ML112270229

301 Draft SRO Written Exam

ML112270229
Person / Time
Site:	Vogtle
Issue date:	08/08/2011
From:	NRC/RGN-II/DRS/OLB
To:	Southern Nuclear Operating Co
References
05-424/11-301, 05-425/11-301
Download: ML112270229 (237)

Text

HL-16 NRC Written Examination KEY

76. 003G2.2.22 001 / 1/2/DROPPED ROD-LCO/4.7 MEM/BANK 2004 CALLAWAY/SRO/NRC/GCW Unit one is at 90% power

- Control Bank Rod D12 drops to the bottom of the core.

Which ONE of the following describes the status of Control Rod Dl 2 and which initial condition assumed in the Safety Analysis is challenged?

A. Inoperable Shutdown Margin will be challenged.

B Misaligned - Power distribution will be challenged.

C. Misaligned - Shutdown Margin will be challenged.

D. Inoperable - Power distribution will be challenged.

Page 153 of 208

HL-16 NRC Written Examination KEY Feedback 003 Dropped Control Rod Equipment Control 2.2.22 Knowledge of limiting conditions for operations and safety limits.

(CFR: 41.5/43.2/45.2)

K/A MATCH ANALYSIS The question matches the dropped rod and its operability per TSs and Safety Analysis.

SRO 10CFR 55.43(b) 2 ANSWER/DISTRACTOR ANALYSIS A. Incorrect-SDM is not challenged due to the fact that the rod was trippable and has dropped into the core. Plausible because the rod is> 12 steps from the group demand position, but it is not mop.

B. Correct C. Incorrect-The rod is misaligned per Tech Specs. Plausible because TS requires a SDM calculation to be performed.

D. Incorrect-Plausible because power distribution may be challenged. The rod is operable because of trippability by dropping into the core.

REFERENCES Tech Spec 3.1.4 and bases (Amendment 157/Rev 9)

VEGP learning obiectives:

LO-LP-39205-O1 For any given item in section 3.1 of Tech Specs, be able to:

a. State the limiting condition for operation (LCO), and

b. State any one hour or less required actions.

Page 154 of 208

Rod Group Alignment Limits 3.1.4 3.1 REACTIVITY CONTROL SYSTEMS 3.1.4 Rod Group Alignment Limits LCO 3.1.4 All shutdown and control rods shall be OPERABLE, with all individ ual indicated rod positions within 12 steps of their group step counte r demand position.

APPLICABILITY: MODES 1 and 2.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more rod(s) A.1 .1 Verify SDM is the limit 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> untrippable. specified in the COLR.

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

AND A.2 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> B. One rod not within B.1 .1 Verify SDM is the limit 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> alignment limits, specified in the COLR.

OR (continued)

Vogtle Units I and 2 3.1.4-1 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

Rod Group Alignment Limits 3.1.4 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued)

B.1.2 Initiate boration to restore 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> SDM to within limit.

AND B.2 Reduce THERMAL 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> POWER to 75% RTP.

AND B.3 Verify SDM is the limit Once per specified in the COLR. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> AND B.4 Perform SR 3.2.1.1. 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> AND 8.5 Perform SR 3.2.2.1. 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> AND B.6 Reevaluate safety 5 days analyses and confirm results remain valid for duration of operation under these conditions.

(continued)

Vogtle Units 1 and 2 3.1.4-2 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

Rod Group Alignment Limits 3.1.4 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and C.1 Be in MODE 3 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition B not met.

D. More than one rod not D.1 .1 Verify SDM is the limit 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> within alignment limit, specified in the COLR.

OR D. 1.2 Initiate boration to restore 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> required SDM to within limit.

AND D.2 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.4.1 Verify individual rod positions within alig nment 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> limit.

AND Once within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> thereafter when the rod position deviation monitor is inoperable (continued)

Vogtle Units 1 and 2 3.1.4-3 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

Rod Group Alignment Limits 3.1.4 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.1.4.2 Verify rod freedom of movement by moving each 92 days rod not fully inserted in the core 10 steps in either direction.

