDM FANS - STOPPED: o Stop ALL CRDM fans.

0

1-HV-F-37A and 1-HV-F-37D 0

1-HV-F-37B and 1-HV-F-37E 0

1-HV-F-37C and 1-HV-F-37F CAUTION: If less than four Service Water Pumps are running, then no more than two Unit 1 RS Heat Exchangers should receive Service Water flow, in order to avoid Service Water Pump runout.

11. CHECK 1-RS-P-1A - AVAILABLE Put 1-RS-P-1 B in service:

a) Align Service Water to 1-RS-E-1 B by opening the following valves:

o

1-SW-MOV-1 01 D o

1-SW-MOV-103B o

1-SW-MOV-104B o

1-SW-MOV-105B o b) Start 1-RS-P-1B.

o c) GO TO Step 13.

NUMBER PROCEDURE TITLE REVISION 5

1-FR-ZA RESPONSE TO CONTAINMENT POSITIVE PRESSURE PAGE 8 of 9 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

12. PUT 1-RS-P-1A IN SERVICE:

a) Align Service Water to 1-RS-E-1 A by opening the following valves:

0

1-SW-MOV-101A 0

1-SW-MOV-103A 0

1-SW-MOV-104A 0

1-SW-MOV-105C 0 b) Start 1-RS-P-1A

13. OPERATE 1-RS-P-1A OR 1-RS-P-1B TO MAINTAIN CONTAINMENT PRESSURE LESS THAN 13 PSIA

14. RETURN TO PROCEDURE AND STEP IN EFFECT

15. VERIFY RWST LEVEL - GREATER THAN 3% 0 Consult TSC or Plant Staff.

16. VERIFY ALL CRDM FANS - STOPPED: 0 Stop ALL CRDM fans.

0

1-HV-F-37A and 1-HV-F-37D 0

1-HV-F-37B and 1-HV-F-37E 0

1-HV-F-37C and 1-HV-F-37F

(

STUDENT GUIDE FOR EMERGENCY PROCEDURES (92) 4.3. It is important to remember there is a 2-minute time delay between the start of the outside and inside Recirculation Spray pumps to prevent diesel overload.

4.4. In addition, it must be remembered that recirculation spray is the primary heat removal mechanism for long term core cooling.

2.15 Objective U 12460 Explain the following concepts concerning checking if quench spray is required in 1-E-0, "Reactor Trip or Safety Injection."

Why steam generator pressure is verified to be stable

Purpose for starting quench spray

Why manually initiating COA is not directed 2.15 Content

1. If a COA is not required in E-O, manually staring quench spray pumps may be prudent in order to reduce containment pressure and protect the public from a possible release of radioactivity.

1.1. The operator is directed to verify containment pressure has exceeded 20 psia and that steam generator pressures are stable.

1.2. Steam generator pressures are verified stable and under operator control in order to determine whether the accident in progress is a primary loss-of-coolant accident or a faulted steam generator.

2. It is important that the correct determination be made as to what is causing the increase in containment pressure.

2.1. A primary loss-of-coolant accident will result in a release of radioactive iodine to the containment atmosphere whereas a secondary break will not.

REACTOR OPERATOR Page 48 of 187 Revision 19, 11/06/2008

STUDENT GUIDE FOR EMERGENCY PROCEDURES (92) 2.2. The presence of radioactive iodine in the containment atmosphere would pose a potential health threat to the public.

2.3. If the primary break was small, containment pressure might not increase to the point where the initiation of a COA is required.

2.4. However, quench spray should be manually placed in service so that the iodine in containment can be stripped by the sodium hydroxide in the sprayed water.

2.5. This will limit the possibility that the public will be exposed to radioactivity in excess of the limits set by 10CFR50.67.

3. Although initiation of quench spray is desirable in a circumstance such as this, it should be noted that initiation of COA is undesirable.

3.1. If COA were initiated, the component cooling water pumps would trip and lockout.

3.2. In addition, the COA would result in a Phase B isolation that would close the component cooling trip valves to the containment.

3.3. The loss of component cooling would necessitate the removal of the reactor coolant pumps from service.

3.4. This action would be undesirable during a small break loss-of-coolant accident where forced circulation is required to help mitigate the accident.

2.16 Objective U 12461 Explain the following concepts concerning the verification of auxiliary feedwater (AFW) flow in 1-E-0, "Reactor Trip or Safety Injection."

Basis

How feedwater flow to a faulted steam generator should be treated when determining total AFW flow

Minimum acceptable AFW flow to a steam generator that can be considered part of the minimum total AFWflow REACTOR OPERATOR Page 49 of 187 Revision 19, 11/06/2008

STUDENT GUIDE FOR EMERGENCY PROCEDURES (92)

Topic13A1~E$-t.tConcepts 13.4 Objective U 12204 Explain the following concepts associated with preparing for Reactor Coolant System cooldown during a post-LOCA cooldown and depressurization (1-ES-1.2).

Why safety injection, phase A isolation, and phase 8 isolation are reset

Why instrument air is realigned to containment

Why quench spray is required if containment pressure has exceeded 20 psia and steam generators are not faulted

Why the low-head safety injection pumps are stopped if Reactor Coolant System pressure is greater than 225 psig

How a steam generator tube rupture is identified 13.4 Content

1. The first two steps of ES-1.2 direct the operator to reset safety injection, Phase "A" Isolation, and Phase "8" Isolation.

1.1. The resets are performed early in order to allow the operator to manipulate components that receive automatic actuation signals from the Engineering Safety Functions.

2. Instrument air is then aligned to containment.

2.1. Aligning instrument air to containment ensures a sustained supply of air for operation of air-operated equipment (i.e. charging flow control, auxiliary spray valve, PRZR spray valves and PORVs, etc.).

2.2. It should be noted that the outside instrument air supply is more reliable than the receivers and compressors inside containment.

3. During the performance of ES-1.2, the operator is directed to check if quench spray is required.

3.1. This is accomplished by verifying all of the following:

REACTOR OPERATOR Page 132 of 187 Revision 19, 11/06/2008

STUDENT GUIDE FOR EMERGENCY PROCEDURES (92) 3.1.1. No quench spray pumps running 3.1.2. Chemical addition tank level is greater than 23%

3.1.3.Containment pressure has exceeded 20 psia 3.1.4. Containment pressure is above 13 psia and; 3.1.5. No faulted steam generators 3.2. This verification step has the operator diagnose the cause of the high containment pressure.

3.3. If containment pressure has exceeded 20 psia due to a loss of primary coolant, then high levels of radioactive iodine are likely inside containment.

3.4. The operator is directed to manually start quench spray pumps in order to allow iodine removal by the sodium hydroxide contained within the chemical addition tank.

3.5. However, if the high containment pressure was the result of a faulted steam generator, no iodine will be present in the containment atmosphere and starting quench spray pumps will be unnecessary.

( 4. Following the check for quench spray requirements, the operator is directed to determine if continued operation of the low-head safety injection pumps is required.

4.1. If RCS pressure is above the shut-off head of the low-head safety injection pumps, all pump flow will be directed to the recirculation lines.

4.2. In order to reduce pump wear, the operator is directed by ES-1.2 to secure low-head safety injection pumps in the event RCS pressure remains above 225 psig [450 psig].

5. Next, ES-1.2 has the operator determine if the loss-of-coolant is the result of a ruptured steam generator.

5.1. Ruptured steam generators are identified by narrow range level increasing in an uncontrolled manner.

REACTOR OPERATOR Page 133 of 187 Revision 19, 11/06/2008

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

81. 024-AA2.04081INEW/IH/3/SROINAPS/8/20/20081 The crew is performing 1-ES-O.1, Reactor Trip Response, and is establishing emergency boration due to four (4) control rods indicating greater than 10 steps.

The crew was unable to open 1-CH-MOV-13S0, Emergency Boration valve from the control room or locally.

Based on these plant conditions, which ONE of the following identifies the flowpath that will be established by 1-ES-O.1, and the indication used to determine when the required amount of boric acid has been added?

A. Open 1-CH-MOV-111SB & D, charging pump suction from RWST, then close 1-CH-MOV-111SC

& E, charging pump suction from VCT; Charging flow B. Open 1-CH-MOV-111SB & D, charging pump suction from RWST, then close 1-CH-MOV-111SC

& E, charging pump suction from VCT; RWST level C. Open 1-CH-FCV-1113A, boric acid to blender, and 1-CH-241, manual emergency borate valve; Boric Acid and PG Controller Integrators D~ Open 1-CH-FCV-1113A, boric acid to blender, and 1-CH-241, manual emergency borate valve; Boric Acid Storage Tank level Feedback

a. Incorrect. First part plausible since this alternative is used by FR-S.1 if emergency boration from the control room does not work, FR-S.1 prefers this method vice waiting for local actions to be taken; second part also incorrect but plausible since by swapping suction to the RWST makeup flow would be a direct indication of boric acid sollution being added to the RCS.

b. Incorrect. First part incorrect as noted above; second part incorrect but plausible and was chosen as a distractor since tank level is used when done in accordance with the procedure, but the procedure uses the BAST not the RWST.

c. Incorrect. First part is correct in accordance with ES-O.1; second part incorrect but plausible as it would be an indication of flow but the attachment on ES-0.1 stipulates BAST level is used when mnaual emergency borate flowpath is required.

d. Correct. First part is correct as noted above; second part also correct per ES-0.1, Attachment 2.

QUESTIONS REPORT for 2009 NRC SRO exam Validation 3 copy with SRC formatting - for submittal Notes Emergency Boration Ability to determine and interpret the following as they apply tothe Emergency Boration: Availability of BWST (CFR: 43.5/45.13)

Tier: 1 Group: 2 Importance Rating: 3.4/4.2 Technical

Reference:

1-ES-O.1 Proposed references to be provided to applicants during examination: None Learning Objective:

Question History: New additional info:

NUMBER PROCEDURE TITLE REVISION 27 1-ES-O.1 REACTOR TRIP RESPONSE PAGE 11 of 21 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

7. VERIFY ALL IRPls - 10 STEPS OR LESS !E TWO or more IRPls indicate greater than 10 STEPS, THEN emergency borate as follows:

D a) Place the in-service Boric Acid Transfer Pump in FAST.

D b) Open 1-CH-MOV-1350, Emergency Borate Valve.

c) Verify Emergency Boration flow:

D

Emergency Boration Flow - 35 GPM OR GREATER D

On-service Boric Acid Tank Level -

DECREASING D d) !E Emergency Boration flow NOT verified, THEN locally open 1-CH-MOV-1350 and verify flow.

e) !E Emergency Boration flow STILL NOT verified, THEN do the following:

D 1) Place Blender Mode switch in BORATE.

D 2) Place Blender Control switch in START.

D 3) Fully open 1-CH-FCV-1113A.

D 4) Close 1-CH-FCV-1113B.

D 5) Locally open 1-CH-241, Manual Emergency Borate Valve.

(STEP 7 CONTINUED ON NEXT PAGE)

(

NUMBER PROCEDURE TITLE REVISION 27 1-ES-O.1 REACTOR TRIP RESPONSE PAGE 12 of 21 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

7. VERIFY ALL IRPls -10 STEPS OR LESS (Continued) o f) Record the following:

Time Emergency Boration started: _ _ _ _ _ __

Initial on-service BAST level: _ _ _ _ _ __

o g) Initiate ATTACHMENT 2, EMERGENCY BORATION FOR CONTROL RODS NOT FULLY INSERTED, to determine when emergency boration can be secured.

o h) Have the SRO refer to Tech Spec 3.1.1.

8. VERIFY ADEQUATE HP TURBINE GLAND o Throttle 1-MS-MOV-106, GLAND STEAM STEAM PRESSURE ON 1-MS-PI-131 DUMP BYPASS VALVE.

o IF gland steam pressure can NOT be increased, THEN throttle open 1-MS-198, Gland Steam Supply Header 1-MS-PCV-120 Bypass Valve, to control pressure on 1-MS-PI-118 between 1.5 and 5 psig.

NUMBER ATTACHMENT TITLE ATTACHMENT 1-ES-O.1 2 EMERGENCY BORATION FOR CONTROL RODS NOT FULLY REVISION INSERTED PAGE 27 1 of 2 NOTE: If 1-CH-241 is used as the flow path, then the boration amount should be verified by the change in BAST level or by a 1-PT-1 0 series procedure.

1. Determine conditions to stop Emergency Boration:

a) Determine total Equivalent Stuck Rods using the following table:

Record IRPI IDs Convert Actual Record ActualiRPI for IRPls IRPI to Equivalent Equivalent Indication indicating NOT Stuck Rods Stuck Rod fully inserted (EQSR): Subtotals:

Any Rod >20 steps 1 rod = 1 EQSR 1-5 rods = 1 EQSR Rods indicating 6-9 rods = 2 EQSR 11-20 (inclusive) 10- 16 rods = 3 EQSR steps withdrawn 17 - 32 rods = 4 EQSR 33 or more = 5 EQSR Total Equivalent Stuck Rods:

D b)!E ONLY ONE Total Equivalent Stuck Rod was recorded in Step 1a table, THEN GO TO ATTACHMENT 2, EMERGENCY BORATION FOR CONTROL RODS NOT FULLY INSERTED, Step 2 to stop Emergency Boration.

c) !E TWO or more Total Equivalent Stuck Rods were recorded in Step 1a table, THEN monitor for one of the following conditions to stop Emergency Boration:

D

25 minutes for each Equivalent Stuck Rod has elapsed.

OR D

15% BAST Level for each Equivalent Stuck Rod has been inserted.

OR D

Adequate shutdown margin has been verified using a 1-PT-1 0 series procedure.

NUMBER ATTACHMENT TITLE ATTACHMENT 1-ES-O.1 2 EMERGENCY BORATION FOR CONTROL RODS NOT FULLY REVISION PAGE INSERTED 27 2 of 2

2. WHEN Emergency Boration is no longer required, THEN stop Emergency Boration as follows:

o a) Place Boric Acid Transfer Pump in AUTO.

b) Close valves that were opened:

o

1-CH-MOV-1350 o

1-CH-241 c) Ensure the following valves are in AUTO:

o

1-CH-FCV-1113A o

1-CH-FCV-1113B o d) Place Blender in AUTO or OFF.

e) Record the following:

o

Time Emergency Boration stopped:

o

Final on-service BAST level: _ _ _ _ _ __

3. Return to procedure and step in effect.

-END-

NUMBER PROCEDURE TITLE REVISION 15 1-FR-S.1 RESPONSE TO NUCLEAR POWER GENERATION/ATWS PAGE 3 of 12 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED 3 ] _ VERIFY CONTROL RODS -INSERTING D Manually insert control rods.

IN AUTO AT GREATER THAN 48 STEPSI MINUTE

4. CHECK ALL AFW PUMPS - RUNNING D Manually start pumps.

<3- INITIATE EMERGENCY BORATION OF RCS:

D a) Verify at least one Charging Pump - D a) Start Charging Pumps as necessary.

RUNNING b) Emergency borate:

D 1) Put Boric Acid Transfer Pump in FAST D 2) Open 1-CH-MOV-1350, Emergency Borate Valve (STEP 5 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 15 1-FR-S.1 RESPONSE TO NUCLEAR POWER GENERATION/ATWS PAGE 4 of 12 ACTIONI EXPECTED RESPONSE RESPONSE NOT OBTAINED

5. INITIATE EMERGENCY BORATION OF RCS: (Continued) c) Verify adequate negative reactivity c) Inject the BIT:

insertion:

1) Open Charging Pump Suction From o

Emergency boration - FLOW RWST Isolation Valves:

INDICATED AND o

1-CH-MOV-1115B o

Control Rods - MOVING IN OR o

1-CH-MOV-1115D FULLY INSERTED

,,[ 2) Close Charging Pump Suction From o

AND

Neutron flux - DECREASING fO VCT Isolation Valves:

1-CH-MOV-1115C

'1~ o

1-CH-MOV-1115E

~?

3) Close BIT Recirc Valves:

o

1-SI-TV-1884A o

1-SI-TV-1884B o

1-SI-TV-1884C (STEP 5 CONTINUED ON NEXT PAGE)

STUDENT GUIDE FOR EMERGENCY PROCEDURES (92) 4.9 Objective U 12481 Explain the following concepts concerning verifying that all control rods are fully inserted in 1-ES-O.1, "Reactor Trip Response" (SEN-132, SEN-134).

Basis

Condition requiring emergency boration

Three acceptable methods of establishing boration flow

How the required emergency boration time is determined

Three conditions that allow termination of emergency boration flow 4.9 Content

1. Following a reactor trip, it is important to verify that all control rods have fully inserted.

1.1. This verification provides the operating crew with assurance that the core is in a subcritical condition.

1.2. The reactor core is designed such that adequate shutdown margin will exist with one rod fully withdrawn after a reactor trip.

1.3. However, shutdown margin is compromised when one or more control rods are stuck more than 10 steps from the fully inserted position.

2. ES-0.1 directs the operator to initiate an emergency boration when two or more control rods indicate that they are stuck more than 10 steps from the fully inserted position.

3. There are three acceptable methods used for establishing boration flow.

3.1. Each of these three methods begins with shifting the in-service boric acid transfer pump to fast speed.

3.2. The first and most desirable method is to open the emergency borate motor-operated valve electrically by placing its control switch in the OPEN position.

(

REACTOR OPERATOR Page 76 of 187 Revision 19, 11/06/2008

STUDENT GUIDE FOR EMERGENCY PROCEDURES (92) 3.3. If this method of emergency boration fails, an operator is dispatched to manually open the emergency borate motor-operated valve locally.

3.4. If the emergency borate motor-operated valve cannot be opened, then the Blender is placed in the Borate Mode to allow the boric acid integrator to function, then the boric acid to blender flow control valve is opened and an operator is dispatched to locally open the manual emergency borate valve.

4. The amount of emergency boration that is required is determined by using an attachment to ES-O.1.

4.1. The attachment to ES-0.1 has the operator determine "total equivalent stuck rods".

4.2. Any rod indicating greater than 20 steps is considered as one equivalent stuck rod.

4.3. For rods indicating 11 to 20 steps inclusive a table is used to determine the equivalent stuck rods (EQSR) 4.3.1.4.3.1. 1-5 rods 1 EQSR 4.3.2.4.3.2. 6-9 rods 2 EQSR 4.3.3.4.3.3. 10-16 rods 3EQSR 4.3.4.4.3.4. 17-32 rods 4EQSR 4.3.5.4.3.5. 33 or more 5 EQSR.

4.4. As an example, assume five control rods failed to fully insert following a reactor trip.

4.4.1.lndicated rod position is as follows: 14, 11,20,35, and 200 steps.

4.4.2.The two rods that are> 20 steps out have the reactivity worth of 2 EQSR.

4.4.3.The three rods that are between 11 and 20 steps out have the reactivity worth of 1 EQSR.

4.5. The total number of "equivalent stuck rods" is three.

5. Emergency boration is to continue until one of three conditions is satisfied.

5.1. Emergency boration has been in service for at least 25 minutes for each "equivalent stuck rod."

5.2. Boric acid storage tank level has decreased 15% for each "equivalent stuck rod."

5.3. Adequate shutdown margin has been verified using a PT-10 series procedure.

REACTOR OPERATOR Page 77 of 187 Revision 19, 11/06/2008

STUDENT GUIDE FOR EMERGENCY PROCEDURES (92) 5.4. A note at the beginning of the attachment states that if the manual emergency borate valve is used then the boration amount should be verified by the change in BAST level or by a 1-PT-10 series procedure.

[Review SEN-132 and SEN 134 with trainees.

SEN-132 On January 30, 1996 the Wolf Creek facility experienced a manual reactor trip from 100% power due to ice formation on the circulating water and service water traveling screens. Following the trip the control room crew identified that five control rods did not insert fully. Although subsequent analysis indicated that the reactor was adequately shutdown, with the rods not fully inserted, the crew initiated an emergency boration in accordance with the emergency procedures.

SEN-134 A similar event occurred December 18, 1995 at South Texas. They were at 100% power when a pilot wire relay actuated resulting in a main transformer lockout and an automatic reactor trip. The operations crew noted that three control rods had not fully inserted. One of the three rods did eventually drift to the bottom while the other two rods were manually inserted.

Following each of the events described above, the utility conducted extensive rod drop testing in order to determine the magnitude and possible cause of the incident. Although neither utility has identified the specific cause of each event, each has indicated that the most likely cause is "bowing" of the fuel assemblies. At Wolf Creek all of the affected fuel assemblies were thrice burned Vantage 5H fuel which had a higher burnup than any other Vantage 5H fuel had experienced (at Wolf Creek). The residence time of these fuel assemblies in the core may have contributed to the bowing.

Operations personnel at North Anna should be aware that a similar condition could occur here. Refueling personnel have had the pleasure of trying to load bowedltwisted banana and some "S" shaped fuel REACTOR OPERATOR Page 78 of 187 Revision 19, 11/06/2008

STUDENT GUIDE FOR EMERGENCY PROCEDURES (92) assemblies into the reactor vessel. Should an operations crew detect that control rods have not fully inserted following a reactor trip, emergency boration should be initiated in accordance with the emergency procedures.]

4.10 Objective U 12483 Explain why 1-ES-O.1, "Reactor Trip Response," directs the operator to verify that all AC busses are energized by off-site power.

4.10 Content

1. The operator is directed to verify all AC busses are energized by offsite power.

1.1. It should be noted that the step directs verification of ALL busses, not just emergency busses.

1.2. Plant recovery requires the availability of both safety-related and non-safety-related equipment.

( 1.3. This step is used to determine if 0-AP-10, Loss of Electrical Power should be initiated.

Topic.4.110peratiqnOfSteamDumr)s .Foil oWihg Reactor Trips 4.11 Objective U 12027 Explain why the steam dumps are operated in the steam pressure mode following a reactor trip.

4.11 Content

1. ES-0.1 directs that the steam dumps be placed in the STEAM PRESSURE MODE of operation.

1.1. Operation of the steam dumps in the steam pressure mode facilitates finer control of RCS temperature.

1.2. Additionally, any controlled cooldown below 543°F will have to be performed in the steam pressure mode.

REACTOR OPERATOR Page 79 of 187 Revision 19, 11/06/2008

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

82. 025-AG2.4.11 082INEW/1H/3/SROINAPS//

Given the following conditions:

Unit 1 is in Mode 5 for drained-down RCS maintenance.

Reactor coolant loops are isolated.

RCS level is +12" above centerline.

A loss of RHR occurs.

The crew is performing actions of 1-AP-11, Loss of RHR.

RCS temperature is rising, and NEITHER RHR pump can be started.

Which ONE of the following describes the preferred method, and the actions that will be taken to restore core cooling in accordance with 1-AP-11?

A~ Hot Leg Injection Forced Feed and Spill; start ONE charging pump, and if necessary, ONE LHSI pump.

B. Cold Leg Injection Forced Feed and Spill; start TWO charging pumps and BOTH LHSI pumps.

C. Cold Leg Injection Forced Feed and Spill; start ONE charging pump, and if necessary, ONE LHSI pump.

D. Hot Leg Injection Forced Feed and Spill; start TWO charging pumps and BOTH LHSI pumps.

Feedback

a. Correct. This is the preferred method per attachment 5 of AP-11, the other method (cold leg injection) would only be used if this were not available; under these plant conditons only 1 train is necessary for core cooling thus the procedure only permits operation of 1 train of equipment.

b. Incorrect. As noted above cold leg path is only used if hot leg is unavailable, the candidate who does not have detailed knowledge of the procedure may overlook this and default to this distractor since the normal injection flowpath at power is via the cold legs; similarly the candidate may have a sense of urgency and if they do not have detailed procedure knowledge may conclude that starting all available pumps to cool the core is preferred.

c. Incorrect. Flow path incorrect but plausible as previously noted; operation of only one train is correct per AP-11.

d. Incorrect. Flowpathis correct as previously noted; operation of more than onetrain is not permitted by the procedure, but plausible as discussed in Distractor b.

QUESTIONS REPORT for 2009 NRC SRO exam Validation 3 copy with SRC formatting - for submittal Notes Loss of Residual Heat Removal System (RHRS)

Knowledge of abnormal condition procedures.

(CFR: 41.10/43.5/45.13)

Tier: 1 Group: 1 Importance Rating: 4.0/4.2 Technical

Reference:

1-AP-11 Proposed references to be provided to applicants during examination: None Learning Objective:

Question History: new additional info:

NUMBER PROCEDURE TITLE REVISION 25 1-AP-11 LOSS OF RHR PAGE 6 of 23 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

5. VERIFY RHR ISOLATION VALVES -

OPEN:

a) RHR Inlet Isolation Valves - OPEN a) Do the following:

D

1-RH-MOV-1700 D 1) Stop RHR Pump(s).

D

1-RH-MOV-1701 D 2) Reduce RCS pressure as necessary.

D 3) WHEN RCS pressure is less than 418 psig, THEN open valves.

b) AT least one RHR Outlet Isolation D b) Open at least one RHR Outlet Isolation Valve.

Valve - OPEN D

1-RH-MOV-1720A D

1-RH-MOV-1720B CAUTION: RHR flow less than minimum requirements may cause RCS temperature to increase.

NOTE:

Operating at low RHR system flow rates during reduced inventory operations greatly reduces the risk of air entrainment (vortexing).

Indications of a pump sheared shaft are low flow and low motor amps. A degraded pump or a pump with a sheared shaft is to be considered as NOT running.

6. CHECK ONE RHR PUMP - RUNNING Do the following:

D a) IF the other RHR pump is available, THEN stop any degraded RHR pump.

(STEP 6 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 25 1-AP-11 LOSS OF RHR PAGE 7 of 23 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

6. CHECK ONE RHR PUMP -

RUNNING (Continued) o b) !E a degraded RHR pump is running AND the other RHR pump is NOT available, THEN GO TO Step 7.

c) IF electrical power is available, THEN do the following:

1) Manually close the following RHR Control Valves:

o

1-RH-FCV-1605 o

1-RH-HCV-1758 o 2) !E an RHR Pump was previously stopped due to air entrainment, THEN locally vent both RHR Pumps.

o 3) IF both RHR pumps are stopped, THEN start one RHR pump.

4) Restore RHR flow by repositioning the following RHR Control Valves:

o

1-RH-HCV-1758 o

1-RH-FCV-1605 o 5) !E an RHR Pump has been started, THEN GO TO Step 7.

o !E no RHR Pump can be started, THEN GO TO Step 11 .

(STEP 6 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 25 1-AP-11 LOSS OF RHR PAGE 8 of 23 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

6. CHECK ONE RHR PUMP-RUNNING (Continued) d) IF electrical power is NOT available, THEN do the following:

0 1) Initiate O-AP-10, LOSS OF ELECTRICAL POWER.

0 2) GO TO Step 11.

7. VERIFY RHR SYSTEM - NORMAL: Do the following:

0

RHR flow - NORMAL a) !E RHR Pump is vortexing, THEN do the

( following:

0

RHR flow - STABLE 0 1) Start increasing RCS level to at least 0

RHR Motor amps - STABLE +10 inches above centerline by increasing charging flow.

0

RCS temperature - STABLE

2) Check RHR flow - less than or equal to design flow of ATTACHMENT 3:

o

2 RHR HXs in use - Page 1 of 2 o

1 RHR HX in use - Page 2 of 2

!E RHR flow is greater than the design flow rate of ATTACHMENT 3, THEN reduce flow to the design flowrate using:

o

1-RH-HCV-1758 o

1-RH-FCV-1605 (STEP 7 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 25 1-AP-11 LOSS OF RHR PAGE 9 of 23 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

7. VERIFY RHR SYSTEM - NORMAL:

(Continued) o 3) Check RCS level - Greater than minimum for indicated flow of ATTACHMENT 2.

o IF RCS level is not greater than minimum for indicated flow of ATTACHMENT 2, THEN STOP the RHR Pumps and GO TO Step 11.

4) Send an Operator to locally check pump operation:

o

RHR pump noise o

RHR pump seals o

RHR pump vibration o b)!E the running RHR pump is degraded AND the other RHR pump is available, THEN RETURN TO Step 6.

o c) IF RHR System cannot be stabilized, THEN stop running RHR Pump AND GO TO Step 11.

NUMBER PROCEDURE TITLE REVISION 25 1-AP-11 LOSS OF RHR PAGE 10 of 23 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED B. CHECK SERVICE WATER TO CC HEAT EXCHANGER - AVAILABLE:

0 a) Verify Service Water System - IN a) IF Service Water flow is NOT available, THEN SERVICE initiate the following while continuing with this procedure:

0

0-AP-12, LOSS OF SERVICE WATER 0

1-AP-15, LOSS OF COMPONENT COOLING 0 GO TO Step 11.

b) Verify Service Water Supply Valves b) Open Service Water Supply Valves to CC to CC System - OPEN: System:

0

1-SW-MOV-10BA 0

1-SW-MOV-10BA 0

1-SW-MOV-1 OBB 0

1-SW-MOV-10BB 0 c) Locally check Service Water to CC 0 c) GO TO Step 11 .

Heat Exchanger L1P - NORMAL

NUMBER PROCEDURE TITLE REVISION 25 1-AP-11 LOSS OF RHR PAGE 11 of 23 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

9. CHECK CC FLOW TO RHR HEAT Do the following:

EXCHANGERS-NORMAL:

D

1-CC-FI-132A a) Open CC valves for in service CC Heat Exchanger:

D

1-CC-FI-132B D

1-CC-TV-103A, A RHR Heat Exchanger Return Isolation D

1-CC-TV-103B, B RHR Heat Exchanger Return Isolation D

1-CC-MOV-100A, A CC Heat Exchanger Outlet Isolation D

1-CC-MOV-100B, B CC Heat Exchanger Outlet Isolation b) IF either 1-CC-TV-103A or 1-CC-TV-103B cannot be opened, THEN close the associated RHR CC MOV:

D

1-CC-MOV-1 OOA for 1-CC-TV-1 03A D

1-CC-MOV-1 OOB for 1-CC-TV-1 03B D c)!E CC flow is restored, THEN GO TO Step 10.

D d) !E CC is NOT restored, THEN initiate 1-AP-15, LOSS OF COMPONENT COOLING, while continuing with this procedure.

D e) GO TO Step 11.

NUMBER PROCEDURE TITLE REVISION 25 1-AP-11 LOSS OF RHR PAGE 12 of 23 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

10. RETURN TO PROCEDURE AND STEP IN EFFECT CAUTION: If RCS boiling is determined to exist, then non-essential personnel should be evacuated from the Containment.

11. INITIATE PERSONNEL PROTECTIVE ACTIONS:

D a) Record most recent time to boiling estimate from 1-GOP-13.0, ALTERNATE CORE COOLING METHODASSESSMEN~

Time (minutes): _ _ __

D b) Evaluate need to implement EPIP-1.01, EMERGENCY MANAGER CONTROLLING PROCEDURE c) Monitor Containment Radiation:

D

1-RM-RMS-159 D

1-RM-RMS-160 12._ INITIATE ATTACHMENT 11, CONTAINMENT CLOSURE, WHILE CONTINUING WITH THIS PROCEDURE 13._ VERIFY 1-RC-Ll-105, INDEPENDENT D Place the keylock switch for 1-RC-Ll-105 in RCS LEVEL INDICATOR - ENABLE.

ENERGIZED

NUMBER PROCEDURE TITLE REVISION 25 1-AP-11 LOSS OF RHR PAGE 13 of 23 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

14. START AVAILABLE CONTAINMENT AIR RECIRC FANS USING 1-0P-21.1, CONTAINMENT VENTILATION NOTE: If RCPs are stopped, then Attachment 10, NATURAL CIRCULATION should be used to establish and maintain natural circulation.

15. MAINTAIN CORE COOLING USING FORCED CIRCULATION:

o a) Verify at least one RCP - o a) GOTO Step 16.

RUNNING b) Stabilize RCS temperature by dumping steam using either of the following:

o

Condenser Steam Dumps OR o

SG PORVs c) Maintain SG narrow range levels between 23% and 75% using any of the following:

o

Auxiliary Feedwater OR o

Main Feedwater OR o

Condensate o d) GO TO Step 18

NUMBER PROCEDURE TITLE REVISION 25 1-AP-11 LOSS OF RHR PAGE 14 of 23 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

16. CHECK IF THE RCS SHOULD BE COOLED WITH SPENT FUEL POOL COOLING:

o a) Verify Reactor Cavity - FLOODED o a) GO TO Step 17.

o b) Verify Spent Fuel Pit level - o b) Initiate O-AP-27, MALFUNCTION OF SPENT NORMAL FUEL PIT SYSTEM, AND GO TO Step 17.

o c) Initiate ATTACHMENT 9, COOLING THE RCS WITH SFP COOLERS o d) GO TO Step 18

NUMBER PROCEDURE TITLE REVISION 25 1-AP-11 LOSS OF RHR PAGE 15 of 23 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION:

Personnel working in Containment should be warned before the RCS is refilled to avoid contamination of personnel near any RCS openings.

Only borated water should be added to the RCS to maintain adequate shutdown margin.

Differences exist in RCS levels between active and inactive cold and hot legs during reduced inventory operations. At saturated conditions, the hot and cold leg levels can differ by several feet.

NOTE: The alternate cooling method priority is obtained from 1-GOP-13.0, ALTERNATE CORE COOLING METHOD ASSESSMENT.

17. DETERMINE APPROPRIATE ALTERNATE CORE COOLING METHOD:

o

Natural Circulation - Initiate ATTACHMENT10,NATURAL CIRCULATION, while continuing with this procedure OR o

Reflux Boiling - Initiate ATTACHMENT 8, REFLUX BOILING, while continuing with this procedure OR (STEP 17 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 25 1-AP-11 LOSS OF RHR PAGE 16 of 23 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

17. DETERMINE APPROPRIATE ALTERNATE CORE COOLING METHOD: (Continued)

D

Hot Leg Injection Forced Feed and Spill - Initiate ATTACHMENT5,HOTLEG INJECTION FORCED FEED AND SPILL, while continuing with this procedure OR D

Cold Leg Injection Forced Feed and Spill - Initiate ATTACHMENT 6, COLD LEG INJECTION FORCED FEED AND SPILL, while continuing with this procedure OR D

Gravity Feed and Spill - Initiate ATTACHMENT 4, GRAVITY FEED AND SPILL, while continuing with this procedure

NUMBER ATTACHMENT TITLE ATTACHMENT 1-AP-11 5 HOT LEG INJECTION FORCED FEED AND SPILL REVISION PAGE 25 1 of 10 CAUTION:

If the RCS is vented to the PRT, then PRT pressure indication should be monitored as an indication of RCS pressure. Changes in RCS pressure can result in Reactor Vessel water level changes that may not show on RCS standpipe level indicator 1-RC-L1-1 03.

Depending on equipment and RCS conditions, boiling in the core may lead to PRZR surge line flooding and cause RVLlS and RCS Standpipe level indications to read higher than actual.

If RWST level decreases to 15%, then the SI System should be aligned for recirculation using ATTACHMENT 7, ALIGNING THE SI SYSTEM FOR RECIRC, to provide long-term cooling.

Charging and Low-Head Pumps taking suction from the RWST must be stopped when RWST level decreases to 8%. An alternate water source will be necessary in order to prevent loss of pump suction.

* * * * * * * * * * * * * * * * *.~ * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * ,

~U>~."Y'~

NOTE: Hot leg injection usi t s Attachment is the preferred m~* of RCS m.akeup for forced feed and spill operation . If *Ieg injection is not available, hen ~ACHMSNT 6, COLD LEG INJECTION FOR EED AND SPILL should be use. c:11 S~c~

1. !E desired to conserve Containment Sump inventory for RCS recirculation, THEN place the following Containment Sump Pumps in OFF:

1-DA-P-4A

1-DA-P-4B

2. Verify a Charging Pump is available AND is specified for RCS makeup by the Alternate Core Cooling Method Assessment. !E a Charging Pump is NOT available, THEN GO TO Step 5.

3. Verify a Charging Pump flow path to the RCS hot legs is available. !E a Charging Pump flow path is NOT available, THEN GO TO Step 5.

NUMBER ATTACHMENT TITLE ATTACHMENT 1-AP-11 5 HOT LEG INJECTION FORCED FEED AND SPILL REVISION PAGE 25 2 of 10

4. Align a Charging Pump to make up to the RCS as follows:

a. Open Charging Pump Suction from RWST Isolation Valves:

1-CH-MOV-1115B

1-CH-MOV-1115D

b. Close Charging Pump Suction from VCT Isolation Valves:

1-CH-MOV-1115C

1-CH-MOV-1115E

c. Open 1-CH-MOV-1373, Charging Pump Recirc Header Isolation Valve.

d. Open the Charging Pump Recirc Valves:

1-CH-MOV-1275A for 1-CH-P-1 A

1-CH-MOV-1275B for 1-CH-P-1 B

1-CH-MOV-1275C for 1-CH-P-1 C

e. Start one Charging Pump.

f. Close the Normal Charging Isolation Valves:

1-CH-MOV-1289A

1-CH-MOV-1289B

g. Align one of the following hot leg injection flow paths as desired:

1-SI-MOV-1869B OR

1-SI-MOV-1869A (STEP 4 CONTINUED ON NEXT PAGE)

NUMBER ATTACHMENT TITLE ATTACHMENT 1-AP-11 5 HOT LEG INJECTION FORCED FEED AND SPILL REVISION PAGE 25 3 of 10

h. Close the Charging Pump Recirc Valves:

1-CH-MOV-1275A for 1-CH-P-1 A

1-CH-MOV-1275B for 1-CH-P-1 B

1-CH-MOV-1275C for 1-CH-P-1 C

i. Check the following to determine if charging flow is adequate:

RCS level is stable or increasing

RCS temperature is stable or decreasing

j. IF charging flow is adequate, THEN GO TO Step 6. IF charging flow is NOT adequate, THEN GO TO Step 5 to align a Low-Head SI Pump.

STUDENT GUIDE FOR INTEGRATED PLANT OPERATIONS (98)

(

7.13 Objective U 10509 Explain the following concepts associated with the "forced feed and spill" alternate core-cooling method in response to a loss of the Residual Heat Removal System.

Conditions that must exist for forced feed and spill to be effective

Why the size of the pressurizer vent path required may vary

Why hot-leg injection is preferred 7.13 Content

1. In the event that all RCS loops are isolated, forced feed and spill can be used to remove core decay heat.

1.1. This method of heat removal is done by opening an RCS vent path and allowing water pumped from the Refueling Water Storage Tank (RWST) to flow through the core to the vent.

1.2. If force feed and spill is to be an effective means of removing core heat, the following conditions

( must exist:

1.2.1.An adequately sized RCS vent path must be established ..

1.2.2.An adequate time must have expired since shutdown.

1.2.3. Required safety injection pump and flow path must be available.

1.2.4.RWST level must be above 50%.

2. The size of the pressurizer vent path required may vary.

2.1. In order for decay heat to be removed, sufficient flow must be established through the core 2.2. The size of the vent controls the amount of flow that will be established through the core.

2.3. A specific vent path must be established to ensure adequate flow will be available to remove decay heat based on the time since shutdown

3. Safety injection flow may be established through either the RCS hot-legs or the RCS cold-legs.

3.1. The preferred safety injection flow path is though the RCS hot-legs for the following reasons:

REACTOR OPERATOR Page 69 of 142 Revision 16, 08/20/2008

STUDENT GUIDE FOR INTEGRATED PLANT OPERATIONS (98) 3.1.1.Prevents reaching saturated conditions in the reactor head.

3.1.1.1. If the reactor vessel head region reaches saturation conditions, the head will become pressurized with steam.

3.1.1.2. The steam will force water out of the core region, up the down comer, and into the cold leg piping.

3.1.2.Ensures adequate makeup flow reaches the core and does not flow out a cold leg opening.

3.1.3.Prevents thermally stressing the reactor vessel with cold RWST water.

7.14 Objective U 10511 Explain the following concepts associated with the "gravity feed and spill" alternate core-cooling method in response to a loss of the Residual Heat Removal System (SOER-85-4).

(

Purpose

How long the method is designed to provide sufficient cooling

Conditions that must exist for gravity feed and spill to be effective

Preferred path of feed to the Reactor Coolant System

Why a minimum level is required in the refueling water storage tank

Required Reactor Coolant System vent path 7.14 Content

1. If all alternate core-cooling mechanisms are unavailable, gravity feed and spill may be used to suppress core boiling for a short period of time until a long-term method becomes available.

2. Gravity feed and spill is meant to suppress core boiling for 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after it is initiated.

2.1. It should be noted that gravity feed and spill is not a long term cooling mechanism and actions should continue to establish one of the long-term cooling mechanisms.

REACTOR OPERATOR Page 70 of 142 Revision 16, 08/20/2008

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

83. 032-AA2.06 083INEW/1H/3/SRO///

Given the following conditions:

Unit 1 was initially in Mode 2 starting up following a reactor trip.

Burnup is 14,000 MWO/MTU.

The "A" main steamline failed catastrophically inside containment.

Operators have completed 1-E-0, Reactor Trip or Safety Injection and are preparing to transition.

The OATC notes that "A" loop cold-leg temperature indicates 325°F.

Based on these plant conditions, which ONE of the following identifies the procedure operators will implement upon leaving 1-E-0, and the indication that will be used to monitor the Subcriticality CSF Status Tree?

A. 1-FR-P.1, Response to Imminent Pressurized Thermal Shock Condition; Source Range SUR.

B. 1-FR-P.1, Response to Imminent Pressurized Thermal Shock Condition; Gamma-Metrics Wide-Range.

C. 1-E-2, Faulted Steam Generator Isolation; Source Range SUR.

D~ 1-E-2, Faulted Steam Generator Isolation; Gamma-Metrics Wide-Range.

Feedback

a. Incorrect. First part plausible since a large cooldown has occurred and if the candidate does not know CSF paths from memory they may conclude that this is correct; second part also incorrect but plausible since the candidate may conclude that at this point adverse containment conditions would no longer apply and sellect this distractor; F-O however requires use of gamma metrics for the duration of the event.

b. Incorrect. First part incorrect but plausible as discussed above; second part is correct since for a MSL break the threshold for adverse containment conditions will be crossed and the note in F-O mentioned above requires use of gamma metrics.

c. Incorrect. First part is correct based on the information provided. Second part incorrect as previously discussed.

d. Correct. First part is correct since there are no red or orange path conditions the procedural transition will be to E-2; Second part is also correct as discussed above.

QUESTIONS REPORT for 2009 NRC SRO exam Validation 3 copy with SRC formatting - for submittal Notes Loss of Source Range Nuclear Instrumentation Ability to determine and interpret the following as they apply to the Loss of Source Range Nuclear Instru mentation:

(CFR: 43.5 /45.13)

Tier: 1 Group: 2 Importance Rating: 3.9/4.1 Technical

Reference:

1-F-O and1-E-O Proposed references to be provided to applicants during examination: None Learning Objective:

Question History: new additional info:

not a direct KA match but intent is met; question does not present a situation involving an obvious loss of source range, (e.g. pegged low, no hi volts indicated, etc.), however the plant conditions given effectively result in a loss of source range since these instruments are not qualified. The SRO should recognize this.

NUMBER ATTACHMENT TITLE ATTACHMENT 1-F-O 1 SUBCRITICALITY REVISION PAGE 7 1 of 1 NOTE: IF adverse Containment conditions have been exceeded, THEN the Gamma-Metrics Excore Neutron Monitor system (Source and Wide Ranges) should be used to monitor neutron flux for the duration of the event.