SR 3.1.4.3 Verify rod drop time of each rod, from the physical Prior to reactor fully withdrawn position, is 2.7 seconds from the criticality after beginning of decay of stationary gripper coil each removal of voltage to dashpot entry, with: the reactor head

a. Tavg551°F and

b. All reactor coolant pumps operating.

Vogtle Units 1 and 2 3.1.4-4 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

Rod Group Alignment Limits B 3.1.4 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.4 Rod Group Alignment Limits BASES BACKGROUND The OPERABILITY (i.e., trippability) of the shut rods is an initial assumption in all safety analy down and control ses that assume rod insertion upon reactor trip. Maximum rod misa assumption in the safety analysis that direc lignment is an initial tly affects core power distributions and assumptions of available SDM The applicable criteria for these reactivity and design requirements are 10 CFR 50, Appendi power distribution x

Reactor Design, and GDC 26, Reactivity ConA, GDC 10, Redundancy and Capability (Ref. 1), and 10 trol System Acceptance Criteria for Emergency Core CFR 50.46, Cooling Systems for Light Water Nuclear Power Plants (Ref. 2).

Mechanical or electrical failures may cau se inoperable or to become misaligned from its a control rod to become grou inoperability or misalignment may cause incre p. Control rod ased power peaking, due to the asymmetric reactivity distribution and a reduction in the total available rod worth for reactor shutdow n.

rod alignment and OPERABILITY are related Therefore, control design power peaking limits and the core desig to core operation in minimum SDM. n requirement of a Limits on control rod alignment have been estab positions are monitored and controlled durin lished, and all rod g power operation to ensure that the power distribution and react ivity the design power peaking and SDM limits are limits defined by preserved.

Rod cluster control assemblies (RCCAs), or rods, are moved by their control rod drive mechanisms (CRDMs its RCCA one step (approximately inch) ). Each CRDM moves at a time, but at varying rates (steps per minute) depending on the sign Rod Control System. al output from the The RCCAs are divided among control bank s and shutdown banks. Each bank may be further subdivided to provide for precise reactivity control. A into two groups group consists (continued)

Vogtle Units 1 and 2 B 3.1.4-1 Revision No. 0

Rod Group Alignment Limits B 3.1.4 BASES BACKGROUND of two or more RCCAs that are electrically paralleled to step (continued) simultaneously. A bank of RCCAs consists of two groups that moved in a staggered fashion, but always within one step of are each other. There are four control banks and five shutdown banks.

control banks contain two rod groups, two shutdown banks All contain two rod groups, and the remaining three shutdown banks contain one rod group.

The shutdown banks are maintained either in the fully inserte fully withdrawn position. The control banks are moved in d or an overlap pattern, using the following withdrawal sequence

When control bank A reaches a predetermined height in the core, control bank B begins to move out with control bank A. Control bank A stops at the position of maximum withdrawal, and control bank continues to move out. When control bank B reaches B a

predetermined height, control bank C begins to move out with control bank B. This sequence continues until control banks and C are at the fully withdrawn position, and control bank A, B, D

approximately halfway withdrawn. The insertion sequence is opposite of the withdrawal sequence. The control rods is the are arranged in a radially symmetric pattern, so that control bank motion does not introduce radial asymmetries in the core power distributions.

The axial position of shutdown rods and control rods is indicat two separate and independent systems, which are the Bank ed by Demand Position Indication System (commonly called group step counters) and the Digital Rod Position Indication (DRPI)

System.

The Bank Demand Position Indication System counts the from the rod control system that moves the rods. There pulses is counter for each group of rods. Individual rods in a group one step receive the same signal to move and should, therefore, all all be at the same position indicated by the group step counter for that group.

The Bank Demand Position Indication System is considered precise (+/- 1 step or +/- inch). If a rod does not move highly one step for each demand pulse, the step counter will still count the incorrectly reflect the position of the rod. pulse and The DRPI System provides a highly accurate indication actual control rod position, but at a lower precision than of the step counters. This system is based on inductive analog (continued)

Vogtle Units 1 and 2 B 3.1.4-2 Revision No. 0

Rod Group Alignment Limits B 3.1.4 BASES BACKGROUND signals from a series of coils spaced along (continued) a hollow tube with a center to center distance of 3.75 inches, whic h

However, the magnetic drive rod concentrates is six steps.

flux developed in the coil resulting in a chan the magnetic lines of ge in coil output voltage when the shaft is close to it. This provides a +/- 4 step accuracy with all coils operable. To increase system, the inductive coils are connected alterthe reliability of the nately to data system A or B. Thus, if one system fails, the DRPI will go on half accuracy (System A failure = +10, -4 steps and 10, ÷4 steps) with an effective coil spacing System B failure = -

of 7.5 inches, which is 12 steps. The resolution of the rod position indicator channel is +/- 5 percent of span (+/- 7.5 in. or +/- 12 steps). Devi ation of any RCCA from its group by 10 percent of span (15 inch es or 24 steps) will not cause power distributions worse than the desig n limits. The deviation alarm alerts the operator to rod devi the group position in excess of 5 percent of ation with respect to span (12 steps).

Therefore, since indication from one system is alignment within 24 steps, operation with one sufficient to maintain of failure of the other) is acceptable. system (in the event APPLICABLE Control rod misalignment accidents are analy SAFETY ANALYSES zed in the safety analysis (Ref. 3). The acceptance criteria for rod inoperability or misalignment are that: addressing control

a. There be no violations of:

1. specified acceptable fuel design limits, or

2. Reactor Coolant System (RCS) pressure boundary integrity; and

b. The core remains subcritical after accident trans ients.

Two types of misalignment are distinguished of a control rod group, one rod may stop mov During movement ing, rods in the group continue. This condition may while the other power peaking. The second type of misalignm cause excessive rod fails to insert upon a reactor trip and rema ent occurs if one withdrawn. This condition requires an evalu ins stuck fully ation to determine that (continued)

Vogtle Units 1 and 2 B 3.1.4-3 Revision No. 0

Rod Group Alignment Limits B 3.1.4 BASES APPLICABLE sufficient reactivity worth is held in the control rods to meet the SAFETY ANALYSES SDM requirement, with the maximum worth rod stuck fully withdrawn.

(continued)

Two types of analysis are performed in regard to static rod misalignment. With control banks at their insertion limits, one type of analysis considers the case when any one rod is completely inserted into the core. The second type of analysis considers the case of a completely withdrawn single rod from a bank inserte d to its insertion limit. Satisfying limits on departure from nuclea te boiling ratio in both of these cases bounds the situation when is misaligned from its group by 12 steps. a rod Another type of misalignment occurs if one RCCA fails to insert upon a reactor trip and remains stuck fully withdrawn. This condition is assumed in the evaluation to determine that the required SDM is met with the maximum worth RCCA also fully withdrawn (Ref. 3).

The Required Actions in this LCO ensure that either deviations from the alignment limits will be corrected or that THERMAL POWER will be adjusted so that excessive local linear heat rates (LHRs) will not occur, and that the requirements on SDM and ejected rod worth are preserved.

Continued operation of the reactor with a misaligned contro l rod is allowed if the heat flux hot channel factor (FQ(Z)) and the nuclea r

enthalpy hot channel factor (FH)are verified to be within their limits in the COLR and the safety analysis is verified to remain valid.

When a control rod is misaligned, the assumptions that are used to determine the rod insertion limits, AFD limits, and quadra nt power tilt limits are not preserved. Therefore, the limits may not preserve the design peaking factors, and FQ(Z) and FH must be verifie d

directly by incore mapping. Bases Section 3.2 (Power Distrib ution Limits contains more complete discussions of the relatio n of F(Z) and FH to the operating limits.

Shutdown and control rod OPERABILITY and alignment are directly related to power distributions and SDM, which are initial conditions assumed in safety analyses. Therefore they satisfy Criterion 2 of 10 CFR 50.36 (c)(2)(ii).

(continued)

Vogtle Units 1 and 2 B 3.1.4-4 Rev. 1-10/01

Rod Group Alignment Limits B 3.1.4 BASES (continued)

LCO The limits on shutdown or control rod alignments ensure that the assumptions in the safety analysis will remain valid. The requirements on OPERABILITY ensure that upon reactor trip, the assumed reactivity will be available and will be inserted. The OPERABILITY requirements (i.e., trippability) are separate from the alignment requirements which ensure that the RCCAs and banks maintain the correct power distribution and rod alignment.