GOTO 1-FR-S.1 POWER RANGE LESS THAN 5% NO GOTO

[GAMMA-METRICS III 1-FR-S.1 WIDE-RANGE POWER LEVEL LESS THAN 5 X 10°] YES GOTO Y 1-FR-S.2 INTERMEDIATE NO RANGE SUR MORE NEGATIVE THAN -0.2 DPM YES INTERMEDIATE RANGE SUR ZERO NO CSF OR NEGATIVE G SAT

[GAMMA-METRICS WIDE-RANGE POWER LEVEL ADVERSE NO STABLE OR YES CONTAINMENT DECREASING] YES CSF G SAT SOURCE RANGE ENERGIZED NO

[GAMMA-METRICS SOURCE RANGE ON SCALE] YES Y GOTO 1-FR-S.2 SOURCE RANGE SUR ZERO OR NEGATIVE NO

[GAMMA-METRICS SOURCE RANGE POWER LEVEL STABLE OR YES DECREASING]

G CSF SAT

NUMBER PROCEDURE TITLE REVISION 39 1-E-O REACTOR TRIP OR SAFETY INJECTION PAGE 12 of 21 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

- CHECK SGs- NOT FAULTED: o GO TO 1-E-2, FAULTED STEAM GENERATOR ISOLATION, STEP 1.

o

All SG pressures:

GREATER THAN 80 PSIG AND

UNDER CONTROL OF OPERATOR

- CHECK THAT SG TUBES ARE NOT RUPTURED:

o a) Level in any SG - INCREASING IN AN o a) GO TO Step 12c.

UNCONTROLLED MANNER o b) GO TO 1-E-3, STEAM GENERATOR TUBE RUPTURE,STEP 1 c) Check Radiation Monitors - NORMAL: o c) GO TO 1-E-3, STEAM GENERATOR TUBE RUPTURE, STEP 1.

o

SG Blowdown radiation last known valid indication o

Condenser Air Ejector radiation last known valid indication o

SG Main Steamline radiation o

Terry Turbine AFW Pump exhaust radiation

NUMBER ATTACHMENT TITLE ATTACHMENT 1-F-O 4 INTEGRITY REVISION PAGE 7 1 of 2 GO TO 1-FR-P.1

.,.11111 .111I1I~1II111111 !II I GO TO III 1-FR-P.1 ALL RCS PRESSURE-COLD LEG NO III TEMPERATURE POINTS TO RIGHT OF LIMIT A OF CURVE ON PAGE 2 YES III III 0

~\~

III ffillW

" Y GO TO ALL RCS COLD LEG NO 1-FR-P.2 TEMPERATURES GREATER THAN 285°F YES ALL RCS COLD LEG NO TEMPERATURES GREATER THAN 315°F YES TEMPERATURE DECREASE NO IN ALL RCS COLD LEGS LESS THAN 100°F IN THE YES LAST 60 MINUTES CSF SAT

. GOTO 1-FR-P.1 RCS PRESSURE LESS NO THAN 535 PSIG YES CSF RCS COLD LEG NO SAT TEMPERATURES GREATER THAN 285°F YES CSF G SAT

0 m z c

< , s:

INTEGRITY CSF OPERATIONAL LIMITS CURVE "eno 71 OJ Om Pressure z JJ (psig) 30001~~I[ITI~~~~~1ig'~ 2560 ps

!I I 2500 2000 i~kb-~i1Jtih.m¥iif.idII:r~ll,rA-~hll~JSMflil'l' I

Dm:tTd-jJ;l-dlJl-ll-ill'lllif-,j I i II !-fl-! 1.1 IIII 11*.1 I'! i i i i II ]-:,! i J l l i l i J t! i"'ll!! i l II i i i II z

>>~

0

...,f,>"' t;;! I !! [,-f! J I I' ! Ii* ,i -; I 1500 I , I I ! ' "I! t l t*! t , ' .1 I

1--1-1 j ! II m s:

G) m

0 Z

~ -;

r J; I , :::j 1000 i! ! i

"; I II i

r! , I, II r m

500 o

o 100 200 300 400 500 600

~

Cold Leg Temperature (OF) .....

f\) "lJ Drawing No: WT316E o >> oI

-G) .j:>,

f\) m s:

m Z

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95)

Critical Safety Function Trees (1-F-O)

TQpic ..1.1F-O . *lnforrnation 1.1 Objective U 13015 List the following information associated with 1-F-0, "Critical Safety Function Status Trees."

Purpose of the procedure

Modes of applicability

Entry conditions

Order of priority for monitoring the critical safety functions 1.1 Content

1. F-O provides a means for evaluating the plant safety state in terms of the status of each critical safety

( function.

2. 1-F-0 is applicable with the unit in modes 1 - 4.

3. 1-F-0 is entered from 1-E-0 (Reactor trip or safety injection) when directed to initiate monitoring of CSF status trees, or when a transition is made from 1-E-0 to another EOP.

4. There is a specified priority for monitoring CSFs.

4.1. From the highest priority to the lowest priority:

4.1.1.Subcriticality 4.1.2.Core cooling 4.1.3. Heat sink 4.1.4.lntegrity 4.1.5.Containment 4.1.6.lnventory REACTOR OPERATOR Page 5 of 99 Revision 14, 11/06/2008

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95) 4.2. Attachments in 1-F-0 are ordered such that monitoring of CSFs adheres to the above priority requirements.

Topj91~2CSF Cdhcept!;

1.2 Objective U 12704 Explain the following concepts associated with the critical safety functions (1-F-0).

Defense in depth, including barriers to the release of radioactive material

How maintenance of each critical safety function prevents the loss of barrier(s)

Why the order of monitoring and implementing critical safety functions is prioritized 1.2 Content

1. A fundamental goal of nuclear safety is the prevention of uncontrolled releases of radioactive materials.

1.1. The concept of defense in depth was adopted as a cornerstone of nuclear safety.

1.1.1. Defense in depth translates into providing multiple barriers to the release of radioactive material.

1.1.2. The barriers consist of the fuel matrix and fuel clad, the RCS pressure boundary, the containment, and distance of the power plant from the general public.

1.1.2.1. The first three barriers are direct physical barriers to the transport of radioactive materials and together provide the required defense in depth.

1.1.2.1.1. The fuel matrix and fuel cladding are the first barrier against release.

1.1.2.1.2. The goal of nuclear safety is to ensure that as many as possible of the three physical barriers remain intact at all times and under all conditions and/or circumstances that may exist.

1.1.2.2. The RCS pressure boundary blocks the transport of radionuclides that escape through the fuel rod barriers and those that are produced outside of the fuel rods themselves.

REACTOR OPERATOR Page 6 of 99 Revision 14, 11/06/2008

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95)

TopiCJ.3 Mohit()ring C$Fs 1.3 Objective U 13016 Explain the following concepts associated with monitoring the critical safety function status trees (1-F-O).

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 R/hr.

Topic1.4.RedpathConditiq.ns .

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)

Response to an Imminent Pressurized Thermal Shock Condition (1-FR-P.1) 12.1 Objective U 13011 List the following information associated with 1-FR-P.1, "Response to Imminent Pressurized Thermal Shock Condition."

Purpose of the procedure

Modes of applicability

Entry conditions

Major action categories

Conditions that result in leaving the procedure 12.1 Content

1. The purpose of FR-P.1 is to provide guidance to Operations personnel for responding to a high priority challenge to reactor vessel integrity by actions which mitigate the effects of cooldown/pressurization transients.

2. FR-P.1 is applicable when the unit is initially in Modes 1 - 3.

3. FR-P.1 is entered from the integrity CSFST on one RED condition or either of two ORANGE conditions.

3.1. RED - Temperature decrease in any RCS cold leg is greater than or equal to 100°F in the last 60 minutes AND any RCS pressure/cold leg temperature point to the left of limit A.

3.2. ORANGE - Temperature decrease in any RCS cold leg is greater than or equal to 100°F in the last 60 minutes, all RCS pressure/cold leg temperature points to the right of limit A, and at least one RCS cold leg temperature less than or equal to 285°F.

REACTOR OPERATOR Page 73 of99 Revision 14, 11/06/2008

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95)

(

3.3. ORANGE - Temperature decrease in all RCS cold legs less than 100°F in the last 60 minutes, any RCS cold leg temperature is less than or equal to 285°F, and RCS pressure greater than or equal to 535 psig.

4. This procedure's major action categories include:

4.1. Stop RCS cooldown 4.2. Terminate SI if criteria satisfied.

4.3. Depressurize RCS to minimize pressure stress 4.4. Establish normal operating conditions and stable RCS conditions.

4.5. Soak if necessary prior to further restricted cooldown.

5. FR-P.1 is exited when the following conditions exist:

5.1. Following a RCS temperature soak, if required.

5.2. Large break LOCA diagnosed in Step 1.

12.2 Objective U 9137 For a given plant condition, determine if conditions for pressurized thermal shock exist or could potentially occur.

12.2 Content

1. Determine the if PTS conditions exist or could potentially occur.

1.1. Assuming the following conditions.

1.1.1. The unit was at 100% power prior to the event 1.1.2.A steam break occurred 20 minutes ago 1.1.3. The break was been isolated 10 minutes ago REACTOR OPERATOR Page 74 of99 Revision 14, 11/06/2008

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

84. 039-02.1.25 084/MODIFIEDINAPS/H/3/SROIII Given the following conditions:

Unit 1 is at 100% power.

RCS boron is 1120 ppm.

Engineering identified calculation errors during the previous Main Steam Safety Valve (MSSV)

Testing.

The data was recalculated, and the following lists the actual setpoints for the affected SG MSSVs:

MS-SV-101A -- 1092 psig MS-SV-102B -- 1103 psig MS-SV-103A -- 1115 psig MS-SV-103B -- 1120 psig MS-SV-104A -- 1160 psig MS-SV-105B --1170 psig Which ONE of the following identifies the Technical Specification Required Action, and the Technical Specification Bases for the action?

(Reference provided)

A. Reduce power to < 52% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ; ensure primary-to-secondary pressure limitations are not exceeded.

B. Reduce power to < 37% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months and reduce PR HI Flux trip to a maximum of 37%

RTP within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months ; ensure primary-to-secondary pressure limitations are not exceeded.

C'!" Reduce power to < 52% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ; provide protection against overpressurizing the Reactor Coolant System.

D. Reduce power to < 37% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months and reduce PR HI Flux trip to a maximum of 37%

RTP within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months ; provide protection against overpressurizing the Reactor Coolant System.

Feedback

a. Incorrect. First part is correct as there are two inoperable safeties but only one one each steam line; second part is incorrect but plausible, the candidate who does not have detailed knowledge of the basis may correlate the role of the MSSVs solely with the function of limiting SG pressure and conclude that by virtue of that pri-sec DIP is limited. There are design limits for both sec-pri and pri-sec (with one of the limit curves displayed on the ICCM), but that is not the bases for MSSV TS requirements.

b. Incorrect. First part is correct as there are two inoperable safeties; second part incorrect but plausible as discussed in distractor a.

c. Correct. Action is correct per TS with 1 MSSV inoperable in A SG and 1 inoperable in B SG; bases is correct per TS.

d. Incorrect. First part incorrect but plausible as discussed in Distactor b; second part is the correct Bases.

QUESTIONS REPORT for 2009 NRC SRO exam Validation 3 copy with SRC formatting - for submittal Notes Main and Reheat Steam System (MRSS)

Ability to interpret reference materials, such as graphs, curves, tables, etc.

(CFR: 41.10/43.5/45.12)

Tier: 2 Group: 1 Importance Rating: 3.9/4.2 Technical

Reference:

TS 3.7.1 and Bases Proposed references to be provided to applicants during examination: TS 3.7.1 Learning Objective:

Question History: modified from 2006-1 audit Associated objective( s):

MSSVs 3.7.1 3.7 PLANT SYSTEMS 3.7.1 Main Steam Safety Valves (MSSVs)

LCO 3.7.1 Five MSSVs per steam generator APPLICABILITY: MODES 1, 2, and 3.

ACTIONS

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

Separate Condition entry is allowed for each MSSV.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more steam A.1 Reduce THERMAL POWER 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months generators with one to less than or equal MSSV inoperable and to 52% RTP.

the Moderator Temperature Coefficient (MTC) zero or negative at all power levels.

B. One or more steam B.1 Reduce THERMAL POWER 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months generators with one to less than or equal ~

MSSV inoperable and to the Maximum the MTC positive at All owabl e % RTP any power levels. specified in Table 3.7.1-1 for the OR One or more team generators i th two or AND MSSV/

number of OPERABLE more MSSVs inoper 1e. (continued) tC\(

"'--'" .~v

(

North Anna Units 1 and 2 3.7.1-1 Amendments 231/212

MSSVs 3.7.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.2 ---------NOTE---------

Only required in MODE 1.

Reduce the Power Range 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Neutron Flux-High reactor trip setpoint to less than or equal to the Maximum Allowable % RTP specified in Table 3.7.1-1 for the number of OPERABLE MSSVs.

C. Required Action and C.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND OR

- C.2 Be in MODE 4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months One or more steam generators with greater than or equal to 4 MSSVs inoperable.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.1.1 -------------------NOTE--------------------

Only required to be performed in MODES 1 and 2.

Verify each required MSSV lift setpoint per In accordance Table 3.7.1-2 in accordance with the with the Inservice Testing Program. Following Inservice testing, lift setting shall be within +/-1%. Testing Program North Anna Units 1 and 2 3.7.1-2 Amendments 231/212

MSSVs 3.7.1 Table 3.7.1-1 (page 1 of 1)

OPERABLE Main Steam Safety Valves versus Maximum Allowable Power NUMBER OF OPERABLE MSSVs MAXIMUM ALLOWABLE POWER PER STEAM GENERATOR % RTP 4

3 2 21 North Anna Units 1 and 2 3.7.1-3 Amendments 231/212

MSSVs 3.7.1 Table 3.7.1-2 (page 1 of 1)

Main Steam Safety Valve Lift Settings STEAM GENERATOR

1 #2 #3 LIFT SETTING Unit 1 VALVE NUMBER (psig +/- 3%)

MS-SV-101A MS-SV-101B MS-SV-101C 1085 MS-SV-102A MS-SV-102B MS-SV-102C 1095 MS-SV-103A MS-SV-103B MS-SV-103C 1110 MS-SV-104A MS-SV-104B MS-SV-104C 1120 MS-SV-105A MS-SV-105B MS-SV-105C 1135 Unit 2 VALVE NUMBER MS-SV-201A MS-SV-201B MS-SV-201C 1085 MS-SV-202A MS-SV-202B MS-SV-202C 1095 MS-SV-203A MS-SV-203B MS-SV-203C 1110 MS-SV-204A MS-SV-204B MS-SV-204C 1120 MS-SV-205A MS-SV-205B MS-SV-205C 1135 North Anna Units 1 and 2 3.7.1-4 Amendments 231/212

- NUCLEAR DESIGN INfORMATION PORTAL-MSSVs B 3.7.1 B 3.7 PLANT SYSTEMS B 3.7.1 Main Steam Safety Valves (MSSVs)

BASES BACKGROUND The primary purpose of the MSSVs is to provide overpressure protection for the secondary system. The MSSVs also provide protection against overpressurizing the reactor coolant pressure boundary (RCPB) by providing a heat sink for the removal of energy from the Reactor Coolant System (RCS) if the preferred heat sink, provided by the Condenser and Circulating Water System, is not available.

Five MSSVs are located on each main steam header, outside containment, upstream of the main steam isolation valves, as described in the UFSAR, Section 10.3.1 (Ref. 1). The MSSVs must have sufficient capacity to limit the secondary system pressure to ~ 110% of the steam generator design pressure in order to meet the requirements of the ASME Code,Section III (Ref. 2). The MSSV design includes staggered lift settings, according to Table 3.7.1-2 in the accompanying LCO, so that only the needed valves will actuate. Staggered lift settings reduce the potential for valve chattering that is due to steam pressure insufficient to fully open all valves following a turbine reactor trip. These lift settings are for ambient conditions of the valve associated with MODES 1, 2, and 3. This requires either that the valves be set hot or that a correlation between hot and cold settings be established.

APPLICABLE The design basis for the capacity of the MSSVs comes from SAFETY ANALYSES Reference 2 and its purpose is to limit the secondary system pressure to ~ 110% of design pressure for any anticipated operational occurrence (AOO) or accident considered in the Design Basis Accident (DBA) and transient analysis.

The events that challenge the relieving capacity of the MSSVs, and thus RCS pressure, are those characterized as decreased heat removal events, which are presented in the UFSAR, Section 15.2 (Ref. 3). Of these, the full power turbine trip without steam dump is typically the limiting AOO. This event also terminates normal feedwater flow to the steam generators.

(continued)

North Anna Units 1 and 2 B 3.7.1-1 Revision 8

MSSVs B 3.7.1 BASES APPLICABLE The safety analysis demonstrates that the transient response SAFETY ANALYSES for turbine trip occurring from full power without a direct (continued) reactor trip presents no hazard to the integrity of the RCS or the Main Steam System. One turbine trip analysis is performed assuming primary system pressure control via operation of the pressurizer relief valves and spray. This analysis demonstrates that the DNB design basis is met.

Another analysis is performed assuming no primary system pressure control, but crediting reactor trip on high pressurizer pressure and operation of the pressurizer safety valves. This analysis demonstrates that RCS integrity is maintained by showing that the maximum RCS pressure does not exceed 110% of the design pressure. All cases analyzed demonstrate that the MSSVs maintain Main Steam System integrity by limiting the maximum steam pressure to less than 110% of the steam generator design pressure.

In addition to the decreased heat removal events, reactivity insertion events may also challenge the relieving capacity of the MSSVs. The uncontrolled rod cluster control assembly (RCCA) bank withdrawal at power event is characterized by an increase in core power and steam generation rate until reactor trip occurs when either the Overtemperature ~T or Power Range Neutron Flux-High setpoint is reached. Steam flow to the turbine will not increase from its initial value for this event. The increased heat transfer to the secondary side causes an increase in steam pressure and may result in opening of the MSSVs prior to reactor trip, assuming no credit for operation of the atmospheric or condenser steam dump valves. The UFSAR Section 15.2 safety analysis of the RCCA bank withdrawal at power event for a range of initial core power levels demonstrates that the MSSVs are capable of preventing secondary side overpressurization for this AOO.

The UFSAR safety analyses discussed above assume that all of the MSSVs for each steam generator are OPERABLE. If there are inoperable MSSV(s), it is necessary to limit the primary system power during steady-state operation and AOOs to a value that does not result in exceeding the combined steam flow capacity of the turbine (if available) and the remaining OPERABLE MSSVs. The required limitation on primary system power necessary to prevent secondary system overpressurization may be determined by system transient analyses or conservatively arrived at by a simple heat balance calculation. In some circumstances it is necessary to limit the primary side heat generation that can be achieved during an AOO by reducing the setpoint of the Power Range Neutron Flux-High reactor trip function. For example, (continued)

North Anna Units 1 and 2 B 3.7.1-2 Revision 8

MSSVs B 3.7.1 BASES APPLICABLE if more than one MSSV on a single steam generator is SAFETY ANALYSES inoperable, an uncontrolled RCCA bank withdrawal at power (continued) event occurring from a partial power level may result in an increase in reactor power that exceeds the combined steam flow capacity of the turbine and the remaining OPERABLE MSSVs. Thus, for multiple inoperable MSSVs on the same steam generator it is necessary to prevent this power increase by lowering the Power Range Neutron Flux-High setpoint to an appropriate value. When Moderator Temperature Coefficient (MTC) is positive, the reactor power may increase above the initial value during an RCS heat up event (e.g., turbine trip). Thus, for any number of inoperable MSSVs it is necessary to reduce the trip setpoint if a positive MTC may exist at partial power conditions.

The MSSVs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO The accident analysis requires five MSSVs per steam generator be OPERABLE to provide overpressure protection for design basis transients occurring at 102% RTP. The LCO requires that five MSSVs per steam generator be OPERABLE in compliance with Reference 2, and the DBA analysis.

The OPERABILITY of the MSSVs is defined as the ability to open upon demand within the setpoint tolerances to relieve steam generator overpressure, and reseat when pressure has been reduced. The OPERABILITY of the MSSVs is determined by periodic surveillance testing in accordance with the Inservice Testing Program.

This LCO provides assurance that the MSSVs will perform their designed safety functions to mitigate the consequences of accidents that could result in a challenge to the RCPB or Main Steam System integrity.

APPLICABILITY In MODES 1, 2, and 3, five MSSVs per steam generator are required to be OPERABLE to prevent Main Steam System overpressurization.

In MODES 4 and 5, there are no credible transients requiring the MSSVs. The steam generators are not normally used for heat removal in MODES 5 and 6, and thus cannot be overpressurized; there is no requirement for the MSSVs to be OPERABLE in these MODES.

North Anna Units 1 and 2 B 3.7.1-3 Revision 8

- NUCLEAR DESIGN INFORMATION PORTAL-Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.8 Steam Generator (SG) Program

a. (continued) inspection results or by other means, prior to the plugging of tubes. Condition monitoring assessments shall be conducted during each outage during which the SG tubes are inspected or plugged to confirm that the performance criteria are being met.

b. Performance criteria for SG tube integrity. SG tube integrity shall be maintained by meeting the performance criteria for tube structural integrity, accident induced leakage, and operational LEAKAGE.

1. Structural integrity performance criterion: All in-service steam generator tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, and cool down and all anticipated transients included in the design specification) and design basis accidents. This includes retaining a safety factor of 3.0 against burst under normal steady state full power operation primary to secondary pressure differential and a safety factor of 1.4 against burst applied to the design basis accident primary to secondary pressure differentials. Apart from the above requirements, additional loading conditions associated with the design basis accidents, or combination of accidents in accordance with the design and licensing basis, shall also be evaluated to determine if the associated loads contribute significantly to burst or collapse. In the assessment of tube integrity, those loads that do significantly affect burst or collapse shall be determined and assessed in combination with the loads due to pressure with a safety factor of 1.2 on the combined primary loads and 1.0 on axial secondary loads.

2. Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Leakage is not to exceed 1 gpm for all SGs.

3. The operational LEAKAGE performance criterion is specified in LCD 3.4.13, "RCS Operational LEAKAGE."

North Anna Units 1 and 2 5.5-6 Amendments 248/228

SG Tube Integrity B 3.4.20 BASES LCO when the addition of such loads in the assessment of the (continued) structural integrity performance criterion could cause a lower structural limit or limiting burst/collapse condition to be established." For tube integrity evaluations, except for circumferential degradation, axial thermal loads are classified as secondary loads. For circumferential degradation, the classification of axial thermal loads as primary or secondary loads will be evaluated on a case-by-case basis. The division between primary and secondary classifications will be based on detailed analysis and/or testing.

Structural integrity requires that the primary membrane stress intensity in a tube not exceed the yield strength for all ASME Code,Section III, Service Level A (normal operating conditions) and Service Level B (upset or abnormal conditions) transients included in the design specification.

This includes safety factors and applicable design basis loads based on ASME Code,Section III, Subsection NB (Ref. 5) and Draft Regulatory Guide 1.121 (Ref. 6).

The accident induced leakage performance criterion ensures that the primary to secondary LEAKAGE caused by a design basis accident, other than a SGTR, is within the accident analysis assumptions. The accident analysis assumes that accident induced leakage does not exceed 1 gpm. The accident induced leakage rate includes any primary to secondary LEAKAGE existing prior to the accident in addition to primary to secondary LEAKAGE induced during the accident.

The operational LEAKAGE performance criterion provides an observable indication of SG tube conditions during plant operation. The limit on operational LEAKAGE is contained in LCO 3.4.13, "RCS Operational LEAKAGE," and limits primary to secondary LEAKAGE through anyone SG to 150 gallons per day.

This limit is based on the assumption that a single crack leaking this amount would not propagate to a SGTR under the stress conditions of a LOCA or a main steam line break. If this amount of LEAKAGE is due to more than one crack, the cracks are very small, and the above assumption is conservative.

APPLICABILITY SG tube integrity is challenged when the pressure differential across the tubes is large. Large differential pressures across SG tubes can only be experienced in MODE 1, 2, 3, or 4.

(continued)

North Anna Units 1 and 2 B 3.4.20-4 Revision 28

SG Tube Integrity B 3.4.20 BASES APPLICABILITY SG integrity limits are not provided in MODES 5 and 6 since (continued) RCS conditions are far less challenging than in MODES 5 and 6 than during MODES 1, 2, 3, and 4. In MODES 5 and 6, primary to secondary differential pressure is low, resulting in lower stresses and reduced potential for LEAKAGE.

ACTIONS The ACTIONS are modified by a Note clarifying that separate Conditions entry is permitted for each SG tube. This is acceptable because the Required Actions provide appropriate compensatory actions for each affected SG tube. Complying with the Required Actions may allow for continued operation, and subsequent affected SG tubes are governed by subsequent Condition entry and application of associated Required Actions.

A.1 and A.2 Condition A applies if it is discovered that one or more SG tubes examined in an inservice inspection satisfy the tube repair criteria but were not plugged in accordance with the Steam Generator Program as required by SR 3.4.20.2. An evaluation of SG tube integrity of the affected tube(s) must be made. Steam generator tube integrity is based on meeting the SG performance criteria described in the Steam Generator Program. The SG repair criteria define limits on SG tube degradation that allow for flaw growth between inspections while still providing assurance that the SG performance criteria will continue to be met. In order to determine if a SG tube that should have been plugged has tube integrity, an evaluation must be completed that demonstrates that the SG performance criteria will continue to be met until the next refueling outage or SG tube inspection. The tube integrity determination is based on the estimated condition of the tube at the time the situation is discovered and the estimated growth of the degradation prior to the next SG tube inspection. If it is determined that tube integrity is not being maintained, Condition B applies.

A Completion Time of 7 days is sufficient to complete the evaluation while minimizing the risk of plant operation with a SG tube that may not have tube integrity.

If the evaluation determines that the affected tube(s) have tube integrity, Required Action A.2 allows plant operation to continue until the next refueling outage or SG inspection provided the inspection interval continues to be supported (continued)

North Anna Units 1 and 2 B 3.4.20-5 Revision 28

STUDENT GUIDE FOR MAIN STEAM SYSTEM (23-A)

3. A main steam piping fault on the main steam distribution manifold is mitigated by automatic closure of the main steam trip valves.

3.3 Objective U 4113 List the technical specification requirements if the following conditions exist.

Main steam safety valve(s) fail during unit operation in modes 1, 2, and 3 (TS-3. 7.1)

Main steam trip valve(s) fail during unit operation in modes 1,2, and 3 (TS-3.7.2)

Maximum closing time for the main steam trip valves (TS-3.7.2)

Steam flow channel failure during unit operation in modes 1 and 2 (TS-3.3.1) or in mode 1, 2, or 3 (TS-3.3.2)

Steam pressure channel failure during unit operation in mode 1, 2, or 3 (TS-3.3.2)

First-stage pressure channel failure during unit operation in mode 1, 2, or 3 (TS-3.3.2)

Maximum temperature when either the primary or secondary pressure of a steam generator is < 200 psig (TRM-3.7.3) 3.3 Content

1. Main steam safety valves TS-3.7.1

2. Main Steam Trip Valves TS-3.7.2

3. Maximum closing time TS-3.7.2

4. Steam Flow Channel Failure TS-3.3.1 and 3.3.2

5. Steam Pressure Channel Failure TS-3.3.2 REACTOR OPERATOR Page 41 of 41 Revision 1, 10/11/2007

STUDENT GUIDE FOR MAIN STEAM SYSTEM (23-A)

6. First-Stage Pressure Channel Failure TS-3.3.2

7. When the temperature in the primary or secondary coolant in the steam generator is </=70°F, the pressure of both coolants shall be </+200 psig.

Topic.3.4Malnsteam* Line Code-Safety Valve Basis 3.4 Objective U 10084 State the basis for the operability of the main steam line code-safety valves.

3.4 Content

1. The technical specification basis for operability of the SG safety valves is to limit secondary pressure to within 110% of the system design pressure during the most severe anticipated system operational transient.

3.5 Objective U 10083 State the basis for the operability of the main steam trip valves.

3.5 Content

1. The technical specification basis for operability of the MSTVs is to ensure only one steam generator will blowdown during a main steam line rupture, therefore minimizing the positive reactivity effects of the RCS cooldown and limiting the containment pressure rise (don't take credit for operation of the NRVs).

REACTOR OPERATOR Page 42 of 42 Revision 1, 10/11/2007

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

85. 045-A2.17 085IBANKINAPS/H/3/SROINAPSII Given the following conditions:

Unit 1 is at 25% power.

The shift is raising power at 0.3% per minute lAW 1-0P-2.1, Unit Startup from Mode 2 to Mode 1.

The following alarms are received in succession:

EH FLUID RESERVOIR LOW LEVEL

EH FLUID RESERVOIR LOW-LOW LEVEL

HP FLUID PUMP LOCKOUT Which ONE of the following identifies the correct operator response?

A'! Go to 1-AP-2.1, Turbine Trip Without Reactor Trip Required; place the running EHC pump in PULL-TO-LOCK.

B. Verify the running EHC pump tripped; go to 1-AP-2.1, Turbine Trip Without Reactor Trip Required.

C. Verify the running EHC pump tripped; go to 1-E-0, Reactor Trip or Safety Injection.

D. Go to 1-E-0, Reactor Trip or Safety Injection; place the running EHC pump in PULL-TO-LOCK.

Feedback

a. Correct. Since power is below 30% a Reactor trip is not required provided steam dumps are available (which is the normal condition) although implied by the title "HP fluid pump lockout" the running EHC pump is not tripped so the operator is directed to place the running pump in PTL to prevent damage from loss of suction (previous to performing a design change the running pump DID trip, now function only prevents start of the standby pump, thus operators may rely on past knowledge and sellect an incorrect distractor).

b. Incorrect. Plausible since the candidate who does not have detailed systems knowledge may conclude that the running pump will trip; second part is correct as noted above.

c. Incorrect. First part is plausible as discussed in Distractor b; second part is plausible and would be corect if power level were higher or steam dumps were unavailable.

d. Incorrect. First part incorrect as discussed in Distractor c; second part is correct.

QUESTIONS REPORT for 2009 NRC SRO exam Validation 3 copy with SRC formatting - for submittal Notes Main Turbine Generator (MT/G) System Ability to (a) predict the impacts of the following malfunctions or operation on the MT/G system; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those malfunctions or operations: Malfunction of electrohydraulic control (CFR: 41.5/43.5 145.3/45.5)

Tier: 2 Group: 2 Importance Rating: 2.7/2.9 Technical

Reference:

1-AR-T-E3 Proposed references to be provided to applicants during examination: None Learning Objective:

Question History: bank but never used as of 8/20/2008 additional info:

VIRGINIA POWER l-EI-CB-l0T ANNUNCIATOR A4 l-AR-T-A4 NORTH ANNA POWER STATION REV. 3

~PPROVAL: ON FILE Effective Date:l0/13/07 EH FLUID RESERVOIR LOW-LEVEL 17.25" above bottom

(~ 7/8 on l-EH-LI-l02)

NOTE: Empty to Full on l-EH-LI-l02 corresponds to an actual level of 0" to 21" above the bottom of the EHC Reservoir.

1.0 Probable Cause 1.1 System integrity failure.

2.0 Operator Action 2.1 Verify tank level and locate source of leak.

2.2 Add oil to system until convenient to shutdown unit and repair leak, using 0-OP-40.2, EHC Reservoir Makeup.

3.0 References 3.1 W tech manual steam turbine 3.2 Unit 1 Loop Book, pg EH 002 3.3 DUR 88-098Y 3.4 11715-FM-l09A 3.5 LSK-1l-5 3.6 CR022115, Unit 1 EH Rsvr Lvl Indicator (1-EH-LI-l02) Reading Slightly High. (Rev 3)

.0 Actuation 4.1 l-EH-LS-l00

VIRGINIA POWER 1-EI-CB-10T ANNUNCIATOR F2 1-AR-T-F2 NORTH ANNA POWER STATION REV. 3 APPROVAL: ON FILE Effective Date:10/13/07 EH FLUID RESERVOIR LOW-LOW LEVEL 11.62" above bottom

(~ 3/4 on 1-EH-LI-I02)

NOTE: Empty to Full on 1-EH-LI-102 corresponds to an actual level of 0" to 21" above the bottom of the EHC Reservoir.

1.0 Probable Cause 1.1 Low level in reservoir.

1.2 System integrity failure.

2.0 Operator Action 2.1 Verify turbine load and control valve position.

2.2 Determine cause for loss of fluid.

2.3 Add oil to system using 0-OP-40.2, EHC Reservoir Makeup.

3.0 References 3.1 W tech manual steam turbine 3.2 11715-FM-109A 3.3 Unit 1 Loop Book, pg EH 003 3.4 DUR 88-098Z 3.5 LSK-1l-5 3.6 CR022115, Unit 1 EH Rsvr LvI Indicator (1-EH-LI-102) Reading Slightly High. (Rev 3)

.0 Actuation 4.1 1-EH-LS-101

VIRGINIA POWER 1-EI-CB-10T ANNUNCIATOR E3 1-AR-T-E3 NORTH ANNA POWER STATION REV. 4 ZiPPROVAL: ON FILE Effective Date:10/13/07 HP FLUID PUMP LOCKOUT 7.62" from bottom

(~ 1/2 on 1-EH-LI-102)

NOTE: Empty to Full on 1-EH-LI-102 corresponds to an actual level of 0" to 21" above the bottom of the EHC Reservoir.

1.0 Probable Cause 1.1 EH fluid reservoir extreme low level.

1.2 System integrity failure.

2.0 Operator Action NOTE: This Alarm prevents the starting of an EHC Pump. Any running EHC Pump will continue to run. There is no auto trip¢o~ the turbine 2.1 OR running EHC Pump due to inadequate EHC level.

Check EHC Reservoir Level - NORMAL:

IF level is normal, THEN GO TO Step 2.4

IF level is NOT normal, THEN GO TO Step 2.2 2.2 IF Turbine is latched, THEN do one of the following while continuing with this procedure.

A",..J...".,~v-h.rr a) IF power >30%, THEN GO TO~~E~O, Reactor Trip or Safety Injection.