The rod OPERABILITY (i.e., trippability) requirement is satisfied provided that the rod will fully insert in the required rod drop time assumed in the safety analyses. Rod control malfunctions that result in the inability to move a rod (e.g., rod lift coil failures), but that do not impact trippability, do not result in rod inoperability. However, where rod(s) are not moving, the rod(s) must be considered untrippable unless there is verification that a rod control system failure is preventing rod motion. If the rod control system is demanding motion properly and no motion occurs, the rod is considered untrippable (i.e.,

inoperable).

The requirement to maintain the rod alignment to within plus or minus 12 steps of their group step counter demand position is conservative. The safety analysis assumes a total misalignment from fully withdrawn to fully inserted. When required, movab le incore detectors may be used to determine rod position and verify the rod alignment requirement of this LCO is met.

Failure to meet the requirements of this LCO may produce unacceptable power peaking factors and LHRs, or unacceptable SDMs, all of which may constitute initial conditions inconsistent with the safety analysis.

APPLICABILITY The requirements on RCCA OPERABILITY and alignment are applicable in MODES 1 and 2 because these are the only MODE in which a self-sustaining chain reaction (K S 1 1) occurs, and the f

6 OPERABILITY (i.e., trippability) and alignment of rods have the potential to affect the safety of the plant. In MODES 3, 4, 5, and the alignment limits do not apply because the control rods are 6, fully inserted and the reactor is shut down, with no self-sustainin g chain reaction. In the shutdown MODES, the OPERABILITY of the shutdown and control rods has the potential to affect the require d

SDM, but this effect can be compensated for by an increase in the boron concentration of the RCS. See LCO 3.1.1, SHUTDOWN MARGIN (SDM), for SDM in MODES 3,4, and 5 and LCO 3.9.1, Boron Concentration, for boron concentration requirements during refueling.

(continued)

Vogtle Units 1 and 2 83.1.4-5 Rev. 1-8/03

ES-401 Written Examination Question Worksheet Form ES-401 -5 Examination Outline Cross-reference: Level RO SRO Tier# N/A Group # N/A 2 K/A # 003G2.2.22 Importance Rating N/A 4.1 Proposed Question:

The plant was initially at 100% when Control Bank Rod D12 drops to the bottom of the core.

Which ONE of the following describes the status of Control Rod D12 and which initial condition assumed in the Safety Analysis is challenged?

A. INOPERABLE-Upon a reactor trip, the assumed reactivity will be available and will be inserted B. MISALIGNED-The correct power distribution is maintained C. MISALIGNED-Upon a reactor trip, the assumed reactivity will be available and will be inserted D. INOPERABLE-The correct power distribution is maintained Proposed Answer: B Explanation:

A. Incorrect-The rod is misaligned and this is the operability basis B. Correct-The rod is misaligned and power distribution is affected C. Incorrect-The rod is misaligned, but the operability basis is separate D Incorrect- The rod is misaligned NUREG-1021 Draft Revision 9

HL-16 NRC Written Examination KEY

77. 003G2.2.25 002/2/I[RCP -TS BASES/4. 1 MEMIBANK SEABROOK 2004/SRO/NRC/EMT/GCW Technical Specification 3.4.4 requires all Reactor Coolant Loops to be OPERABLE and in operation while in Modes 1 and 2.

Which of the following describes the primary basis for this Technical Specification?

A. Provides even distribution of flow through the core to prevent fuel damage.

B. Provides a second barrier against fission product release to the environment.

C. Ensures reactor coolant system flow is sufficient for proper boration and chemistry control.

D Ensures DNBR remains above design limits during all normal operations and anticipated transients.

Page 155 of 208

HL-16 NRC Written Examination KEY Feedback 003 Reactor Coolant Pump System (RCPS)

Equipment Control 2.2.25 Knowledge of the bases in Technical Specifications for limiting conditions for operations and safety limits.

(CFR: 41.5/41.7/43.2)

K/A MATCH ANALYSIS Question is a direct match for the KA. All four RCPs are required. An OPERABLE loop consists of a OPERABLE RCP in operation and an OPERABLE SIG.

SRO-10CFR55.43 (b2)

ANSWER I DISTRACTOR ANALYSIS A. Incorrect Plausible-Secondary function of the RCS.

B. Incorrect Plausible-Secondary function of the RCS.

C. Incorrect Plausible-Secondary function of the RCS.

D. Correct per Applicable Safety Analysis section of of T.S. 3.4.4 bases.

REFERENCES Tech Spec 3.4.4 amendment U1-157/U2-139 Tech spec bases Rev 9 VEGP learning obiectives:

LO-LP-39208-04 Describe the bases for any given Tech Spec in section 3.4.

Page 156 of 208

RCS LoopsMODES 1 and 2 B 3.4.4 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.4 RCS LoopsMODES 1 and 2 BASES BACKGROUND The primary function of the RCS is removal of the heat generated in the fuel due to the fission process, and transfer of this heat, via the steam generators (SGs), to the secondary plant.

The secondary functions of the RCS include:

a. Moderating the neutron energy level to the thermal state, to increase the probability of fission;

b. Improving the neutron economy by acting as a reflector;

c. Carrying the soluble neutron poison, boric acid;

d. Providing a second barrier against fission product release to the environment; and

e. Removing the heat generated in the fuel due to fission product decay following a unit shutdown.

The reactor coolant is circulated through four loops connected in parallel to the reactor vessel, each containing an SG, a reactor coolant pump (RCP), and appropriate flow and temperature instrumentation for both control and protection. The reactor vessel contains the clad fuel. The SGs provide the heat sink to the isolated secondary coolant. The RCPs circulate the coolant through the reactor vessel and SGs at a sufficient rate to ensure proper heat transfer and prevent fuel damage. This forced circulation of the reactor coolant ensures mixing of the coolant for proper boration and chemistry control.

APPLICABLE Safety analyses contain various assumptions for the design SAFETY ANALYSES bases accident initial conditions including RCS pressure, RCS temperature, reactor power level, core parameters, and safety system setpoints. The important aspect for this LCO is the reactor coolant forced flow rate, which is represented by the number of RCS loops in service.

(continued)

Vogtle Units 1 and 2 B 3.4.4-1 Revision No. 0

RCS LoopsMODES 1 and 2 B 3.4.4 BASES APPLICABLE All of the accident/safety analyses performed at full rated thermal SAFETY ANALYSES power assume that all four RCS loops are in operation as an initial (continued) condition. Some accident/safety analyses have been performed at zero power conditions assuming only two RCS loops are in operation to conservatively bound lower modes of operation. The events which assume only two RCPs in operation include the uncontrolled RCCA (Bank) withdrawal from subcritical and the rod ejection events. While all accident/safety analyses performed at full rate thermal power assume that all the RCS loops are in operation, selected events examine the effects resulting from a loss of RCP operation. These include the complete and partia loss of forced RCS flow, reactor coolant pump rotor seizure, and reactor coolant pump shaft break events. For each of these events, it is demonstrated that all the applicable safety criteria are satisfied. For the remaining accident/safety analyses, operation of all four RCS loops during the transient up to the time of reactor trip is assumed thereby ensuring that all the applicable acceptance criteria are satisfied. Those transients analyzed beyond the time of reactor trip were examined assuming that a loss of offsite power occurs which results in the RCPs coasting down.

By ensuring that the plant operates with all RCS loops in operation in MODES 1 and 2, adequate heat transfer is provided between the fuel cladding and the reactor coolant.

RCS LoopsMODES 1 and 2 satisfy Criterion 2 of 10 CFR 50.36 (c)(2)(ii).

LCO The purpose of this LCO is to require an adequate forced flow rate for core heat removal. Flow is represented by the number of RCPs in operation for removal of heat by the SGs. To meet safety analysis acceptance criteria for DNB, four pumps are required at rated power.

An OPERABLE RCS loop consists of an OPERABLE RCP in operation providing forced flow for heat transport and an OPERABLE SG.