b) IF <30% power, THEN GO TO 1-AP-2.1,Turbine Trip Without Reactor Trip Required. l'!.--O~r-ec1-2.3 IF level is decreasing as confirmed by other Annunciators (Low Level,

~~~Lo/Lo.Level), THEN to prevent pump damage place the running EHC ~~

Pump ~n P:!-L. (p y- .. -e.,.,c.....~

NOTE: Lockout relay must be manually reset to restart any EHC Pump.

2.4 Determine cause, and submit a Work Request and Deviation Report as necessary.

2.5 Reset manual reset lockout relay. (behind Control Board) 2.6 Return EH system to normal.

3.0 References 3.1 11715-FM-109A 3.2 W tech manual steam turbine 3.3 Unit 1 Loop Book, pg EH 002 3.4 LSK-11-5 3.5 DUR 88-098Y 3.6 DCP 95-220, Modification of EHC Low Fluid Trip 3.7 CR022115, Unit 1 EH Rsvr Lvl Indicator (1-EH-LI-102) Reading Slightly High. (Rev 4)

'.0 Actuation 4.1 1-EH-LS-100

STUDENT GUIDE FOR ELECTRO-HYDRAULIC CONTROL SYSTEM (31)

Electro-hydraulic Control Pumps To.pici3.fEHCPump$.**.**.

3.1 Objective U 1771 Explain the following concepts associated with the electro-hydraulic control pumps.

Purpose

Where the pumps take a suction

Interlocks associated with automatic pump start

Interlocks associated with automatic pump trip 3.1 Content

1. The EHC pumps provide the motive force for circulating the EHC fluid through the system.

(

2. The EHC pumps take suction from the EHC reservoir.

3. The EHC pumps will automatically start on a low EHC discharge pressure of 1400 psig as long as they are not locked out by a reservoir level of 7.62 inches (HP FLUID PUMP LOCKOUT alarm).

4. EHC pumps will trip on motor overload.

Topic3~2EI-IC.Pump . Reset 3.2 Objective U 10147 Describe the method for resetting the electro-hydraulic control pumps following an automatic lockout.

REACTOR OPERATOR Page 9 of 9 Revision 3, 09/20/2007

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91)

(

Evaluating Plant Conditions Using Reactivity Event Abnormal Procedures 5.1 Objective U 14308 Evaluate a set of plant conditions associated with reactivity event abnormal procedures in light of the following issues (AP-1.1, AP-1.2, AP-1.3, AP-2.1, AP-2.2).

Procedure entry conditions

Major action categories

Step bases

Proper procedure usage 5.1 Content

This objective has "NO" content

Integrated system knowledge will be required to answer any questions linked to this objective REACTOR OPERATOR Page 26 of 158 Revision 30, 11/06/2008

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

86. 054-AG2.1.27 086INEW/1H/3/SRO///

Given the following conditions:

Unit shutdown was in progress for scheduled refueling.

Power was held, and the unit has been stabilized at 40% because the "A" MFRV did not appear to be responding to decreasing controller demand.

Local inspection revealed that "A" MFRV is mechanically bound, and is NOT capable of closing.

Based on these plant conditions, which ONE of the following completes the statement to identify the safety-related function that is not met, and the associated Technical Specification required action?

The "A" MFRV is NOT capable of providing isolation _ _ _ _ . TS-required action is to _ _ __

A. following a reactor trip to prevent an uncontrolled RCS cooldown; enter information-only action for "A" MFRV.

B. following a high-energy line break on the "A" SG secondary side; enter information-only action for "A" MFRV.

C. following a reactor trip to prevent an uncontrolled RCS cooldown; close OR isolate "A" MFRV within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

D~ following a high-energy line break on the "A" SG secondary side; close OR isolate "A" MFRV within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

Feedback

a. Incorrect. Plausible since this would be a logical concern but the stem specifically elicits the safety related function so this is incorrect; second part is plausible since redundancy is provided by the MFIV, however since single failure is lost?tech specs require action within -72 hours.

b. Incorrect. First part is correct regarding the safety related function discussed in the TS basis and UFSAR. Second part is incorrect as discussed in distractor A.

c. Incorrect. First part is incorrect as discussed in distractor A. Second part is correct as discussed in distractor A.

d. Correct. As previously discussed the safety related function is correct and the given action to close or isolate the subject valve is also correct.

QUESTIONS REPORT for 2009 NRC SRO exam Validation 3 copy with SRC formatting - for submittal Notes Loss of Main Feedwater (MFW)

Knowledge of system purpose and/or function.

(CFR: 41.7)

Tier: 1 Group: 1 Importance Rating: 3.9/4.0 Technical

Reference:

Technical Specification 3.7.3 and basis Proposed references to be provided to applicants during examination: None Learning Objective:

Question History: new additional info: The KA did not seem to be a logical tie since it related system function to an APE; discussed with USNRC on 9/4/2008 for clarification. Writing a question on a component within the feedwater system and relating it to safety related function and technical specification actions tests SRO level knowledge at the appropriate discriminatory level and satisfies the KA.

MFIVs, MFPDVs, MFRVs, and MFRBVs 3.7.3 3.7 PLANT SYSTEMS 3.7.3 Main Feedwater Isolation Valves (MFIVs), Main Feedwater Pump Discharge Valves (MFPDVs), Main Feedwater Regulating Valves (MFRVs), and Main Feedwater Regulating Bypass Valves (MFRBVs)

LCO 3.7.3 Three MFIVs, three MFPDVs, three MFRVs, and three MFRBVs shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3 except when MFIV, MFPDV, MFRV, or MFRBV is closed and de-activated or isolated by a closed manual valve.

ACTIONS

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

Separate Condition entry is allowed for each valve.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more MFIVs A.1 Close or isolate MFIV. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months inoperable.

AND A.2 Verify MFIV is closed Once per 7 days or isolated.

B. One or more MFRVs B.1 Close or isolate MFRV. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months inoperable.

AND B.2 Verify MFRV is closed Once per 7 days or isolated.

C. One or more MFRBVs C.1 Close or isolate 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months inoperable. MFRBV.

AND C.2 Verify MFRBV is closed Once per 7 days or isolated.

North Anna Units 1 and 2 3.7.3-1 Amendments 231/212

MFIVs, MFPDVs, MFRVs, and MFRBVs 3.7.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. One or more MFPDV 0.1 Close or isolate 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months inoperable. MFPDV.

AND 0.2 Verify MFPDV is closed Once per 7 days or isolated.

E. Two valves in the same E.1 Isolate affected flow 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months flow path inoperable. path.

F. Required Action and F.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND F.2 Be in MODE 4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

(

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.3.1 Verify the isolation time of each MFIV, In accordance MFRV, and MFRBV is ~ 6.98 seconds and the with the isolation time of each MFPDV is Inservice

~ 60 seconds. Testing Program SR 3.7.3.2 Verify each MFIV, MFPDV, MFRV, and MFRBV 18 months actuates to the isolation position on an actual or simulated actuation signal.

North Anna Units 1 and 2 3.7.3-2 Amendments 231/212

MFIVs, MFPDVs, MFRVs, and MFRBVs B 3.7.3 B 3.7 PLANT SYSTEMS B 3.7.3 Main Feedwater Isolation Valves (MFIVs), Main Feedwater Pump Discharge Valves (MFPDVs), Main Feedwater Regulating Valves (MFRVs),

and Main Feedwater Regulating Bypass Valves (MFRBVs)

BASES BACKGROUND The MFIV and the MFRV are in series in the Main Feedwater (MFW) line upstream of each steam generator. The MFRBV is parallel to both the MFIV and the MFRV. The MFPDV is located at the discharge of each main feedwater pump. The valves are located outside of the containment. These valves provide the isolation of each MFW line by the closure of the MFIV and MFRBV, the MFRV and MFRBV, or the closure of the MFPDV. To provide the needed isolation given the single failure of one of the valves, all four valve types are required to be OPERABLE. The MFIVs and the MFRVs provide single failure protection for each other in one flow path and the MFPDVs and the MFRBVs provide single failure protection for each other in the other flow path.

The safety-related function of the MFIVs, MFPDVs, MFRVs and the MFRBVs is to provide isolation of MFW from the secondary side of the steam generators following a high energy line break. Closure of the MFIV and MFRBV, the MFRV and MFRBV, or the closure of the MFPDV terminates the addition of feedwater to an affected steam generator, limiting the mass and energy release for steam or feedwater line breaks and minimizing the positive reactivity effects of the Reactor Coolant System (RCS) cool down associated with the blowdown.

In the event of pipe rupture inside the containment, the valves limit the quantity of high energy fluid that enters the containment through the broken loop.

The containment isolation MFW check valve in each loop provides the first pressure boundary for the addition of Auxiliary Feedwater (AFW) to the intact loops and prevents back flow in the feedwater line should a break occur upstream of these valves. These check valves also isolate the non-safety-related portion of the MFW system from the safety-related portion of the system. The piping volume from the feedwater isolation valve to the steam generators is considered in calculating mass and energy release following either a steam or feedwater line break.

(continued)

North Anna Units 1 and 2 B 3.7.3-1 Revision 23

- NUCLEAR DESIGN INFORMATION PORTAL-MFIVs, MFPDVs, MFRVs, and MFRBVs B 3.7.3 BASES BACKGROUND The MFIVs, MFPDVs, MFRVs, and MFRBVs close on receipt of (continued) Safety Injection or Steam Generator Water Level-High High signal. The MFIVs, MFPDVs, MFRVs, and MFRBVs may also be actuated manually.

A description of the operation of the MFIVs, MFPDVs, MFRVs, and MFRBVs is found in the UFSAR, Section 10.4.3 (Ref. 1).

APPLICABLE The design basis for the closure of the MFIVs, MFPDVs, MFRVs, SAFETY ANALYSES and MFRBVs is established by the analyses for the Main Steam Line Break (MSLB). It is also influenced by the accident analysis for the Feedwater Line Break (FWLB). Closure of the MFIVs and MFRBVs, or MFRVs and MFRBVs, or the MFPDVs, may also be relied on to terminate an MSLB on receipt of an SI signal for core response analysis and for an excess feedwater event upon the receipt of a Steam Generator Water Level-High High signal.

Failure of an MFIV and MFRV, or an MFRBV and MFPDV to close following an MSLB or FWLB can result in additional mass and energy being delivered to the steam generators, contributing to cooldown. This failure also results in additional mass and energy releases following an MSLB or FWLB event.

The MFIVs, MFPDVs, MFRVs, and MFRBVs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO This LCO ensures that the MFIVs, MFPDVs, MFRVs, and MFRBVs will isolate MFW flow to the steam generators, following an FWLB or MSLB.

This LCO requires that three MFIVs, three MFPDVs, three MFRVs, and three MFRBVs be OPERABLE. The valves are considered OPERABLE when isolation times are within limits and they close on an isolation actuation signal. The MFIVs and the MFRVs provide single failure protection for each other, and the MFPDV and the MFRBV provide single failure protection for each other.

Failure to meet the LCO requirements can result in additional mass and energy being released to containment following an MSLB or FWLB inside containment. A feedwater isolation signal on high high steam generator level is relied on to terminate an excess feedwater flow event, and failure to meet the LCO may result in the introduction of water into the main steam lines.

(continued)

North Anna Units 1 and 2 B 3.7.3-2 Revision 23

MFIVs, MFPDVs, MFRVs, and MFRBVs B 3.7.3 BASES APPLICABILITY The MFIVs, MFPDVs, MFRVs, and MFRBVs must be OPERABLE whenever there is significant mass and energy in the RCS and steam generators. In MODES 1, 2, and 3, the MFIVs, MFPDVs, MFRVs, and MFRBVs are required to be OPERABLE to limit the amount of available fluid that could be added to containment in the case of a secondary system pipe break inside containment. When the valves are closed and de-activated or isolated by a closed manual valve, they are already performing their safety function.

In MODES 4, 5, and 6, steam generator energy is low.

Therefore, the MFIVs, MFPDVs, MFRVs, and MFRBVs are not required to be OPERABLE.

ACTIONS The ACTIONS table is modified by a Note indicating that separate Condition entry is allowed for each valve.

A.1 and A.2 With one MFIV in one or more flow paths inoperable, action must be taken to restore the affected valves to OPERABLE status, or to close or isolate inoperable affected valves within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . When these valves are closed or isolated, they are performing their required safety function.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the redundancy afforded by the remaining OPERABLE valves and the low probability of an event occurring during this time period that would require isolation of the MFW flow paths.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable, based on operating experience.

Inoperable MFIVs that are closed or isolated must be verified on a periodic basis that they are closed or isolated. This is necessary to ensure that the assumptions in the safety analysis remain valid. The 7 day Completion Time is reasonable, based on engineering judgment, in view of other administrative controls, to ensure that these valves are closed or isolated.

B.1 and B.2 With one MFRV in one or more flow paths inoperable, action must be taken to restore the affected valves to OPERABLE status, or to close or isolate inoperable affected valves within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . When these valves are closed or isolated, they are performing their required safety function.

(continued)

North Anna Units 1 and 2 B 3.7.3-3 Revision 23

MFIVs, MFPDVs, MFRVs, and MFRBVs B 3.7.3 BASES ACTIONS B.1 and B.2 (continued)

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the redundancy afforded by the remaining OPERABLE valves and the low probability of an event occurring during this time period that would require isolation of the MFW flow paths.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable, based on operating experience.

Inoperable MFRVs, that are closed or isolated, must be verified on a periodic basis that they are closed or isolated. This is necessary to ensure that the assumptions in the safety analysis remain valid. The 7 day Completion Time is reasonable, based on engineering judgment, in view of other administrative controls to ensure that the valves are closed or isolated.

C.1 and C.2 With one MFRBV in one or more flow paths inoperable, action must be taken to restore the affected valves to OPERABLE status, or to close or isolate inoperable affected valves within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . When these valves are closed or isolated, they are performing their required safety function.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the redundancy afforded by the remaining OPERABLE valves and the low probability of an event occurring during this time period that would require isolation of the MFW flow paths.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable, based on operating experience.

Inoperable MFRBVs that are closed or isolated must be verified on a periodic basis that they are closed or isolated. This is necessary to ensure that the assumptions in the safety analysis remain valid. The 7 day Completion Time is reasonable, based on engineering judgment, in view of other administrative controls to ensure that these valves are closed or isolated.

D.1 and D.2 With one MFPDV in one or more flow paths inoperable, action must be taken to restore the affected valves to OPERABLE status, or to close or isolate inoperable affected valves within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . When these valves are closed or isolated, they are performing their required safety function.

(continued) l North Anna Units 1 and 2 B 3.7.3-4 Revision 23

- NUCLEAR DESIGN INFORMATION PORTAL-MFIVs, MFPDVs, MFRVs, and MFRBVs B 3.7.3 BASES ACTIONS D.1 and D.2 (continued)

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the redundancy afforded by the remaining OPERABLE valves and the low probability of an event occurring during this time period that would require isolation of the MFW flow paths.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable, based on operating experience.

Inoperable MFPDVs that are closed or isolated must be verified on a periodic basis that they are closed or isolated. This is necessary to ensure that the assumptions in the safety analysis remain valid. The 7 day Completion Time is reasonable, based on engineering judgment, and in view of other administrative controls, to ensure that these valves are closed or isolated.

E.1 With two inoperable valves in the same flow path, there may be no redundant system to operate automatically and perform the required safety function. For example, either a MFIV and a MFRV in the same main feedwater line are inoperable or a MFPDV and a MFRBV are inoperable. Under these conditions, at least one of the affected valves must be restored to OPERABLE status, or the affected flow path isolated within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

This action returns the system to the condition where at least one valve in each flow path is performing the required safety function. The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is reasonable, based on operating experience, to complete the actions required to close the affected valves, or otherwise isolate the affected flow path.

F.1 and F.2 If the inoperable valve(s) cannot be restored to OPERABLE status, or closed, or isolated 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 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and in MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

North Anna Units 1 and 2 B 3.7.3-5 Revision 23

- NUCLEAR DESIGN INFORMATION PORTAL-MFIVs, MFPDVs, MFRVs, and MFRBVs B 3.7.3 BASES SURVEILLANCE SR 3.7.3.1 REQUIREMENTS This SR verifies that the isolation time of each MFIV, MFRV, and MFRBV is ~ 6.98 seconds and the isolation time for each MFPDV is ~ 60 seconds. The isolation times are assumed in the accident and containment analyses. This Surveillance is normally performed during a refueling outage.

The Frequency for this SR is in accordance with the Inservice Testing Program.

SR 3.7.3.2 This SR verifies that each MFIV, MFRV, MFRBV, and MFPDV can close on an actual or simulated actuation signal. This Surveillance is normally performed upon returning the plant to operation following a refueling outage.

The Frequency for this SR is every 18 months. The 18 month Frequency for testing is based on the refueling cycle.

Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, this Frequency is acceptable from a reliability standpoint.

REFERENCES 1. UFSAR, Section 10.4.7.

North Anna Units 1 and 2 B 3.7.3-6 Revision 0

- NUCLEAR DESIGN INFORMATION PORTAL-ESFAS Instrumentation B 3.3.2

( BASES APPLICABLE 8. Engineered Safety Feature Actuation System Interlocks SAFETY ANALYSES, LCO, To allow some flexibility in unit operations, several AND interlocks are included as part of the ESFAS. These APPLICABILITY interlocks permit the operator to block some signals, (continued) automatically enable other signals, prevent some actions from occurring, and cause other actions to occur. The interlock Functions back up manual actions to ensure bypassable functions are in operation under the conditions assumed in the safety anal a.

The P-4 int lock is enabled when a reactor trip breaker B) and its associated bypass breaker are ope ce the P-4 interlock is enabled, automatic SI lnitiation is blocked after a 60 second time delay.

This Function allows operators to take manual control of SI systems after the initial phase of injection is complete. Once SI is blocked, automatic actuation of SI cannot occur until the RTBs have been manually closed, resetting the P-4 interlock. The functions of the P-4 interlock are:

Function Purpose Required MODES Feedwater 1, 2 isolation Trip the main Prevents excess i ve 1, 2 turbine cool down, thereby Condition II event does not propagate to Condition III event (continued)

North Anna Units 1 and 2 B 3.3.2-30 Revision 31

DESIGN ESFAS Instrumentation B 3.3.2 BASES APPLICABLE 8. Engineered Safety Feature Actuation System Interlocks SAFETY (continued)

ANALYSES, LCO, AND a. Engineered Safety Feature Actuation System APPLI CAB I LITY Interlocks-Reactor Trip, P-4 (continued)

Function Purpose Required MODES Prevent automatic Allows alignment 1, 2, 3 reactuation of SI of ECCS for after a manual recirculation reset of SI mode, prevents subsequent inadvertent alignment to injection mode by auto SI (continued)

North Anna Units 1 and 2 B 3.3.2-31 Revision 31

STUDENT GUIDE FOR MAIN FEEDWATER SYSTEM (26-A)

(

4.2. This results in less fast neutrons leaking from the core and less neutrons reaching the excore nuclear instrumentation detectors.

5. Actual reactor power will increase.

5.1. The increase in moderator density will increase the number of neutrons reaching thermal energy levels.

5.2. As a result, more fissions will occur and actual reactor power will increase.

6. With the high-pressure feed heater removed from service, the flow path from the main feedwater pumps will be limited.

6.1. This restriction in feedwater flow will cause a reduction in steam generator level.

6.2. In order to compensate for this level decrease, the main feedwater regulating valves will open to reestablish program steam generator levels.

6.3. The feedwater regulating valves will have to open more to match steam flow with feed flow once program steam generator level is attained.

3.6 Objective U 11989 Given a set of plant conditions, evaluate Main Feedwater 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 main feedwater 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 REACTOR OPERATOR Page 27 of 33 Revision 3, 10109/2008

STUDENT GUIDE FOR MAIN FEEDWATER SYSTEM (26-A) 3.6 Content

This objective has "NO" content.

Integrated system knowledge will be required to answer any questions linked to this objective.

(

REACTOR OPERATOR Page 28 of 33 Revision 3, 10109/2008

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

87. 055-EA2.03 087INEWIIH/3/SROIII Given the following conditions:

Unit 1 was initially at 100% power with 1H EDG tagged out for voltage regulator replacement.

A loss of offsite power occurred, and 1J EDG tripped on overs peed and cannot be restarted.

Letdown automatically isolated due to decreasing PRZR level, and PRZR level is still slowly decreasing.

The crew is performing 1-ECA-0.0, Loss of All AC Power.

Based on these plant conditions, which ONE of the following identifies the procedure used to restore power, and the recovery actions once power is restored?

A. Use 0-OP-6.4, Operation of the SBO Diesel to energize an Emergency Bus; Following power restoration, manually actuate Safety Injection and go to 1-ECA-0.2, Loss of All AC Power with SI Required.

B. Use 0-AP-10, Loss of Electrical Power to energize an Emergency Bus; Following power restoration, manually actuate Safety Injection and go to 1-ECA-0.2, Loss of All AC Power with SI Required.

C'!'" Use 0-OP-6.4, Operation of the SBO Diesel to energize an Emergency Bus; Following power restoration, go to 1-ECA-0.2, Loss of All AC Power with SI Required and manually load required equipment.

D. Use 0-AP-10, Loss of Electrical Power to energize an Emergency Bus; Following power restoration, go to 1-ECA-0.2, Loss of All AC Power with SI Required and manually load required equipment.

Feedback

a. Incorrect. First part is correct. Second part is plausible since conditions exist that would normally require manual SI initiation, this is not correct in this case however since ECA-O.O does not have Si initiaition criteria because controlled loading of equipment is preferred so as not to jeopardize the only source of power to the unit.

b. Incorrect. First part is incorrect but plausible, use of 0-AP-1 0 is required by ECA-O.O to perform other actions required as a result of losing offsite power. For events where one bus is powered it would provide guidance to restore power to the de-energized bus, however for the SBO event 0-OP-6.4 performs that function; second part is incorrect but plausible as discussed in Distractor a.

c. Correct. 0-OP-6.4 is the correct procedure for restoring power; second part is also correct for reason given in Distractor a.

d. Incorrect. First part is incorrect as discussed in Distractor b; second part is correct for reason given in Distractor a.

QUESTIONS REPORT for 2009 NRC SRO exam Validation 3 copy with SRC formatting - for submittal Notes Loss of Offsite and Onsite Power (Station Blackout)

Ability to determine or interpret the following as they apply to a Station Blackout: Actions necessary to restore power (CFR 43.5 / 45.13)

Tier: 1 Group: 1 Importance Rating: 3.9/4.7 Technical

Reference:

1-ECA-O.O, O-AP-10, O-OP-6.4 Proposed references to be provided to applicants during examination: None Learning Objective:

Question History: new Associated objective(s):

additional info: Two part question to expand on KA; the SRO should know the importance of NOT taking certain actions that could jeopardize the power supply, as well as the procedure used to restore power.

/:

Dominion' NORTH ANNA POWER STATION EMERGENCY CONTINGENCY ACTION NUMBER PROCEDURE TITLE REVISION 22 1-ECA-O.O LOSS OF ALL AC POWER PAGE (WITH FOUR ATTACHMENTS) 1 of 22 PURPOSE To provide instructions to follow when both Unit 1 Emergency Busses are de-energized.

ENTRY CONDITIONS This procedure is entered from:

1-E-O, REACTOR TRIP OR SAFETY INJECTION,

O-AP-10, LOSS OF ELECTRICAL POWER, or

By direction of SRO.

CONTINUOUS USE

NUMBER PROCEDURE TITLE REVISION 22 1-ECA-O.O LOSS OF ALL AC POWER PAGE 2 of 22 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED 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).

CSF Status Trees should be monitored for information only. FRs should not be implemented.

1 1- VERIFY REACTOR TRIP: D !E. Reactor will NOT trip, THEN verify automatic control rod insertion.

D a) Manually Trip Reactor D IF NOT, THEN manually insert control rods.

b) Check the following:

D

Reactor Trip and Bypass Breakers -

OPEN D

Rod Bottom Lights - LIT D

Neutron flux - DECREASING 2 ]_ VERIFY TURBINE TRIP:

D a) Manually Trip Turbine D b) Verify all Turbine Stop Valves - CLOSED D b) Put both EHC Pumps in PTL.

D !E. Turbine is still NOT tripped, THEN manually run back Turbine.

D !E. Turbine cannot be run back, THEN close MSTVs and Bypass Valves.

D c) Reset Reheaters D d) Verify Generator Output Breaker - OPEN D d) !E. Generator Output Breakers do NOT open after 30 seconds, THEN manually open G-12 AND Exciter Field Breaker.

NUMBER PROCEDURE TITLE REVISION 22 1-ECA-O.O LOSS OF ALL AC POWER PAGE 3 of 22 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

3. STOP ALL RCPs G- TRY TO RESTORE POWER TO 1 H (1 J) 4160-VOLT EMERGENCY BUS:

o a) Verify 1H (1 J) Emergency Diesel o a) Attempt to start 1H (1J) Emergency Generator - RUNNING Diesel Generator by completing ATTACHMENT 4, ATTEMPTING TO RESTORE POWER TO 1H (1J)

EMERGENCY BUS.

o WHEN ATTACHMENT 4, Step 2 complete, THEN perform Step 4b.

( o Continue with Step 5.

o b) Verify 1H (1 J) 4160-Volt Emergency Bus - o b) Attempt to energize 1H (1J) Emergency ENERGIZED Bus by completing ATTACHMENT 4, ATTEMPTING TO RESTORE POWER TO 1H (1J) EMERGENCY BUS.

o Continue with Step 5.

NUMBER PROCEDURE TITLE REVISION 22 1-ECA-O.O LOSS OF ALL AC POWER PAGE 4 of 22 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

5. VERIFY RCS ISOLATION:

o a) PRZR PORVs - CLOSED o a) !E PRZR pressure is less than 2335 psig, THEN manually close PORVs.

b) Letdown Isolation Valves - CLOSED: o b) Manually close valves.

o

1-CH-HCV-1200A o . 1-CH-HCV-1200B o

1-CH-HCV-1200C o

1-CH-LCV-1460A o

1-CH-LCV-1460B c) Excess Letdown Isolation Valves - o c) Manually close valves.

CLOSED:

o

1-CH-HCV-1201 o

1-CH-HCV-1137 o d) 1-CH-HCV-1142, RHR System to Letdown o d) Manually close valve.

Isolation Valve - CLOSED (STEP 5 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 22 1-ECA-O.O LOSS OF ALL AC POWER PAGE 5 of 22 ACTION! EXPECTED RESPONSE RESPONSE NOT OBTAINED

5. VERIFY RCS ISOLATION: (Continued) e) RCS Sample Valves - CLOSED: 0 e) Manually close valves.

0

1-SS-TV-1 OOA 0

1-SS-TV-101A 0

1-SS-TV-1 02A 0

1-SS-TV-1 03A 0

1-SS-TV-1 06A 0

1-SS-TV-1 OOB 0

1-SS-TV-101B 0

1-SS-TV-1 02B 0

1-SS-TV-1 03B 0

1-SS-TV-1 06B f) Reactor Vent Valves - CLOSED: 0 f) Manually close valves.

0

1-RC-SOV-1 01 A-1 0

1-RC-SOV-101A-2 0

1-RC-SOV-1 01 B-1 0

1-RC-SOV-101 B-2 g) PRZR Vent Valves - CLOSED: 0 g) Manually close valves.

0

1-RC-SOV-102A-1 0

1-RC-SOV-102A-2 0

1-RC-SOV-102B-1 0

1-RC-SOV-102B-2

NUMBER PROCEDURE TITLE REVISION 22 1-ECA-O.O LOSS OF ALL AC POWER PAGE 6 of 22 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

6. VERIFY AFW FLOW - GREATER THAN Do the following:

340 GPM a) Open Turbine-Driven AFW Pump Steam Supply Valves:

o

1-MS-TV-111A o

1-MS-TV-111B o b) IF AFW flow is still less than 340 gpm, THEN locally open 1-FW-MOV-100D, Turbine-Driven AFW Pump Discharge Valve.

7. CHECK IF APPENDIX R FIRE IN UNIT 1 o GO TO Step 9.

EMERGENCY SWITCHGEAR ROOM EXISTS o

Emergency Switchgear Room has become inoperable due to fire OR o

Safe Shutdown equipment is threatened by fire 8._ GO TO 1-FCA-2, EMERGENCY SWITCHGEAR ROOM FIRE

NUMBER PROCEDURE TITLE REVISION 22 1-ECA-O.O LOSS OF ALL AC POWER PAGE 7 of 22 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED 0)_ VERIFY POWER TO 1H (1J) 4160-VOLT EMERGENCY BUS - RESTORED:

D a) Verify 1H (1J) Emergency Diesel D a) Continue attempts to start 1H (1 J)

Generator - RUNNING Emergency Diesel Generator using ATTACHMENT 4, Step 2 before continuing with Step 9b.

D IF at least one EDG can NOT be started, THEN GO TO Step 10.

D b) Verify 1H (1J) 4160-Volt Emergency Bus- D b) Continue attempts to energize 1H (1J)

ENERGIZED Emergency Bus using ATTACHMENT 4, Step 3 before continuing with Step 9c.

D IF at least one Emergency Bus can NOT be energized, TH EN GO TO Step 10.

D c) Check 1H (1 J) Emergency Bus voltage D c) Place 1H (1 J) EDG MOP Defeat switch to and frequency - NORMAL MANUAL and control voltage and frequency within normal range.

D !E EDG voltage AND frequency cannot be controlled as required, THEN GO TO Step 10.

D 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:

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

@_INITIATEATTACHMENT3TOLOCALLY ISOLATE RCP SEALS

NUMBER PROCEDURE TITLE REVISION 22 1-ECA-O.O LOSS OF ALL AC POWER PAGE 90f22 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

12. DETERMINE IF SBO DIESEL GENERATOR IS AVAILABLE:

o a) Verify Unit 2 Annunciator Panel "F"-G5, o a) GO TO Step 13.

AAC DIESEL GENERATOR RUNNING, is LIT o b) Initiate use of SBO Diesel Generator using 0-OP-6.4, OPERATION OF THE SBO DIESEL (SBO EVENT), while continuing with this procedure 13._ INITIATE 0-AP-10, LOSS OF ELECTRICAL POWER, TO RESTORE AC POWER

14. INITIATE ATTACHMENT 2 TO LOCALLY PERFORM TURBINE BUILDING OPERATIONS

15. CHECK SG STATUS: o Manually close valves.

o

MSTVs and Bypass Valves - CLOSED o

Main Feed Reg Valves - CLOSED o

Main Feed Reg Bypass Valves -

CLOSED o

SG Blowdown Valves - CLOSED

16. CHECK SGs - NOT FAULTED: o Initiate ATTACHMENT 1 to isolate any faulted SGs.

o

All SG pressures - GREATER THAN 80 PSIG o

All SG pressures - UNDER CONTROL OF OPERATOR

NUMBER PROCEDURE TITLE REVISION 22 1-ECA-O.O LOSS OF ALL AC POWER PAGE 19 of 22 ACTION I 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 * !E 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-101A 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.

NUMBER PROCEDURE TITLE REVISION 22 1-ECA-O.O LOSS OF ALL AC POWER PAGE 22 of 22 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

_ DETERMINE RECOVERY METHOD:

D a) Check RCS subcooling based on Core Exit D a) GO TO 1-ECA-O.2, LOSS OF ALL AC TCs - GREATER THAN 25°F [75°F] POWER RECOVERY WITH SI REQUIRED, STEP 1.

D b) Check PRZR level- GREATER THAN D b) GO TO 1-ECA-O.2, LOSS OF ALL AC 21% [26%] POWER RECOVERY WITH SI REQUIRED, STEP 1.

c) Check SI equipment status: D c) GO TO 1-ECA-O.2, LOSS OF ALL AC POWER RECOVERY WITH SI D

SI equipment - HAS REMAINED REQUIRED, STEP 1.

SECURED UPON AC POWER RESTORATION D

SI flow - ISOLATED D d) GO TO 1-ECA-O.1, LOSS OF ALL AC POWER RECOVERY WITHOUT SI REQUIRED, STEP 1.

- END-

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:

D 1) GROUP DISP MENU D 2) MOTOR TEMP INFORMATION D 3) RC - REACTOR COOLANT b) Monitor Seal Water Outlet Temp for all RCPs.

c) IF any RCP 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:

D a. Place Unit 1 Charging pumps in PTL, prior to continuing power restoration.

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

D a. Ensure ATTACHMENT 3, RCP SEAL ISOLATION is complete.

D b. Start Unit 1 Charging Pumps, as required.

(

NUMBER ATTACHMENT TITLE ATTACHMENT 1-ECA-O.O 4 ATTEMPTING TO RESTORE POWER TO 1H (1J) EMERGENCY BUS REVISION PAGE 22 2 of 3

2. IF attempting to start 1H (1 J) Emergency Diesel Generator, THEN do the following:

_ a) Place 1H (1J) EDG Mode Selector switch to MANUAL-LOCAL.

_ b) Push Emer Gen 1H (1J) Alarm & Shutdown Reset button.

_ c) Verify 1H (1 J) Shutdown Relay Status Light is LIT.

_ d) IF neither 1 H nor 1J Shutdown Relay Status Light is LIT, THEN GO TO 1-ECA-O.O, LOSS OF ALL AC POWER, Step in effect.

_ e) Wait 1 minute.

f) WHEN one minute has elapsed, THEN do the following:

1) Verify ALL RCP Seal Water Outlet Temperatures:$; 235°F. IF NOT, THEN perform the actions of Step 1.c before continuing.

2) Place 1 H (1 J) EDG Mode Selector switch to MANUAL-REMOTE.

_ g) Verify 1H (1 J) EDG starts.

_ h) IF neither 1H nor 1J EDG starts, THEN GO TO 1-ECA-O.O, LOSS OF ALL AC POWER, Step in effect.

_ i) IF 1H (1J) Emergency Diesel Generator is running AND 1H (1J) Emergency Bus does NOT energize, THEN GO TO Step 3.

NUMBER ATTACHMENT TITLE ATTACHMENT 1-ECA-O.O 4 ATTEMPTING TO RESTORE POWER TO 1H (1J) EMERGENCY BUS REVISION PAGE 22 30f3

3. IF attempting to energize 1H (1 J) 4160-Volt Emergency Bus, THEN do the following:

_ a) Verify ALL RCP Seal Water Outlet Temperatures ~ 235°F. IF NOT, THEN perform the actions of Step 1.c before continuing.

_ b) Place the 4160V Emer Gen Supply Feed To Bus 1H (1 J) Synchronizing 15H2 (15J2) switch to ON.

_ c) Verify Incoming Voltage is indicated.

_ d) IF voltage is NOT indicated, THEN push Exciter Reset button AND control voltage.

_ e) IF voltage is still NOT indicated, THEN turn off Synch Scope.

_ f) IF neither 1H nor 1J incoming voltage is indicated, THEN GO TO 1-ECA-O.O, LOSS OF ALL AC POWER, Step in effect.

_ g) Verify 15H2 (15J2) is closed.

_ h) IF 15H2 (15J2) is NOT closed, THEN manually close 15H2 (15J2) and turn off Synch Scope.

_ i) IF neither 15H2 nor 15J2 can be closed, turn off Synch Scope and GO TO 1-ECA-O.O, LOSS OF ALL AC POWER, Step in effect.

- END-

NORTH ANNA POWER STATION EMERGENCY CONTINGENCY ACTION NUMBER PROCEDURE TITLE REVISION 14 1-ECA-O.2 LOSS OF ALL AC POWER RECOVERY WITH SI REQUIRED PAGE (WITH ONE ATTACHMENT) 1 of 17 PURPOSE To provide instructions to use Engineered Safeguards Systems to recover plant conditions following restoration of AC emergency power to at least one bus.

ENTRY CONDITIONS This procedure is entered from:

1-ECA-O.O, LOSS OF ALL AC POWER, or

1-ECA-O.1, LOSS OF ALL AC POWER RECOVERY WITHOUT SI REQUIRED.

CONTINUOUS USE

NUMBER PROCEDURE TITLE REVISION 14 1-ECA-O.2 LOSS OF ALL AC POWER RECOVERY WITH SI REQUIRED PAGE 2 of 17 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE:

CSF Status Trees should be monitored for information only.

FRs should not be initiated before completion of Step 12.

Setpoints in brackets [ 1are for adverse Containment atmosphere (20 psi a Containment pressure or Containment Radiation has reached or exceeded 1.0E5 R/hr or 70% on High Range Recorder).

1. VERIFY BOTH TRAINS OF SI - RESET 0 Reset both trains of SI.

2. CHECK RWST LEVEL - GREATER THAN Manually align valves to establish Cold Leg 15% recirculation path for energized bus or busses:

0 a) Verify Recirc Spray Sump level -

GREATER THAN 8 FT 0 IN 0 !E. NOT, THEN GO TO Step 3.

b) Open Low-Head SI Pump Discharge Valves to Charging Pumps:

0

1-SI-MOV-1863A (H Bus) 0

1-SI-MOV-1863B (J Bus) c) Close Low-Head SI Pump Recirc Valves:

0

1-SI-MOV-1885A (H Bus) 0

1-SI-MOV-1885C (H Bus) 0

1-SI-MOV-1885B (J Bus) 0

1-SI-MOV-1885D (J Bus)

(STEP 2 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 14 1-ECA-O.2 LOSS OF ALL AC POWER RECOVERY WITH SI REQUIRED PAGE 3 of 17 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

2. CHECK RWST LEVEL - GREATER THAN 15% (Continued) d) Open Low-Head SI Pump Suction From Containment Sump:

D

1-SI-MOV-1860A (H Bus)

D

1-SI-MOV-1860B (J Bus) e) Close Low-Head SI Pump Suction From RWST:

D

1-SI-MOV-1862A (H Bus)

D

1-SI-MOV-1862B (J Bus) f) Open the following valves:

1) Low-Head SI Pump Discharge Valves:

D

1-SI-MOV-1864A (H Bus)

D

1-SI-MOV-1864B (J Bus)

2) Low-Head SI Pump Cold Leg Injection Valves:

D

1-SI-MOV-1890C (H Bus)

D

1-SI-MOV-1890D (J Bus) g) Close Charging Pump Suction From RWST Isolation Valves:

D

1-CH-MOV-1115B (J Bus)

D

1-CH-MOV-1115D (H Bus)

(STEP 2 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 14 1-ECA-O.2 LOSS OF ALL AC POWER RECOVERY WITH SI REQUIRED PAGE 4 of 17 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

2. CHECK RWST LEVEL - GREATER THAN 15% (Continued) h) Close Charging Pump Suction From VCT Isolation Valves:

D

1-CH-MOV-1115C (H Bus)

D

1-CH-MOV-1115E (J Bus) i) Close Normal Charging Isolation Valves:

D

1-CH-MOV-1289A (H Bus)

D

1-CH-MOV-1289B (J Bus) j) Close BIT Recirc Valves:

D

1-SI-TV-1884A D

1-SI-TV-1884B D

1-SI-TV-1884C k) Open BIT Outlet Valves:

D

1-SI-MOV-1867C (H Bus)

D

1-SI-MOV-1867D (J Bus)

I) Open BIT Inlet Valves:

D

1-SI-MOV-1867A (H Bus)

D

1-SI-MOV-1867B (J Bus)

D m) GO TO Step 5.

NUMBER PROCEDURE TITLE REVISION 14 1-ECA-O.2 LOSS OF ALL AC POWER RECOVERY WITH SI REQUIRED PAGE S of 17 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

3. MANUALLY ALIGN VALVES TO ESTABLISH CHARGING PUMP COLD LEG INJECTION:

a) Open Charging Pump Suction From RWST Isolation Valves:

D

1-CH-MOV-111SD (H Bus)

D

1-CH-MOV-111SB (J Bus) b) Close Charging Pump Suction From VCT Isolation Valves:

D

1-CH-MOV-111SC (H Bus)

D

1-CH-MOV-111SE (J Bus) c) Close Normal Charging Isolation Valves:

D

1-CH-MOV-1289A (H Bus)

D

1-CH-MOV-1289B (J Bus) d) Close BIT Recirc Valves:

D

1-SI-TV-1884A D

1-SI-TV-1884B D

1-SI-TV-1884C e) Open BIT Outlet Valves:

D

1-SI-MOV-1867C (H Bus)

D

1-SI-MOV-1867D (J Bus) f) Open BIT Inlet Valves:

D

1-SI-MOV-1867A (H Bus)

D

1-SI-MOV-1867B (J Bus)

NUMBER PROCEDURE TITLE REVISION 14 1-ECA-O.2 LOSS OF ALL AC POWER RECOVERY WITH SI REQUIRED PAGE 6 of 17 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

4. MANUALLY ALIGN VALVES TO ESTABLISH LOW-HEAD 81 PUMP COLD LEG INJECTION:

a) Open Low-Head SI Pump Suction From RWST:

0

1-81-MOV-1862A (H Bus) 0

1-SI-MOV-1862B (J Bus) b) Open the following valves:

1) Low-Head SI Pump Discharge Valves:

0

1-SI-MOV-1864A (H Bus) 0

1-SI-MOV-1864B (J Bus)

2) Low-Head SI Pump Cold Leg Injection Valves:

0

1-SI-MOV-1890C (H Bus) 0

1-SI-MOV-1890D (J Bus)

NUMBER PROCEDURE TITLE REVISION 14 1-ECA-O.2 LOSS OF ALL AC POWER RECOVERY WITH SI REQUIRED PAGE 7 of 17 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

5. VERIFY SERVICE WATER SPRAYS -

ALIGNED FOR SI MODE:

a) Spray Array Valves - OPEN: o a) Manually or locally open valves.

0

1-SW-MOV-121A 0

1-SW-MOV-122A 0

1-SW-MOV-121 B 0

1-SW-MOV-122B b) Spray Bypass Valves - CLOSED: o b) Manually or locally close valves.

0

1-SW-MOV-123A 0

1-SW-MOV-123B

NUMBER PROCEDURE TITLE REVISION 14 1-ECA-O.2 LOSS OF ALL AC POWER RECOVERY WITH SI REQUIRED PAGE 8 of 17 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION:

To prevent overloading the power supply, loads put on the AC Emergency Bus should not exceed the capacity of the power source.

To prevent possible pump damage, Charging Pump Recirc Valves should be open when RCS pressure is greater than 2000 psig.

6. MANUALLY LOAD THE FOLLOWING f.:;;; /'0 .,-('t-L.--

k SAFEGUARDS EQUIPMENT ON AC EMERGENCY BUS:

o a) Low-Head SI Pumps b) Do the following to start Charging Pumps:

1) Verify RCP seal injection and RCP o 1) IF RCP seal injection OR RCP seal seal cooling isolated in either of the cooling has NOT been previously following: restored, THEN initiate ATTACHMENT 1.

o

1-ECA-0.0, LOSS OF ALL AC POWER o WHEN seal injection is isolated, THEN do Step 6b2.

OR o . 1-ECA-0.1, LOSS OF ALL AC POWER RECOVERY WITHOUT SI REQUIRED o 2) Start Charging Pumps

STUDENT GUIDE FOR EMERGENCY CONTINGENCY ACTION PROCEDURES (94)

Loss of All AC Power (1-ECA-O.O)

Topic.1:1 hECA-(LOlnforrnafion 1.1 Objective U 13830 List the following information associated with 1-ECA-0.0, "Loss of All AC Power."

Purpose of the procedure

Modes of applicability

Entry conditions

Major action categories

Conditions that result in leaving the procedure 1.1 Content

( 1. ECA-O.O, "Loss of All AC Power," provides procedural guidance for loss of all ac power as an initiating event or as a coincident occurrence in combination with a Loss of Reactor Coolant, Loss of Secondary Coolant or Steam Generator Tube Rupture.

1.1. The guideline and supporting analysis are primarily structured to address the Loss of All AC Power as an initiating event that occurs when the plant is in the startup or power operational mode.

1.2. However, the guideline has been augmented to provide appropriate guidance should a concurrent Loss of Reactor Coolant, Loss of Secondary Coolant or Steam Generator Tube Rupture exists.

1.3 Appropriate actions are provided to:

1.1.1.Minimize RCS inventory loss 1.1.2.Maintain an ultimate heat sink 1.1.3.Restore AC power and recover the plant following restoration.

2. ECA-O.O is applicable in modes 1, 2, 3, and 4.

2.1. The Reactor Coolant System is assumed to be partly hot and pressurized.

(

REACTOR OPERATOR Page 4 of 4 Revision 7,09/17/2008

STUDENT GUIDE FOR EMERGENCY CONTINGENCY ACTION PROCEDURES (94) 2.2. Problems with RCP seals are minimal if the RCS is cold and depressurized.

3. Primary entry into ECA-O.O is from Step 3 of E-O, "Reactor Trip or Safety Injection," if both emergency busses are de-energized.

3.1. ECA-O.O is also entered from Step 1 of AP-1 0, or by direction of Shift Manager, if both emergency busses are de-energized

4. The major action categories of ECA-O.O are:

4.1. Check Plant Conditions 4.1.1. Immediate actions to verify reactor trip and turbine trip are performed, as well as actions to check RCS isolation and Secondary Heat Sink availability. These actions are appropriate for all loss of AC power scenarios.

4.2. Restore AC Power

( 4.2.1. Optimal recovery cannot be initiated until AC power is restored to at least one emergency bus.

4.2.2. AC power to be restored from the control room or locally.

4.3. Maintain Plant Conditions for Optimal Recovery 4.3.1. Consists of actions to mitigate deterioration of RCS conditions and establish plant conditions amenable to optimal recovery following AC power restoration.

4.3.1.1. By minimizing RCS inventory loss and maintaining a secondary heat sink the operator can extend the time to core uncovery.

4.4. Evaluate Energized AC Emergency Bus 4.4.1. Following restoration of AC power, the operator is instructed to stabilize steam generator pressures, (if a secondary depressurization was in progress) and to evaluate the status of the energized emergency bus.

4.4.2. These actions provide the operator with information that will aid him in loading subsequent equipment on the energized AC emergency bus.

4.5. Select Recovery Guideline After AC Power Restoration REACTOR OPERATOR Page 5 of 5 Revision 7,09/17/2008

STUDENT GUIDE FOR EMERGENCY CONTINGENCY ACTION PROCEDURES (94) 4.5.1. Selection depends on the existence of RCS subcooling, existence of pressurizer level, and verification that SI equipment has not automatically actuated upon power restoration.

5. ECA-O.O has the following transitions:

5.1. Exited to procedure and step in effect if power is restored early, i.e. prior to placing components in PTL.

5.1.1. Initial efforts for AC power restoration are addressed from the control room.

5.1.1.1. The operator uses an attachment and attempts to start and/or load an emergency diesel generator.

5.1.1.2. Procedure steps are also included for controlling diesel voltage and frequency manually, if necessary.

5.1.2. If AC power is restored in this step (via an EOG) the power supply should be sufficiently stable to accept automatic sequencing of blackout or SI loads on the AC emergency bus without detrimental effects.

5.2. If power is restored to any emergency bus after the early attempt, then recovery actions are continued with step 29.

5.3. Eventually, a transition to ECA-0.1 will occur if SI is not required or ECA-0.2 if it is.

5.4. If an Appendix-R fire exists in the emergency switchgear room, a transition to FCA-2 occurs.

Topic.1.2i.CheckRCRSeaIVVate~(lutl~f I~mperatlJre 1.2 Objective U 5687 Explain the following about the importance of RCP seal water outlet temperature in 1-ECA-0.0:

The maximum seal water temperature allowed to start an EOG with charging pumps available

What actions must be taken when 1-ECA-0.0 is exited in step 9 with charging pumps in PTL due to high seal water outlet temperature.

1.2 Content REACTOR OPERATOR Page 6 of 6 Revision 7,09/17/2008

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 7 of7 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 a" 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 charginglSI pump is started as part of the recovery.

REACTOR OPERATOR Page 8 of 8 Revision 7, 09/17/2008

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

88. 056-A2.04 088IMODIFIEDINAPS/H/3/SRO///

Given the following conditions:

Unit 1 is at 90% power.

"A" & "C" MFW pumps are running, and "B" MFW pump is tagged out.

"A" & "C" Condensate pumps are running, and "B" Condensate pump is tagged out.

The following alarms and conditions occur:

G-G6, CONDENSATE PP 1A-1B-1C AUTO TRIP, alarms and the OATC notes that "A" Condensate pump is tripped.

F-B6, MAIN FD PPS SUCT HDR LO PRESS, and F-B5, MAIN FD PPS LO DIFF PRESS, are subsequently received.

MFW pump suction pressure is 270 psig and slowly lowering.

MFW pump differential pressure is 680 psig and slowly lowering.

Based on these plant conditions, which ONE of the following identifies the direction(s) the SRO should provide to the OATC?

A. Reduce turbine load until the MAIN FD PPS LO DIFF PRESS alarm is clear.

B. Reduce turbine load until steam flow is less than available feed flow.

C'!'" Trip the reactor and go to 1-E-0, Reactor Trip or Safety Injection.

D. Reduce turbine load until MFW pump suction pressure is greater than 300 psig.

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

a. Incorrect. This is normally a strategy and clearing of the alarm is a milestone in the load reduction, however based on the plant conditions of low suction pressure a running feed pump will automatically trip long before plant load can be reduced and require a reactor trip; the candidate should realize that the situation is non-recoverable based on the max load reduction rate of 5%/min. and trip the unit.

b. Incorrect. This is normally a strategy and reducing steam flow to less than available feed flow is a milestone in the load reduction, however based on the plant conditions of low suction pressure a running feed pump will automatically trip long before plant load can be reduced and require a reactor trip; the candidate should realize that the situation is non-recoverable based on the max load reduction rate of 5%/min. and trip the unit.