(continued)

Vogtle Units I and 2 B 3.4.4-2 Rev. 2-9/06

RCS LoopsMODES 1 and 2 B 3.4.4 BASES (continued)

APPLICABILITY In MODES 1 and 2, the reactor is critical and thus has the potential to produce maximum THERMAL POWER. Thus, to ensure that the assumptions of the accident analyses remain valid, all RCS loops are required to be OPERABLE and in operation in these MODES to prevent DNB and core damage.

The decay heat production rate is much lower than the full power heat rate. As such, the forced circulation flow and heat sink requirements are reduced for lower, noncritical MODES as indicated by the LCOs for MODES 3, 4, and 5.

Operation in other MODES is covered by:

LCO 3.4.5, RCS LoopsMODE 3; LCO 3.4.6, RCS LoopsMODE 4; LCO 3.4.7, RCS LoopsMODE 5, Loops Filled; LCO 3.4.8, RCS LoopsMODE 5, Loops Not Filled; LCO 3.9.5, Residual Heat Removal (RHR) and Coolant CirculationHigh Water Level (MODE 6); and LCO 3.9.6, Residual Heat Removal (RHR) and Coolant Circulation Low Water Level (MODE 6).

ACTIONS A1 If the requirements of the LCO are not met, the Required Action is to reduce power and bring the plant to MODE 3. This lowers power level and thus reduces the core heat removal needs and minimizes the possibility of violating DNB limits.

The Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging safety systems.

SURVEILLANCE SR 3.4.4.1 REQUIREMENTS This SR requires verification every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> that each RCS loop is in operation. Verification may include flow rate, temperature, or pump status monitoring, which help ensure that forced flow is providing heat removal while maintaining (continued)

Vogtle Units 1 and 2 B 3.4.4-3 Revision No. 0

HL-16 NRC Written Examination KEY

78. 007A2.02 OO1/2/IIPRT-ABNORM PRESSI3.4 MEMJBANK TURKEY PT 09/SRO/NRC/EMT/GCW Unit 1 is at 100% power.

- PRT pressure and PRZR PORV 456 tailpipe temperature is slowly rising.

Which ONE of the following identifies the required operator action and the subsequent operability status of 1 PV-0456?

A. Close and remove power from PRZR PORV 456A Block Valve 1 HV-8000B.

1PV-0456 is INOPERABLE.

B. Close and remove power from PRZR PORV 456A Block Valve 1 HV-8000B.

1 PV-0456 is OPERABLE.

C. Close and maintain power to PRZR PORV 456A Block Valve 1 HV-8000B.

1 PV-0456 is INOPERABLE.

D Close and maintain power to PRZR PORV 456A Block Valve 1 HV-8000B.

1 PV-0456 is OPERABLE.

Feedback 007 Pressurizer Relief Tank/Quench Tank System (PRTS)

Ability to (a) predict the impacts of the following malfunctions or operations on the PRTS; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those malfunctions or operations:

(CFR: 41.5/43.5/45.3! 4513)

A2.02 Abnormal pressure in the PRT K/A MATCH ANALYSIS KA matches do to the leaking PORV and actions required to take to mitigate the leakage. Operability is determined on the leaking PORV.

SRO-1 OCFR55.43 (b2)

ANSWER I DISTRACTOR ANALYSIS A. Incorrect-Plausible because the Block Valve is closed, but the power is maintained in order to allow opening of the Block Valve and allow operation of the PORV. PORV is Operable because it is capable of being manually operated.

Page 157 of 208

HL-16 NRC Written Examination KEY B. Incorrect-Plausible because the Block Valve is closed, but the power is maintained in order to allow opening of the Block Valve and allow operation of the PORV. PORV is Operable because it is capable of being manually operated.

C. Incorrect-The Block valve is closed and power is maintained to allow manual operation of the PORV. As long as the PORV can be capable of being manually cycled, this is the case. PORV is Operable because it is capable of being manually operated.

D. Correct-See above.

REFERENCES Turkey Point March 2009 Q #88 TS 3.4.11 PORVs (and Bases)

VEGP learning objectives:

LO-PP-1 6301-01 List the sources of input into the PRT LO-PP-1 6301-11 Describe the reason for the PRT rupture discs and state the approximate rupture pressure.