c. Correct. As discussed above it is not possible to reduce load quickly enough given the initial power level and a Reactor Trip is required.

d. Incorrect. This is normally a strategy and clearing of the alarm is a milestone in the load reduction, however based on the plant conditions of low suction pressure a running feed pump will automatically trip long before plant load can be reduced and require a reactor trip; the candidate should realize that the situation is non-recoverable based on the max load reduction rate of 5%/min. and trip the unit.

Notes Condensate System Ability to (a) predict the impacts of the following malfunctions or operations on the Condensate System; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those malfunctions or operations: Loss of condensate pumps (CFR: 41.5 /43.5 /45.3/45.13)

Tier: 2 Group: 2 Importance Rating: 2.6/2.8 Technical

Reference:

1-AP-31 Proposed references to be provided to applicants during examination: None Learning Objective: 5039 Question History: modified Associated objective( s):

VIRGINIA POWER 1-EI-CB-21G ANNUNCIATOR G6 1-AR-G-G6 NORTH ANNA POWER STATION REV. 0 1?PROVAL: ON FILE Effective Date:09-26-96 CONDENSATE PP 1A-1B-1C AUTO TRIP 1.0 Probable Cause 1.1 4160 Volt bus undervoltage 1.2 Motor protection relays 1.3 4160 volt pump speed switch 2.0 Operator Action 2.1 Verify start of other condensate pump. If required, start standby pump using 1-0P-30.1, Operation of the Condensate System.

2.2 IF pump was being started, THEN reset speed switch in 307' switchgear room.

2.3 Notify Shift Supervisor.

2.4 If required, submit WR.

3.0 References 3.1 11715-ESK-5G, H, J, 5BD, 6QH, 10AAZ 4.0 Actuation 4.1 86-15A4, 86-15B4 lockout relays on Condensate pump breakers

VIRGINIA POWER 1-EI-CB-21F ANNUNCIATOR B6 1-AR-F-B6 NORTH ANNA POWER STATION REV. 0

~PPROVAL: ON FILE Effective Date:09/119/7 MAIN FD PPS 280 psig SUCT HDR NOTE: This is the MFW pump LO PRESS trip setpoint after the following time delay 1.0 Probable Cause A MFP - 40 sec B MFP - 55 sec 1.1 Loss of HP or LP Heater Drain Pump C MFP - 70 sec 1.2 Feed Train transient 1.3 Failure of Main Condensate Pump 2.0 Operator Action 2.1 Verify auto-start of standby Main Condensate Pump.

2.2 Check operation of Main Condensate Pumps:

Amperage

Discharge pressure

Suction strainer differential pressure 2.3 Check operation of HP and LP Heater Drain Pumps.

2.4 Verify proper operation of Steam Generator Level Control System and feedwater FCVs.

2.5 Verify operation of 1-CN-FCV-107 (Condensate Recirc Valve) and 1-CN-LCV-108 (Condenser HLD valve) .

3.0 References 3.1 Instrument Test Loops (CN page 41) 3.2 DCP 88-16-3 4.0 Actuations 4.1 1-CN-PSL-150A-3 4.2 1-CN-PSL-150B-3 4.3 1-CN-PSL-150C-3

VIRGINIA POWER 1-EI-CB-21F ANNUNCIATOR BS 1-AR-F-BS NORTH ANNA POWER STATION REV. 0

'PPROVAL: ON FILE Effective Date:09/11/97 MAIN FD PPS LO DIFF 700 psid PRESS 1.0 Probable Cause 1.1 Failed open feedwater reg valve.

1.2 Loss of feed pump.

1.3 Loss of condensate pump.

1.4 Recirc valve failed open.

1.S Feedwater line rupture.

2.0 Operator Action 2.1 Verify recirc valve closed.

2.2 GO TO 1-AP-31, Loss of Main Feedwater.

3.0 References 3.1 1171S-FM-17A, 18A 3.2 NAPS Instrumentation Page FW 018 3.3 1-AP-31, Loss of Main Feedwater

.0 Actuations 4.1 1-FW-PDT-102

NORTH ANNA POWER STATION ABNORMAL PROCEDURE NUMBER PROCEDURE TITLE REVISION 4

1-AP-31 LOSS OF MAIN FEEDWATER (WITH ONE ATTACHMENT) PAGE 1 of 7 PURPOSE To provide instructions for recovering from a loss of Feedwater flow in Mode 1 or Mode 2.

ENTRY CONDITIONS This procedure is entered when any of the following conditions exists:

(

Loss of 1 or 2 Main Feed Water Pumps

Annunciator Panel F-A4, MAIN FD PPS DISCH HDR LO PRESS

Annunciator Panel F-A5, MAIN FD PP 1A-1B-1C AUTO TRIP

Annunciator Panel F-B5, MAIN FD PPS LO DIFF PRESS

Inadequate Main Feed Water Pump suction pressure

Inadequate Feed Flow to more than one Steam Generator as indicated by:

Annunciator Panels F-C1/C2/C3, STM GEN 1A11 B/1 C LO LEVEL CH I-II OR Annunciator Panels F-D1/D2/D3, STM GEN 1A/1 B/1C FW<STM FLOW CH III-IV OR Annunciator Panels F-F1/F2/F3, SG 1A11B/1C LEVEL ERROR CONTINUOUS USE

NUMBER PROCEDURE TITLE REVISION 4

1-AP-31 LOSS OF MAIN FEEDWATER PAGE 2 of 7 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-0, REACTOR TRIP OR SAFETY INJECTION.

o b) Two MFW Pumps - RUNNING o b) IF a second MFW Pump cannot be immediately started, THEN GO TO 1-E-0, 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.

NUMBER PROCEDURE TITLE REVISION 4

1-AP-31 LOSS OF MAIN FEEDWATER PAGE 3 of 7 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION:

Turbine ramp rates must be limited to 5%/minute or less.

Control rods should be maintained above insertion limits.

NOTE: Ramp rates close to 5%/minute may cause the Steam Dumps to arm.

4. EVALUATE REDUCING TURBINE LOAD TO LESS THAN 55% POWER:

o a) Verify ONLY ONE MFW Pump- o a) GO TO Step 5.

RUNNING Db) Check Reactor Power level - o b) GO TO Step 5.

GREATER THAN 55%

c) Check Turbine load control:

o 1) Verify Turbine valve position o 1) Take Turbine off Valve Position Limiter.

- OFF VALVE POSITION LIMITER o 2) Verify Turbine Load Control o 2) Place Turbine Load Control in IMP-IN by in IMP-IN depressing the IMP-IN pushbutton.

o d) Reduce Turbine load to 50-55%

using OPERATOR AUTO or TURBINE MANUAL o e) Insert Control Rods in AUTO or MANUAL as required to maintain Tavg within 5 of of Tref (STEP 4 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 4

1-AP-31 LOSS OF MAIN FEEDWATER PAGE 4 of?

ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

4. EVALUATE REDUCING TURBINE LOAD TO LESS THAN 55%

POWER: (Continued) 0 f) Borate as required to maintain final Control Rod position above insertion limits 0 g) Energize additional PRZR Heaters as required to maintain PRZR Pressure above 2205 psig 0 h) Monitor Steam Dumps for proper

5.

0 operation STABILIZE SG LEVELS:

a) Verify steam flow - LESS THAN AVAILABLE FEED FLOW

,?

¥" 0 a) Reduce Turbine load.

o b) Verify SG levels - AT OR b) Place associated valves in MANUAL and control TRENDING TO PROGRAM LEVEL SG levels:

o

Main Feed Reg Valves o

Main Feed Reg Bypass Valves

NUMBER PROCEDURE TITLE REVISION 4

1-AP-31 LOSS OF MAIN FEEDWATER PAGE 50f7 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

6. VERIFY ACCEPTABLE MFW PUMP PERFORMANCE:

c;V o a) MFW Suction Pressure -

ADEQUATE Q:,sV 0 a) Do the following, as required:

Start an additional Condensate Pump o . Reduce Turbine load o b) Verify MFW Motor amps - LESS o b) Reduce Turbine load.

THAN 550 AMPS ON EACH MOTOR o c) Verify Annunciator Panel F-B5, 0 c) Reduce Turbine load.

MAIN FD PPS LO DIFF PRESS \c;;: \ \ _......r NOT LIT 0-\c,~(..-~ .

7. MAINTAIN STABLE PLANT CONDITIONS

8. CHECK IF ISOTOPIC ANALYSIS OF RCS IS REQUIRED:

o a) Check Reactor Power - HAS o a) GO TO Step 9.

DECREASED MORE THAN 15% IN ONE HOUR o b) Have Chemistry perform isotopic analysis of RCS for iodine within 2 to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months

NUMBER PROCEDURE TITLE REVISION 4

1-AP-31 LOSS OF MAIN FEEDWATER PAGE 6 of 7 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED

9. MAKE NOTIFICATIONS:

0

STA 0

Operations Manager On Call 0

System Operator 0

Other notifications as required by VPAP-2802, NOTIFICATIONS AND REPORTS 0

Energy Supply (MOC)

10. INVESTIGATE REASON FOR LOSS OF FEEDWATER:

a) Have Operator locally check the following as required:

0

MFW Pump that auto-started 0

MFW Pump that tripped 0

Breakers for tripped MFW Pump 0

Condensate Pump that was started b) Verify non-isolated Main Feedwater b) Locally isolate failed FCV(s) by closing the Pump Recirc Valves - NOT FAILED following as applicable:

0

1-FW-FCV-150A o . 1-FW-292 (1-FW-FCV-150A) 0

1-FW-FCV-150B o . 1-FW-293 (1-FW-FCV-150B) 0

1-FW-FCV-150C o . 1-FW-294 (1-FW-FCV-150C)

(STEP 10 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 4

LOSS OF MAIN FEEDWATER 1-AP-31 PAGE 7 of?

ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

10. INVESTIGATE REASON FOR LOSS OF FEEDWATER:

(Continued) o c) Check for unexplained increase in FW Heater level o d) Walk down Condensate and Feedwater systems as required

11. INITIATE ANY REQUIRED WORK REQUESTS

12. RETURN TO PROCEDURE AND STEP IN EFFECT

- END-

STUDENT GUIDE FOR MAIN FEEDWATER SYSTEM (26-A)

Integrated Plant Operations T Of.l ic.3.1MFW.PtotectioI1SystemActuations 3.1 Objective U 1826 Explain how the following conditions affect the Main Feedwater System.

Safety injection

Steam generator level> 75%

Reactor trip with low T avg

Loss of condensate

High-pressure or low-pressure heater drain pump trip 3.1 Content

(

1. A safety injection signal will result in the following Main Feedwater System actuations:

1.1. Closure of the feedwater regulating bypass valves 1.2. Closure of the main feedwater regulating valves 1.3. Closure of the feed header isolation valves (MOV-154A/B/C) on a Train "A" safety injection signal only.

1.4. Closure of the main feedwater pump discharge valves (MOV-150AlB/C) on a Train "B" safety injection signal only.

1.5. Tripping of the main feedwater pumps 1.6. Tripping of the main turbine 1.7. A safety injection signal automatically starts the three auxiliary feedwater pumps and trips the reactor trip breakers.

2. A P-14 actuation occurs when two out of three steam generator narrow range level channels are 75% or greater and will result in the following actuations:

REACTOR OPERATOR Page 22 of 33 Revision 3, 10/09/2008

STUDENT GUIDE FOR MAIN FEEDWATER SYSTEM (26-A) 2.1. Closure of the feedwater regulating bypass valves 2.2. Closure of the main feedwater regulating valves 2.3. Closure of the feed header isolation valves (MOV-154A/8/C) on a Train "A" P-14 signal only.

2.4. Closure of the main feedwater pump discharge valves (MOV-150Al8/C) on a Train "8" P-14 signal only.

2.5. Tripping of the main feedwater pumps, which will start the three auxiliary feedwater pumps 2.6. Tripping of the main turbine

3. The main feed regulating valves receive an automatic closure signal when the reactor trip breakers are open, P-4, and two of the three T AVG channels are ~ 554°F, Low TAVG .

3.1. This condition will result in the automatic closure of the main feedwater regulating valves only.

3.2. In this situation excessive feedwater could result in an excessive RCS cool-down.

3.3. Control of feedwater flow should be shifted to the feedwater reg. 8YPASS valves.

4. If insufficient condensate is available, the main feedwater pumps will trip due to low suction pressure.

4.1. The loss of feedwater will ultimately result in a unit trip due to decreasing water level in the steam generators

5. Should either a LP or HP heater drain pump or a condensate pump trip for some reason, the third condensate pump should auto start to provide the required suction to main feedwater pump for continued operation.

REACTOR OPERATOR Page 23 of 33 Revision 3, 10109/2008

STUDENT GUIDE FOR MAIN FEEDWATER SYSTEM (26-A) 4.2. This results in less fast neutrons leaking from the core and less neutrons reaching the excore nuclear instrumentation detectors.

5. Actual reactor power will increase.

5.1. The increase in moderator density will increase the number of neutrons reaching thermal energy levels.

5.2. As a result, more fissions will occur and actual reactor power will increase.

6. With the high-pressure feed heater removed from service, the flow path from the main feedwater pumps will be limited.

6.1. This restriction in feedwater flow will cause a reduction in steam generator level.

6.2. In order to compensate for this level decrease, the main feedwater regulating valves will open to reestablish program steam generator levels.

6.3. The feedwater regulating valves will have to open more to match steam flow with feed flow once program steam generator level is attained.

Tqpic3.6Terminal . Knowledg¢iObjeCtive .

3.6 Objective U 11989 Given a set of plant conditions, evaluate Main Feedwater 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 main feedwater 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 REACTOR OPERATOR Page 27 of 33 Revision 3, 10109/2008

STUDENT GUIDE FOR MAIN FEEDWATER SYSTEM (26-A) 3.6 Content

This objective has "NO" content.

Integrated system knowledge will be required to answer any questions linked to this objective.

(

REACTOR OPERATOR Page 28 of 33 Revision 3, 10/09/2008

STUDENT GUIDE FOR MAIN CONDENSATE SYSTEM (25)

3. The condensate recirculation line discharges into the West Side of "8" main condenser on the mezzanine level.

2.19 Objective U 4013 Explain the following concepts associated with operation of the main condensate pumps.

Conditions required to start the main condensate pump manually

Interlocks that will start the main condensate pump automatically

Interlocks that will result in a main condensate pump trip

Why the main condensate pump discharge valve is throttled prior to manually starting a condensate pump

Why the main condensate pump discharge valve is throttled prior to manually stopping a condensate pump 2.19 Content

1. To start a condensate pump, the following conditions must exist:

1.1. No motor electrical faults and feedwater heaters 5A, 6A, 58, and 68 shell side level below the high-high setpoint (86 lockout reset).

1.2. No locked rotor protection actuation (86SS reset).

1.3. No reserve station service load shed actuation.

1.4. In addition, the unit 2 "8" condensate pump is locked out from starting if a safety injection occurs on unit 1 with the unit 2 "8" station service bus fed from "8" reserve station service transformer (unit 1 SI/CDA load shed).

2. A condensate pump will automatically start if any of the following conditions occur:

2.1. Condensate pump discharge header pressure decreases below 440 psig.

REACTOR OPERATOR Page 23 of 33 Revision 2, 03/04/2008

STUDENT GUIDE FOR MAIN CONDENSATE SYSTEM (2S) 2.2. Trip of a running pump as indicated by the pump's control switch in the START or AUTO-AFTER-START position with the associated pump's breaker open.

2.3. Suction pressure for a running main feedwater pump less than 280 psig.

3. A condensate pump will automatically trip if any of the following conditions occur:

3.1. Motor electrical fault (86 lockout).

3.2. Feedwater heater 5A, 6A, 58, or 68 shell side level above the high-high setpoint for 5 seconds (86 lockout).

3.3. Locked rotor protection actuation (86SS).

3.4. Reserve station service load shed actuation; associated station service bus under-voltage.

3.5. In addition, the unit 2 "8" condensate pump is tripped and locked out from starting if a safety injection occurs on unit 1 with the unit 2 "8" station service bus fed from "8" reserve station service transformer.

4. Prior to starting a condensate pump, the discharge valve may be throttled to minimize the pressure surge on the condensate system when the pump is started.

5. Prior to stopping a condensate pump, the discharge valve may be throttled to minimize the effects of a stuck open discharge check valve when the pump is stopped.

2.20 Objective U 837 Explain the consequences of failing to place the control switch for a standby condensate pump in PULL-TO-LOCK when manually starting a condensate pump.

2.20 Content

1. Prior to starting the second condensate pump, the procedure directs the operator to place the third REACTOR OPERATOR Page 24 of 33 Revision 2, 03/04/2008

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

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-18-1C AUTO TRIP, lit.

2.4. F-85, MAIN FD PPS LO DIFF PRESS, lit.

2.5 Inadequate main feedwater pump suction pressure 2.6. Inadequate feed flow to more than one S/G as indicated any of the following annunciators 2.6.1.F-C1/C2/C3, STM GEN 1A118/1C LO LEVEL CH I-II 2.6.2.F-D11D2/D3, STM GEN 1A11 8/1 C FW<STM FLOW CH III-IV 2.6.3.F-F1/F2/F3, SG 1A11 8/1 C 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.

To~ic2t.13 High-level* Acfiol1s AssoclafedwifhAP-31 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, 11/06/2008

STUDENT GUIDE FOR ABNORMAL PROCEDURES (91)

Check for stuck open check valve on un isolated 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-85, 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.

Topic 21.14AP-3S*.Purpose, Applicabllity,*& Entry (;onditlons 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 SRO exam Validation 3 copy with SRC formatting - for submittal

89. 058-AA2.02 089fNEW//L/3/SRO///

Given the following conditions:

Unit 1 is at 100% power.

Annunciator H-B2, BATTERY CHGR 1-11 TROUBLE alarms.

Battery Charger 1-11 DC Output breaker has tripped and CANNOT be reset.

Based on these plant conditions, which ONE of the following identifies the Technical Specification required action, and the action required by AR-H-B2?

A'! Restore DC electrical power subsystem to OPERABLE status within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months ; Place battery charger 1C-I in service.

B. Restore DC electrical power subsystem to OPERABLE status within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ; Place battery charger 1C-I in service.

C. Restore DC electrical power subsystem to OPERABLE status within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months ; Place battery charger 1C-II in service.

D. Restore DC electrical power subsystem to OPERABLE status within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ; Place battery charger 1C-II in service.

Feedback

a. Correct. The appicable TS action is 3.8.4 A with a completion time of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months ; charger 1C-1 is the spare for battery charger 1-1 or 1-11 so it will be placed in service.

b. Incorrect. Plausible since the candidate may not have knowledge of the TS basis of the battery to supply loads for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months and the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months time would not seem unreasonable and is the shutdown action if the subsystem isn't restored within the 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months ; second part is correct as discussed above.

c. Incorrect. Action time is correct; second part is incorrect but plausible since the affected chgr is 1-11, the candidate who does not have knowledge of the system configuration may assume that 1C-II would be the logical choice of spare chargers.

d. Incorrect. Action time is incorrect but plausible as discussed in Dlstractor c; second part is incorrect but plausible since the affected chgr is 1-11, the candidate who does not have knowledge of the system configuration may assume that 1C-II would be the logical choice of spare chargers.

QUESTIONS REPORT for 2009 NRC SRO exam Validation 3 copy with SRC formatting - for submittal Notes Loss of DC Power Ability to determine and interpret the following as they apply to the Loss of DC Power: 125V dc bus voltage, low/critical low, alarm (CFR: 43.5/45.13)

Tier:

Group:

Importance Rating: 3.3/3.6 Technical

Reference:

TS 3.8.7 and AR Proposed references to be provided to applicants during examination: None Learning Objective:

Question History: New Associated objective(s):

additional information:

VIRGINIA POWER l-EI-CB-21H ANNUNCIATOR B2 l-AR-H-B2

'TORTH ANNA POWER STATION REV. 4

?PROVAL: ON FILE Effective Date:07/24/01 BATTERY CHGR 1 - II TROUBLE 1.0 Probable Cause 1.1 AC input failure 1.2 DC output hi voltage (can be caused by low load) 1.3 DC output 10 voltage 1.4 Not charging 1.5 Ground 1.6 Blown ground indicating bulb on DC Bus 2.0 Operator Action 2.1 Dispatch Operator to battery charger.

2.2 IF indication is normal on battery charger, THEN depress "reset" pushbutton on charger.

2.3 IF alarm does not clear, or indication is NOT normal, THEN notify Electrical Department.

2.4 IF required, THEN place swing charger in service using 1-0P-26.4.3, Main Station Swing Battery Chargers lC-I & lC-II Operation.

2.5 Notify Shift Supervisor.

2.6 IF a ground is indicated on the DC Bus, THEN submit an Emergency W.R.

2.7 IF DC Bus I-II voltage is lost AND IH EDG is in action for an extended outage with the Unit in Modes 1-4, THEN breaker 15F3 from SBO Diesel to IH Emergency Bus is NOT operable. Refer to Technical Specification 3.B.l.l (ITS 3.B.l) for more restrictive LCO time requrirements and actions.

3.0 References 3.1 Gould instruction book 3.2 Gould drawing CI0B013 3.3 LSK-22-B 4.0 Actuation 4.1 AC input failure - device 27 4.2 DC hi output voltage - direct sensing 4.3 DC 10 output voltage - device 27 4.4 Not charging - device 95 4.5 Ground detector - relay K2 74 device NOTE: These are located in the charger cabinet

DC Sources-Operating 3.8.4 3.8 ELECTRICAL POWER SYSTEMS 3.8.4 DC Sources-Operating LCO 3.8.4 The following DC electrical power sources shall be OPERABLE:

a. The Train H and Train J DC electrical power subsystems;

b. The Emergency Diesel Generator (EDG) DC systems for each required EDG; and

c. One DC electrical power subsystem on the other unit for each required shared component.

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

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One LCO 3.8.4.a DC A.1 Restore DC electrical 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months electrical power power subsystem to subsystem inoperable. OPERABLE status.

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Associated Completion Time for Condition A -

AND not met.

B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months C. --------NOTE---------- C.1 Enter applicable Immediately Separate Condition Conditions and entry is allowed for Required Actions for each EDG DC system. associated EDG(s) made

inoperable.

One or more required EDG DC system(s) inoperable.

(

North Anna Units 1 and 2 3.8.4-1 Amendments 231/212

DC Sources-Operating B 3.8.4 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.4 DC Sources-Operating BASES BACKGROUND The station DC electrical power system provides the AC emergency power system with control power. It also provides both motive and control power to selected safety related equipment and preferred AC vital bus power (via inverters).

As required by Reference 1, the DC electrical power system is designed to have sufficient independence, redundancy, and testability to perform its safety functions, assuming a single failure. The DC electrical power system also conforms to the recommendations of Safety Guide 6 (Ref. 2) and IEEE-308 (Ref. 3).

The 125 VDC electrical power system consists of two independent and redundant safety related Class IE DC electrical power subsystems (Train H and Train J). Each subsystem consists of two 125 VDC batteries, the associated battery charger(s) for each battery, and all the associated control equipment and interconnecting cabling. A spare battery charger is installed on each train and can be substituted for either of the train's chargers.

During normal operation, the 125 VDC load is powered from the battery chargers with the batteries floating on the system. In case of loss of normal power to the battery charger, the DC load is automatically powered from the station batteries.

The Train H and Train J DC electrical power subsystems provide the control power for its associated Class IE AC power load group, 4.16 kV switchgear, and 480 V load centers. The DC electrical power subsystems also provide DC electrical power to the inverters, which in turn power the AC vital buses.

The DC power distribution system is described in more detail in Bases for LCO 3.8.9, "Distribution Systems-Operating,"

and LCO 3.8.10, "Distribution Systems-Shutdown."

Each battery has adequate storage capacity to carry the required load continuously for at least 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

(continued)

North Anna Units 1 and 2 B 3.8.4-1 Revision 0

DESIGN DC Sources-Operating B 3.8.4 BASES BACKGROUND Each 125 VDC battery is separately housed in a ventilated (continued) room apart from its charger and distribution centers. Each subsystem is located in an area separated physically and electrically from the other subsystem to ensure that a single failure in one subsystem does not cause a failure in a redundant subsystem. There is no sharing between redundant Class IE subsystems, such as batteries, battery chargers, or distribution panels.

The criteria for sizing large lead storage batteries are defined in IEEE-485 (Ref. 5).

Each Train H and Train J DC electrical power subsystem has ample power output capacity for the steady state operation of connected loads required during normal operation, while at the same time maintaining its battery bank fully charged.

Each battery charger also has sufficient capacity to restore the battery from the design minimum charge to its fully charged state within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months while supplying normal steady state loads discussed in the UFSAR, Chapter 8 (Ref. 4).

The EDG DC electrical power system consists of the battery, battery charger, and interconnecting cabling to supply the

( required DC voltage to allow the associated EDG components to perform the required safety function.

For the other unit, the DC electrical power system provides control power for breakers and electrical power for solenoid operated valves that are needed to support operation of each required Service Water (SW) pump, Main Control Room (MCR)/Emergency Switchgear Room (ESGR) Emergency Ventilation System (EVS) fan, Auxiliary Building central exhaust fan, and Component Cooling Water (CC) pump. SW, MCR/ESGR EVS, Auxiliary Building central exhaust system, and CC are shared systems.

APPLICABLE The initial conditions of Design Basis Accident (DBA) and SAFETY ANALYSES transient analyses in the UFSAR, Chapter 6 (Ref. 6), and in the UFSAR, Chapter 15 (Ref. 7), assume that Engineered Safety Feature (ESF) systems are OPERABLE. The DC electrical power system provides normal and emergency DC electrical power for the emergency auxiliaries and control and switching during all MODES of operation.

(continued)

North Anna Units 1 and 2 B 3.8.4-2 Revision 8

- NUCLEAR DESIGN INFORMATION PORTAL-DC Sources-Operating B 3.8.4 BASES APPLICABLE The OPERABILITY of the DC sources is consistent with the SAFETY ANALYSES initial assumptions of the accident analyses and is based (continued) upon meeting the design basis of the unit. This includes maintaining the DC sources OPERABLE during accident conditions in the event of:

a. An assumed loss of all offsite AC power or all onsite AC power; and

b. A worst case single failure.

The OPERABILITY of the EDG DC electrical power system ensures the EDG may perform its required safety function.

The DC sources satisfy Criterion 3 of 10 CFR 50.36(c) (2) (ii).

LCO The DC electrical power subsystems, each subsystem consisting of two batteries, battery charger for each battery and the corresponding control equipment and interconnecting cabling supplying power to the associated bus within the train are required to be OPERABLE to ensure the availability of the required power to shut down the reactor and maintain it in a safe condition after an anticipated operational occurrence (AOO) or a postulated DBA. Loss of any train DC electrical power subsystem does not prevent the minimum safety function from being performed (Ref. 4).

The EDG DC electrical power system consists of the battery, battery charger, and interconnecting cabling to supply the required DC voltage to allow the associated EDG components to perform the required safety function.

An OPERABLE DC electrical power subsystem requires all required batteries and respective chargers to be operating and connected to the associated DC bus(es).

Additionally, the unit's electrical sources must include DC sources from the other unit that are required to support the SW, MCR/ESGR EVS, Auxiliary Building central exhaust system, or CC safety functions. Control power for breakers and electrical power for solenoid operated valves are examples of support systems required to be OPERABLE that are needed for the operation of each required SW pump, MCR/ESGR EVS fan, (continued)

North Anna Units 1 and 2 B 3.8.4-3 Revision 0

- NUCLEAR DESIGN INFORMATION PORTAL-DC Sources-Operating B 3.8.4 BASES LCO Auxiliary Building central exhaust fan, and CC pump. SW, (continued) MCR/ESGR EVS, Auxiliary Building central exhaust system, and CC are shared systems.

APPLICABILITY The DC electrical power sources are required to be OPERABLE in MODES 1, 2, 3, and 4 to ensure safe unit operation and to ensure that:

a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AOOs or abnormal transients; and

b. Adequate core cooling is provided, and containment integrity and other vital functions are maintained in the event of a postulated DBA.

The EDG DC system is required to be OPERABLE in MODES 1, 2, 3, and 4 to ensure the OPERABILITY of the associated EDG in accordance with LCO 3.8.1. In MODES 5 or 6, the OPERABILITY requirements of the EDG DC system are determined by the EDGs that they support in accordance with LCO 3.8.2.

The DC electrical power requirements for MODES 5 and 6 are addressed in the Bases for LCO 3.8.5, "DC Sources-Shutdown."

ACTIONS A.l Condition A represents one train with a loss of ability to completely respond to an event, and a potential loss of ability to remain energized during normal operation. It is, therefore, imperative that the operator's attention focus on stabilizing the unit, minimizing the potential for complete loss of DC power to the affected train. The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months limit is consistent with the allowed time for an inoperable DC distribution system train.

If one of the required LCO 3.8.4.a DC electrical power subsystems is inoperable (e.g., inoperable battery, inoperable battery charger(s), or inoperable battery charger and associated inoperable battery), the remaining LCO 3.8.4.a DC electrical power subsystem has the capacity to support a safe shutdown and to mitigate an accident condition. For the Station batteries, a spare battery charger may be substituted for the normal charger without (continued)

North Anna Units 1 and 2 B 3.8.4-4 Revision 0

- NUCLEAR DESIGN INFORMATION PORTAL-DC Sources-Operating B 3.8.4 BASES ACTIONS A.1 (continued) entry into Condition A. Since a subsequent worst case single failure would, however, result in the complete loss of the remaining 125 VDC electrical power subsystems with attendant loss of ESF functions, continued power operation should not exceed 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is based on Regulatory Guide 1.93 (Ref. 8) and reflects a reasonable time to assess unit status as a function of the inoperable DC electrical power subsystem and, if the DC electrical power subsystem is not restored to OPERABLE status, to prepare to effect an orderly and safe unit shutdown.

B.1 and B.2 If the inoperable DC electrical power subsystem cannot be restored to OPERABLE status within the required Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. The Completion Time to bring the unit to MODE 5 is consistent with the time required in Regulatory Guide 1.93 (Ref. 8).

C.1 Condition C represents the loss of the ability of the EDG DC system (e.g., inoperable battery charger or inoperable battery) to supply necessary power to the associated EDG. In this condition, the associated EDG is immediately declared inoperable and the associated Conditions or Required Actions of LCO 3.8.1 are followed.

D.1 Condition D represents the loss of one or more required LCO 3.8.4.c DC electrical power subsystem(s) needed to support the operation of required shared components on the other unit. SW, MCR/ESGR EVS, Auxiliary Building central exhaust system, and CC are shared systems. In this condition, the associated required shared components are declared inoperable immediately. The associated Conditions or Required Actions of LCO 3.7.8, "Service Water System,"

(continued)

North Anna Units 1 and 2 B 3.8.4-5 Revision 0

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

Vital Electrical Distribution Topic1.1125-volt IlChatterycbargers 1.1 Objective U 5509 List the following information associated with the 125-volt DC battery chargers.

Purpose

Source of power to each normal and swing battery charger (SOER-81-15)

Color designation associated with each vital DC bus

Output voltage during normal operation (SOER-81-15)

Output voltage during an equalizer battery charge

Nominal output current (SOER-81-15)

Maximum current flow (SOER-81-15) 1.1 Content

1. The battery chargers convert 480 VAC power to a 125 VDC regulated output, which powers the associated 125 VDC buses and maintains a floating charge on the batteries connected to the buses.

2. The normal and swing battery chargers are powered from their respective 480 volt emergency busses:

2.1. 1H1-4 supplies input power to normal battery chargers 1-1 and 1-/1 and swing battery charger 1C-I 2.2. 1J1-1 supplies input power to normal battery chargers 1-1/1 and 1-IV and swing battery charger 1C-/I

3. Each vital DC bus has a designated identifying color:

3.1. Red identifies the 1-1 vital bus.

3.2. White identifies the 1-2 vital bus 3.3. Blue identifies the 1-3 vital bus 3.4. Yellow identifies the 1-4 vital bus REACTOR OPERATOR Page 4 of 36 Revision 4, 07/31/2008

STUDENT GUIDE FOR VITAL AND EMERGENCY ELECTRICAL DISTRIBUTION SYSTEM (35) 2.10 Content

1. If an 81 signal is present when a UV/DV condition occurs, the DV time delay is reduced to 7.5 seconds.

Topic* 2.11 Vita.fandEmergencyElectricaf plstribuUon SystemTS 2.11 Objective U 5500 List the following information associated with the Vital and Emergency Electrical Distribution 8ystem technical specifications.

Modes of operation requiring two operable emergency busses (T8-3.8.1)

Modes of operation requiring one operable emergency bus (T8-3.8.2)

8urveillance time interval for performing PT-80 during mode 1 (8R-3.8.1.1)

8urveillance time interval for performing PT-80 during mode 1 with one diesel inoperable (T8-3.8.1 Condition A)

Technical specification time limit for a vital bus being powered by its regulating transformer (T8-3.8.7 Condition A)

Length of time that a vital bus can be de-energized (T8-3.8.9)

Required action when one vital bus is de-energized (T8-3.8.9) 2.11 Content

1. Two operable emergency busses are required in modes 1 through 4 (T8-3.8.1).

2. Only one operable emergency bus is required in modes 5 & 6. (T8-3.8.2).

3. The surveillance time interval for performing PT -80 during mode 1 is once every 7 days (T8-3.8.1.1).

4. The surveillance time interval for performing PT-80 during mode 1 with one diesel inoperable is within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and every 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter (T8-3.8.1 Condition A).

REACTOR OPERATOR Page 26 of 36 Revision 4, 07/31/2008

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

5. The technical specification time limit for a vital bus being powered by its regulating transformer is 7 days.

(TS-3.8.7 Condition A).

6. The length of time that a vital bus can be de-energized is 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months (TS-3.8.9 Condition B).

7. If a vital bus is de-energized, it must be re-energized within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or the plant must be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (TS-3.8.9 Action F).

Topic2.t2 Vita.lan(f ErrlergendYElectriCal** Distr.ibuti()n System TSBases 2.12 Objective U 5501 Explain the following concepts associated with the Vital and Emergency Electrical Distribution System technical specifications (TS-3.8.1 Bases, TS-3.8.2 Bases, TS-4.8.1 Bases, TS-4.8.2 Bases).

Why the AC and DC sources are required during modes 1 through 4

Why the AC and DC sources are required during modes 5 and 6 2.12 Content

1. The operability of the AC and DC power sources and associated distribution systems during modes 1-4 ensures that sufficient power will be available to supply the safety-related equipment required for; 1.1. Safe shutdown of the facility and 1.2. Mitigation and control of accident conditions within the facility.

1.3. The minimum specified independent and redundant AC and DC power sources and distribution systems satisfy the requirements of GDC 17.

2. The operability of the AC and DC power sources and associated distribution systems during modes 5 &

6 ensures that:

2.1. The facility can be maintained in the shutdown or refueling condition for extended time periods.

REACTOR OPERATOR Page 27 of 36 Revision 4,07/31/2008

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

90. 074-EG2.1.23 090INEW/IH/3/SROIII

. Given the following conditions:

Unit 1 has experienced a LOCA with multiple equipment failures.

The crew is implementing 1-FR-C.1, Response to Inadequate Core Cooling.

Attempts to establish safety injection flow have been unsuccessful.

The crew is at step 20 of 1-FR-C.1, which directs the operator to "Check if RCPs Should be Started."

Core-exit TCs (CETC) are 1250°F and rising at approximately 3°F/min.

All RCPs are stopped.

SG levels are as follows:

"A" -- 25% narrow-range and slowly increasing.

"B" -- 30% narrow-range and stable.

"C" -- 50% wide-range and slowly decreasing.

Containment pressure peaked at 38 psia, and is now 24 psia and slowly decreasing.

Based on these plant conditions, which ONE of the following identifies the actions required by 1-FR-C.1?

A"! Start "A" RCP; if CETCs are still increasing after "A" RCP is running, then start "B" RCP; if CETCs are still increasing after "B" RCP is running, then open PRZR PORVs and block valves.

B. Start "A" RCP; if CETCs are still increasing after "A" RCP is running, then start "B" RCP; if CETCs are still increasing after "B" RCP is running, then open all Reactor vent valves and PRZR vent valves.

C. Start ALL RCPs; if CETCs are still increasing after all RCPs are running, then open PRZR PORVs and Block Valves, and open all available RCS vent paths to containment.

D. Start ALL RCPs; if CETCs are still increasing after all RCPs are running, then go to 1-SACRG-1, Severe Accident Control Room Guideline Initial Response.

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

a. Correct. Operator must realize that starting 'C' RCP is not permitted due to insufficient level in the SG, the concern is creep rupture failure of the U-tubes.

b. Incorrect. Plausible since first portion of choice (start "A" RCP, then start "8" RCP) is correct, and second portion is an alternative means of establishing an RCS bleed path (similar to FR-H.1 bleed & feed).

c. Incorrect. Plausible since the candidate may assume that at this stage of the game it is desirable to throw everything you have at it in an attempt to cool the core, but as noted above starting 'C' RCP is specifically prohibited by the procedure, the second part is a procedural action based on Core Exit TCs continuing to increase so it flows with plausibility.

d. Incorrect. First part is plausible as noted above; the second part is a procedural action based on Core Exit TCs continuing to increase so it flows with plausibility.

Notes Inadequate Core Cooling Ability to perform specific system and integrated plant procedures during all modes of plant operation.

(CFR: 41.10/43.5/45.2 /45.6)

Tier: 1 Group: 2 Importance Rating: 4.3/4.4 Technical

Reference:

1-FR-C.1 Proposed references to be provided to applicants during examination: None Learning Objective:

Question History: new additional info:

NUMBER PROCEDURE TITLE REVISION 13 1-FR-C.1 RESPONSE TO INADEQUATE CORE COOLING PAGE 18 of 26 ACTION I EXPECTED RESPONSE RESPONSE NOT OBTAINED

_ CHECK CORE COOLING:

o a) Core Exit TCs - LESS THAN 1200°F o a) GO TO Step 20.

o b) At least two Hot Leg temperatures - LESS o b) RETURN TO Step 16.

THAN 345°F o c) RVLlS full range indication - GREATER o c) RETURN TO Step 16.

THAN 67%

19. GO TO 1-E-1, LOSS OF REACTOR OR SECONDARY COOLANT, STEP 15 NOTE: Normal conditions are desired but not required for starting the RCPs.

(

_ CHECK IF RCPs SHOULD BE STARTED:

o a) Core exit TCs - GREATER THAN 1200°F o a) GO TO Step 21.

b) Check if an idle RCS loop is available: b) Do the following:

o

Narrow range SG level - GREATER o 1) !E required, THEN reset both trains of THAN 11% [22%] ~ (9\'J~ .~ Phase A Isolation.

~,\>

o RCP in associated loop - o 2) !E required, THEN reset both trains of AVAILABLE AND NOT OPERATING Phase B Isolation.

o 3) Verify at least one Air Compressor is supplying Instrument Air System.

o !E NOT, THEN start at least one Air Compressor.

(STEP 20 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 13 1-FR-C.1 RESPONSE TO INADEQUATE CORE COOLING PAGE 19 of 26 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED

20. CHECK IF RCPs SHOULD BE STARTED:

(Continued)

4) Open the following valves to align Instrument Air to Containment:

0

1-IA-TV-102A 0

1-IA-TV-102B 0 5) Open both PRZR PORVs and block valves.

6) !E Core Exit TCs remain greater than 1200°F, THEN open the following RCS vent paths to Containment:

a. Open Reactor Vent Valves:

1-RC-SOV-1 01 A-2

1-RC-SOV-101 B-2

1-RC-SOV-101A-1

1-RC-SOV-101 B-1

b. Open PRZR Vent Valves:

o . 1-RC-SOV-102A-2 o . 1-RC-SOV-102B-2 o . 1-RC-SOV-102A-1 o . 1-RC-SOV-102B-1 o 7) GO TO Step 21.

o c) Start the RCP in one idle RCS loop o d) RETURN TO Step 20a

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95)

Response to Inadequate Core Cooling (1-FR-C.1) 4.1 Objective U 11670 List the following information associated with 1-FR-C.1, "Response to Inadequate Core Cooling."

Purpose of the procedure

Modes of applicability

Entry conditions

Major action categories

Conditions that result in leaving the procedure

( 4.1 Content

1. FR-C.1 provides guidance to operations personnel to respond to an extreme challenge to core heat removal and to restore adequate core cooling with minimum core damage.

2. FR-C.1 is applicable when the unit is initially in Modes 1 - 3.

3. FR-C.1 is entered from the Core Cooling Critical Safety Function Status Tree on either of two RED conditions:

3.1. Core exit TICs;::o: 1200°F, OR 3.2. All of the following:

3.2.1. RCS subcooling ::::: 25°F [75]

3.2.2. No RCPs running 3.2.3.Core exit TICs;::o: 700°F (but less than 1200°F) 3.2.4.RVLlS full range::::: 48%

REACTOR OPERATOR Page 32 of 99 Revision 14, 11/06/2008

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95)

4. The major action categories of FR-C.1 are:

4.1. Establish safety injection flow to the RCS.

4.2. Rapidly depressurize SGs to depressurize RCS.

4.3. Start RCPs and open all RCS vent paths to containment.

5. FR-C.1 is exited when core cooling has been reestablished as evidenced by any of the following sets of conditions.

5.1. Core exit TICs < 1200°F AND RVLlS full range indication> 48%.

5.2. Core exit TICs < 700°F.

5.3. Core exit TICs < 1200°F AND at least 2 hot leg temperatures < 345°F AND RVLlS full range indication> 67%.

4.2 Objective U 11671 Explain the following concepts associated with depressurizing steam generators in accordance with 1-FR-C.1, "Response to Inadequate Core Cooling."

Why intact steam generators are depressurized to atmospheric pressure

Why steam generator depressurization is temporarily stopped at 120 psig

How to determine whether a faulted steam generator or a ruptured steam generator should be used if no intact steam generators exist

Why reactor coolant pumps must be stopped before the steam generators are depressurized to atmospheric pressure 4.2 Content

1. The rapid secondary depressurization has been shown to be the most effective way to reduce RCS pressure.

1.1. RCS pressure must be reduced in order for the SI accumulators and low-head SI pumps to inject.

REACTOR OPERATOR Page 33 of 99 Revision 14, 11/06/2008

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95) 1.2. SG depressurization is continued until SG pressure is at atmospheric to ensure RCS pressure is reduced below the shutoff head of the low-head SI pumps.

1.2.1.Low-head safety injection should then begin to refill the reactor vessel, and provide some measure of core cooling.

2. The operator should stop the secondary depressurization when SG pressures are <120 psig and two RCS hot leg temperatures are below 355°F.

2.1. SG depressurization is stopped to prevent accumulator nitrogen injection into the RCS.

2.1.1. Nitrogen could collect in the RCS high points and produce either a "hard" PRZR bubble or cause gas binding and reduce heat transfer in the SG tubes.

3. If no intact SGs are available the operator is permitted to feed a faulted SG or steam a ruptured SG.

3.1. The following factors should be considered when determining whether to use a faulted SG or a ruptured SG, when no intact SGs exist:

3.2. Steaming a ruptured SG may create a path to the atmosphere for release of radioactive materials, or increase the spread of radioactivity to the secondary systems.

3.3. Feeding a faulted SG that has dried out could result in thermal stress, which could damage SG components (i.e. tubes).

4. In preparation for the subsequent depressurization of the SGs to atmospheric pressure, the RCPs are stopped due to the anticipated loss of Number 1 seal delta P.

4.1. Continued operation without adequate seal delta P may result in damage to the RCPs.

4.2. Since RCPs may be used as a last resort to cool the core, pump protection is still desired at this point.

REACTOR OPERATOR Page 34 of99 Revision 14, 11/06/2008

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95)

T()pic 4.3**. CqreCooling 4.3 Objective U 11672 Explain the following concepts associated with 1-FR-C.1, "Response to Inadequate Core Cooling."

Most effective means of restoring core cooling

Why, if inadequate core cooling still exists after attempts to depressurize steam generators, a reactor coolant pump must be started even if support conditions do not exist

Why, if inadequate core cooling still exists after the reactor coolant pumps are started one at a time, the Reactor Coolant System is depressurized using pressurizer power-operated relief valves

Why reactor coolant pumps must be stopped if hot-leg temperatures have decreased to less than the required value 4.3 Content

1. Re-initiation of high-pressure safety injection is the most effective method to recover the core and restore adequate core cooling.

(

2. The RCPs could be required to temporarily cool the core under highly voided RCS conditions.

2.1. The RCPs should be started when required even if all normal startup conditions have not been met.

2.1.1.Failure to start the RCPs at this point could result in core damage.

2.2. The actions of this step may provide temporary core cooling until some form of makeup flow to the RCS is established.

2.3. To temporarily restore core cooling, the operator is instructed to start RCPs one at a time until core exit TICs are less than 1200°F.

2.4. The RCPs should force two phase flow through the core, temporarily keeping it cool.

2.5. Even single phase forced steam flow will cool the core for some time provided the RCPs can be kept running and a heat sink is available.

2.6. RCP start has only a small chance of preventing core damage or melting.

3. If RCP restart is not effective in decreasing core exit TIC temperatures below 1200°F, the PRZR PORVs should be opened.

REACTOR OPERATOR Page 35 of 99 Revision 14, 11/06/2008

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95) 3.1. This may help reduce RCS pressure enough to cause low-head safety injection pumps to begin injecting cooling water into the core.

4. If the required conditions are satisfied, i.e., at least two RCS hot leg temperatures are less than 345°F and at least intermittent low-head SI flow is established, then the RCPs are no longer needed for core cooling and can be stopped.

4.1. The 345°F temperature criterion ensures that the core is cool and that very little superheat remains in the RCS.

4.2. Two RTDs are used to ensure that one RTD is not giving an erroneous reading.

(

REACTOR OPERATOR Page 36 of 99 Revision 14, 11/06/2008

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

91. 076-A2.02091INEW/1H/3/SROINAPS/S/20/200S1 Given the following conditions:

Both units are at 100% power.

1-SW-P-1A and 1-SW-P-1 B are running.

Service Water is throttled in accordance with O-OP-49.6, Service Water System Throttling Alignment.

The OATC observes 1-SW-P-1A discharge pressure is 0 psig, and motor current is 10 amps.

Which ONE of the following identifies the procedurally required action, and describes the status of the SW system AFTER the applicable pump is started?

A. Start 2-SW-P-1A; The Service Water System can perform its required safety function in the event of a DBA only if NO additional failures occur.

B. Start 2-SW-P-1A; The Service Water System can perform its required safety function in the event of a DBA assuming ONE additional failure.

C. Start 2-SW-P-1 B; The Service Water System can perform its required safety function in the event of a DBA only if NO additional failures occur.

D~ Start 2-SW-P-1 B; The Service Water System can perform its required safety function in the event of a DBA assuming ONE additional failure.

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

a. Incorrect. Plausible since although the candidate realizes the need to start a pump they may not havedetailed knowledge of the procedure which specifically requires that a pump is running on each header, to comply with that requirement 2-SW-P-1 B is the pump that must be started; second part is also incorrect but plausible since it would be true if service water were NOT throttled as given in the stem.

b. Incorrect. First part incorrect but plausible as discussed above; second part is true in that with one pump OOS and the system throttled the system can accomodate one additional single failure.

c. Incorrect. First part is correct, based on these plant conditions O-AP-12 Step 2c RNO directs the operator to start pumps to establish one running on each header, for this case since 1-SW-P-1A is tripped 2-SW-P-1 B will be started to establish flow in that header; second part also incorrect as discussed in distractor a.

d. Correct. First part is correct as discussed in Distractor c; second part is correct per TS 3.7.8 Basis (action A.1 describes why system is throttled and that the action maintains single failure proof) given the information provided in the stem stating that the system is throttled.

Notes Service Water System (SWS)

Ability to (a) predict the impacts of the following malfunctions or operations on the SWS; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those malfunctions or operations: Service water header pressure (CFR: 41.5 143.5 145/3 1 45/13)

Tier: 2 Group: 1 Importance Rating: 2.7/3.1 Technical

Reference:

O-AP-12 and TS 3.7.8 Bases 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 33 O-AP-12 LOSS OF SERVICE WATER PAGE (WITH NINE ATTACHMENTS) 1 of 15 PURPOSE To provide the instructions to use in the event of a loss of Service Water.

ENTRY CONDITIONS This procedure is entered when there is a loss of Service Water as indicated by any or all of the following:

Annunciator Panel "j" B-3, SERV WTR RETURN HOR LO FLOW, is LIT, or

Annunciator Panel "j" 0-3, SW PP 1-P1A, 2-P1A AUTO TRIP, is LIT, or

Annunciator Panel "j" E-3, AUX SW PP 1-P4 LO FLOW, is LIT, or

Annunciator Panel "j" H-3, SW PP 1-P1 B, 2-P1 B AUTO TRIP, is LIT, or

Annunciator Panel "j" 0-4, AUX SW PP 2-P4 LO FLOW, is LIT, or

Annunciator Panel "j" E-4, AUX SW PP 1-P4, 2-P4 AUTO TRIP, is LIT.

CONTINUOUS USE

NUMBER PROCEDURE TITLE REVISION 33 O-AP-12 LOSS OF SERVICE WATER PAGE 2 of 15 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE:

If a Reactor trip is initiated, then, to restore cooling to necessary plant equipment, this procedure should be performed in conjunction with Emergency Operating Procedures.

Loss of Service Water will result in loss of Component Cooling and Residual Heat Removal Systems for the affected unit(s). This procedure should be performed in conjunction with the appropriate Abnormal Procedures.

To ensure proper operation of important equipment, CC temperatures should be continuously monitored during loss of Service Water conditions.

In emergency situations, Attachment 8, OPERATION OF AUXILIARY SERVICE WATER PUMPS may be used to place Auxiliary Service Water Pumps in service. If the Auxiliary Service Water pumps are placed in service, then NRC reportability requirements should be evaluated.

If high volume blowdown of Service Water Reservoir is in service, then evaluate using O-OP-49.7, High Volume Blowdown Of The Service Water Reservoir, to secure blowdown.

1. CHECK SERVICE WATER SYSTEM INTEGRITY:

o a) Check Service Water Reservoir level - a) Do the following:

GREATER THAN 310 FEET o 1) IF the Service Water Reservoir is intact, THEN begin a makeup using either ATTACHMENT 8 or O-OP-49.3, SERVICE WATER RESERVOIR MAKEUP.

o 2) !E level cannot be restored, THEN place the Auxiliary Service Water Pumps in operation using either ATTACHMENT 8 or O-OP-49.2, SERVICE WATER SYSTEM LAKE-TO-LAKE OPERATION.

(STEP 1 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 33 O-AP-12 LOSS OF SERVICE WATER PAGE 3 of 15 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. CHECK SERVICE WATER SYSTEM INTEGRITY: (Continued) b) Check the following for flooding - NOT b) Initiate appropriate procedure based on INDICATED: location of flooding:

D

Auxiliary Building Sump level - D

O-AP-39.1, TURBINE BUILDING NORMAL FLOODING D

Chiller Room Sump level - NORMAL D

O-AP-39.2, AUXILIARY BUILDING FLOODING D

Turbine Building Valve Pit Sump level - NORMAL !E flooding is in other plant areas, THEN do the following:

D

No report of flooding D 1) Evaluate the need to isolate affected header or equipment.

D 2)!E required, THEN stop the Service Water Pumps on the affected header.

3) !E required, THEN isolate the affected header using either of the following:

D

Attachment 6 for "A" Service Water Header rupture OR D

ATTACHMENT 7 for "B" Service Water Header rupture

NUMBER PROCEDURE TITLE REVISION 33 O-AP-12 LOSS OF SERVICE WATER PAGE 4 of 15 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

2. CHECK SERVICE WATER SUPPLY HEADER STATUS:

o a) Verify at least one Supply Header - o a) Trip both Reactors.

INTACT o GO TO Step 14.

o b) Verify both Supply Headers - INTACT o b) Verify running or start at least one Service Water Pump on the intact Supply Header and GO TO Step 3.

o !E at least one Service Water Pump on the intact Supply Header cannot be started, THEN trip both Reactors and GO TO Step 14.

o c) Verify at least one Service Water Pump on o c) Start at least one Service Water Pump on each Supply Header - RUNNING each Supply Header.

o IF one Supply Header has NO running SW Pump, THEN align Service Water to both headers using ATTACHMENT 4.

(STEP 2 CONTINUED ON NEXT PAGE)

SW System B 3.7.8 B 3.7 PLANT SYSTEMS B 3.7.8 Service Water (SW) System BASES BACKGROUND The SW System provides a heat sink for the removal of process and operating heat from safety related components during a Design Basis Accident (DBA) or transient. During normal operation, and a normal shutdown, the SW System also provides this function for various safety related and nonsafety related components. The safety related function is covered by this LCO.

The SW System is common to Units 1 and 2 and is designed for the simultaneous operation of various subsystems and components of both units. The source of cooling water for the SW System is the Service Water Reservoir. The SW System consists of two loops and components can be aligned to operate on either loop. There are four main SW pumps taking suction on the Service Water Reservoir, supplying various components through the supply headers, and then returning to the Service Water Reservoir through the return headers.

Eight spray arrays are available to provide cooling to the service water, as well as two winter bypass lines. The isolation valves on the spray array lines automatically open, and the isolation valves on the winter bypass lines automatically shut, following receipt of a Safety Injection signal. The main SW pumps are powered from the four emergency buses (two from each unit). There are also two auxiliary SW pumps which take suction on North Anna Reservoir and discharge to the supply header. When the auxiliary SW pumps are in service, the return header may be redirected to waste heat treatment facility if desired. However, the auxiliary SW pumps are strictly a backup to the normal arrangement and are not credited in the analysis for a DBA.

During a design basis loss of coolant accident (LOCA) concurrent with a loss of offsite power to both units, one SW loop will provide sufficient cooling to supply post-LOCA loads on one unit and shutdown and cooldown loads on the other unit. During a DBA, the two SW loops are cross-connected at the recirculation spray (RS) heat exchanger supply and return headers of the accident unit. On a Safety Injection (SI) signal on either unit, all four main SW pumps start and the system is aligned for Service Water Reservoir spray operation. On a containment high-high (continued)

North Anna Units 1 and 2 B 3.7.8-1 Revision 0

SW System B 3.7.8 BASES BACKGROUND pressure signal the accident unit's Component Cooling (CC)

(continued) heat exchangers are isolated from the SW System and its RS heat exchangers are placed into service. All safety-related systems or components requiring cooling during an accident are cooled by the SW System, including the RS heat exchangers, main control room air conditioning condensers, and charging pump lubricating oil and gearbox coolers.

The SW System also provides cooling to the instrument air compressors, which are not safety-related, and the non-accident unit's CC heat exchangers, and serves as a backup water supply to the Auxiliary Feedwater System, the spent fuel pool coolers, and the containment recirculation air cooling coils. The SW System has sufficient redundancy to withstand a single failure, including the failure of an emergency diesel generator on the affected unit.

Additional information about the design and operation of the SW System, along with a list of the components served, is presented in the UFSAR, Section 9.2.1 (Ref. 1). The principal safety related function of the SW System is the removal of decay heat from the reactor following a DBA via the RS System.

APPLICABLE The design basis of the SW System is for one SW loop, in SAFETY ANALYSES conjunction with the RS System, to remove core decay heat following a design basis LOCA as discussed in the UFSAR, Section 6.2.2 (Ref. 2). This prevents the containment sump fluid from increasing in temperature, once the cooler RWST water has reached equilibrium with the fluid in containment, during the recirculation phase following a LOCA and provides for a gradual reduction in the temperature of this fluid which is supplied to the Reactor Coolant System by the ECCS pumps. The SW System also prevents the buildup of containment pressure from exceeding the containment design pressure by removing heat through the RS System heat exchangers. The SW System is designed to perform its function with a single failure of any active component, assuming the loss of offsite power.

The SW System, in conjunction with the CC System, also cools the unit from residual heat removal (RHR), as discussed in the UFSAR, Section 5.5.4, (Ref. 3) entry conditions to MODE 5 during normal and post accident operations. The time required for this evolution is a function of the number of CC and RHR System trains that are operating.

(continued)

North Anna Units 1 and 2 B 3.7.8-2 Revision 0

SW System B 3.7.8

(

BASES APPLICABLE The SW System satisfies Criterion 3 of 10 CFR SAFETY ANALYSES 50.36(c) (2) (ii).

(continued)

LCO Two SW loops are required to be OPERABLE to provide the required redundancy to ensure that the system functions to remove post accident heat loads, assuming that the worst case single active failure occurs coincident with the loss of offsite power.

A SW loop is considered OPERABLE during MODES 1, 2, 3, and 4 when:

a. Either a.l Two SW pumps are OPERABLE in an OPERABLE flow path; or a.2 One SW pump is OPERABLE in an OPERABLE flow path provided two SW pumps are OPERABLE in the other loop and SW flow to the CC heat exchangers is throttled; and

b. Either b.l Three spray arrays are OPERABLE in an OPERABLE flow path; or b.2 Two spray arrays are OPERABLE in an OPERABLE flow path, provided two spray arrays are OPERABLE in the other loop; and the spray valves for the required OPERABLE spray arrays in both loops are secured in the accident position and power removed from the valve operators; and

c. The associated piping, valves, and instrumentation and controls required to perform the safety related function are OPERABLE.

A required valve directing flow to a spray array, bypass line, or other component is considered OPERABLE if it is capable of automatically moving to its safety position or if it is administratively placed in its safety position.

North Anna Units 1 and 2 B 3.7.8-3 Revision 14

-- NUCLEAR DESIGN INFORMATION PORTAL-SW System B 3.7.8 BASES APPLICABILITY In MODES 1. 2. 3. and 4. the SW System is a normally operating system that is required to support the OPERABILITY of the equipment serviced by the SW System and required to be OPERABLE in these MODES.

In MODES 5 and 6. the OPERABILITY requirements of the SW System are determined by the systems it supports.

ACTIONS A.l If one SW System loop is inoperable due to an inoperable SW pump. the flow resistance of the system must be adjusted within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months by throttling component cooling water heat exchanger flows to ensure that design flows to the RS System heat exchangers are achieved following an accident. The required resistance is obtained by throttling SW flow through the CC heat exchangers. In this configuration. a single failure disabling a SW pump would not result in loss of the SW System function.

B.l and B.2 If one or more SW System loops are inoperable due to only two SW pumps being OPERABLE. the flow resistance of the system must be adjusted within one hour to ensure that design flows to the RS System heat exchangers are achieved if no additional failures occur following an accident. The required resistance is obtained by throttling SW flow through the CC heat exchangers. Two SW pumps aligned to one loop or one SW pump aligned to each loop is capable of performing the safety function if CC heat exchanger flow is r£properly throttled. However. overall reliability is reduced

~. becau a single failure disabling a SW pump could result in

~~ loss of t e e m unc lon. e one our lme re ects f~ the nee to minimize t e time that two pumps are inoperable

~ .t8 and CC heat exchanger flow is not properly throttled. but is a reasonable time based on the low probability of a DBA

. occurring during this time period. Restoring one SW pump to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months together with the throttling ensures that design flows to the RS System heat exchangers are achieved following an accident. The required resistance is obtained by throttling SW flow through the CC heat exchangers. In this configuration. a single failure disabling a SW pump would not result in loss of the SW System function.

North Anna Units 1 and 2 B 3.7.8-4 Revision 14

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 0-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)

Possible causes of service water lost

Conditions that would require the unit to be shutdown

Alternate cooling supplies to critical service water loads 22.8 Content

1. O-AP-12 provides guidance to the operator in response to either a complete or partial loss of the Service Water System.

2. This procedure is applicable during all modes of plant operation.

3. 0-AP-12 is entered when any off the following conditions exist:

3.1. Service water return header low flow alarm is actuated 3.2. Auxiliary service water pump low flow alarm(s) are actuated 3.3. Any service water or auxiliary service water pump auto trip alarm is actuated.

4. Possible causes of service water lost 4.1. Service Water System leak 4.1.1. Check for abnormal sump level in areas or buildings in which service water piping is located and investigate any report of flooding.

4.1.2. Low or decreasing service water reservoir level may be an indication of severe damage to system piping or the reservoir.

4.2. Failure of a running service water pump.

4.2.1.lf a running service water pump trips, attempt to start the other pump normally aligned to the same header, align a pump that normally supplies the other header to the affected header, or place an auxiliary service water pump in service to supply the affected header.

4.3. Loss of a return header flowpath.

4.3.1.lf no flow is indicated on one of the service water return headers, check for proper valve alignment to the spray arrays, the spray bypass, or the discharge tunnel.

REACTOR OPERATOR Page 136 of 158 Revision 30, 11/06/2008

STUDENT GUIDE FOR SERVICE WATER SYSTEM (13) 1.7.2.Maximum CCHX SW delta-Ps.

1.7.3.Three SW spray arrays in service on each header.

1.8. If only one SW pump is supplying a header with spray in service, observe the following:

1.8.1. Operation with a maximum of two spray arrays on the associated header is the preferred mode of operation to minimize MIC and sedimentation in spray array piping.

1.8.2.lf more than two spray arrays must be maintained open on the associated header to support plant conditions, notify Chemistry that biofilm sampler flow may not be sufficient.

2. During the winter months, the following guidelines are provided for controlling service water temperature:

2.1. Both service water headers should be aligned for full bypass flow.

2.2. All service water spray arrays should be removed from service.

2.3. Maintain service water flow to two component cooling heat exchangers on each service water header with a maximum obtainable delta-P.

Topic4~4rrs~3.7.8,nSel"ViCeWater$ystem-OpEjrating" .

4.4 Objective U 7697 Explain the following concepts concerning ITS-3.7.8, "Service Water (SW) System."

Number of service water pumps required operable

Requirements of action statement for Service Water System upgrades

Basis for maintaining the auxiliary service water pumps operable in modes 1 through 4 4.4 Content

1. The Service Water System is designed such that one OPERABLE service water loop is capable of removing the heat loads associated with a design basis accident on one unit coincident with a loss of off-site power on both units.

REACTOR OPERATOR Page 37 of 46 Revision 7,07/16/2008

STUDENT GUIDE FOR SERVICE WATER SYSTEM (13) 1.1. Although one OPERABLE service water loop is capable of performing the design function of the Service Water System, two OPERABLE service water loops are required by Technical Specification 3.7.8 when either unit is in modes one through four.

1.2. Having two OPERABLE service water loops ensures the Service Water System will be able to perform its design function in the event that one loop is lost due to a single failure.

1.3. A service water loop is considered OPERABLE when it meets all of the following conditions:

1.3.1.Either two service water pumps are operable, or one service water pump is operable with service water throttled and two service water pumps are operable on the other loop, 1.3.2.Either three spray arrays are operable, or two spray arrays are operable on each loop with their MOV's secured open and power removed, and 1.3.3.AII associated piping, valves, instrumentation, and controls required to perform safety related functions are OPERABLE.

1.4. A valve is considered operable if it is capable of automatically moving to, or is administratively placed in its safety position.

1.5. If one service water loop becomes inoperable due to an inoperable pump with either unit in mode one through four, the service water flow to the component cooling heat exchangers must be throttled within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

1.6. If two service water pumps become inoperable with either unit in mode one though four, service water flow to the component cooling heat exchangers must be throttle within one hour and one service water pump must be returned to operable status in 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

1.7. If a service water loop is inoperable for any reason than one inoperable service water pump, the service water loop must be restored to operable within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months unless the conditions that allow service water upgrade are met.

2. Technical Specification 3.7.8 allows a longer action time when service water upgrades are being performed.

2.1. It is permissible for one loop to be inoperable for up to 7 days for Service Water System upgrades

(

provided all the following conditions are met:

REACTOR OPERATOR Page 38 of 46 Revision 7,07/16/2008

STUDENT GUIDE FOR SERVICE WATER SYSTEM (13) t 2.1.1. The service water loop is inoperable as part of the service water upgrade being performed, 2.1.2.Three of the four service water pumps are operable (the third pump does not require auto start capabilities meaning it can be in PULL-TO-LOCK) and, 2.1.3.Both auxiliary service water pumps have been operable since initial entry into the action statement and remained operable during the 168 hours0.00194 days 0.0467 hours 2.777778e-4 weeks 6.3924e-5 months .

2.2. If at any time two service water loops become inoperable for reasons other than two service water pumps being inoperable, the following actions must be taken:

2.2.1. Both units must be placed in MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , and 2.2.2.Actions must be initiated to place both units in MODE 5 in 13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months .

3. Although the auxiliary service water pumps are not required for service water operability, they are required for extended service water outages and have been taken credit for in the 10 CFR 50 Appendix-R analyses for a service water pump house fire.

iOpiC4-.5 *.ITRM~3~I-11 ,"Ser'!iceWa.ter System-Shutdown II 4.5 Objective U 7698 Explain the following concepts concerning ITRM-3.7.11, "Service Water System--Shutdown."

Number of service water pumps and auxiliary service water pumps required operable

Requirements of action statement for inoperable service water pumps

Basis for maintaining the Service Water System operable in modes 5 and 6 4.5 Content

1. When both units are operating in mode 5-6, only one service water loop is required to be operable.

1.1. The operable loop will consist of two operable service water pumps (or two auxiliary service water pumps) and an operable flow path using either the service water reservoir or the Lake Anna reservoir as a heat sink.

REACTOR OPERATOR Page 39 of 46 Revision 7, 07/16/2008

STUDENT GUIDE FOR SERVICE WATER SYSTEM (13) 1.1. This applied potential opposes the natural potential developed when two dissimilar metals (piping and ground minerals) are immersed in an electrolyte solution (ground water).

1.2. If this natural potential is not opposed and neutralized, the underground service water piping is susceptible to galvanic corrosion.

4.13 Objective U 12011 Given a set of plant conditions, evaluate Service Water 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 service water 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 4.13 Content

This objective has "NO" content.

Integrated system knowledge will be required to answer any questions linked to this objective REACTOR OPERATOR Page 46 of 46 Revision 7, 07/16/2008

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

92. 077-AA2.03 092INEW//L/2/SROINAPS/S/20/200S1 Given the following conditions:

. Generator Load is 900 MWe.

Main generator hydrogen pressure is 60 psig.

Based on these conditions, which ONE of the following identifies the condition that exceeds a limit of the generator capability curve, and the action required to restore the parameter to within limits?

(Reference provided)

A. 250 MVAR OUT; restore VARS to within limits by raising on the voltage regulator B. 250 MVAR OUT; restore VARS to within limits by lowering on the voltage regulator C~ 250 MVAR IN; restore VARS to within limits by raising on the voltage regulator D. 250 MVAR IN; restore VARS to within limits by lowering on the voltage regulator Feedback

a. Incorrect. Plausible since candidate may not be able to relate the over/under excited condition given on the curve with the VARS in/out indication provided on the control board. Likewise with the effect of raising/lowering voltage depending on the condition (operation in the lead or in the lag).

b. Incorrect. Plausible as discussed in Distractor A.

c. Correct. 250 MVAR in place you below the 'safe operating limit' line and in order to reduce VARS to get above the line the voltage regulator must be raised.

d. Incorrect. Plausible, the VAR condition is correct, but lowering on the voltage regulator will exasperate the condition vice restoring it to within limits.

QUESTIONS REPORT for 2009 NRC SRO exam Validation 3 copy with SRC formatting - for submittal Notes Generator Voltage and Electric Grid Disturbances Ability to determine and interpret the following as they apply to Generator Voltage and Electric Grid Disturbances: Generator current outside the capability curve (CFR: 41.5 and 43.5 /45.5,45.7, and 45.8)

Tier:

Group:

Importance Rating: 3.5/3.6 Technical

Reference:

1-SC-4.3 Proposed references to be provided to applicants during examination: 1-SC-4.3 Learning Objective:

Question History: new additional info: At NAPS RO would not be expected to interpret this graph thus this falls under the SRO function.

1:'::SC-4'*.3

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HYDROGEN INNER-COOLED TURB1NE GENERATOR Approved by: >~~.' ,",' "

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1088.6,'MVA~ 0.90'PF~0"58*SCR. 75 PSIG Safety'and Operating Cotnmitte CALCULATED CAPABILITY CURVE

, Date: st~

, \'9.. ,:\ '.,' ., ",:~,'

STUDENT GUIDE FOR MAIN GENERATOR CONTROL AND PROTECTION SYSTEM (76)

Main Generator Operating Limitations 4.1 Objective U 7890 State the maximum main generator power allowed if one hydrogen cooler is removed from service.

4.1 Content

1. If one main generator hydrogen cooler must be removed from service then generator load must first be reduced to 80% or less.

4.2 Objective U 7891 Explain the actions that must be taken if all main transformer cooling is lost (1-0P-15.2).

4.2 Content

1. If all cooling is lost to the main transformers, the main generator must be removed from service and the main transformers must be de-energized.

4.3 Objective U 7885 Explain how the main generator capability curve is used to determine operating limits.

4.3 Content

1. The main generator capability curve is used to determine the maximum operating limits for the main generator as a function of real power (MW), reactive power (MVAR), and hydrogen pressure.

REACTOR OPERATOR Page 29 of 36 Revision 3,02/07/2008

STUDENT GUIDE FOR MAIN GENERATOR CONTROL AND PROTECTION SYSTEM (76) 1.1. The vertical axis displays reactive power and the horizontal axis displays real power. The generator operating point on the graph is at the intersection of the MWand MVAR readings.

1.2. The operating point must be maintained inside the curve that represents generator hydrogen pressure.

1.3. The capability curve can also be used to determine the maximum allowed reactive load, given current generator power and hydrogen pressure.

4.4 Objective U 7886 List the following information associated with the main generator capability curve.

Parameters that are used for determining the operating limits

Generator component that limits operation between a power factor of 0.0 and 0.9 (overexcited)

Generator component that limits operation between a power factor of 0.9 (overexcited) and 0.95 (underexcited)

Generator component that limits operation between a power factor of 0.0 and 0.95 (underexcited) 4.4 Content

1. Parameters used for determining the operating limits associated with the main generator are real power (MW), reactive power (MVAR), and hydrogen pressure.

2. Between a power factor of 0 and .9, over-excited, the limiting component is the generator field (rotor windings)

3. Between a power factor of .9 over-excited and .95, under-excited, the limiting component is the generator armature (stator windings),

4. Between a power factor of 0 and .95, under-excited, the limiting component is the generator stator core.

REACTOR OPERATOR Page 30 of 36 Revision 3, 02/07/2008

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

93. G2.1.28SRO 093INEW//L/3/SROINAPSII For the Emergency Condensate Storage Tank to be OPERABLE, it must contain a minimum volume of

_ _ _ _ _ ; the Basis for this requirement is to _ _ _ _ _ _ _ _ __

A. 100,000 gallons; maintain the unit in MODE 3 for 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

B. 100,000 gallons; maintain the unit in MODE 3 for 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months .

C'!I" 110,000 gallons; maintain the unit in MODE 3 for 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

D. 110,000 gallons; maintain the unit in MODE 3 for 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months .

Feedback

a. Incorrect. Plausible this is close to the requirement and the tank is sometimes called 'the 1OOk tank' (term differentiates it from the CST which is called the 300k tank); time is correct per the basis.

b. Incorrect. Volume incorrect as noted above; times are also incorrect but plausible especially since CC system has a design time of 16 hrs from RHR entry to cold shutdown.

c. Correct. Volume is correct per surveilance requirement of TS, time is correct per basis.

d. Incorrect. Volume is correct per surveilance requirement of TS, time is incorrect but plausible as discussed in Distractor b.

Notes Conduct of Operations 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:

1-E-1 and Background document Proposed references to be provided to applicants during examination: None Learning Objective:

Question History: new additional info:

ECST 3.7.6 3.7 PLANT SYSTEMS 3.7.6 Emergency Condensate Storage Tank (ECST)

LCO 3.7.6 The ECST shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3, MODE 4 when steam generator is relied upon for heat removal.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. ECST inoperable. A.1 Verify by 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months administrative means OPERABILITY of -AND Condensate Storage Tank. Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND A.2 Restore ECST to 7 days OPERABLE status.

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND B.2 Be in MODE 4, without 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months reliance on steam generator for heat removal.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.6.1 Verify the ECST contains ~ 110,000 gal. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months North Anna Units 1 and 2 3.7.6-1 Amendments 231/212

ECST B 3.7.6 B 3.7 PLANT SYSTEMS B 3.7.6 Emergency Condensate Storage Tank (ECST)

BASES BACKGROUND The ECST provides a safety grade source of water to the steam generators for removing decay and sensible heat from the Reactor Coolant System (RCS). The ECST provides a passive flow of water, by gravity, to the Auxiliary Feedwater (AFW)

System (LCO 3.7.5). The steam produced is released to the atmosphere by the main steam safety valves (MSSVs) or the steam generator power operated relief valves (SG PORVs). The AFW pumps operate with a continuous recirculation to the ECST.

When the main steam trip valves are open, the preferred means of heat removal is to discharge steam to the condenser by the nonsafety grade path of the steam dump valves. The condensed steam is returned to the hotwell and is pumped to the 300,000 gallon condensate storage tank which can be aligned to gravity feed the ECST. This has the advantage of conserving condensate while minimizing releases to the environment.

( Because the ECST is a principal component in removing residual heat from the RCS, it is designed to withstand earthquakes and other natural phenomena, including missiles that might be generated by natural phenomena. The ECST is designed to Seismic Category I to ensure availability of the feedwater supply. Feedwater is also available from alternate sources.

A description of the ECST is found in the UFSAR, Section 9.2.4 (Ref. 1).

APPLICABLE The ECST provides cooling water to remove decay heat and to SAFETY ANALYSES cool down the unit following all events in the accident analysis as discussed in the UFSAR, Chapters 6 and 15 (Refs. 2 and 3, respectively). For anticipated operational occurrences and accidents that do not affect the OPERABILITY of the steam generators, the analysis assumption is 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months in MODE 3, steaming through the MSSVs, followed by a 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months cool down to residual heat removal (RHR) entry conditions at the design cool down rate.

(continued)

North Anna Units 1 and 2 B 3.7.6-1 Revision 0

ECST B 3.7.6 BASES APPLICABLE The limiting event for the condensate volume is the large SAFETY ANALYSES feedwater line break coincident with a loss of offsite (continued) power. Single failures accommodated by the accident include the following:

a. Failure of the diesel generator powering the motor driven AFW pump to one unaffected steam generator (requiring additional steam to drive the remaining AFW pump turbine); and

b. Failure of the steam driven AFW pump (requiring a longer time for cooldown using only one motor driven AFW pump).

These are not usually the limiting failures in terms of consequences for these events.

A nonlimiting event considered in ECST inventory determinations is a break in either the main feedwater or AFW line near where the two join. This break has the potential for dumping condensate until terminated by operator action, since the Engineered Safety Features Actuation System (LCO 3.3.2, ESFAS) starts the AFW system and would not detect a difference in pressure between the steam generators

( for this break location. This loss of condensate inventory is partially compensated for by the retention of steam generator inventory.

The ECST satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO To satisfy accident analysis assumptions, the ECST must contain sufficient cooling water to remove decay heat for 30 minutes following a reactor trip from 102% RTP, and then to cool down the RCS to RHR entry conditions, assuming a coincident loss of offsite power and the most adverse single failure. In doing this, it must retain sufficient water to ensure adequate net positive suction head for the AFW pumps during cool down, as well as account for any losses from the steam driven AFW pump turbine, or before isolating AFW to a broken line.

The ECST level required is equivalent to a contained volume of 2 110,000 gallons, which is based on holding the unit in MODE 3 for 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months , or maintaining the unit in MODE 3 for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months followed by a 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months cooldown to RHR entry (continued)

North Anna Units 1 and 2 B 3.7.6-2 Revision 0

- NUCLEAR DESIGN INFORMATION PORTAL-ECST B 3.7.6 BASES LCO conditions within the limit of 100°F/hour. The basis for (continued) these times is established in the accident analysis.

The OPtRABILITY of the ECST is determined by maintaining the tank level at or above the minimum required level to ensure the minimum volume of water.

APPLI CAB I LITY In MODES 1, 2, and 3, and in MODE 4, when steam generator is being relied upon for heat removal, the ECST is required to be OPERABLE.

In MODE 5 or 6, the ECST is not required because the AFW System is not required.

ACTIONS A.l and A.2 If the ECST is not OPERABLE, the OPERABILITY of the backup supply, the Condensate Storage Tank, should be verified by administrative means within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months and once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter. OPERABILITY of the backup feedwater supply must include verification that the flow paths from the backup water supply to the AFW pumps are OPERABLE, and that the backup supply has the required volume of water available.

The ECST must be restored to OPERABLE status within 7 days, because the backup supply may be performing this function in addition to its normal functions. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable, based on operating experience, to verify the OPERABILITY of the backup water supply. Additionally, verifying the backup water supply every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is adequate to ensure the backup water supply continues to be available.

The 7 day Completion Time is reasonable, based on an OPERABLE backup water supply being available, and the low probability of an event occurring during this time period requiring the ECST.

B.l and B.2 If the ECST 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 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and in MODE 4, without reliance on the steam generator for heat removal, within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

North Anna Units 1 and 2 B 3.7.6-3 Revision 0

- NUCLEAR DESIGN INFORMATION PORTAL-ECST B 3.7.6 BASES SURVEILLANCE SR 3.7.6.1 REQUIREMENTS This SR verifies that the ECST contains the required volume of cooling water. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is based on operating experience and the need for operator awareness of unit evolutions that may affect the ECST inventory between checks. Also, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered adequate in view of other indications in the control room, including alarms, to alert the operator to abnormal deviations in the ECST level.

REFERENCES 1. UFSAR, Section 9.2.4.

2. UFSAR, Chapter 6.

3. UFSAR, Chapter 15.

North Anna Units 1 and 2 B 3.7.6-4 Revision 0

STUDENT GUIDE FOR AUXILIARY FEEDWATER SYSTEM (26-8)

ToPici2~23En'lergencyConclehsateStorageTank . (ECST) 2.23 Objective U 5926 List the following information associated with the emergency condensate storage tank.

Purpose

Source of makeup

Minimum level required in the 300,000-galion condensate storage tank to fill the emergency condensate storage tank sufficiently

Overflow path 2.23 Content

1. The purpose of the ECST is to store and supply water to the suction of the AFW pumps for use as a heat sink under emergency conditions.

(

2. The 300,000-galion condensate storage tanks provide makeup to the ECST.

3. The minimum level required in the 300,000-galion condensate storage tank to fill the ECST tank sufficiently is 62%.

4. The ECST overflows to the yard.

Topic 2.24 ECST **Levelll1c1 icatiof)*

2.24 Objective U 6041 State the following information associated with operation of the emergency condensate storage tank level indicators.

Differences between the unit-1 and unit-2 indicators REACTOR OPERATOR Page 53 of 53 Revision 4,07/16/2008

STUDENT GUIDE FOR AUXILIARY FEEDWATER SYSTEM (26-8)

Topi6****.~~.5 ECS,.. in*. 1\11 odes 1,.2, *and3,and4(ll'S-3. 7:6) 3.5 Objective U 5931 List the following information associated with the emergency condensate storage tank in modes 1, 2, 3, and 4 (ITS-3.7.6).

Minimum water volume required

Bases for the minimum water volume

Actions required if the minimum level is not available 3.5 Content

1. Technical Specification 3.7.6 requires an operable emergency condensate storage tank when the unit is operating in Mode 1, 2, or 3 and Mode 4 when steam generators are relied on for heat removal.

1.1. In order for the emergency condensate storage tank to be considered operable, it must have a minimum water volume of 110, 000 gallons.

2. The 110,000 gallons of water is sufficient to ensure the following criteria can be met:

2.1. Decay heat removal for 30 minutes after a reactor trip from 102% power, followed by an RCS cooldown to 350 F (RCS temperature for placing the Residual Heat Removal System in service).

2.1.1.This is in conjunction with a loss of offsite power and the most adverse single failure.

2.2. Holding the unit in Mode 3 for 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or; 2.3. Holding the unit in Mode 3 for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months followed by a 4-hour cooldown to RHR entry conditions.

3. If the minimum level is not available, then within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months operability of the main condensate storage tank must be demonstrated.

3.1. Additionally, the main condensate storage must be determined as being operable once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter until the emergency condensate storage tank (ECST) is restored to operable

(

status.

REACTOR OPERATOR Page 64 of 64 Revision 4, 07/16/2008

STUDENT GUIDE FOR AUXILIARY FEEDWATER SYSTEM (26-8) 3.2. Operability of the main condensate storage tank requires a minimum water volume of 62% and an operable flow path from the tank to the auxiliary feedwater pumps.

3.3. Reliance on the main condensate storage tank as a source of water to the auxiliary feedwater pumps is allowed for 7 days.

3.4. In other words, the ECST must be restored to operable status in 7 days.

3.5. Failure to meet this requirement mandates entry into Condition "S".

3.6. Condition "S" mandates that the unit is placed in Mode 3 in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and Mode 4 in 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

3.7. Operation in Mode 4 is such that the steam generators are not relied on for RCS heat removal.

3.8. This implies RHR is placed in service.

3.6 Objective U 6104 Draw a basic one-line drawing of the Auxiliary Feedwater System, including the following components.

Emergency Condensate Storage Tank

AFWpumps

Main Steam system connection including lV-111A and S

AFW pump recirculation lines

PCV-159A and 159S

MOV-100D and downstream orifice

HCV-100AlS/C

MOV-100AlS/C

Steam Generators

Service Water Connection

Fire Main Connection REACTOR OPERATOR Page 65 of 65 Revision 4, 07/16/2008

QUESTIONS REPORT

( for 2009 NRC SRO exam Validation 3 copy with SRC formatting - for submittal

94. G2.1.32 094INEW//H/3/SROINAPS//

Operators are performing 1-ES-1.1, SI Termination, and are preparing to isolate the BIT.

The OATC is not able to open 1-CH-MOV-1373, Charging Pump Recirc Header Isolation Valve.

Based on these plant conditions, which ONE of the following identifies the sequence of actions required in accordance with 1-ES-1.1?

A. Establish normal charging and maintain 25 gpm charging flow using 1-CH-FCV-1122 in MANUAL, then isolate the BIT.

B:' Establish normal charging and maintain 60 gpm charging flow using 1-CH-FCV-1122 in MANUAL, then isolate the BIT.

C. Isolate the BIT, then establish normal charging and maintain 25 gpm charging flow using 1-CH-FCV-1122 in MANUAL.

D. Isolate the BIT, then establish normal charging and maintain 60 gpm charging flow using 1-CH-FCV-1122 in MANUAL. .

Feedback

a. Incorrect. Plausible since 25 gpm is the normal value when preparing to reestablish letdown, however since the Charging pump recirc path is isolated this value is inadequate.

b. Correct. Per the caution and procedure step 60 gpm must be maintained to ensure adequate charging pump cooling.

c. Incorrect. As noted in Distractor A 25 gpm is the normal amount and if the recircs were open this would be the normal sequence.

d. Incorrect. Plausible as noted in distractor C; candidate may assume that momentarily reducing Charging flow below the minimum for a short period of time is acceptable under the circumstances.

QUESTIONS REPORT for 2009 NRC SRO exam Validation 3 copy with SRC formatting - for submittal Notes Conduct of operations Ability to explain and apply system limits and precautions.

(CFR: 41.10 /43.2 /45.12)

Tier: 3 Importance Rating: 3.8/4.0 Technical

Reference:

1-ES-1.1 Proposed references to be provided to applicants during examination: None Learning Objective:

Question History: new additional info:

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 2of24 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

1. RESET BOTH TRAINS OF SI o Perform 1-AP-0, RESETTING SI LOCALLY, while continuing with this procedure.

2. STOP ALL BUT ONE CHARGING PUMP AND PUT IN AFTER-STOP 0)_ CHECK RCS PRESSURE - STABLE OR o GO TO 1-ES-1.2, POST LOCA INCREASING COOLDOWN AND DEPRESSURIZATION, STEP 1.

NUMBER PROCEDURE TITLE REVISION 20 1-ES-1.1 SI TERMINATION PAGE 30f24 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) IF 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 D

1-CH-MOV-1289B o

1-CH-MOV-1275C D 3) Open 1-CH-FCV-1122 in Manual to establish 60 gpm Charging flow.

\ v-J~ 4) Close BIT Inlet Isolation Valves:

'!'-ovY""' I ~l/V") D

1-SI-MOV-1867A l Q:iSO' v-(STEP 4 CONTINUED ON NEXT PAGE) o

1-SI-MOV-1867B

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) IF 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-1H1-2N D1, BIT Inlet o

1-SI-MOV-1867B Isolation Valve Circuit Breaker, 1-SI-MOV-1867A o

1-EE-BKR-1 J1-2N 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-S I-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 6of24 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

6. CONTROL CHARGING FLOW TO MAINTAIN IF any isolated SG pressure is decreasing in PRZR LEVEL an uncontrolled manner, THEN do NOT proceed until one of the following conditions is met:

o

Faulted SG depressurization stops OR o

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:

o a) Manually start Charging Pumps and align BIT as necessary.

o b) GO TO 1-ES-1.2, POST LOCA COOLDOWN AND DEPRESSURIZATION, STEP 1.

0- CHECK RCS PRESSURE - STABLE OR INCREASING o IF any isolated SG pressure is decreasing in an uncontrolled manner, THEN do NOT proceed until faulted SG depressurization stops.

IF SGs are NOT faulted, THEN do the following:

o a) Manually start Charging Pumps and align BIT as necessary.

o 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 15 of 24 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

18. ESTABLISH LETDOWN: o Establish excess letdown using 1-0P-8.5, OPERATION OF EXCESS LETDOWN.

o a) Put 1-CH-PCV-1145 in MANUAL and open to 100% \v-e.

\ JIr fo s.

b) Open the following:

~? ~~~~J" o

1-CH-TV-1204A ~u' ~c ~~"~

o \.rf J \\ ~ ~...(\)

1-CH-TV-1204B

\ r7~0(V* 0-' V o

1-CH-LCV-1460A ).;~S~~# ~~ ~~J o

1-CH-LCV-1~ (J'- -0 VJ va o c) Open 1-CH-FCV-1122 to establish at least 25 gpm charging flow d) Open one of the following Letdown Orifice 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 in AUTO o f) Maintain seal injection flow to each RCP between 6 gpm and 8 gpm

STUDENT GUIDE FOR EMERGENCY PROCEDURES (92)

Safety Injection Termination (1-ES-1.1) t TQpiC12;11 ~ES-1 .. GeneraJlnformation 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 EMERGENCY PROCEDURES (92) 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-0.2A 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

STUDENT GUIDE FOR EMERGENCY PROCEDURES (92) 1.1. Once the boron injection tank has been isolated, the recirculation valves should remain closed.

1.2. This requirement is necessary in order to prevent diluting the contents of the in-service boric acid storage tank.

REACTOR OPERATOR Page 128 of 187 Revision 19, 11/06/2008

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

95. G2.2.21SRO 095INEW//L/3/SROINAPSII In accordance with OP-AA-102, Operability Determination, the _ _ _ _ _ _ _ _ is responsible for approving prompt Operability Determinations (ODs).

Facility Safety Review Committee review and recommendation for approval _ _ _ _ _ _ __

A'I Shift Manager; is ONLY required for Operability Determinations that involve compensatory measures.

B. Supervisor - Shift Operations; is ONLY required for Operability Determinations that involve compensatory measures.

C. Shift Manager; is required for ALL Operability Determinations.

D. Supervisor - Shift Operations; is required for ALL Operability Determinations.

Feedback

a. Correct. This person (by title) has the final approval authority and FSRC review and recommendation is only required fort he case where compensatory measures must be put in place.

b. Incorrect. Plausible since the candidate who is not knowledgable of the process would default to this individual since he is involved and is by definition the serior license on site; second part is correct as noted above.

c. Incorrect. First part is correct; second part plausible since again the candidate who is not knowledgable of the process would likely conclude that FSRC involvement would be manditory under all circumstances.

d. Incorrect. First part incorrect but plausible as discussed in distractor b; second part also incorrect but plausible as discussed in distractor c.

(

QUESTIONS REPORT for 2009 NRC SRO exam Validation 3 copy with SRC formatting - for submittal Notes Equipment Control Knowledge of pre- and post-maintenance operability requirements.

(CFR: 41.10/43.2)

Tier: 3 Importance Rating: 2.9/4.1 Technical

Reference:

VPAP-2003 Proposed references to be provided to applicants during examination: None Learning Objective:

Question History: new additional info:

DOMINION OP-AA-102 REVISION 3 PAGE 27 OF 48

(

4.2 The following documents completed as a result of the implementation of this procedure are not Quality Assurance records and are not required to be transmitted to Records Management:

None 5.0 ADMINISTRATIVE INFORMATION 5.1 Commitments None 5.2 Responsibilities 5.2.1 Discipline Supervisor The Discipline Supervisor is responsible for:

a. Concurring with the OD evaluation conclusions and Immediate Operability Determination or RAS conclusions when documented on Attachment 3 or 4, when used.

b. Ensuring OD evaluations are updated to reflect any testing or analysis done that affect the initial OD evaluation.

c. Initiating and ensuring OD closeout.

5.2.2 Manager Nuclear Operations The Manager Nuclear Operations is responsible for ensuring the OD process is implemented to permit timely disposition of SSC operability or functionality.

5.2.3 Shift Manager (SM)

The Shift Manager (SM) or designated Operations SRO is responsible for:

a. Performing immediate and prompt ODs or FAs for degraded or nonconforming SSCs.

b. Providing a time frame for completion of the OD evaluations or FAs.

c. Ensuring personnel assigned an operator action are technically and physically qualified to perform the control action and have been briefed on their responsibilities.

d. Directing Engineering or other appropriate departments to provide support for the OD evaluations or FAs.

e. Coordinating the implementation of compensatory measures.

INFORMATION USE

DOMINION OP-AA-102 REVISION 3 PAGE 29 OF 48 5.2.10 Facility Safety Review Committee The Facility Safety Review Committee is responsible for:

a. Reviewing and recommending for approval an OO/RAS that include compensatory measures.

b. Reviewing the 6 month review of open 00 evaluations and any RAS that is active.

c. Reviewing and recommending for approval corrective action extension requests and revisions of 00 evaluations or FAs for SSCs that are not fully qualified.

5.3 Definitions 5.3.1 Administrative Control Specific actions that must be taken or controlled by station personnel to ensure proper operation of station components, adherence to regulatory requirements, and safety of personnel and equipment when substitute operating methods are used in lieu of normal operating methods or when methods must be established to limit access or prevent operation.

5.3.2 Allowed Outage Time (AOT) I Completion Time (CT)

The time specified in the TS action requirement in which conformance to the conditions of the LCO must be met. This time limit is the allowable outage time permitted to restore an inoperable SSC to operable status or for restoring parameters to within specified limits prior to taking action to place the plant in a mode or condition in which the specification no longer applies.

5.3.3 Automatic (Auto)

The associated equipment is available for service and will start, activate, and control without additional action required.

5.3.4 Certificate of Compliance The certificate issued by the NRC that approves the design of a spent fuel storage cask in accordance with the provisions of Subpart L of 10 CFR Part 72.

INFORMATION USE

DOMINION OP-AA-102 REVISION 3 PAGE 46 OF 48 Prompt Operability Determination

'Dominion< Documentation OP-AA-102 - Attachment 5 Page 1 of 1 Condition Report Number 00 Number B. Extent of Condition

e. CLB Requirements or Commitments D. SSC Specified Safety Function E. Impact on sse Ability to Perform Specified Safety Function F. Operability Statement, including Basis for Determination G. Required Compensatory Measures and How They result in an Accepted Condition H. References (e.g., FSAR, TS, TS Bases), if applicable vlJ-v~,efi.uility Determ ination; SSC Structu res, an ponents; TS-Technical Specifications; 0 & M-Operations and Maintenance; CLB-Current Licensing Basis Form No. 730906,",U9 2008)

STUDENT GUIDE FOR ADMINISTRATIVE PROCEDURES (100) 1.2. Determining corrective actions to resolve discrepancies found by Independent and Simultaneous Verification.

1.20 Objective U 13125 Explain the three conditions that allow the shift manager or unit supervisors to modify or delete independent verification or simultaneous verification requirements within a procedure without being considered a procedure change (VPAP-1405).

1.20 Content

1. Explain the three conditions that allow the shift manager or unit supervisors to modify or delete independent verification or simultaneous verification requirements within a procedure without being

( considered a procedure change.

1.1. Verification may be waived by a Shift Manager or Unit Supervisor. Indirect Independent Verification or Simultaneous Verification should be considered if radiation exposure is a concern. Verification may be waived under the following conditions:

1.1.1. Emergency 1.1.2.High Radiation Area if excessive radiation exposure would result 1.1.3.very High Radiation Area 1.21 Objective U 13628 Explain the responsibilities of the following individuals associated with determining the operability of systems, structures, and components (OP-AA-1 00, SOER-98-1).

SENIOR REACTOR OPERATOR Page 30 of 81 Revision 23, 09/19/2008

STUDENT GUIDE FOR ADMINISTRATIVE PROCEDURES (100)

Shift manager

Shift Technical Advisor 1.21 Content

1. The Shift Manager (SM) or designated Operations SRO is responsible for:

1.1. Performing immediate and prompt ODs or FAs for degraded or nonconforming SSCs.

1.2. Providing a time frame for completion of the 00 evaluations or FAs.

1.3. Ensuring personnel assigned an operator action are technically and physically qualified to perform the control action and have been briefed on their responsibilities.

1.4. Directing Engineering or other appropriate departments to provide support for the 00 evaluations or FAs.

1.5. Coordinating the implementation of compensatory measures.

1.

2. The STA/Engineering Personnel are responsible for:

2.1. Providing technical information to the SM for determining SSC operability or functionality.

2.2. Performing independent reviews of SSC 00 evaluations and RECO or RAS documentation involving compensatory measures when documented in the 00 database (MPS) or on Attachments 3 or 4 (SPS, NAPS, KPS), when used.

1.

T()pic1 .* 22 Deviati6n **(PI-AA-~oo) 1.22 Objective U 13629 Explain the shift manager's responsibilities associated with station condition reports (PI-AA-200).

1.22 Content

1. The Shift Manager is responsible for:

1.1. Promptly reviewing condition reports to determine initial safety implications, component operability, Technical Specification compliance, and immediate reportability requirements in accordance with VPAP-2802, Notifications and Reports.

SENIOR REACTOR OPERATOR Page 31 of 81 Revision 23, 09/19/2008

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

96. G2.2.5 096IMODIFIEDINAPSIHI4/SROINAPSII An activity has been proposed that constitutes a test not described in the UFSAR. Additionally, performance of the activity conflicts with the requirements of the Technical Specifications.

Which ONE of the following identifies the requirements to conduct the activity?

A. The activity will screen out in the 10 CFR 50.59 review; prior approval from the NRC is NOT required.

B. The activity will screen out in the 10 CFR 50.59 review; prior approval from the NRC i.§. required.

C. The activity will require a 10 CFR 50.59 Evaluation; prior approval from the NRC is NOT required.

D!' The activity will require a 10 CFR 50.59 Evaluation; prior approval from the NRC i.§. required.

Feedback

a. and b. are incorrect but plausible since the student may assume that since a change to the license is required, that 10CFR50.59 does not apply. This is the case if a change to Tech Specs is the only aspect of a proposed change, since the change also involves (as stated) a change, test, or experiment not described in the FSAR, both processes must be performed. The candidate who does not have detailed knowledge of the process may conclude that based on a satisfactory License ammendment requests that would demonstrate no significant hazadrs exist that there may (or may not) be a requirement to have prior approval.

c. is also incorrect but is plausible since if unfamiliar with the process the student may perceive that an evaluation is all that is needed to proceed.

d. is correct since 1) the screening has determined that the activity constitutes a test not described in the FSAR so it must be further evaluated against the eight criteria of 10 CFR 50.59 c.ii, and 2) since there is a TS conflict a license ammendment request must be submitted and approval obtained prior to conducting the activity.

QUESTIONS REPORT

) for 2009 NRC SRO exam Validation 3 copy with SRC formatting - for submittal Notes Equipment Control Ability to explain and apply system limits and precautions.

(CFR: 41.10/43.2/45.12)

Tier: 3 Importance Rating: 2.2/3.2 Technical

Reference:

Design Change VPAP 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).

STUDENT GUIDE FOR ADMINISTRATIVE PROCEDURES (100) 1.38 Content

1. Explain the requirements associated with the interpretations of Technical Specification Interpretations (TSls) and Technical Requirements Interpretations (TRls).

1.1. TSls and TRls are intent statements for conditions that do not have a conclusively established, specific method of compliance for which several interpretations are possible. TSls and TRls cannot be used to change the intent of a TSITR requirement or TSITR Basis, and must be consistent with the Station design and licensing bases. Station Personnel are responsible for identifying the need for TSls and TRls.

1.2. NRC Administrative Letter 98-10 states that imposing administrative controls in response to an improper or inadequate TS is considered an acceptable short-term action. A TSI may be used to impose conservative administrative controls, along with appropriate procedural controls, until a TS amendment is implemented.

1.39 Objective U 13643 Define the following terms associated with safety evaluations (VPAP-3001).

Activity Checklist

Operating license

Safety review 1.39 Content

1. Define Activity Checklist 1.1. A process to document whether an activity (including changes, tests, and experiments), not included in 6.2 requires a Regulatory Review as defined in VPAP-3001.

SENIOR REACTOR OPERATOR Page 54 of 81 Revision 23, 09/19/2008

STUDENT GUIDE FOR ADMINISTRATIVE PROCEDURES (100) 1.1.1.When the responses to the General Screening questions are all "NO", then it can be concluded that the activity cannot impact nuclear plant safety or regulations; the activity "screens out".

1.1.2.Further review against 10 CFR 50.59 and 10 CFR 72.48 is not required and the activity may be implemented without a Regulatory Evaluation or prior NRC approval.

1.1.3.An activity screening is not a regulatory screen.

2. Define Operating License 2.1. The Operating License consists of:

2.1.1. The Facility Operating License, 2.1.2.The Technical Specifications (Appendix A to the Operating License), and 2.1.3.The Environmental Protection Plan (Appendix B to the Operating License).

2.1.4.For ISFSI, this consists of the Materials License and Technical Specifications (Appendix "A" to the Materials License).

3. Define Safety Review 3.1. The review is completed to determine that a change is safe.

3.1.1.A Safety Review provides the conclusion that a proposed change, test, or experiment is safe, based on the technical/engineering information that supports the proposed change.

3.1.2.This is documented in a manner consistent with the safety significance of the activity.

Note: See Activity Screening for information about the safety review when the activity being reviewed screens out from further review with the completion of an Activity Screening Checklist.

3.1.3.This safety and review process is entered when other interfacing processes identify a proposed activity as having a link to safety.

3.1.4.When this process is applied, the Safety Review Checklist ensures this review is completed and provides for explanations as to why a change is safe.

SENIOR REACTOR OPERATOR Page 55 of 81 Revision 23, 09/19/2008

STUDENT GUIDE FOR ADMINISTRATIVE PROCEDURES (100)

)

3.1.5. Reviews completed within other processes or as a result of this Admin Procedure (VPAP-3001) examine the proposed activity against the requisite elements of the program(s), and as such form the basis for determining that a proposed activity is safe.

3.1.6.A change, test, or experiment involving the facility or procedures is controlled in accordance with change control processes established by admin procedures and standards intended to comply with 10 CFR 50, Appendix "8".

3.1.7.Completed program reviews (e.g., the Program Review checklist of STD-GN-0001) may be substituted for the safety review questions contained in Attachment 3, where specified within this procedure (VPAP-3001), to document technical/engineering information supporting the change and forming the conclusion that the change is safe.

3.1.8.A safety review includes a review of the applicable documents that collectively establish plant descriptions and associated technical data, including:

3.1.8.1. Programs 3.1.8.2. Plans 3.1.8.3. Parameters as described in Attachment 3.

1.40 Objective U 15935 Describe the following concepts associated with SOER-96-01, Control Room Supervisor, Operational Decision Making and Teamwork.

Areas in which safety culture weaknesses existed

Indications associated with each safety culture weakness

lessons learned from these industry experiences 1.40 Content SOER 96-1 l

/

SENIOR REACTOR OPERATOR Page 56 of 81 Revision 23, 09/19/2008

DOMINION VPAP-3001 REVISION 15 PAGE 3 OF 80 1.0 PURPOSE This procedure establishes responsibilities and requirements for evaluating proposed changes, tests, or experiments having a link to safety by:

Performing an Activity Checklist to determine when an activity requires further safety and regulatory reviews

Reviewing proposed activities against program requirements and criteria to determine that the activities are safe

Directing the use of DNAP-3004, when required, to document Regulatory Screens and Evaluations, as required 2.0 SCOPE NOTE: UFSAR and ISFSI SAR are meant to be referenced together where the term "UFSAR" is used.

NOTE: The use of ISFSI throughout this procedure includes associated SSCs related to the ISFSI.

NOTE: When required, Regulatory Screens and Regulatory Evaluations are performed in accordance with DNAP-3004 and are synonymous with 50.59 / 72.48 Screen and 50.59 /72.48 Evaluation.

2.1 This procedure applies to the following consistent with the 10 CFR 50.59 and 10 CFR 72.48 regulations and associated guidance:

Proposed changes to the facility described in the UFSAR (including proposed changes to items incorporated by reference)

Proposed design changes (temporary or permanent)

Proposed changes to plant procedures outlined, summarized or completely described in the UFSAR (including new procedures, procedure revisions, and procedure deletions) v

~s-t~(~~~~pe~~~ts~~~~~;~j"~,!h;~clUding new or revised plant tests or experiments)

Other specified processes

Revisions to NRC-approved analysis methodology or assumptions described in the UFSAR

Proposed compensatory actions to address degraded or non-conforming conditions.

, . ** n Nuclear jjjJ.~ Domlnlo Administrative Procedure

Title:

Dominion Program for 10 CFR 50.59 and 10 CFR 72.48 - Changes, Tests, and Experiments Procedure Number Revision Number Effective Date and Approvals On File DNAP-3004 3 SPS NAPS MPS KPS Revision Summary The following change was made for consistency between Substep 3.2.4.b and Attachment 4, 50.59/72.48 Screen:

Revised Substep 3.2.4.b as follows:

OLD - "If the activity exceeds or potentially affects a DBLFPB, answer the last question YES.

An evaluation is required."

NEW - "If the activity exceeds or potentially affects a DBLFPB, answer the last question YES."

Process / Program Owner: Director Nuclear Engineering

DOMINION DNAP-3004 REVISION 3 PAGE20F32 TABLE OF CONTENTS Section Page 1.0 PURPOSE ........................................................................................................................... 3 2.0 SCOPE ................................................................................................................................ 3 3.0 INSTRUCTIONS ............................................................................................................... 4 3.1 Applicability Determination .................................................................................... 4 3.2 Screening .................................................................................................................... 5 3.3 Evaluation .................................................................................................................. 8 4.0 RECORDS ........................................................................................................................ 10 4.1 Screens .................... ................................................................................................. 10 4.2 Evaluations .............................................................................................................. 10 5.0 ADMINISTRATIVE INFORMATION ......................................................................... 10 5.1 Commitments .......................................................................................................... 10 5.2 Responsibilities ...... .................................................................................................. 11 5.3 Definitions ..................... ........................................................................................... 12 5.4 References ................................................................................................................ 15 ATTACHMENTS 1 Editorial and Non-Technical Changes ........................................................................... 16 2 Processes and Documents ................................................................................................ 18 3 Procedures ........................................................................................................................ 21 4 50.59/72.48 Screen - 730943(Apr 2008) .......................................................................... 23 5 Guidance for Filling Out Screen Form ................... ....................................................... 25 6 50.59/72.48 Evaluation - 730947(Apr 2008) ................................................................... 29 7 50.59/72.48 Supplemental Page(s) - 731026(Sep 2006) ................................................. 32

DOMINION DNAP-3004 REVISION 3 PAGE 3 OF32 1.0 PURPOSE This procedure provides guidance for performing the following elements in support of changes, tests, or experiments as required by 10 CFR 50.59 and 10 CFR 72.48, and is part of the Regulatory review process:

Applicability determination

Screening

Evaluation 2.0 SCOPE This procedure only addresses the 10 CFR 50.59 and 10 CFR 72.48 requirements of change and configuration control processes. The other aspects are specified in the governing procedure for that process.

DOMINION DNAP-3004 REVISION 3 PAGE 4 OF 32 3.0 INSTRUCTIONS NOTE The following references available from the Dominion network provide detailed guidance for implementing 50.59172.48.

NEI 96-07, Revision 1 [Reference 5.4.1]

NEI 96-07, Appendix B [Reference 5.4.2]

USA 50.59 Resource Manual [Reference 5.4.8]

3.1 Applicability Determination NOTE Applicability Determination is based upon the following provisions in 10 CFR 50.59 and 72.48.

10 CFR 50.59 (c)(4) The provisions in this section do not apply to changes to the facility or procedure when the applicable regulations establish more specific criteria for accomplishing such changes.

10 CFR 72.48 (c)(4) The provisions in this section do not apply to changes to the facility or procedures when the applicable regulations establish more specific criteria for accomplishing such changes.

3.1.1 Editorial and Non-Technical Changes For clearly editorial or non-technical changes to procedures, other controlled documents, the FSAR, or any document incorporated by reference, 10 CFR 50.59172.48 does not apply and this procedure can be exited; however, some processes conservatively require this review (See Attachment 1 for examples of editorial and non-technical changes). Process the proposed change in accordance with the applicable program/process/procedure.

3.1.2 Exempt ProcesseslDocuments If all aspects of the proposed activity are controlled by processes for which another regulation specifies the NRC review process, 50.59172.48 does not apply and this procedure can be exited; however, some processes conservatively require this review (See Attachment 2 for guidance). Process the proposed change in accordance with the applicable program/process/procedure.

DOMINION DNAP-3004 REVISION 3 PAGE 5 OF 32 3.1.3 Exempt Procedure Changes For non-technical or managerial procedures and procedures for exempted processes, 10 CFR 50.59/72.48 does not apply and this procedure can be exited (See Attachment 3 for guidance). Process the proposed change in accordance with the procedure change process.

3.1.4 Changes Affecting Multiple Processes If some aspects of the proposed activity are controlled exempt processes and some aspects are not, 10 CFR 50.59/72.48 must be applied to the non-exempt aspects of the activity.

3.2 Screening NOTE Screening is the process for determining whether a proposed activity requires a 10 CPR 50.59/72.48 evaluation to be performed.

If it is obvious a Technical Specification or Operating License change is needed, this procedure can be exited. If, after determining a Technical Specification or Operating License change is not needed, it is obvious an Evaluation is required, Subsection 3.2 can be skipped.

3.2.1 Documentation Document the screening on Attachment 4, 50.59/72.48 Screen. Provide sufficient detail such that a reviewer or auditor can understand the basis for determining why an evaluation was not required.

3.2.2 Plant and Document Identification NumberlRevision Identify on the screening form the plant and the parent document / activity title or number being screened.

3.2.3 Part I of the Screening Form

a. Summarize the proposed activity and describe the scope of the activity being screened.

DOMINION DN REv.

PAGE

b. Document the results of the search of the Technical Specifications, FSAR atlU orner documents incorporated by reference. Identify all relevant functions, performance requirements, and evaluations and cite the TS or FSAR section, or document where this information is located.

c. {fd~~~if;-i~,~~~,~~c~i~i~;';~q~i;~~"'acha~g~t~th~T~~h~i'~'~i's~~~ifi~~~E1;or a license

,;:"~" -,,' ,'",.,. -"-"'-.~ '~"'~'r,< ~.,,_ ~,,' ".""_~._, ** ,~,__ *** __ ""~,,,,,"-" "~_~"_~v<""~,""~.A'~*-.~.,,*,,,,o,,,,.y_, "_"?""~'M_", ",""" ""_."".,",""~,,,,,,,,,,,,,,.' ,,,,-,,,.,,, ",'$~-''_~_''''''=-=" ____ '".J-"~"""",,p, ""~,,.. <~;,~" ~.~:,_~~<~~ ,._> ~ _,_~_, <_'_

amendment request. If NO, explain the basis for this conclusion.(,IfYES, prqs:~ss;c'..""

7 ch~g~~,I?~!:"th~ijI~£g.I1i£al_~p,~~_i.fi~at;igll, and License Amendment proc~~-~' a~~~iD

-this proced~re.*

"'-,."".""._""'~",..,..~~" 0 "" -""~ .,.,.,

d. If the activity is fully bounded by an approved screen or evaluation for another activity or fully bounded by a change submitted for NRC approval, document this in Part lA. Reference shall be made to the appropriate documents retrievable from Nuclear Records or will be attached to this screen. Go to Step 3.2.6.

3.2.4 Part II of the Screening Form Part II of the screening form determines if the activity involves a design function N~ (---describ~~.i.~,:~~,.ES~ affec~s a ~~!¥!.:.~~~~~.!~~it. for.Jl!~ssio~ product barrier, ~.

'nrvotves a method of evaluatlOrt~ test or ex~~~~~~~~~,~>

-,---~-.--""~.- ...

a. Answer each ofthe questions YES or NO. If there is any uncertainty, respond YES.

If any questions is YES, identify the specific design function, method of evaluation, or Design Basis Limit for a Fission Product Barrier (DBLFPB) involved.

b. If the activity exceeds or potentially affects a DBLFPB, answer the last question YES.

c. If all of the answers in Part II are NO, Part III is not applicable. An evaluation is not required. Check the Not Applicable box in Part III and go to Step 3.2.6.

DOMINION DNAP-3004 REVISION 3 PAGE 7 OF32 3.2.5 Part III of the Screening Form NOTE NEI 96-07 Revision 1 provides detailed guidance and definitions to be used in answering the questions in Part III of the screening fonn.

Part III of the screening fonn determines if the activity involves adverse effects.

Attachment 5, Guidance for Filling Out Screen Fonn, provides detailed questions to be considered in answering Part III.

a. If Part III is checked Not Applicable, go to Step 3.2.6. An evaluation is not required.

b. Complete Part III by answering each of the applicable questions YES or NO. If any answer in PART 111.1,111.2,111.3, or IlIA is YES, an evaluation is required.

c. If the answer in PART 111.1 is NO, a complete written basis shall be provided.

d. For Part 111.2, if not checked Not Applicable, and the answer is NO, a complete written basis shall be provided.

e. For Part 111.3, if not checked Not Applicable, and the answer is NO, a complete written basis shall be provided.

f. For Part IlIA, if not checked Not Applicable, and the answer is NO, a complete written basis shall be provided.

3.2.6 Part IV of the Screening Form

a. Identify whether an evaluation is required. If required, perfonn the evaluation in accordance with Step 3.3.

b. Indicate whether there is a change required to the FSAR or any document incorporated by reference. Process the change appropriately.

c. Provide completed screen to a peer reviewer for review and comment.

d. The completed fonn shall be signed by the preparer and reviewer. If the preparer is not qualified, the fonn shall also be signed by a qualified co-signer. The reviewer shall also be qualified and may not be the co-signer.

e. If it is determined an evaluation is not needed, the completed fonn shall be attached to the document/activity/change package and processed in accordance with the applicable process.

DOMINION DNAP-3004 REVISION 3

\ PAGE80F32 i

f. If an evaluation is needed, the screen form need not be retained. While not required, it is recommended that the screen be retained with the document/activity/change package if it will provide useful information for the evaluation.

3.3 Evaluation NOTE The evaluation determines if NRC approval is required prior to implementing the proposed activity.

3.3.1 Documentation The evaluation shall be documented on DNAP-3004, Attachment 6, 50.59172.48 Evaluation. Provide sufficient detail such that a reviewer or auditor can understand the basis for determining why NRC approval is not required.

3.3.2 Plant and Document Identification NumberIRevision Identify on the evaluation form the plant and the parent document / activity title or number being evaluated.

3.3.3 Evaluation Number Obtain an Evaluation Number from the facility safety review committee Coordinator or Document Administration. Identify the Evaluation number on the evaluation form.

3.3.4 Part I of the Evaluation Form NOTE NEI 96-07 Revision 1 provides detailed guidance and definitions to be used in answering the questions in Part II of the evaluation form.

a. Summarize the proposed activity and describe the specific aspects of the activity being evaluated.

b. Document the results of the search of the Technical Specifications, FSAR and other documents incorporated by reference. Identify all relevant functions, performance requirements, and evaluations and cite the TS or FSAR section, or document where this information is located.

DOMINION DNAP-3004 REVISION 3 PAGE90F32 3.3.5 Part II of the Evaluation Form

a. If the answer to any of the eight criteria/questions is YES, NRC approval is required prior to implementing the activity.

b. All eight criteria questions shall be addressed, except as follows:

1. If a method of evaluation described in the FSAR is not involved, Criteria question eight does not require a response. In this case, the response to question eight is N/A.

2. If the only reason for performing the evaluation is that a FSAR-described method of evaluation is affected, only criteria question eight requires a response. In this case, the response to questions one through seven are N/A.

c. A complete written basis for each question shall be provided (except as noted in Step 3.3.5.b. above). A simple yes or no, or rephrasing the question to become a statement is not an adequate basis. Refer to NEI 96-07, Revision 1, for guidance.

3.3.6 Part III of the Evaluation Form

a. Complete Part III of the evaluation form by indicating whether a license amendment is required (i.e., NRC approval) prior to implementing the activity.

3.3.7 Part IV of the Evaluation Form

a. Complete Part IV of the evaluation form by providing a summary of the activity/

change and the evaluation. This summary is used to prepare the required periodic report to the NRC. The summary shall include a description of what is being changed and why, why an evaluation was required, what design functions and/or methods of evaluation were affected, and a summary of the answers to the eight evaluation criteria questions.

b. Provide completed evaluation to a peer reviewer for review and comment.

c. The completed form shall be signed by the preparer and reviewer. If the preparer is not qualified, the form shall also be signed by a qualified co-signer. The reviewer shall also be qualified and may not be the co-signer.

d. The completed evaluation shall be presented to the applicable station approving body (facility safety review committee) for concurrence that NRC approval is not required

DOMINION DNAP-3004 REVISION 3 PAGE 10 OF 32

e. The completed evaluation shall be approved and signed by the applicable station approving body (facility safety review committee) chairperson (or designee).

f. If a license amendment is necessary initiate a license request per the applicable procedure.

g. The completed approved form shall be separately transmitted to Records Management or Document Administration for record retention and retrieval.

3.3.8 Evaluation Revision

a. Preparation, review, and approval of the evaluation revision are accomplished as described in the above steps, except as follows:

1. The revised evaluation shall include the reason for the revision and clearly indicate the changes (e.g., change bars).

2. The revised evaluation shall be identified with the same Evaluation Number as the original, followed by a revision number.

4.0 RECORDS 4.1 Screens Completed regulatory screen forms are attached to the document/activity change package.

They are not separately indexed for records retention.

4.2 Evaluations Completed regulatory evaluation forms are attached to the document/activity change package.

They are also separately indexed for records retention.

4.3 NRC Report A report every 24 months, as required by 10 CFR 50.59 or 10 CFR 72.48, is submitted to the NRC to describe all Changes, Tests, and Experiments made to the plant(s) or ISFSI for which a 50.59172.49 evaluation has been documented.

5.0 ADMINISTRATIVE INFORMATION 5.1 Commitments None

DOMINION DNAP-3004 REVISION 3 PAGE 11 OF 32 5.2 Responsibilities 5.2.1 Preparers of Regulatory ScreenslEvaluations Preparers are responsible for ensuring they meet the applicable qualification requirements. In the case of a non-qualified preparer, a qualified co-signer shall take equal responsibility with the non-qualified preparer.

Preparers are responsible for:

Performing screens and evaluations in accordance with this procedure

Completing the applicable forms and supporting documentation

Obtaining the appropriate document number

Presenting evaluations to the facility safety review committee for review and approval.

Attaching screens and evaluations to the document/activity change package.

5.2.2 Reviewers of Regulatory ScreenslEvaluations

) Reviewers are responsible for ensuring that they meet the applicable qualification requirements. In the case of a non-qualified preparer, the co-signer and reviewer can not be the same individual. The reviewer reviews the required forms for technical adequacy, completeness and procedure adherence.

5.2.3 Supervisors and Managers Supervisors and managers are responsible for ensuring preparer of screens and evaluations is qualified. The supervisors and managers provide support and guidance in completing the required forms.

5.2.4 Facility Safety Review Committee The facility safety review committee is responsible for reviewing evaluations and support documentation. These committees concur that the proposed activity may be implemented without prior NRC approval and recommends evaluation approval to the Chairman.

5.2.5 Facility Safety Review Committee Chairperson The Chairperson is responsible for approving all evaluations and subsequent revisions.

Approval signature indicates concurrence with the evaluation conclusion.

DOMINION DNAP-3004 REVISION 3 PAGE 120F32 5.2.6 Facility Safety Review Committee Coordinator The coordinator is responsible for documenting facility safety review committee approval of evaluations and assuring that the evaluation is transmitted to Records Management or Document Administration for records retention.

5.2.7 Nuclear Engineering Director Nuclear Engineering is responsible for monitoring and maintaining the 50.59/

72.48 process, which includes, but is not limited to the following: procedure maintenance, monitoring procedure implementation, assisting in training and qualification and mentoring preparers and reviewers. The Director schedules periodic self-assessments of the 50.59/72.48 program and implementation and shall provide information from the 50.59/72.48 program to the Management Safety Review Committee as required.

5.3 Definitions NOTE NEI 96-07 and Appendix B to NEI 96-07 provide a complete set of definitions relevant to the performance of screens and evaluations.

5.3.1 Change A modification or addition to, or removal from, the facility or spent fuel storage cask design or procedures that affects a design function, method of performing or controlling a design function, or an evaluation that demonstrates that intended design functions will be accomplished.

DOMINION DNAP-3004 REVISION 3 PAGE 13 OF 32 5.3.2 Departure from a method of evaluation described in the FSAR (as updated) used in establishing the design bases or in the safety analyses

Changing any of the elements of the method described in the FSAR (as updated) unless the results of the analysis are conservative or essentially the same;

Changing from a method described in the FSAR to another method unless that method has been approved by NRC for the intended application; or

Changing from a method described in the FSAR to another method unless the method is documented as providing results that are essentially the same as, or more conservative than, either the previous revision of the same methodology or another methodology previously accepted by the NRC.

5.3.3 Facility or spent fuel storage cask design as described in the final safety analysis report (FSAR)(as updated)

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

The design and performance requirements for such SSCs described in the FSAR (as updated), and

The evaluations or methods of evaluation included in the FSAR (as updated) for such SSCs which demonstrate that their intended function(s) will be accomplished.

5.3.4 Final Safety Analysis Report (as updated)

The Final Safety Analysis Report (or Final Hazards Summary Report) submitted in accordance with 10 CFR 50.34 / 72.56 /72.244, as amended and supplemented, and as updated per the requirements of 10 CFR 50.71(e) / 50.72 (f) /72.70172.248, as applicable. For the purposes of this document, FSAR, Final Safety Analysis Report (as updated), UFSAR, USAR and ISFSI SAR are synonymous. The FSAR also includes documents incorporated by reference. The list of documents is plant specific (e.g., for Kewaunee, the list includes: TS Bases, TRM (including COLR), commitments, EQ plan, RG 1.97 plan, Fire plan, Appendix R description, Fire Protection Program and Analysis, ODCM, REMM, Station Blackout Design Description and Control Room Habitability Study).

)

DOMINION DNAP-3004 REVISION 3 PAGE 140F32 5.3.5 Procedures as described in the Final Safety Analysis Report (as updated)

Those procedures that contain information describe in the FSAR (as updated) such as how structures, systems, and components are operated and controlled (including assumed operator actions and response times).

5.3.6 Tests or experiments not described in the final safety analysis report (as updated)

Any activity where any structure, system or component is utilized or controlled in a manner which is either:

Outside the reference bounds of the design bases as described in the final safety analysis report (as updated)

Inconsistent with the analyses or descriptions in the final safety analysis report (as described) 5.3.7 Design Basis That information which identifies the specific functions to be performed by a structure, system or component of a facility, and the specific values or ranges of values chosen for controlling parameters as reference bounds for design. These values may be:

Restraints derived from generally accepted "state of the art" practices for achieving functional goals, or

Requirements derived from analysis (based on calculation and!or experiments) of the effects of a postulated accident for which a structure, system, or component must meet its functional goals.

5.3.8 Design Basis Functions Functions performed by systems, structures and components (SSCs) that are:

Required by, or otherwise necessary to comply with, regulations, license conditions, orders or technical specifications, or

Credited in licensee safety analyses to meet NRC requirements.

DOMINION DNAP-3004 REVISION 3 PAGE 15 OF32 5.3.9 Design Functions FSAR-described design bases functions and other SSC functions described in the FSAR that support or impact design bases functions. Implicitly included within the meaning of design function are the conditions under which intended functions are required to be performed, such as equipment response times, process conditions, equipment qualification and single failure.

Design functions may be performed by safety related SSCs or non-safety related SSCs and include functions that, if not performed, would initiate a transient or accident that the plant is required to withstand. SSCs may have preventative, as well as mitigative design functions.

5.3.10 Regulatory Review The process of reviewing changes as required by 10 CPR 50.59 and 10 CFR 72.48. A Regulatory Review will include screening (with an Activity Checklist (VPAP-3001, applicable to Dominion - Virginia) and/or a Regulatory Screen) and/or a Regulatory Evaluation. The Regulatory Screen and Regulatory Evaluation are documented in accordance DNAP-3004. Regulatory Screen is synonymous with 50.59 /72.48 Screen and Regulatory Evaluation is synonymous with 50.59 / 72.48 Evaluation.

5.4 References 5.4.1 NEI 96-07, Revision 1, "Guidelines for 10 CFR 50.59 Implementation," November 2000 5.4.2 NEI 96-07, Appendix B, "Guidelines for 10 CFR 72.48 Implementation," March 5, 2001 5.4.3 Regulatory Guide 1.187, "Guidance for Implementation of 10 CFR 50.59, Changes, Tests, and Experiment," November 2000 5.4.4 NEI 97-04 Appendix B, "Guidance and Examples for Identifying 10 CPR 50.2 Design Bases," November 2000 5.4.5 Regulatory Guide 1.186, "Guidance and examples for Identifying 10 CFR 50.2 Design Bases," December 2000 5.4.6 NEI 98-03, Revision 1, "Guidelines for Updating Final Safety Analysis Reports," June 1999 5.4.7 Regulatory Guide 1.181, "Content of the Updated Final Safety Analysis Report in Accordance with 10 CPR 50.71(e)," September 1999 5.4.8 USA 50.59 Resource Manual

DOMINION DNAP-3004 REVISION 3 PAGE 160F32 ATTACHMENT 1 (Page 1 of 2)

Editorial and Non-Technical Changes NOTE In some cases, the procedure controlling the process will conservatively require the application of 50.59/72.48. In this case, follow the process procedure.

10 CFR 50.59/72.48 does not apply for permanent or temporary changes to procedures and other controlled documents which are considered clearly editorial or non-technical as defined below.

Editorial changes are typically corrections or clarifications. Non-technical changes do not affect the control of plant equipment, do not involve operator actions, or affect assumed operator response times. Changes that introduce new failure modes require a 50.59 / 72.48 Screening.

1. Plant Procedures and Other Controlled Documents NOTE Reordering procedural steps may require a screen unless the procedure previously allowed those steps to be done out of sequence.

Changes to Table of Contents, page numbers, and/or step numbering

Correction to grammar and misspelled words.

Changes to reflect approved changes to document numbers, revision numbers, or other references to documents.

Format modification (e.g., tablellist organization, Writer's Guide).

Adding component description or numbering for clarification.

Adding or modifying clearly non-technical information (e.g., add step to log data, add/modify steps on how to complete and distribute forms, modify steps due to organizational changes.

Rearranging clarifying information so the document is more easily understood.

Subdividing a procedure step into sub-steps provided no details are deleted.

DOMINION DNAP-3004 REVISION 3 PAGE 17 OF32 ATTACHMENT 1 (Page 20f2)

Editorial and Non-Technical Changes

2. Plant Drawings, Figures, Tables, and Attachments

Provide corrections to spelling.

Split or consolidate existing drawings, figures, tables or attachments, provided no information is added, deleted or removed.

Redraw figures or drawings for clarity (no information added or removed).

Change references to other drawings, figures, or documents, or revise reference arrows that have the wrong coordinates.

Add or revise identification numbers to components already shown on the drawing (without changing the classification of the component).

Provide corrections to as-built drawings, provided the original markup received a screen or evaluation which remains consistent with the correction.

3. FSAR NOTE A screen may be required for a change to the FSAR to reflect the original as-built configuration of the plant, even though no physical plant configuration change ever took place since the original plant construction.

In some cases, the procedure controlling the process will conservatively require the application of 50.59/72.48. In this case, follow the process procedure.

Provide clarification not affecting meaning or substance of information

Correct internal inconsistencies

Designate or relocate historical information (e.g., initial licensing or startup information).

Remove excessive detail (e.g., simplify, incorporate by reference)

Remove obsolete or redundant information (e.g., not required to be in the FSAR).

DOMINION DNAP-3004 REVISION 3 PAGE 18 OF 32 ATTACHMENT 2 (Page 1 of 3)

Processes and Documents NOTE In some cases, the procedure controlling the process will conservatively require the application of 50.59172.48. In this case, follow the process procedure.

Table 1:

Document or Applicable Is 50.59 Is 72.48 Procedure Process Regulation Applicable? Applicable?

72.212 Evaluation N/A Yes NAF-245 Calculations and 10 CPR 50, Appendix No No STD-GN-0041 Evaluations which do B NDCM3.7 not establish a 10 CFR 72 Subpart G NDCM 3.11 methodology of DCM Chapter 5 evaluation described in the UFSAR.

Computer Software 10 CFR 50, Appendix No No DNAP-0306 independent of Plant B Hardware and not used 10 CFR 72 Subpart G as part of a method of evaluation described in the UFSAR.

Degraded/Non -con- 10 CFR 50, Appendix No No DNAP-1408 forming condition to be B (Corrective Action) restored to original con- 10 CFR 72 Subpart G dition in a timely man- (Corrective Action) ner Degraded/Non Con- Yes Yes DNAP-1408 forming Condition accepted as is or not restored in a timely manner Degraded/Non Con- Yes Yes DNAP-1408 forming Condition Compensatory Measure

DOMINION DNAP-3004 REVISION 3 PAGE 19 OF32 ATTACHMENT 2 (Page 20f3)

Processes and Documents Table 1:

Document or Applicable Is 50.59 Is 72.48 Procedure Process Regulation Applicable? Applicable?

Design Change Yes Yes VPAP-0301 DCM Chapter 3 ECCS Analysis 10 CFR 50.46 No N/A NAF-237 SAM-5F None Emergency Plan 10 CFR 50.54(q) No N/A VPAP-2601 EPCP-0007 MP-26-EPA-FAP02 Environmental 10 CFR51 No No Protection Plan MP-2S-EMS-FAPOO.l Fire Protection and License Condition No Yes VPAP-2401 Mitigation Plan SECY-00-0203 MP-24-FPP-FAPl.1 & 1.2 FSARChange Yes Yes VPAP-2S03 MP-03-LBM-SAP03 Inservice Inspection 10 CFR 50.55a(g) No N/A VPAP-I003 Plan CEN 101B Inservice Test Plan 10 CFR 50.55a(f) No N/A VPAP-I003 MP-24-IST-FAP01.2 Replacement with 10 CFR50.65 No No VPAP-070S Equivalent Component MPM-3.02 Maintenance Activities 10 CFR 50.65 No Yes VPAP-OSI5 MP-20-WM-FAP02.1 NRC Commitments NEI99-04 No No VPAP-2S01 MP-03-LDM-FAP06 License Renewal 10 CFR 54 No No DNAP-OSI9 Operating License or 10 CFR 50.90 No No VPAP-2SlO Technical Specification 10 CFR 72.44 Change MP-03-LBM-SAP04 Post Modification Test- 10CFR 50.65 No Yes ENAP-0025 ing DCM Chapter 3 MP-02-NO-FAP01.2

DOMINION DNAP-3004 REVISION 3 PAGE 20 OF 32 ATTACHMENT 2 (Page 3 of3)

Processes and Documents Table 1:

Document or Applicable Is 50.59 Is 72.48 Procedure Process Regulation Applicable? Applicable?

Quality Assurance Plan 10 CPR 50.54(a) No No DNAP-2812 10 CFR n,212(b)(6)

Radiological Environ- Technical Specification No Yes VPAP-2103N mental Monitoring and Administrative Control VPAP-2103S Offsite Dose Calcula- MP-22-REC-FAPOl.l tions Manual Radiation Protection 10 CFR 20 No No Program APM 1.1.2 Reactor Vessel Surveil- 10 CFR 50 Appendix H No No lance Security Plan 10 CFR 5b.54(p) No No VPAP-2505 10 CPR n.212(b)95) SPIP 51 Technical Require- Yes N/A VPAP-2807 ments Manual MP-03-LBM-SAP04 Technical Specification Yes Yes VPAP-281O Bases MP-03-LBM-SAP04 Temporary Design Yes Yes STD-GN-OOl Change not associated WClO with Maintenance Temporary Design 10 CPR 50.65 No Yes VPAP-1403 Change associated with WClO maintenance and in place less than 90 days during power opera-tions

DOMINION DNAP-3004 REVISION 3 PAGE 21 OF32 ATTACHMENT 3 (Page 1 of 2)

Procedures 10 CFR 50.59 and 10 CFR 72.48 does not apply to new/revised procedures or changes to other controlled documents which clearly do not affect or control plant equipment (non-technical or managerial). In addition 10 CFR 50.59 and 10 CFR 72.48 do not apply for a change to any procedure or other controlled document which is clearly editorial/non-technical (See ATTACHMENT 1).

10 CFR 50.59 and 10 CFR 72.48 applies to procedures/changes having the potential to directly or indirectly affect operation, control, or configuration of SSCs described in the FSAR. This typically includes changes or activities involving any of the following:

Operation of plant SSCs

Acceptance criteria or operation limits for plant SSCs

Parts, materials, chemicals, lubricants, etc. to be used in plant SSCs

Compensatory actions to address plant SSCs out of service, or to address nonconforming conditions

Operator access to operating areas for the plant NOTE Certain Maintenance and Chemistry procedures may be the only document controlling design basis parameters; such as valve stroke time, setpoints, torque values, and materials. If this is the the case, 10 CFR 50.59/72.48 must be applied to changes in these parameters.

10 CFR 50.59 typically would not apply for procedures or changes which do not permanently alter design, performance requirements, or operation or control of systems, structures, or components (SSCs). This typically includes routine maintenance, I&C, surveillance and test, and inspection procedures. However, for 72.48, since the Maintenance Rule (10CFR50.65) does not apply to the ISFSI, 72.48 may apply to maintenance procedure changes.

In any case, the applicability determination may indicate that another regulation applies to the procedure or document change. In all cases, Technical Specification and Quality Assurance requirements continue to apply.

DOMINION DNAP-3004 REVISION 3 PAGE 22 OF 32

)

ATTACHMENT 3 (Page 20f2)

Procedures The following table provides guidance for determining when a 50.59 review should be considered for new/revised procedures.

Procedure Type Is 50.59 Applicable? Is 72.48 Applicable?

Administrative No No Alarm Response Procedures Yes Yes Calculations and Evaluation Process No No Chemistry Procedures (exceptions No No noted above)

Design Change Process No No Emergency Operating Procedures Yes No Emergency Plan Implementing Proce- No No dures Fire Plan Procedures No Yes Health Physics Procedures No Yes Instrumentation - General No Yes Instrumentation Control No Yes Maintenance -Corrective No No Yes Maintenance - General No Yes Maintenance - Preventive No Yes Operations Process and Work Process No No Operating Procedures Yes Yes Reactor Test Procedures Yes No Refueling Procedures - Fuel Handling Yes Yes Refueling Procedures- Non-Fuel No No Handling Refueling Procedures - Spent Fuel Yes Yes Pool Operation Security Procedures No No Severe Accident Management Guide- No No line Special Test Procedure Yes Yes Surveillance Procedure that meets the No Yes definition of Maintenance Training Procedures No No

DNAP-3004 REVISION 3 PAGE 23 OF 32

')

~rt.. 50.59/72.48 Screen

~DOminion DNAP-3004 - Attachment 4 Page 1 of 2 ApRlli;able Station Parent Document! Revision

. uNorth Anna Power Station Applicable Unit DSurry Power Station DUnn 1 DUnit2 DMilistone Power Station DKewaunee Power Station DUnn 3 DISFSI B. Search the Technical Specifications and FSAR including documents incorporated by reference. Describe relevant FSAR described design function(s), performance requirements, and methods of evaluation of the affected SSCs, and where this information is described in the Technical Specifications and FSAR. Identify Technical Specification and FSAR sections reviewed.

C. Does the Activny involve a change to the Operating License or Technical Specifications? DYES DNO If the answer is YES, process Operating License or Technical Specification change according to the appropriate procedure and N/A this block. If the answer is NO, describe the basis for the conclusion. 0 N/A Basis:

1. Does the proposed activity involve a change to a Safety Analysis?

2. Does the proposed activny involve a change to an SSC(s) credited in the Safety Analysis? DYES DNO 3 Does the proposed activity involve a change to an SSC(s) that support SSC(s) credited in the Safety DYES DNO Analyses?

4. Does the proposed activity involve a change to an SSC(s) whose failure could initiate a transient (e.g., reactor trip, loss of feedwater, etc.) or accident? DYES DNO

5. Does the proposed activity involve FSAR-described SSC(s) or procedure controls that perform functions that are required by or otherwise necessary to com ply with, regulations, license conditions, orders or DYES DNO Tech nical Specifications?

6. Does the activity involve a method of evaluation described in the FSAR? DYES DNO

7. Is the activity a test or experiment? (i.e., a non-passive activity which gathers data) DYES DNO

8. Does the activity exceed or potentially affect a design basis limit for a fission product barrier (DBLFPB)? DYES DNO If the answers to all of the questions are NO, answer PART III as Not Applicable, and proceed to Part IV. An evaluation is not needed: IF any of the above questions are checked YES, identify in Part III below, the specific design basis function, method of evaluation, DBLFPB, or the test or experiment.

Key: DBLFPB-Design Basis Limit for a Fission Product Barrier Form No. 730943(Apr2008)

DNAP-3004 REVISION 3 PAGE 24 OF 32 50.59/72.48 Screen DNAP-3004 - Attachment 4 Page 2 of 2 111.1 Design Basis Functions Does the actiVITY have an adverse effect on a design lunction? DYES DNa II the answer is YES an Evaluation is required. II the answer is NO, describe the basis lor the conclusion.

Basis:

111.2 Method of Evaluation II the activity does not involve a method 01 evaluation, then N/A this block. 0 N/A Does the activity result in a change to a method 01 evaluation as described in the FSAR? DYES DNa II the answer is YES, an Evaluation is required. If the answer is NO, describe the basis lor the conclusion (attach additional discussion as necessary).

Basis:

111.3 Design Basis Limits for a Fission Product Barrier (DBLFPB)

II the activity does not involve a DBLFPB, then N/A this block. DN/A Does the activity change or exceed a D BLFPB? 0 YES DNa II the answer is YES, an Evaluation is required. lithe answer is NO, describe the basis lor the conclusion (attach additional discussion as necessary).

Basis:

111.4 Tests or Experiments II the activity is not a test or experiment, then N/A this block. 0 N/A Is the proposed test or experiment not described in the FSAR AN D Does it utilize an SSC outside the relerence bounds lor design or is inconsistent with the analyses and descriptions in the FSAR?

DYES DNa II the answer is YES, an Evaluation is required. II the answer is NO, describe the basis for the conclusion:

Basis:

Check all that apply

1. An Evaluation is: DNOT REQUIRED 0 REQUIRED (Provide 50.59172.48 Evaluation in accordance with Subsection 3.3)

2. A change to the FSAR and/or any docum ent incorporated by relerence is:

o NOT REQUIRED 0 REQUIRED (Process change in accordance with applicable procedure)

Additional Comments:

Key: SSC-Structures, Systems, and Components Form No. 730943(Apr200B)

I DOMINION DN RE~

PAGEl ATTACHMENT 5 (Page I of 4)

Guidance for Filling Out Screen Form Part I Part I.A Description Provide a brief description of the activity being screened. It is acceptable to reference other documents for additional details. If not all of the aspects of the activity are being addressed, clearly distinguish those aspects being screened from those aspects not being screened.

If the scope of this activity is QIDpl<;leli£:Qjin4~j a 50.59/Zb1~_~&,Qr.eeQQ.r evaluation appn:~~ocifor another activity or by a NRC submittal for a ~hnical Specifi~ license Gi~,!!g~~i~'?s unnecessary to fill out the remainder of Part I, Part II or Part III. Document in Section I.A that this activity is fully bounded and either attach the bounding screen or evaluation or provide a reference that is retrievable from Nuclear Records.

Part I.B Search Provide a brief description of the document search that was performed to identify functions and methods of evaluations potentially impacted by the activity. The documentation is meant to demonstrate that a comprehensive search was performed. However, it is not necessary to identify those functions where the disposition is obvious. The description should identify the specific reference (e.g., FSAR or TS section number) where the function and method of evaluation is documented.

Part I.C Impact on Technical Specifications and Operating License The Technical Specifications and Operating License, including license conditions, exemptions and orders should be reviewed to determine if these documents are impacted by the activity. A broad interpretation should be taken in assessing these requirements because these documents generally specify high level requirements that can be indirectly impacted by changes.

DOMINION DNAP-3004 REVISION 3 PAGE 26 OF32 ATTACHMENT 5 (Page 2 of 4)

Guidance for Filling out Screen Form PART II This part provides questions that determine the design basis functions, methods of evaluation, and design basis limits for which written documentation is required in Part III.

The first five questions address potential changes and impact on design basis functions.

The methods of evaluation addressed in question 6 include only evaluations used either in FSAR safety analyses or in establishing design bases and only if the methods are described, outlined or summarized in the FSAR.

The definition of tests or experiments addressed in question 7 is provided in Step 5.3.6.

The parameters and design basis limits for fission product barriers addressed in question 8 are plant specific. The parameters to be considered are as follows:

Fuel/cladding: safety limits, MDNBR, fuel temperature, linear heat rate, fuel enthalpy, pin failures, rod pressure, burnup, clad stress/strain, clad temperature, and clad oxidation.

RCS pressure boundary: pressure, stress, heatup/cooldown

Secondary side: pressure, steam generator differential pressure

Containment: pressure.

For the ISFSI, a different set of parameters apply:

Fuel cladding: clad temperature, enrichment, decay heat

Confinement boundary: pressure, leakrate, stress

DOMINION DNAP-3004 REVISION 3 PAGE 27 OF32 ATTACHMENT 5 (Page 3 of 4)

Guidance for Filling out Screen Form The following set of questions are provided to assist in answering the screen questions:

PART III Part IlL 1 Design Basis Functions

Does the activity adversely affect the design function (s) identified in Part II?

Does the activity adversely affect how the design function(s) are perfonned or controlled?

Does the activity introduce an accident of a different type than previously described in the FSAR?

Does the activity introduce a malfunction with a different result directly or indirectly affecting an sse having a design function identified in Part II?

Does the activity decrease the reliability of an sse design function, including either functions whose failure would initiate a transient/accident or functions that are relied upon for mitigation?

Does the activity reduce existing redundancy, diversity or defense-in-depth?

Does the activity add or delete an automatic or manual design function of the SSe?

Does the activity convert a feature that was automatic to manual or vice versa?

Does the activity introduce unwanted or previously unreviewed system or materials interaction?

Does the activity adversely affect the ability or response time to perfonn required actions, e.g., alter equipment access or add steps necessary for performing tasks?

Does the activity adversely affect the other unit at the site?

Does the activity have an indirect effect on electrical distribution, structural integrity, environmental conditions or other FSAR-described design functions?

Does the activity affect the existing safety analyses such that the analyses are no longer bounding and must be re-run?

DOMINION DNAP-3004 REVISION 3 PAGE 28 OF 32

)

ATTACHMENT 5 (Page 4 of 4)

Guidance for Filling out Screen Form Part 111.2 Changes in a Method of Evaluation

Does the activity use a revised or different method of evaluation for performing safety analyses than that described in the FSAR?

Does the activity use a revised or different method of evaluation for evaluating SSCs credited in safety analyses than that described in the FSAR?

Does the activity change any of the elements of the method described in the UFSAR?

Part 111.3 Design Basis Limits for a Fission Product Barrier

Does the activity change a design basis limit for a parameter that is fundamental to the barrier's integrity?

Is the limit expressed numerically?

Is the limit identified in the FSAR or a vendor report incorporated by reference into the FSAR?

Does the analysis for the activity show that a design basis limit for a fission product barrier would be exceeded?

Part IliA Tests or Experiments

Does the activity use or control an SSC in a manner that is outside the reference bounds of the design basis as described in the FSAR?

Does the activity use or control an SSC in a manner that is inconsistent with the analyses or descriptions in the FSAR?

Does the activity place the facility in a condition not previously evaluated or that could affect the capability of an SSC to perform its intended function?

)

I DNA REVj PAGE2i

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~b. 50.59/72.48 Evaluation

~Dominion*

DNAP-3004 - Attachment 6 Page 1 of 3 Applicable Station Parent Document I Revision DNorth Anna Power Station DSurry Power Station DUnit 1 DUnit2 DMilistone Power Station DUnit3 DISFSI DKewaunee Power Station Evaluation Number I Revision

.e~#I~p~~Pti~~~ij~.~t9PQ~4Ai#fviW~ij~Rlym~ri~*~~~ffiij~~~~U~~...* *.*.*.*.*. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .* .* .*. .*.*.* * *.* . . * * .* * * * * * * * * .* . * .*.*. *

acti"ities:Approprlatedescriptl"e materialsma}tbe r';'f;';~;';;'(,';'rlnr';tt';"'hArl ................. *1 B. Search the Technical Specifications and FSAR including documents incorporated by reference. Describe relevant function(s),

perform ance requirements, and methods of evaluation of the affected SSCs, and where this information is described in the Technical Specifications and FSAR. Identify Specification and FSAR sections reviewed.

e. Describe any other pertinent background information necessary to perform the evaluation.

cy of occurrence of an accident previously evaluated in the FSAR?

Describe the basis for the answer:

2. Does the activity result in more than the minimal increase in the likelihood of occurrence of a ma~unction of a sse important to safety previously evaluated in the FSAR?

DYES 0 NO 0 N/A Describe the basis for the answer:

)

Key: FSAR-Final Safety Analysis Report Form No. 73094 7(Apr 2(08)

DNAP-3004 REVISION 3 PAGE 300F32 50.59/72.48 Evaluation DNAP-3004 - Attachment 6 Page 2 of 3

3. Does the activity result in more than a minimal increase in the consequences of an accident previously evaluated in the FSAR?

DYES 0 NO 0 N/A Describe the basis for the answer:

4. Does the activity result in more than a minimal increase in the consequences of a malfunction of a sse important to safety previously evaluated in the FSAR?

DYES 0 NO 0 N/A Describe the basis for the answer:

5. Does the activity create a possibility for an accident of a different type than any previously evaluated in the FSAR?

DYES D NO 0 N/A Describe the basis for the answer:

6. Does the activity create a possibility for a malfunction of a sse important to safety with a different result than any previously evaluated in the FSAR?

DYES 0 NO D N/A Describe the basis for the answer:

7. Does the activity result in a design basis limit for a fission product barrier as described in the FSAR being exceeded or altered?

DYES D NO 0 N/A Describe the basis for the answer:

8. Does the activity result in departure from a method of evaluation described in the FSAR used in establishing the design bases or in the safety analyses?

DYES 0 NO 0 N/A the basis for the answer:

Form No. 730947(Apr 2008)

DNAP-3004 REVISION 3 PAGE 31 OF32 50.59/72.48 Evaluation DNAP-3004 - Attachment 6 Page 3 of 3 A License Amendment is: DNOT REQUIRED DREQUIRED (initiate license amendment request per applicable procedure)

This summary is used to prepare the required periodic report to the NRC. This summary includes a description of what is being changed and why, why an evaluation is required, what design functions and lor methods of evaluation are affected, and a summ ary of the answers to the eight evaluation cr~eria.

Co-signer Signature Date Reviewer (Print) Reviewer Signature Date Facility Safety Review Comm ittee (Print) Facil~y Safety Review Comm ~tee Signature Date Meeting Number Date Form No. 73094 7(Apr 2008)

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

97. G2.3.4SRO 097INEW//L/3/SROINAPSII Given the following conditions:

A General Emergency has been declared and an off-site release is in progress.

All Emergency Response Organization facilities are manned and operational.

The TSC has determined that the release point can be isolated by sending an operator into the Auxiliary Building to isolate the flowpath.

Which ONE of the following identifies the exposure limit for this activity per EPIP-4.04, Emergency Exposure Limits, and the person (by title) who has the FINAL approval for authorizing emergency exposure limits?

A. 5 rem ; Station Emergency Manager.

B~ 10 rem; Station Emergency Manager.

C. 5 rem; Radiological Assessment Director.

D. 10 rem; Radiological Assessment Director.

Feedback

)

A. Incorrect. Plausible since the candidate who is not knowledable of the procedure may conclude that this is the limit since there is not indication of large amounts of radioactivity being released; second part is correct ONLY the SEM has waiver authority.

B. Correct. To limit off-site releases up to 10 rem is allowed; second part also correct as discussed above.

C. Incorrect. First part plausible as discussed in distractor a; second part also incorrect but plausible since RWPs are associated with an HP (Radiation Protection) function an the candidate who is not knowlegable of the procedure would likely default to this distaractor.

D. Incorrect. First part correct; second part incorrect but plausible as discussed in distractor a.

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

EPIP-4.04 Proposed references to be provided to applicants during examination: None Learning Objective:

Question History: Crystal river 2007 exam additional info:

NORTH ANNA POWER STATION EMERGENCY PLAN IMPLEMENTING PROCEDURE NUMBER PROCEDURE TITLE REVISION 12 EPIP-4.04 EMERGENCY PERSONNEL RADIATION EXPOSURE PAGE (WITH 5 ATTACHMENTS) 1 of 8 PURPOSE Provide an evaluation of the need for emergency exposure authorization to the Station Emergency Manager.

ENTRY CONDITIONS Anyone of the following:

1) Activation by another EPIP.

2) Survey results indicate 10CFR20 annual limits may be exceeded.

REFERENCE USE

NUMBER PROCEDURE TITLE REVISION 12 EPIP-4.04 EMERGENCY PERSONNEL RADIATION EXPOSURE PAGE i 2 of 8 ACTION I EXPECTED RESPONSE RESPONSE NOT OBTAINED 1 INITIATE PROCEDURE:

By:

Date: _ _ _ __

Time: _ _ _ __

2 REVIEW EMERGENCY EXPOSURE LIMITS LISTED ON ATTACHMENT 1 NOTE:

Exposure to monitoring personnel should be minimized when obtaining data for estimation of emergency dose.

"Planned Special Exposures" (1 OCFR20.1206), are not to be used in lieu of Emergency Worker Exposure authorization.

3 ESTIMATE DOSE:

a) Ask SEM for the following:

Destination of workers

Estimated duration of exposure b) Check dose rate in affected area - KNOWN b) !f dose rate - UNKNOWN, THEN use OR OBTAINABLE: best estimate of dose rate. (An overly conservative dose rate estimate may

Area radiation monitors delay response actions.)

Survey data - Assign EPIP-4.14, INPLANT MONITORING c) Estimate TEDE dose (in Rem) using Attachment 2 (STEP 3 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 12 EPIP-4.04 EMERGENCY PERSONNEL RADIATION EXPOSURE PAGE 30fB ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

3. ESTIMATE DOSE: (Continued) d) Check estimated TEDE dose - GREATER d) IF estimated TEDE dose - LESS THAN limit(s) in Attachment 1, THAN limit(s) in Attachment 1, EMERGENCY EXPOSURE LIMITS EMERGENCY EXPOSURE LIMITS, THEN GO TO Step 6.

4 EVALUATE OPTIONS TO PERFORM TASK:

Perform task by different means

Apply ALARA dose reduction techniques to lower the TEDE to within the limit(s) in Attachment 1, EMERGENCY EXPOSURE LIMITS

Compare consequences of attempted rescue to total exposure of victim (when authorization is for lifesaving actions)

Use mock-up or dry run for damage control activities prior to entry

Wait to allow for radiation decay

Vent radioactive gases from area

Establish shielding

Assign limit(s) in Attachment 1, EMERGENCY EXPOSURE LIMITS, to several individuals and use stay times to complete task 5 GO TO STEP 9 6 CHECK ESTIMATED TEDE DOSE- IF estimated TEDE dose - LESS GREATER THAN 5 REM THAN 5 Rem, THEN GO TO Step 22.

NUMBER PROCEDURE TITLE REVISION 12 EPIP-4.04 EMERGENCY PERSONNEL RADIATION EXPOSURE PAGE 4 of 8 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED 7 EVALUATE OPTIONS TO REDUCE EXPOSURE:

Compare consequences of attempted rescue to total exposure of victim (when authorization is for lifesaving actions)

Use mock-up or dry run for damage control activities prior to entry

Wait to allow for radiation decay

Vent radioactive gases from area

Establish shielding 8 CHECK ESTIMATED TEDE DOSE- IF estimated TEDE dose - LESS THAN 25 GREATER THAN 25 REM Rem, THEN GO TO Step 12.

9 VERIFY VOLUNTEERS - AVAILABLE IF volunteers - NOT AVAILABLE for emergency exposure, THEN ask SEM for guidance.

NUMBER PROCEDURE TITLE REVISION 12 EPIP-4.04 EMERGENCY PERSONNEL RADIATION EXPOSURE PAGE 5 of 8 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE: The following criteria should be considered as guidance in selecting volunteers for emergency exposure.

10 REVIEW VOLUNTEER EMERGENCY WORKER SELECTION CRITERIA:

Personnel should be volunteers or professional rescue personnel (i.e., fire fighters, first aid or rescue personnel)

Volunteers should be in good physical health

Volunteers should be familiar with consequences of exposure

The following criteria are preferable, though not mandatory:

Women capable of reproduction should not be used

Volunteers should be above 45 years of age

__ 11 GET NAME(S) OF WORKERS FROM SEM

NUMBER PROCEDURE TITLE REVISION 12 EPIP-4.04 EMERGENCY PERSONNEL RADIATION EXPOSURE PAGE 6 of 8 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED

__ 12 PROVIDE (FEMALE) WORKER !E worker(s) - MALE, THEN GO TO Step 13. II OPPORTUNITY TO DECLARE PREGNANCY:

a) Check if pregnancy declared a) !E worker is NOT a declared pregnant worker or does NOT wish to declare pregnancy, THEN GO TO Step 13.

b) Select another worker c) RETURN TO Step 10 13 RECOMMEND EMERGENCY EXPOSURE:

a) Review Attachment 1, EMERGENCY EXPOSURE LIMITS, with SEM b) Provide recommendation to SEM 14 COMPLETE ATTACHMENT 3, EMERGENCY WORKER RADIOLOGICAL EXPOSURE RECORD, PART 1 FOR EACH WORKER 15 SEND COPY OF ATTACHMENT 3 TO THE FOLLOWING:

RPS

Exposure Control 16 REVIEW THE FOLLOWING ATTACHMENTS WITH EMERGENCY WORKER(S):

Attachment 2, DETERMINATION OF TEDE/DDE RATIO AND DOE LIMIT

Attachment 4, RADIATION EFFECTS VERSUS EXPOSURE

NUMBER PROCEDURE TITLE REVISION 12 EPIP-4.04 EMERGENCY PERSONNEL RADIATION EXPOSURE PAGE 7 of 8 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE:

Station Emergency Manager may waive requirements for RWP prior to entry and give verbal authorization.

Unless considered necessary, monitoring personnel should not remain in high exposure area.

17 IMPLEMENT PROTECTIVE ACTIONS:

a) Implement RWP unless waived by SEM b) Provide workers with the following equipment:

Protective clothing appropriate for situation

Dosimetry capable of measuring expected dose

Respiratory protection, if necessary

Instrumentation capable of reading radiation levels of up to 1000 R1hr c) Assign HP coverage d) Direct workers to entry route of lowest exposure

NUMBER PROCEDURE TITLE REVISION 12 EPIP-4.Q4 EMERGENCY PERSONNEL RADIATION EXPOSURE PAGE 8 of 8 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 18 DO FOLLOW-UP ASSESSMENT:

a) Check if individual received GREATER a) !E large portion (~80%) of individual's THAN emergency exposure limits (Refer to emergency exposure limit received, Attachment 1, EMERGENCY EXPOSURE THEN do the following:

LIMITS)

1) Limit individual from further exposure.

2) GO TO Step 19.

b) Recommend transport to VCU Medical Center for follow-up assessment

__ 19 COMPLETE ATTACHMENT 3, EMERGENCY WORKER RADIOLOGICAL EXPOSURE RECORD, PART 2 20 SEND COPY OF ATTACHMENT 3 TO SEM 21 FORWARD ORIGINAL ATTACHMENT 3 TO EXPOSURE CONTROL TO UPDATE WORKER'S EXPOSURE HISTORY 22 TERMINATE EPIP-4.04:

Give completed EPIP-4.04, forms and other applicable records to the Radiological Assessment Director

Completed by: _ _ _ _ _ __

Date: _ _ _ __

Time: _ _ _ __

-END-

NUMBER ATTACHMENT TITLE ATTACHMENT EPIP-4.04 1 EMERGENCY EXPOSURE LIMITS REVISION PAGE 12 1 of 1 TABLE 1: EPA-400 EMERGENCY EXPOSURE LIMITS ACTIVITY TEDE (Rem) LDE(Rem) SDE, THY, CDE, OR OTHER ORGAN (Rem)

GENERAL EMERGENCY 5 15 50 EXPOSURE ACTIVITIES PROTECTING VALUABLE 10 30 100 PROPERTY (1)

LIFESAVING OR PROTECTION OF 25 75 250 LARGE POPULATIONS (2)

LIFESAVING OR > 25 > 75 > 250 PROTECTION OF LARGE POPULATIONS (3) Only on a voluntary basis to persons fully aware of the risks involved.

(1) Protecting Valuable Property:

To save valuable equipment.

To limit off-site releases.

(2) Lifesaving Activity:

For search and rescue, first aid, and removal of injured personnel where there is reasonable expectation that the individual(s) is alive within the affected area.

For entry to correct conditions which, if left uncorrected, could result in on-site or off-site injury.

(3) No limit given in extreme case because loss of thyroid may be acceptable to save a life.

This may not be necessary if respirators and/or blocking agents are available for rescue personnel.

TABLE 2: NRC 10CFR20 ANNUAL LIMITS TEDE 5 Rem LDE 15 Rem SDE 50 Rem

NUMBER ATTACHMENT TITLE ATTACHMENT EPIP-4.04 2 DETERMINATION OF TEDE/DDE RATIO AND DDE LIMIT REVISION PAGE 12 1 of 3 NOTE: TEDE =DDE + CEDE, when applied to emergency worker dose.

1. Get TEDE/DDE ratio from MIDAS report AND GO TO Step 3 of this attachment OR IF MIDAS results - NOT AVAILABLE, THEN continue this instruction.

2. Use default TEDE/DDE ratio:

Default TEDEIDDE Ratio Accident Type with cleanup without cleanup LOCA in Containment with sprays 2 (filtered) 4 (unfiltered)

LOCA in Containment without sprays 2 (filtered) 20 (unfiltered)

LOCA outside Containment 2 (filtered) 25 (unfiltered)

MSLB 2 (wet generator) 5 (dry generator)

Primary-to-Secondary Steam release 2 (thru CAE) 5 (other)

FHA < 100 days 2 (fi Itered) 3 (unfiltered)

FHA> 100 days 1 1 RCS leak (VCT, WGDT, etc.) 1 1

3. Record TEDE/DDE ratio from Step 1 or Step 2 above: _ _ _ _ _ _ _ __

4. IF respiratory protection will be used, THEN select Protection Factor (PF) from Attachment 5, PROTECTION FACTORS.

PF= _ _ __

IF NO credit is to be taken for respiratory protection, THEN GO TO NOTE prior to Step 12 of this attachment.

NOTE: Area radiation monitors and survey dose rates my be used to estimate DDE.

5. Calculate estimated DDE:

Exposure time x Dose rate = estimated DDE

NUMBER ATTACHMENT TITLE ATTACHMENT EPIP-4.04 2 DETERMINATION OF TEDEIDDE RATIO AND DOE LIMIT REVISION PAGE 12 2of3

6. Calculate estimated TEDE dose, unmodified for PF or CEDE:

Exposure x Dose x TEDE ratio = estimated TEDE dose, Rem (unmodified) time rate DOE (Step 3 above)

!E estimated TEDE dose - GREATER THAN limit(s) in Attachment 1, EMERGENCY EXPOSURE LIMITS, THEN RETURN TO procedure Step 3.d.

NOTE: DAD or SRD readings are equivalent to DOE.

7. Calculate DOE limit, unmodified for PF or CEDE:

TEDE limit, Rem - estimated TEDE = estimated DOE limit, Rem (unmodified)

(Attachment 1, (Step 6 above)

Table 12.

TEDE/DDE ratio

8. Calculate modified TEDE/DDE ratio, incorporating the respiratory PF:

[(TEDE - DOE) + DOE]

PF modified TEDEIDDE ratio, Rem TEDE: Step 6 above; DOE: Step 7 above; PF: Step 4 above.

9. Calculate estimated TEDE, modified:

Exposure x Dose x TEDE ratio (modified) = modified TEDE dose, Rem time rate DOE (Step 8 above)

NUMBER ATTACHMENT TITLE ATTACHMENT EPIP-4.04 2 DETERMINATION OF TEDE/DDE RATIO AND DOE LIMIT REVISION PAGE 12 3 of 3 NOTE: DAD or SRD readings are equivalent to DOE.

__ 10. Calculate DOE limit:

TEDE limit estimated TEDE, modified = DOE limit, Rem (Attachment 1, (Step 9 above)

Table 1}

TEDE/DDE ratio (Step 8 above)

11. RETURN TO procedure Step 3.d.

NOTE: Step 12 and Step 13 are completed when NO respiratory protection is used.

12. Calculate estimated TEDE Dose:

Exposure x Dose x TEDE ratio = estimated TEDE dose, Rem time rate DOE (Step 3 above)

!E estimated TEDE dose - GREATER THAN limit(s) in Attachment 1, EMERGENCY EXPOSURE LIMITS, THEN RETURN TO procedure Step 3.d.

NOTE: DAD or SRD readings are equivalent to DOE.

13. Calculate DOE limit:

TEDE limit estimated TEDE = DOE limit, Rem (Attachment 1, (Step 12 above)

Table 1}

TEDE/DDE ratio (Step 3 above)

__ 14. RETURN TO procedure Step 3.d.

NUMBER ATTACHMENT TITLE ATTACHMENT EPIP-4.04 3 EMERGENCY WORKER RADIOLOGICAL EXPOSURE RECORD REVISION PAGE 12 1 of 1 PART 1 NAME: _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ AGE: _ _ (YEARS)

Last, First, Middle Initial Plant I.D. #: _ _ _ _ _ __

Authorized Emergency Exposure Limit (TEDE): (Rem)

Authorized by Radiological Assessment Director:

Name: _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ Date: _ _ __ Time: _ _ __

Authorized by Station Emergency Manager:

Name: _________________________________ Date: _ _ __ Time: ______

DAD/SRD ISSUE SECONDARY TLD, if required DOSIMETER # _ _ _ _ _ __ TLD # _ _ _ _ _ _ __

Reading (Rem) _ _ _ _ _ __

Date: _ _ _ _ _ _ _ _ __ Date: _ _ _ _ _ _ _ _ ___

Time: _ _ _ _ _ _ _ _ __ Time: ______________

Issued By: __________________

PART 2 DAD/SRD RETURN DOSIMETER # _ _ _ _ _ __ DDE Dose (Rem) _ _ _ _ __

Reading (Rem) _ _ _ _ _ __ (Return - Issue)

Date: _ _ _ _ _ _ _ _ __ TEDE Dose (Rem)* _ _ _ _ __

Time: _ _ _ _ _ _ _ _ __ (*TEDE Dose (Rem) = DDE x TEDE/DDE ratio from Attachment 2, Received By: _ _ _ _ _ _ _ _ _ _ __ Step 8 or 11 .)

NUMBER ATTACHMENT TITLE ATTACHMENT EPIP-4.04 4 RADIATION EFFECTS VERSUS EXPOSURE REVISION PAGE 12 1 of 1 EXPOSURE EFFECTS o to 25 Rem No measurable effects.

25 to 100 Rem Slight blood changes but no other observable effects.

100 to 200 Rem Vomiting in 5 to 50 percent within 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months , with fatigue and loss of appetite.

Moderate blood changes. Except for the blood-forming system, recovery will occur in essentially all cases within a few weeks.

200 to 600 Rem Vomiting, fatigue and loss of appetite in 50 to 100 percent within 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months . For doses over 300 Rem, these effects will appear in all cases within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . Loss of hair after 2 weeks. Severe blood changes, accompanied by hemorrhage and infection. Death in 0 to 80 percent within 2 months; for survivors, recovery period of 1 month to a year.

600 to 1000 Rem Vomiting within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . Severe blood changes, hemorrhage, infection and loss of hair. Death of 80 to 100 percent within 2 months; survivors convalescent over a long period.

The above effects are based upon:

1. Exposure to the entire body.

2. Exposure to the entire population.

3. No medical treatment, and acute exposure.

Adapted from: Handbook of Health Physics and Radiological Health, 3rd Edition, 1998.

NUMBER ATTACHMENT TITLE ATTACHMENT EPIP-4.04 5 PROTECTION FACTORS REVISION PAGE 12 1 of 1 I

DESCRIPTION MODES PROTECTION FACTORS PARTICULATES PARTICULATES, ONLY GASES & VAPORS Air PuriMng ResQirator:

a. Full-face with Negative Pressure 100 particulate canister

b. Full-face with iodine Negative Pressure 100 canister AtmosQhere SUQQlying ResQirators:

a. Airline Respirators:

Full-face Continuous flow 1,000

b. SCBA:

Full-face Pressure demand 10,000

- -- -_ .. _- ---- ~ --

NUMBER ATTACHMENT TITLE REVISION EPIP-l.Ol 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. "_ _ N, 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-2.01. Attachment 2. Get completed copies if available.

3. Determine status of the "Report of Radiological Conditions to the State." EPIP-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 TSCr .

11~ When sufficient personnel are available. the relief SEM is to assume the following responsibilities from the onshift Station Emergency Manager:

a. Reclassification. :f'

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.

Topic 1.2 (")perations Departrr.Emt'sResp()nse 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, OS/22/2007

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

98. G2.4.28SRO 098INEW!!H!4!SRO!!!

Both Units are at 100% power.

A report is received from the FAA that credible insider information has identified that an air threat exists from a Boeing 747 inbound from Miami, Florida with an estimated time of arrival at the station of 30 minutes.

Which ONE of the following identifies the agency that is contacted to confirm the threat, and the action required by 0-AP-9.01, Station Security Air Threat Operations Response, once the threat is verified to be authentic?

A. Department of Homeland Security (DHS);

maintain both units stable; shutdown the units only if the threat becomes imminent.

B. Nuclear Regulatory Commission (NRC);

maintain both units stable; shutdown the units only if the threat becomes imminent.

C. Department of Homeland Security (DHS);

commence a rapid shutdown of both units using AP-2.2, Fast Load Reduction.

D~ Nuclear Regulatory Commission (NRC);

commence a rapid shutdown of both units using AP-2.2, Fast Load Reduction.

Feedback

a. Incorrect. Plausible since DHS would not seem illogical as this situation is germane to their function, but in all cases the procedure requires confirmation thru the NRC; second part also incorrect but plausible as this would allow resources to be used to perform other activities needed to prepare. Taking both units off could jeopardize the offsite power source which would result in further complications, thus waiting till you know for sure seems logical considering both units could be tripped and stabilized in a few minutes (given no other complications).

b. Incorrect. First part correct per 0-AP-9.01; second part plausible but incorrect as discussed above; further, the candidate who is not knowledgeable of the procedure may conclude that this is the preferred course of action in all cases.

c. Incorrect. First part incorrect but plausible as discussed in Distractor a; second part is correct per 0-AP-9.01 for a threat that is 30 minutes or less away.

d. Correct. First part correct as noted in Distractor b; second part is correct per 0-AP-9.01 for a threat that is 30 minutes or less away.

QUESTIONS REPORT for 2009 NRC SRO exam Validation 3 copy with SRC formatting - for submittal Notes Emergency Procedures 1 Plan Knowledge of procedures relating to a security event (non-safeguards information).

(CFR: 41.10/43.5/45.13)

Tier: 3 Importance Rating: 3.2/4.1 Technical

Reference:

0-AP-9.01 Proposed references to be provided to applicants during examination: None Learning Objective:

Question History: new additional info: This procedure is withheld from public disclosure under 10 CFR 2.390

Withhold from Public Disclosure Under 10 CFR 2.390

~J'Dominion" NORTH ANNA POWER STATION ABNORMAL PROCEDURE NUMBER PROCEDURE TITLE REVISION 5

O-AP-9.01 STATION SECURITY AIR THREAT- OPERATIONS RESPONSE PAGE (WITH SIX AITACHMENTS) 1 of 22 PURPOSE To provide guidance for Operations personnel in the event that Station Security is challenged by an air threat or a credible notification of an air threat.

NOT AVAILABLE ON ELECTRONIC DISTRIBUTION ENTRY CONDITIONS

1) Notification from the Security Department or other plant personnel of a security air threat to the station.

2) A credible report has been received that the plant is specifically targeted for an air terrorist attack.

CONTINUOUS USE Withhold from Public Disclosure Under 10 CFR 2.390

Withhold from Public Disclosure Under 10 CFR 2.390 NUMBER PROCEDURE TITLE REVISION S

O-AP-9.01 STATION SECURITY AIR THREAT- OPERATIONS RESPONSE PAGE 2 of 22 ACTIONI EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION: Any actions taken outside of Technical Specifications or license conditions may require invoking 10 CFR SO.S4(X) before taking such actions.

NOTE: Reports from agencies such as NORAD, FBI, FAA or others should be confirmed as credible with the NRC using the ENS phone.

NOTE: NORAD and other agencies may use terminology unfamiliar to Operations and they may not have time for typical three-way communications. It is incumbent on Operations to ensure the information received is understood.

1. RECORD AVAILABLE CALLER INFORMATION:

o . Name:_ _ _ _ _ _ _ _ _ _ __

o . Phone Number: _ _ _ _ _ _ __

o

Nature of incident: _ _ _ _ _ __

o

Type and/or size of aircraft (e.g. plane, helicopter, 747, small plane etc.):

o

Estimated Time of Arrival at station:

2._ CHECK AIR THREAT-IMMINENT (LESS o GO TO Step 19.

THAN OR EQUAL TO FIVE MINUTES)

Withhold from Public Disclosure Under 10 CFR 2.390

Withhold from Public Disclosure Under 10 CFR 2.390 NUMBER PROCEDURE TITLE REVISION 5

O-AP-9.01 STATION SECURITY AIR THREAT-OPERATIONS RESPONSE PAGE 3 of 22 ACTION! EXPECTED RESPONSE RESPONSE NOT OBTAINED

3. SITE NOTIFIED BY NRC USING NRC ENS Contact NRC and validate authenticity of air PHONE threat while continuing with procedure:

o

NRC ENS Phone o

1-301-816-5100 o

1-301-951-0550 o

1-301-415-0550 NOTE: Reference Attachment 3 of EPIP-1.01, Station Emergency Manager Controlling Procedure.

4. EVALUATE EPIP CLASSIFICATION AND NOTIFY THE FOLLOWING PERSONNEL:

o

Notify OMOC o

Notify STA

5. ESTABLISH COMMUNICATION WITH SECURITY:

a) Use any of the following extensions: o a) Use Base Radio.

0

Automatic Ring-down phone 0

Secondary Alarm Station at 2222 0

Central Alarm Station at 2249 0

Security Shift Supervisor at 2224 b) Notify corporate security:

0

8-730-2020 0 * (804) 273-2020 0

8-730-3161 Withhold from Public Disclosure Under 10 CFR* 2.390

Withhold from Public Disclosure Under 10 CFR 2.390 NUMBER PROCEDURE TITLE REVISION 5

O-AP-9.01 STATION SECURITY AIR THREAT- OPERATIONS RESPONSE PAGE 4 of 22 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

6. VERIFY AIR THREAT - AUTHENTIC: o WHEN air threat authenticated, THEN GO TO Step 7.

o

Threat confirmed by NRC OR o

Shift Manager determines threat authentic

7. MAKE GAITRONICS ANNOUNCEMENT:

o a) Actuate the Station Emergency Alarm o b) Announce - "Attention all personnel, a Security Event is in progress. Fire Brigade report to your designated area and the Control Room team come to the Control Room. All other personnel immediately leave the protected area and go to the Training Building:'

8. EITHER UNIT IN REFUELING OUTAGE: o GO TO Step 9.

o

Increase RCS Inventory o

Place fuel in a safe storage condition

9. CHECK UNIT 1 AND 2 REACTOR Implement Security Event Guidelines while CONTROL - AVAILABLE: continuing with this procedure:

o

From Control Room o

GO TO SEGOPS, Operations Response

- Security Event Severe Accident OR Mitigation.

o

From Auxiliary Shutdown Panel o

WHEN TSC is staffed, THEN have TSC initiate SEGTSC, TSC Response -

Security Event Severe Accident Mitigation.

Withhold from Public Disclosure Under 10 CFR 2.390

! NUMBER PROCEDURE TITLE REVISION 5

O-AP-9.01 STATION SECURITY AIR THREAT- OPERATIONS RESPONSE PAGE 5 of 22 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE: If shutdown of both Units is required, then sequentially tripping and stabilizing the Units should be evaluated as opposed to tripping simultaneously.

NOTE: Guidance for alternate means of Unit control may be established using the FCAs, based on degradation by terrorist activities.

10. UNIT 1 - IN MODE 1 OR 2: Do the following:

D a) Initiate 1-E-O, REACTOR TRIP OR D 1) Stabilize Unit in accordance with Shift SAFETY INJECTION Managers direction.

o b) Stabilize Unit 1 in MODE 3 D 2) GO TO Step 11 .

11. UNIT 2 - IN MODE 1 OR 2: Do the following:

o a) Initiate 2-E-O, REACTOR TRIP OR D 1) Stabilize Unit in accordance with Shift SAFETY INJECTION Managers direction.

D b) Stabilize Unit 2 in MODE 3 D 2) GOTO Step 12.

Withhold-from Public Disclosure Under 10 CFR 2.390

Withhold from Public Disclosure Under 10 CFR 2.390 NUMBER PROCEDURE TITLE REVISION 5

O-AP-9.01 STATION SECURITY AIR THREAT- OPERATIONS RESPONSE PAGE 6 of 22 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

12. ISOLATE CONTROL ROOM:

Close Control Room Rolling Steel Doors:

o

1-BLD-DR-M7626, U1 Control Room o

2-BLD-DR-M7625, U2 Control Room

Isolate Control Room Ventilation:

o 1) At the Unit 1 Ventilation Panel, place the control switch for 1-HV-F-15, CONTROL AND RELAY RM EXH FAN, in STOP o 2) At the Unit 2 Ventilation Panel, place the control switch for 1-HV-AOD-161-2, CONTROL RM EXHAUST DAMPERS, in CLOSE o

Place Control Room ventilation in recirc mode using O-OP-21.7, Main Control Room and Relay Room Emergency Ventilation Operation

As time and personnel permit close all Rolling Steel Doors and Applicable Fire Doors Using the following Attachments:

o

ATTACHMENT 2, SHIELD DOORS AND FIRE DOORS OR o

ATTACHMENT 3, DOORS AND LIGHTING TO SECURE BY WATCHSTATION

. Withhold from PublicDisciosure Under 10 CFR 2.390

Withhold from Public Disclosure Under 10 CFR 2.390 NUMBER PROCEDURE TITLE REVISION 5

O-AP-9.01 STATION SECURITY AIR THREAT- OPERATIONS RESPONSE PAGE 7 of 22 ,

ACTIONI EXPECTED RESPONSE RESPONSE NOT OBTAINED

13. EVALUATE REDUCING LIGHTING: o GO TO Step 14.

o

Reduce station lighting using ATTACHMENT 3, DOORS AND LIGHTING TO SECURE BY WATC HSTAT ION o

Reduce Main Dam lighting using ATTACHMENT 4, MAIN DAM LIGHTING SOURCES

14. SELECT SECURITY CHANNEL ON RADIO

15. RELOCATE SPILLWAY OPERATOR TO o GO TO Step 16.

EMERGENCY ASSEMBLY AREA WITH A RADIO (9-872-3531) 16._ AS TIME PERMITS, PERFORM ATTACHMENT 6, ASSAULT PREPARATION GUIDELINES, FOR ADDITIONAL GUIDELINE INFORMATION

17. SECURITY EVENT - IN PROGRESS WHEN security event has been terminated, THEN do the following:

a) Coordinate watch-station walkdowns with Security for indications of malicious intent:

o

Signs of forcible damage to equipment o

Signs of fire or blast o

Corrosive or chemical material on equipment o

Misaligned valves and/or switches o

Unusual material or packages present o b) Return to procedure and step in effect.

Withhold from Public Disclosure Under 10 CFR 2.390

Withhold from Public Disclosure Under 10 CFR 2.390 NUMBER PROCEDURE TITLE REVISION 5

O-AP-9.01 STATION SECURITY AIR THREAT- OPERATIONS RESPONSE PAGE 8 of 22 ACTIONI EXPECTED RESPONSE RESPONSE NOT OBTAINED

18. RETURN TO STEP 2

19. CHECK AIR THREAT - PROBABLE o GO TO Step 41.

(LESS THAN OR EQUAL TO THIRTY MINUTES)

20. SITE NOTIFIED BY NRC USING NRC ENS Contact NRC and validate authenticity of air PHONE threat while continuing with procedure:

o

NRC ENS Phone o

1-301-816-5100 o

1-301-951-0550 o

1-301-415-0550 NOTE: Reference Attachment 3 of EPIP-1.01, Station Emergency Manager Controlling Procedure.

21. EVALUATE EPIP CLASSIFICATION AND NOTIFY THE FOLLOWING PERSONNEL:

o

Notify OMOC o

Notify STA Withhold from Public Disclosure Under 10 CFR 2.390

Withhold from Public Disclosure Under 10 CFR 2.390 NUMBER PROCEDURE TITLE REVISION 5

O-AP-9.01 STATION SECURITY AIR THREAT- OPERATIONS RESPONSE PAGE 9 of 22 ACTION! EXPECTED RESPONSE RESPONSE NOT OBTAINED

22. ESTABLISH COMMUNICATION WITH SECURITY:

a) Use any of the following extensions: o a) Use Base Radio.

o . Automatic Ring-down phone o

Secondary Alarm Station at 2222 o

Central Alarm Station at 2249 o

Security Shift Supervisor at 2224 o b) Notify Security to relocate their personnel to protected locations.

c) Notify corporate security:

o

8-730-2020 o * (804) 273-2020 o

8-730-3161

23. VERIFY AIR THREAT - AUTHENTIC: o WHEN air threat authenticated, THEN GO TO Step 24.

o

Threat confirmed by NRC OR o

Shift Manager determines threat authentic Withhold from Public Disclosure Under 10 CFR 2.390

Withhold from Public Disclosure Under 10 CFR 2.390 i

I NUMBER PROCEDURE TITLE REVISION 5

O-AP-9.01 STATION SECURITY AIR THREAT- OPERATIONS RESPONSE PAGE 10 of 22 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

24. EVALUATE GAITRONICS ANNOUNCEMENT:

o a) Expected impact less than 15 minutes OR o a) WHEN expected impact is less than Unknown 15 minutes, I1:::IEN GO TO Step 24.b.

o Continue with step Step 25.

0 b) Actuate the Station Emergency Alarm o c) Announce - "Attention all personnel, a Security Event is in progress. Security and

, Fire Brigade report to your designated areas. Operations Shift come to the Control Room. All other personnel immediately leave the protected area and go to the Training Building:'

25. EITHER UNIT IN REFUELING OUTAGE: 0 GO TO Step 26.

o

Establish Containment Closure o

Containment purge and exhaust closed o

Containment penetrations intact o

Increase RCS Inventory o

Place fuel in a safe storage condition Withhold from Public Disclosure Under 10 CFR 2.390

Withhold from Public Disclosure Under 10 CFR 2.390 NUMBER PROCEDURE TITLE REVISION 5

O-AP-9.01 STATION SECURITY AIR THREAT- OPERATIONS RESPONSE PAGE 11 of 22 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE: If shutdown of both Units is required, then sequentially shutting down and stabilizing the Units should be evaluated as opposed to shutting down simultaneously.

NOTE: Guidance for alternate means of Unit control may be established using the FCAs, based on degradation by terrorist activities.

26. UNIT 1 - IN MODE 1 OR 2: o GO TO Step 27.

a) Commence a rapid Unit Shutdown in accordance with the following:

0

1-AP-2.2, Fast Load Reduction 0

1-0P-3.1, Unit Shutdown From Mode 2 to Mode 3 o b) Stabilize Unit 1 in MODE 3

27. UNIT 2 - IN MODE 1 OR 2: o GO TO Step 28.

a) Commence a rapid Unit Shutdown in accordance with the following:

0

2-AP-2.2, Fast Load Reduction 0

2-0P-3.1, Unit Shutdown From Mode 2 to Mode 3 o b) Stabilize Unit 2 in MODE 3

28. BOTH UNITS IN REFUELING OR ON RHR o Commence rapid cool down of unit using OP-3.2, UNIT SHUTDOWN FROM MODE 3 TO MODE 4, and place RHR in service.

Withhold from Public Disclosure Under 10 CFR 2.390

STUDENT GUIDE FOR ADMINISTRATIVE PROCEDURES (100)

Mail 1.49 Content See VPAP-2502.

1.50 Objective U 15511 Describe how a report of a security threat to or from the Nuclear Regulatory Commission (NRC) is verified to be authentic as per OP-AA-900.

1.50 Content

3. Authentication Code o The NRC provides a new alphanumeric code during the daily communications check at approximately 4 a.m. EST.

o This code is valid for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months beginning at 8 a.m. EST.

o The new authentication code is recorded on Attachment 1 of OP-AA-900.

o When the NRC Operations Center calls to report a threat, the NRC Headquarters Operation Officer provides the authentication code.

The operator in the control room verifies that the code is valid by ensuring that it matches the code book.

If the code matches, then notify the NRC "ready to copy the emergency message."

If the codes does not match or if a code is not provided, then hang up and immediately call back to the NRC without using a code.

o WHEN the control room calls to report an onsite security threat, THEN the operator provides the authentication code.

The NRC verifies that the code is valid.

If the code matches, then the NRC informs the operator in the control room that he is "ready to copy the emergency message."

REACTOR OPERATOR Page 52 of 106 Revision 16, 09/19/2008

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 SRO exam Validation 3 copy with SRC formatting - for submittal

99. G2.4.30SRO 099IBANKIMILSTONE 2005/L/3/SROINAPSII Which ONE of the following describes a condition required to be reported to the NRC under 10CFR50.72, and the correct time limit for reporting?

A'! Deviation from the plant Technical Specifications authorized pursuant to 10CFR50.54(x);

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

B. Condition that could have prevented fulfillment of a safety function needed to mitigate consequences of an accident; report within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

C. Failure to perform required surveillance test within technical specification allowable time limits; report within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

D. The nuclear power plant in an unanalyzed condition that significantly degrades plant safety; report within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

Feedback CHOICE (A) - YES 10CFR50.72(b)(1) requires a 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months ENS notification if provisions of CFR50.54(x) invoked.

CHOICE (B) - NO WRONG: Fulfillment of a safety function is an 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months notification under 10CFR50. 72(b )(3)(v).

VALID DISTRACTOR: Plausible that safety function needed for accident mitigation would be a 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months report.

CHOICE (C) - NO WRONG: Failure to perform a surveillance test within allowable time limits is not 1,4 or 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months reportable.

VALID DISTRACTOR: Plausible that missed surveillance would be reportable as a violation of technical specification requirements.

CHOICE (D) - NO WRONG: 10CFR50.72(b)(3) requires an 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months notification.

VALID DISTRACTOR: Plausible that an unanalyzed condition would require a 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months report.

QUESTIONS REPORT for 2009 NRC SRO exam Validation 3 copy with SRC formatting - for submittal Notes Emergency Procedures / Plan 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: 3 Importance Rating: 2.7/4.1 Technical

Reference:

VPAP-2802 Proposed references to be provided to applicants during examination: None Learning Objective:

Question History: milstone exam additional info:

Station Dominion Administrative Procedure

Title:

Notifications and Reports Process I Program Owner: Director Nuclear Station Safety and Licensing Procedure Number Revision Number Effective Date VPAP-2802 30 On File Revision Summary On 10113/08 an Administrative Correction was issued to update the Federal Energy Regulatory Commission (FERC) phone number and address.

Revision 30 Summary:

The following changes were made due to the implementation of LI-AA-500, NRC/INPO/wANO Performance Indicator and MOR Reporting:

Added 3.1.46 - LI-AA-500, NRCIINPO/w ANO Performance Indicator and MOR Reporting.

Revised 6.30, Consolidated Data Entry (CDE) Reporting System - deleted instructions and added reference to LI-AA-500, NRC/INPO/w ANO Performance Indicator and MOR Reporting.

Approvals on File

DOMINION VPAP-2802 REVISION 30

,,,,I PAGE 68 OF 205 6.3 Immediate to 72-Hour Notifications This subsection consolidates requirements for situations or events addressed by Subsections 6.5 through 6.29, for which notifications or reports are required within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

6.3.1 General Requirements

a. When this subsection (Subsection 6.3) designates someone other than the Shift Manager or a member of Station management to notify a government agency, that person shall ensure the Shift Manager or a member of Station management is advised before making the notification. See also Step 6.3.4.a.4.

NOTE: Notifications for events that exceed an Emergency Action Level, as specified in EPIP-1.01, Emergency Manager Controlling Procedure, are controlled by EPIP-2.01, Notification of State and Local Governments and EPIP-2.02, Notification of NRC. See also Steps 6.3.5 and 6.3.7. [10 CFR 50.72(a)(3), 10 CFR 50.72(c)(l), 10 CFR 50.72(c)(2)]

NOTE: When it is discovered that an event or condition had existed, but the basis for the emergency class no longer exists at the time of this discovery and no other reasons exist for an emergency declaration, then declaration of an emergency class is not required. See Step 6.3.3.i. for notification requirements.

b. For events reportable to the NRC Operations Center, the Shift Manager shall:

1. Complete NRC Form 361, Event Notification Worksheet.

2. Fax the Event Notification Worksheet to the NRC Operations Center. See Step 6.1.1.

3. V sing the Emergency Notification System (ENS), verify that NRC received the fax.

4. Be prepared to read the entire contents of the Event Notification Worksheet to the NRC Operations Center officer.

5. Ensure the NRC Operations Center officer has a clear understanding of the issues, and that all questions regarding the notification have been answered.

6. If the ENS is nonfunctional, use commercial telephone service, other dedicated telephone service, or any other method that ensures the NRC Operations Center is notified as soon as practical. See Step 6.1.1. [10 CFR 50.72(a)(2)]

DOMINION VPAP-2802 REVISION 30 PAGE 69 OF 205

7. Maintain an open, continuous communications channel with the NRC Operations Center, when requested by NRC. [10 CFR SO.72(c)(3) & 10 CFR 73.71(a)(3)]

c. For events that are reportable in accordance with 10 CFR 50.72 and 10 CFR 72.75:

Immediately, the Shift Manager shall notify the Manager Nuclear Operations or the Operations Manager On Call, and the STA

Within one hour, the Manager Nuclear Operations or Operations Manager On Call shall notify the Site Vice President and the Plant Manager (Nuclear)

Within one hour, the STA shall notify the Director Nuclear Station Safety and Licensing

Within one hour, the Director Nuclear Station Safety and Licensing (if absent, the Plant Manager (Nuclear>> shall notify the Manager Nuclear Oversight of reactor trips; for other events that are reportable in accordance with 10 CFR 50.72 and 10 CFR 72.75, this notification shall be made within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months

Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , the Director Nuclear Station Safety and Licensing (if absent, the Plant Manager (Nuclear>> shall notify the NRC Resident Inspector.

Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , the Director Nuclear Station Safety and Licensing (if absent, the Plant Manager (Nuclear>> shall notify the Director NL&OS

Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , the Site Vice President, a Director, Manager Nuclear Operations, or Shift Manager shall notify the Senior Vice President Nuclear Operations

When notified, the Director NL&OS shall promptly notify appropriate corporate organizations, including Public Relations, Medical, Risk Services, and Power Supply, as applicable

DOMINION VPAP-2802 REVISION 30 PAGE 70 OF 205 6.3.2 Immediate Notifications NOTE: Some conditions, indicated by "See EPIP-1.01," may exceed an Emergency Action Level (EAL) as specified in EPIP-1.01, Emergency Manager Controlling Procedure.

If a condition exceeds an EAL, Emergency Plan Implementing Procedures (EPIPs) control State and Federal agency notifications. If an event or condition does not exceed an EAL, it may still be reportable in accordance with this procedure.

NOTE: Upon NRC request, the designated responsible person must maintain an open, continuous communications channel with the NRC Operations Center. [10 CFR SO.72(c)(3)]

a. The Shift Manager shall notify the NRC Operations Center via the ENS of:

1. Any further degradation in the level of safety of the plant or other worsening plant conditions, after telephone notifications to NRC as specified in Step 6.3.2 or Step 6.3.3. See EPIP-l.Ol. [10 CFR SO.72(c)(l)]

2. The results of ensuing evaluations or assessments of plant conditions, the effectiveness of response or protective measures taken, and information related to plant behavior that is not understood, after telephone notifications to NRC as specified in Step 6.3.2 or Step 6.3.3. [10 CFR SO.72(c)(2)]

3. Lost, stolen or tnissing licensed material in an aggregate quantity equal to or greater than 1,000 times the quantity specified in 10 CPR 20.1001-20.2401, Appendix C, under circumstances in which it appears persons in unrestricted areas could be exposed. See also Steps 6.6.2.b. and 6.6.2.c. [10 CFR 20.2201(a)(i)]

DOMINION VPAP-2802 REVISION 30 PAGE 71 OF 205 NOTE: The requirements of Step 6.3.2.a.4. do not apply to doses that result from planned special exposures, that are within the limits for planned special exposures, and that are reported in accordance with Step 6.6.5. [10CFR20.2202(e)]

4. Events that involve by-product, source, or special nuclear material possessed by Dominion that may have caused or threatens to cause: [10 CFR 20.2202(a)]

An individual to receive:

- A total effective dose equivalent of ~ 25 rems

- An eye dose equivalent of ~ 75 rems

- A shallow-dose equivalent to the skin or extremities of ~ 250 rads

Release of radioactive material inside or outside a restricted area, so that, if an individual had been present for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , they could have received an intake five times the occupational annual limit on intake If the event involves radiological overexposure, the DEM shall be notified as specified in Step 6.27.2. See also Step 6.6.3.c.

5. A Technical Specifications safety limit violation. See also Steps 6.23.3 (North Anna) and 6.24.3 (Surry). [10 CFR 50.36(c)(1)(i)(A)]

6. Upon declaration of an emergency as specified in the approved emergency plan regarding ISFSI events. [10 CFR 72.75(a)]

b. If:

Removable radioactive surface contamination exceeds the limits of 10 CFR 71.87(i) [10CFR20.1906(d)(1)]

or

External radiation levels exceed the limits of 10 CFR 71.47 [10 CFR 20.1906(d)(2)]

1. Radiological Protection shall notify Supervisor Licensing (Station) and the Shift Manager.

2. Radiological Protection or Supervisor Licensing (Station) shall notify (see Step 6.3.1.a.) the final delivering carrier and, by telephone and telegram, mailgram, or facsimile, the NRC Operations Center. See Step 6.1.1.

ti

°~

Material Released To Table 1 Summary of Reporting Requirements for Non-Radiological Releases To the Environmenta Amountb ReportToC See

°Z Soil Outside containment facilitieso > 25 gallons DEQ&LEPC Solid surface Potential to reach soil or water Case basis Oil 6.3.2.d.

Any discernible State Waters e NaRC, DEQ & LEPC amounfc Land Off-site ;O:RQ NaRC, DEQ & LEPC

<RQ DEQ Hazardous On-sitei

O: RQ NaRC, DEQ, & LEPC SUbstancef , g Water

<RQ DEQ Off-site

O: RQ NaRC,DEQ, 6.3.2.e.

On-site! ;O:RQ NaRC&DEQ 6.3.2.g. h Land Off-site Any amount NaRC, DEQ & LEPC Hazardous

<RQ DEQ Wastei On-sitei Water ;O:RQ NaRC, DEQ, & LEPC Off-site Any amount NaRC, DEQ, & LEPC

a. Step 6.3.2.e. explains "releases to the environment" when hazardous substances or hazardous wastes are involved.

For oil, "releases" includes spilling, leaking, pumping, pouring, eInitting, emptying, discharging, injecting, escaping, leaching, or disposing. Oil releases solely within a workplace (an enclosed building with a concrete floor) are not subject to the RQ unless oil reaches a floor drain connected to a pathway to the environment. All outdoor releases are subject to the RQ.

b. RQ = reportable quantity as specified in VPAP-2202, Control of CheInicals and Hazardous Substances.

c. DEQ =State Department of Environmental Quality; NaRC =National Response Center*; LEPC =Local Emergency Planning Coordinator. *At Surry, if the NaRC is notified, the U.S. Coast Guard must also be notified. DEM (Department of Emergency Management (Emergency Operations Center>> is notified (instead of DEQ) on nights, weekends, and after hours. Environmental "immediate notification" is defined as "as soon as possible, but not to exceed 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ." Phone numbers for the agencies are found in 6.1.1. Attachment 1, Oil or Hazardous Substance Release Report, should be used for spill information requested by the agencies. NRC notification is required within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months of notifying any of these agencies.

d. Oil tank dikes and transformer vaults are typical containment facilities.

e. Includes releases to storm drains or comparable conduits to state waters. See also 4.36, State Waters.

f. Hazardous substances of concern to the Station are identified in VPAP-2202, Control of CheInicals and Hazardous Substances. ;g

g. See Footnote 1. on page 74 if there is an on-site RQ release of a volatile substance.

h. 6.3.2.g. is applicable for transportation-related events. O§

i. An on-site hazardous material spill that, due to location, size, or substance properties, poses imIninent or likely danger of an RQ release to the environment, tI1<~

-....l_

must be reported to the same entities as offsite spills. NC/.l:l>

j. Hazardous waste is defined in the Environmental Protection Plan. 0-;';

'"IjO, k If the oil spill that reaches navigable waters is: a) greater than 1000 gallons or b) the second spill that is greater than 42 gallons in a 12 month NZ~

period, then contact Electric Environmental Services (EES). Additional reporting by EES to the EPA will be required. [Commitment 3.2.30] OWO UlON

DOMINION VPAP-2802 REVISION 30 PAGE 73 OF 205

3. The notifier in Step 6.3.2.b.2. shall initiate a Condition Report as specified in PI-AA-200, including documentation of its notifications on the Condition Report.

c. If an NRC employee is believed to be under the influence of any substance or otherwise unfit for duty, the Fitness for Duty Administrator (Station) or a Station Management staff member shall notify (see Step 6.3 . La. ) (during normal business hours) the NRC Regional Administrator. At other times, notify the NRC Operations Center. See Step 6.1.1. [10 CFR 26.27(d)]

NOTE: Use Table 1, Summary of Reporting Requirements for Non-Radiological Releases To the Environment, to supplement Step 6.3.2.d. for reporting requirements. The Environmental Compliance Coordinator or Electric Environmental Services should be consulted when assessing oil release reportability.

d. If oil may have been released from the Station into state waters that:

Violates applicable water quality standards (i.e., any oil in water) [40 CFR 110.3]

Causes a film or sheen upon or discoloration of the surface of the water or adjoining shorelines [40 CFR 110.3]

Causes a sludge or emulsion to be deposited beneath the surface of the water or upon adjoining shorelines [40 CFR 110.3]

or If oil can reasonably be expected to enter, or there is a substantial threat that oil will enter, state waters or storm drains (Reference 3.1.8) or If more than 25 gallons 1 of oil has been or can reasonably be expected to be released to soil, including a spill within containment facilities 2 (Reference 3.1.8):

or If any spill reaches a solid surface, including surfaces inside secondary containment systems and inside buildings, and (1) if there is the potential for oil to reach surface water, and/or (2) if there is the potential for greater than 25 gallons of oil to reach soil

1. Notice is considered to have been given to the State Water Control Board for oil releases to the ground up to 25 gallons if and only if the Environmental Compliance Coordinator prepares and maintains a record of such oil releases for five years, and the oil is cleaned up.

}

2. Oil tank dikes and transformer vaults are typical containment facilities.

DOMINION VPAP-2802 REVISION 30 PAGE 74 OF 205

1. The individual who observes or suspects such an event or condition shall notify the Shift Manager.

2. The Shift Manager shall notify the Manager Nuclear Operations, the Environmental Compliance Coordinator, or Environmental Policy &

Compliance, as available.

3. If the discharge is to storm drains or state waters, the Environmental Compliance Coordinator or Electric Environmental Services (see Step 6.3.1.a.)

(North Anna) the Shift Manager (Surry) shall notify the National Response Center, the State Department of Environmental Quality (Water) (DEQ), the LEPC, and (Surry) the U.S. Coast Guard. If the discharge is to land, DEQ and the LEPC shall be notified. Notifications shall be documented on Attachment 1, Oil or Hazardous Substance Release Report. See 6.1.1.a. See also Steps 6.3A.aA., 6.20.3, and 6.27.3.n. 3 NOTE: The Environmental Compliance Coordinator or Electric Environmental Services should be consulted when assessing hazardous material release reportability.

e. If a regulated, hazardous material release to the environment 1 exceeds a reporting threshold as specified in Table 12:

1. The individual who becomes aware of the release or potential release shall notify the Shift Manager. See EPIP-1.01.

1. Reportable Quantity (RQ) is the amount of a regulated, hazardous material released to the environment during a 24-hour period that must be reported in accordance with federal agency requirements. RQ only applies to a release to the environment, so will not apply for every release of a regulated, hazardous material. For example, a hazardous substance spill that is contained entirely on-site, even if more than the RQ, is not reportable because it is not a release to the environment. However, if an RQ amount evaporates or is absorbed in soil, the spill has not been contained entirely on-site, and thereby becomes a reportable release to the environment.

If the VPDES or other permit authorizes discharge of a hazardous material, a discharge is not reportable as a release to the environment unless a discharge amount or concentration exceeds the permit-authorized limit or the discharge is via a pathway not specified during the permit application and approval process. Permit-authorized discharges are reportable only as required by the applicable permit (e.g., the monthly Discharge Monitoring Report, per Step 6.27.3.i., required by the VPDES permit).

If an amount or concentration does exceed a permit-authorized limit or is discharged via a pathway other than specified during the permit application and approval process, the RQ and associated reporting requirements will apply.

2. Table 1 does not mention PCBs because no PCBs are in use at the Station. The Environmental Compliance Coordinator or Electric Environmental Services should be contacted for further instructions if any question arises concerning PCBs being introduced on-site and any consequent reporting.

3. If the discharge occurs in the Main Switchyard the Dominion System Operator Transmission shall be notified.

If the discharge is from the transformer belonging to Rappahannock Electric Cooperative at the Dam then that company shall be notified (North Anna)

DOMINION VPAP-2802 REVISION 30 PAGE 75 OF 205

2. The Shift Manager shall notify the Manager Nuclear Operations, the Environmental Compliance Coordinator, or Electric Environmental Services, as available.

3. The Environmental Compliance Coordinator or Electric Environmental Services (see Step 6.3.l.a.) (North Anna) Shift Manager (Surry) shall notify the agencies listed in the "Report To" column of Table 1. If a reportable release involves off-site transportation (including storage incident to such transportation), the Shift Manager shall also notify the 911 operator, local and state police, and the National Response Center. Notifications shall be documented on Attachment 1, Oil or Hazardous Substance Release Report. See Step 6.1.1.a. See also Steps 6.3.2.g., 6.3.4.a.4., 6.22.3.b. and 6.27.3.n. [CERCLA Sec. 304(b)(1); 40 CFR 30]

4. Notifications shall include (to the extent known) [CERCLA Sec. 304(b)(2)]:

The chemical name or identity of the substance involved in the release

Whether the substance is on the list referred to in section 302(a) of CERCLA, 40 CFR 302.

An estimate of the quantity of substance released to the environment

The time and duration of the release

The medium or media into which the release occurred

Any known or anticipated acute or chronic health risks associated with the emergency and, where appropriate, advice regarding medical attention necessary for exposed individuals

Proper precautions to take as a result of the release, including evacuation

The name and telephone number of the Dominion contact

DOMINION VPAP-2802 REVISION 30 PAGE 76 OF 205

f. If the Station does not comply with one or more limitations, standards, monitoring, or management requirements specified in the VPDES permit (if oil is involved, go to Step 6.3.2.d.; if hazardous materials are involved, go to Step 6.3.2.e.) and such noncompliance:

May adversely affect State waters or

May endanger public health 1 As soon as possible, the Environmental Compliance Coordinator or Electric Environmental Services shall notify (see Step 6.3.l.a.) the State Department of Environmental Quality (Water) by telephone with the following information [VPDES Permit II.F.2]:

A description and cause of noncompliance

The period of noncompliance, including exact dates and times or anticipated time when the noncompliance will cease

Actions taken or planned to reduce, eliminate, and prevent recurrence See also Steps 6.3A.aA., 6.27.2.a.1., and 6.27.3.n.

1. Applicable regulations use, but do not define, the terms "adversely affect" and "endanger public health." These terms must be interpreted on a case-by-case basis by individuals with aquatic ecology expertise and thorough familiarity with current regulatory agency reporting and enforcement policy. Such individuals will also determine how soon a specific event must be reported to avoid enforcement (i.e., within minutes of an event, or some longer time within the not-to-exceed 24-hour limit established by the VPDES Permit).

DOMINION VPAP-2802 REVISION 30 PAGE 77 OF 205

g. If an incident occurs during transport (including loading, unloading, and temporary storage) of:

Radioactive materials in which fire, breakage, spillage, or suspected radioactive contamination occurs (see also Step 6.28.3) [49 CFR 171.15(a)(2)]

Hazardous materials in which any of the following is a direct result of the hazardous materials: [49 CFR 171.15(a)(1)]

- A person is killed

- A person requires hospitalization because of injuries

- Estimated carrier or other property damage exceeds $50,000

- An evacuation of the general public occurs lasting one or more hours

- One or more major transportation arteries or facilities are closed or shut down for one hour or more

- The operational flight pattern or routine of an aircraft is altered

A situation exists (e.g., a continuing danger to life exists at the scene of the incident) that, in the judgment of the carrier or Dominion, should be reported even though it does not meet one of the previous criteria [49 CFR 171.15(a)(4)]

Supervisor Licensing (Station) shall notify (see Step 6.3.1.a.) DOT by telephone, or confirm carrier notification of DOT by telephone. See also Steps 6.3.2.e.

and 6.21.2. The notification shall include the [49 CFR 171.15]:

Notifier's name

N arne and address of carrier represented by the notifier

Phone number where the notifier can be contacted

Date, time, and location of incident

The extent of injuries, if any

Classification, name, and quantity of radioactive or hazardous materials involved, if available

Type of incident and nature of radioactive or hazardous material involvement and whether a continuing danger to life exists at the scene

/

DOMINION VPAP-2802 REVISION 30 PAGE 78 OF 20S

h. If a serious accident or a death occurs at or immediately above or below Lake Anna Dam 1 or is alleged to be related to the existence or operation of the dam:

1. The Lake Anna Dam Operator shall notify the Shift Manager and provide information necessary to prepare Attachment 2, FERC Public Safety Database Report.

2. The Shift Manager shall initiate a Condition Report in accordance with PI-AA-200.

3. The Shift Manager should notify the FERC Regional Engineer of the condition by telephone. See Step 6.1.1.a. See also Steps 6.3A.aA., 6.3.S.c., and 6.18.2.b.

(North Anna)

1. If a condition is identified that affects the safety of Lake Anna Dam or its associated works (see Subsection 4.8), but does not require entry into the North Anna Hydroelectric Project Emergency Action Plan:

1. The Lake Anna Dam Operator shall notify the Shift Manager and provide relevant supporting information.

2. The Shift Manager shall notify, by telephone, the FERC Regional Engineer of the condition and initiate a Condition Report in accordance with PI-AA-200.

See Step 6.1.1.a. See also Steps 6.3A.aA. and 6.18.1.b. (North Anna)

[18 CFR 12.10(a)]

1. Incidents which involve other parts of the lake are excluded. [18 CFR 12.10(b)(4)]

DOMINION VPAP-2802 REVISION 30 PAGE 79 OF 205 6.3.3 One-hour Notifications NOTE: Some conditions, indicated by "See EPIP-1.01," may exceed an Emergency Action Level (EAL) as specified in EPIP-1.01, Emergency Manager Controlling Procedure.

If a condition exceeds an EAL, EPIPs control State and Federal agency notifications.

If an event or condition does not exceed an EAL, it may still be reportable in accordance with this procedure.

As soon as practical, but within one hour, the Shift Manager, Station Emergency Manager, or Site Vice President shall notify the NRC Operations Center of:

a. Deviation from Technical Specifications (permitted by 10 CFR 50.54(x)) to protect the health and safety of the public, when no action consistent with license conditions and Technical Specifications can provide adequate or equivalent protection. [10 CFR 50.72(b)(I)]

b. An automatic safety system that does not function as required during operation. See EPIP-1.0 1. [10 CFR 50.36(c)(1)(ii)(A)]

NOTE: Notifications required by Steps 6.3.3.c., 6.3.3.d., and 6.3.3.e., are exempt from the requirement that Safeguards Information be transmitted only by protected telecommunications circuits approved by NRC.

c. An accidental criticality or loss of SNM. See EPIP-l.Ol.

[10 CFR 70.52 (a), 10 CFR 72.74(a), 10 CFR 74.11a]

DOMINION VPAP-2802 REVISION 30 PAGE 80 OF 20S NOTE: Step 6.3.3.d. notifications need not duplicate Step 6.3.3.e. notifications.

[10 CFR 74.U(c), 10 CFR n.74(c)]

d. A loss of any [10 CFR 73.71(a)(1), 10 CFR 73.67(e)(3)(vii), 10 CFR 73.67(g)(3)(iii)]:

SNM shipment

Spent fuel shipment or Availability of supplemental information after initial notification. [10 CFR 73.71(a)(5)]

(See also Step 6.1S.3.a.3.)

or Recovery of or accounting for such lost shipment.

See also Step 6.1S.3.a.2. [10 CFR 73.71(a)(1), 10 CFR 73.67(e)(3)(vii), 10 CFR 73.67(g)(3)(iii)]

NOTE: Steps 6.3.3.e., 6.3.3.f., 6.3.3.g., 6.3.3.h.notifications need not duplicate Step 6.3.3.d.

or 10 CFR SO.72 notifications. [10 CFR n.74(c), 10 CFR 73.71(e), 10 CFR 74.11(c)]

e. A reason to believe that a person has committed or caused, or attempted to commit or cause, or has made a credible threat to commit or cause (See also Step 6.1S.3.b.2.).

[10 CFR 73.71(b)(1), 10 CFR 73 App. G.I, 10 CFR 70.52 (b), 10 CFR n.74(a), 10 CFR 74.11(a)]:

Theft, loss, or unlawful diversion of SNM

Significant physical damage to the Station, nuclear fuel, or carrier of nuclear fuel

Interruption of normal operation through unauthorized use of or tampering with its machinery, components, or controls, including the security system

f. Unauthorized entry into a protected area, material access area, controlled access area, vital area, or transport.

g. Failure, degradation, or the discovered vulnerability in a safeguard system that could allow unauthorized or undetected access to a protected area, controlled access area, vital area, or transport for which compensatory measures have not been employed.

DOMINION VPAP-2802 REVISION 30 PAGE 81 OF 205 NOTE: Fitness-for-duty events are reported in accordance with 10 CFR 26 instead of 10 CFR 73.71. See Steps 6.3.6.b. and 6.8.1. [10 CFR 26.73(c)j

h. Actual or attempted introduction of contraband into a protected area, material access area, or transport.

1. Discovery that an undeclared or misclassified event or condition met all the following criteria:

Exceeded an Emergency Action Level (EAL) as specified in EPIP-1.01, Emergency Manager Controlling Procedure

The basis for the emergency class no longer exists at the time of discovery

No other reasons exist for an emergency declaration In addition, the following shall be notified:

Department of Emergency Management (at approximately the same time)

Director Nuclear Protection Services and Emergency Preparedness

DOMINION VPAP-2802 REVISION 30 PAGE 82 OF 205 6.3.4 Four-hour Notifications NOTE: Some conditions, indicated by "See EPIP-l.O 1," may exceed an Emergency Action Level (EAL) as specified in EPIP-1.01, Emergency Manager Controlling Procedure.

If a condition exceeds an EAL, EPIPs control State and Federal agency notifications.

If an event or condition does not exceed an EAL, it may still be reportable in accordance with this procedure.

a. As soon as practical, but within four hours, the Shift Manager shall notify the NRC Operations Center via the ENS of:

NOTE: If a unit enters a limiting condition for operation (LCO) and a unit shutdown is started due to the LCO, the event is reportable even if shutdown is not completed. LCOs terminated by a unit shutdown for an unrelated reason are still reportable if the condition would not have been corrected within the LCO time limit for shutdown.

1. Initiation of plant shutdown (reduction of power or temperature) required by Technical Specifications. The initiation of plant shutdown does not include mode changes required by Technical Specifications if initiated after the plant is already in a shutdown condition. See EPIP-l.Ol. [10 CFR 50.72(b)(2)(i),

10 CFR 50.36(c)(1)(i)(A), 10 CFR 50.36 (c)(2), NUREG 1022 Item 3.2.1]

2. Any event that results or should have resulted in ECCS discharge into the RCS as a result of a valid signal except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation. [10 CFR 50.72(b)(2)(iv)(A)]

3. Any event or condition that results in actuation of the reactor protection system (RPS) when the reactor is critical except when actuation results from and is part of a pre-planned sequence during testing or reactor operation.

[10 CFR 50.72(b)(2)(iv)(B)]

VPAP-2802 DOMINION REVISION 30 PAGE 83 OF 205 NOTE: "Notification to other government agencies has been or will be made" is not necessarily an automatic notification to the NRC. Refer to NUREG - 1022, Event Reporting Guidelines 10 CFR 50.72 and 50.73, for discussions and examples or contact Station Licensing if clarification is needed. [NUREG-I022, Section 3.2.12]

4. Any event or situation, related to the health and safety of the public or onsite personnel, or protection of the environment, for which a news release is planned, or notification to other government agencies has been or will be made.

Such an event may include an onsite fatality or inadvertent release of radioactively contaminated materials. [Commitment 3.2.16] [10 CFR SO.72(b)(2)(xi)]

5. Any instance of: [10 CFR 72.216(c)]

A defect in any spent fuel storage cask structure, system, or component that is important to safety [10 CFR 72.7S(b)2]

or

A significant reduction in the effectiveness of any spent fuel storage cask confinement system during use of the storage cask [10 CFR 72.7S(b)3]

See EPIP-l.Ol.

6. ISFSI Non-emergency Four-Hour Notifications shall include, if available at time of notification: [10 CFR 72.7S(d)(I)]

The caller's name and call back telephone number

A description of the event, including time and date

The exact location of the event

The quantities, and chemical and physical forms of the spent fuel or HLW involved

Any personnel radiation exposure data

7. An event that prevents immediate actions necessary to avoid exposures to radiation or radioactive material that could exceed regulatory limits or releases of radioactive materials that could exceed regulatory limits (e.g., events such as fires, explosions, and toxic gas releases)-see Step 6.14.7 .e. [10 CFR 72.7S(b)(I)]

DOMINION VPAP-2802 REVISION 30 PAGE 84 OF 205

8. An action taken in an emergency that departs from a license condition, technical specification, or certificate of compliance when the action is immediately needed to protect the public health and safety and no licensed action that provides adequate or equivalent protection is immediately apparent-see Step 6.14.7 .e. [10 CFR 72.75(b)(4)]

9. An unplanned fire or explosion damaging any spent fuel or HLW, or any device, container, or equipment containing spent fuel or HLW when the damage affects the integrity of the material or its container-see Step 6.14.7.e. [10 CPR 72.75(b)(6)]

10. An event at the ISFSI that requires unplanned medical treatment at an offsite medical facility of an individual with radioactive contamination on the individual's clothing or body which could cause further radioactive contamination. [10 CFR 72.75(b)(5)]

11. Groundwater Protection Voluntary Communication Notifications to other government agencies may be reportable under 10 CFR 50.72(b)(2)(xi) requirement for a 4-hour notification to the NRC operations center based upon the following guidance:

If a licensee is notifying a local, state, or other federal agency in accordance with an existing law, regulation, or ordinance, then the licensee should make its notification to the NRC under the 50.72 notification requirement.

If a licensee is informally communicating with a local, state, or other federal agency (i.e., not under a specific law, regulation or ordinance), then the licensee has discretion as to whether to informally communicate with NRC (e.g., through the site resident inspector and/or regional NRC office) or formally through the 50.72 notification process. If due to the site-specific circumstances or heightened sensitivity to the issue at that site, the issue is likely to produce strong media interest, then the licensee should consider notifying NRC under the 50.72 requirement because this is actually the underlying intent of the regulation.

DOMINION VPAP-2802 REVISION 30 PAGE 85 OF 205

b. Any person at the Station who observes smoke originating from Station equipment being released into the outdoor atmosphere shall notify the Shift Manager as soon as possible.

1. If the smoke is not from a fire and there are no certified visible emissions evaluators available to determine the opacity of the smoke being released to the outdoor atmosphere, the Shift Manager or other Station personnel shall take the appropriate steps to determine the source, cause, and duration of the smoke being released.

Once all of the pertinent information regarding the release of smoke has been obtained, the AQD must be notified immediately.

The AQD will report the release of smoke into the outdoor atmosphere to the appropriate DEQ regional office as soon as practical, but no later than four daytime business hours of the occurrence, with all of the pertinent information. If the DEQ regional office determines that it is necessary to obtain smoke readings after receiving all of the pertinent information, the AQD will dispatch a certified visible emissions evaluator to the Station to determine the opacity of the smoke being released into the outdoor atmosphere.

2. The AQD will prepare and submit any written reports to the DEQ regional office regarding the release of smoke into the outdoor atmosphere.

DOMINION VPAP-2802 REVISION 30 PAGE 86 OF 20S 6.3.S Eight-hour Notifications

a. As soon as practical, but within eight hours, the Shift Manager shall notify the NRC Operations Center via the ENS of:

1. Any condition that results in the condition of the Station, including its principal safety barriers, being seriously degraded. [10 CFR SO.72(b)(3)(ii)(A)]

2. Any event or condition that results in the Station being in an unanalyzed condition that significantly degrades plant safety. [10 CFR SO.72(b)(3)(ii)(B)]

3. Any event or condition that results in valid actuation of any of the following systems, except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation: [10 CFR SO.72(b)(3)(iv)(A)]

Reactor Protection System (RPS) - (RPS actuation with the reactor critical may be reportable within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months under 10 CFR SO.72(b)(2)(iv)(B), see Step 6.3.4.a.3.)

General containment isolation signals affecting containment isolation valves in more than one system or multiple Main Steam Isolation Valves (MSIV s)

Emergency Core Cooling Systems (ECCS) including HHSI and LHSI (Actual discharges are reportable within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months under 10 CFR SO.72(b)(2)(iv)(A), see Step 6.3.4.a.2.)

Auxiliary Feedwater System

Containment heat removal and depressurization systems including Containment spray and fan cooler systems

Emergency Diesel Generators (EDGs)

4. Any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to:

Shut down the reactor and maintain it in a safe shutdown condition

Remove residual heat

Control the release of radioactive material; or

Mitigate the consequences of an accident. See EPIP-1.0 1: [10 CFR SO.72(b)(3)(v)]

S. Any event requiring the transport of a radioactively contaminated person to an off-site medical facility for treatment. See also Step 6.27.2. [10 CFR 50.72 (b)(3)(xiO]

Could also be a 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months report in accordance with 10 CFR 72.7S (b)(S).

DOMINION VPAP-2802 REVISION 30 PAGE 87 OF 205

6. An event that results in a major loss of emergency assessment capability 1, off-site response capability, or off-site communications capability, e.g.,

unavailability of any of the following (see Attachment 3, Emergency Response Unavailability, for unavailability criteria)2:

Safety Parameter Display System3 (SPDS)

Emergency response facilities 4 (see Subsection 4.15)

Emergency communications facilities and equipment5

Prompt Notification System, including sirens

Plant monitors necessary for accident monitoring See EPIP-1.0 1. [10 CFR 50.72(b)(3)(xiii)]

b. If an Alert, Site Area Emergency, or General Emergency is declared:

1. The Station Coordinator Emergency Preparedness shall prepare a Summary Report from information in completed Emergency Plan Implementing Procedures, Control Room logs, and interviews with persons involved with the declaration and response, as appropriate. See Attachment 8, Example DEM Summary Report.

2. The Site Vice President, Director Nuclear Station Safety and Licensing, or Plant Manager (Nuclear) shall approve the report.

3. Within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months after termination of the event, Nuclear Emergency Preparedness shall ensure the report is delivered to the State Coordinator of the Virginia Department of Emergency Management. [NAEP 4.4; SEP 4.4]

1. A major loss of emergency assessment capability includes events that significantly impair fulfillment of the Emergency Plan, including safety assessment capability (e.g., loss of a significant portion of Control Room indications). Loss of on-site meteorological information does not constitute a major loss of assessment capability and should not be reported under this part.

2. Engineering judgment may be needed to assess the significance of losing certain equipment.

3. Unavailability of only the SPDS (one function of the Plant Computer System (PCS)) for less than eight hours is not reportable, but unavailability of the SPDS and other assessment capability at the same time may be reportable. Scheduled PCS outages or operation of PCS in the Simulator mode are not reportable if the SPDS can be made available in less than one hour.

4. EOF loss is reportable only if both the LEOF and the CEOF are unavailable.

5. A momentary loss of off-site response capability or emergency communications (e.g., the backup power supply fails while security computer and emergency communications are temporarily connected to perform a surveillance test) is not reportable.

DOMINION VPAP-2802 REVISION 30 PAGE 88 OF 205

c. If, on Dominion property or at Lake Anna Dam, there is a Dominion employee or contractor fatality (regardless of the time between the injury and death, or the length of an illness) or an event in which three or more Dominion employees or contractors are hospitalized:

1. The Shift Manager shall notify Supervisor Nuclear Site Safety (Station) with the following information:

Number of fatalities

The employer of those killed

The circumstances of the event

The extent of injuries

2. Nuclear Site Safety (Station) shall notify OSHA as specified in Step 6.3.S.c.3.

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 250f41 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:

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 J1-2S-F2 (1-RC-MOV-1535) PRZR PORV Isolation Valve b) Check PRZR PORV Block Valves - BOTH o b) Open valves.

OPEN:

o

1-RC-MOV-1536 o

1-RC-MOV-1535 c) Open both PRZR PORVs: o c) Try to open PORVs by placing NDT PROTECTION key switch to OPEN.

o

1-RC-PCV-1456 o

1-RC-PCV-1455C \w< t-CP~'

\" DC; o

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:

D

1-RC-MOV-1536, PRZR PORV D

1-RC-SOV-1 01 A-2 BLOCK VALVE 0

1-RC-SOV-1 01 B-2 D

1-RC-MOV-1535, PRZR PORV BLOCK VALVE D

1-RC-SOV-101A-1 D

1-RC-PCV-1456, PRZR PORV D

1-RC-SOV-1 01 B-1 D

1-RC-PCV-1455C, PRZR PORV b) Open the following PRZR Vent Valves:

D

1-RC-SOV-102A-2 D

1-RC-SOV-102B-2 D

1-RC-SOV-102A-1 D

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:

D

Fire Protection System OR D

Service Water System (STEP 23 CONTINUED ON NEXT PAGE)

NUMBER PROCEDURE TITLE REVISION 19 1-FR-H.1 RESPONSE TO LOSS OF SECONDARY HEAT SINK PAGE 27 of 41 ACTION/ EXPECTED RESPONSE RESPONSE NOT OBTAINED

23. VERIFY ADEQUATE RCS BLEED PATH BY VERIFYING THE FOLLOWING VALVES -

OPEN: (Continued)

2) WHEN low-pressure water source flow path is aligned, THEN do the following:

o a. Depressurize at least one intact SG to atmospheric pressure using SG PORV to inject low-pressure water source.

o b. Initiate ATTACHMENT 2 to isolate SI Accumulators as SG pressure approaches 120 pSig.

24._ INITIATE ATTACHMENT 5, VERIFYING APPLICABLE ACTIONS OF 1-E-O, WHILE CONTINUING WITH THIS PROCEDURE

25. MAINTAIN RCS HEAT REMOVAL:

o

Maintain SI flow o

Maintain both PRZR PORVs - OPEN

Close Charging Pump Recirc Valves:

o

1-CH-MOV-1275A o

1-CH-MOV-1275B o

1-CH-MOV-1275C

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:

J\C~f-&v 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)

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95)

Response to Loss of Secondary Heat Sink (1-FR-H.1)

To pic 7.1 ciniOrri1-~ti()n .aSsociated .with ****1 ..FR;.H:1 7.1 Objective U 11276 List the following information associated with 1-FR-H.1, "Response to Loss of Secondary Heat Sink" (SOER-86-1 ).

Purpose of the procedure

Modes of applicability

Entry conditions

Major action categories

Conditions that result in leaving the procedure 7.1 Content

1. The purpose of 1-FR-H.1 is to provide guidance to operations personnel to respond to an extreme challenge to the heat sink critical safety function.

2. FR-H.1 is applicable when the unit is initially in Modes 1 - 3.

3. Entry conditions for 1-FR-H.1 include:

3.1. Entry from the Heat Sink Critical Safety Function Status Tree on the following RED path condition:

3.1.1.Narrow range level in all SGs less than 11 % [22] AND total auxiliary feedwater flow to SGs less than 340 gpm.

3.2. Entry directly from E-O when:

REACTOR OPERATOR Page 45 of 99 Revision 14, 11/06/2008

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95) 3.2.1.Narrow range level in all SGs is less than 11 %[22] AND 3.2.2.At least 340 gpm of total auxiliary feedwater flow to the SGs cannot be established.

4. Major action categories associated with 1-FR-H.1 include:

4.1. Attempt restoration of feed flow to steam generators.

4.2. Initiate RCS bleed and feed heat removal.

4.3. Restore and verify secondary heat sink.

4.4. Terminate RCS bleed and feed heat removal.

5. Conditions that result in leaving the procedure 5.1. FR-H.1 is exited when a secondary heat sink is reestablished (assuming bleed and feed has not yet been initiated) as indicated by ANY ONE of the following:

5.1.1.At least 340 gpm of total AFW flow is established, OR 5.1.2.At least 0.7 X 106 Ibmlhr MFW flow to at least one SG is established, OR 5.1.3.Core exit TC's decreasing and W/R SG level(s) increasing, OR 5.1.4.Narrow range SG level(s) greater than 11 % [22].

REACTOR OPERATOR Page 46 of 99 Revision 14, 11/06/2008

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95) 3.5. Once boiling begins, depressurization of the RCS using PORVs without uncovering the core would be highly unlikely.

3.6. Core uncovery would then be necessary to reduce the steam generation rate to a rate that would permit RCS depressurization using PRZR PORVs.

3.7. Therefore, the use of "bleed and feed" is preferred to ensure adequate delivery of SI flow to the core, and adequate removal of core decay heat to prevent uncovering the core.

Tppic7.10InabilitYtd-Establis'hBI~'e.d aQd. FeeCi '

7.10 Objective U 11313 Explain the following concepts associated with the inability to establish Reactor Coolant System bleed and feed in response to a loss of secondary heat sink (1-FR-H.1, SOER-86-1).

Why, if the Reactor Coolant System feed path cannot be established, the bleed path must not be established

Why, if both pressurizer power-operated relief valves and block valves cannot be opened, insufficient core heat removal may result

How secondary heat removal capability may be restored using the Fire Protection or Service Water System if both pressurizer power-operated relief valves and block valves cannot be opened 7.10 Content

1. If the Reactor Coolant System feed path cannot be established, the bleed path must not be established.

1.1. A severe uncovering of the core will result.

1.2. For this case, the operator is instructed to continue attempts to establish feed flow since this is the only action that can prevent uncovering the core.

2. If at least two PRZR PORVs are not maintained open:

2.1. The RCS may not depressurize sufficiently to permit adequate feed of sub-cooled SI flow to remove core decay heat.

REACTOR OPERATOR Page 58 of99 Revision 14, 11/06/2008

STUDENT GUIDE FOR FUNCTIONAL RESTORATION PROCEDURES (95) 2.2. If core decay heat exceeds RCS bleed and feed heat removal capability, the RCS will re-pressurize rapidly, further reducing the feed of sub-cooled SI flow and resulting in a rapid decrease of RCS inventory.

2.3. Although only one open PRZR PORV may not be sufficient to maintain adequate RCS bleed flow, the operator should maintain one PRZR PORV open, if possible, and open all reactor vent and PRZR vent valves to provide additional bleed path capability.

3. If either PORV can not be opened:

3.1. The operator should align Fire Protection or Service Water to supply feedwater to the depressurized SG(s) to restore secondary heat removal.

3.2. The operator should then attempt to open a steam generator PORV for at least one intact SG and depressurize that SG to atmospheric pressure to allow a low-pressure injection source to be used to feed the steam generators.

3.3. RCS inventory depletion will occur from the single open PRZR PORV, the PRZR safety valves, and reactor/PRZR vents as the steam generator(s) is being depressurized to atmospheric pressure.

7.11 Objective U 11302 Explain the following concepts associated with terminating Reactor Coolant System bleed and feed after restoring secondary heat removal capability (1-FR-H.1).

Why, if Reactor Coolant System subcooling is below the required value, a pressurizer power-operated relief valve is closed before stopping a high-head safety injection pump

Why Reactor Coolant System pressure should be allowed to increase after closing a pressurizer power-operated relief valve before stopping a high-head safety injection pump

Why, if the low-head safety injection pump suction valves from containment are open, the operator is directed to establish and maintain at least 60 gpm of normal charging flow prior to isolating the bit REACTOR OPERATOR Page 59 of 99 Revision 14, 11/06/2008

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