LO-LP-39208-02 Given a set of Tech Specs and the bases, determine for a specific set of plant conditions, equipment availability, and operational mode:

a. Whether any Tech Spec LCOs of section 3.4 are exceeded.

b. The required actions for all section 3.4 LCOs.

Page 158 of 208

Pressurizer PORVs 3.4.11 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.11 Pressurizer Power Operated Relief Valves (PORVs)

LCO 3.4.11 Each PORV and associated block valve shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS NOTE--

Separate Condition entry is allowed for each PORV.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more PORVs A.1 Close and maintain power 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> inoperable and capable to associated block valve.

of being manually cycled.

B. One PORV inoperable B.1 Close associated block 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and not capable of being valve.

manually cycled.

AND B.2 Remove power from 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> associated block valve.

AND B.3 Restore PORV to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> OPERABLE status.

(continued)

Vogtle Units 1 and 2 3.4.11-1 Amendment No. 137 (Unit 1)

Amendment No. 116 (Unit 2)

Pressurizer PORVs B 3.4.11 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.11 Pressurizer Power Operated Relief Valves (PORVs)

BASES BACKGROUND The pressurizer is equipped with two types of devices for pressure relief pressurizer safety valves and PORVs. The PORVs are safety-related DC solenoid operated valves that are controlled to open at a specific set pressure when the pressurizer pressure increases and close when the pressurizer pressure decreases. The PORVs may also be manually operated from the control room.

Block valves, which are normally open, are located between the pressurizer and the PORVs. The block valves are used to isolate the PORVs in case of excessive leakage or a stuck open PORV. Block valve closure is accomplished manually using controls in the control room. A stuck open PORV is, in effect, a small break loss of coolant accident (LOCA). As such, block valve closure terminates the RCS depressurization and coolant inventory loss.

The PORVs and their associated block valves may be used by plant operators to depressurize the RCS to recover from certain transients if normal pressurizer spray is not available. Additionally, the series arrangement of the PORVs and their block valves permit performance of surveillances on the block valves during power operation.

The PORVs may also be used for feed and bleed core cooling in the case of multiple equipment failure events that are not within the design basis, such as a total loss of feedwater.

The power supplies to the PORVs, their block valves, and their controls are Class 1 E. Two PORVs and their associated block valves are powered from two separate safety trains (Ref. 1).

The plant has two PORVs, each having a relief capacity of 210,000 lb/hr at 2385 psig. The functional design of the PORVs is based on maintaining pressure below the Pressurizer Pressure High reactor trip setpoint up to and including the design step-load decreases with steam dump.

In addition, the PORVs minimize challenges to the pressurizer (continued)

Vogtle Units 1 and 2 B 3.4.11-1 Revision No.0

Pressurizer PORVs B 3.4.11 BASES LCO The LCO requires the PORVs and their associated block valves to be OPERABLE for manual operation to mitigate the effects associated with an SGTR, or loss of heat sink, and to achieve safety grade cold shutdown. The PORVs are considered OPERABLE in either the manual or automatic mode. The PORVs (PV-455A and PV-456A) are powered from 125 V MCCs 1/2AD1M and 1/2BD1M, respectively. If either or both of these MCCs become inoperable, the affected PORV(s) are to be considered inoperable.

By maintaining two PORVs and their associated block valves OPERABLE, the single failure criterion is satisfied.

An OPERABLE PORV is required to be capable of manually opening and closing, and not experiencing excessive seat leakage. Excessive seat leakage, although not associated with a specific criteria, exists when conditions dictate closure of the block valve to limit leakage.

An OPERABLE block valve may be either open and energized, or closed and energized with the capability to be opened, since the required safety function is accomplished by manual operation. Although typically open to allow PORV operation, the block valves may be OPERABLE when closed to isolate the flow path of an inoperable PORV that is capable of being manually cycled (e.g., as in the case of excessive PORV leakage).

Similarly, isolation of an OPERABLE PORV does not render that PORV or block valve inoperable provided the relief function remains available with manual action. Satisfying the LCO helps minimize challenges to fission product barriers.

APPLICABILITY The PORVs are required to be OPERABLE in MODES 1, 2, and 3 for manual actuation to mitigate a steam generator tube rupture event, an inadvertent safety injection, and to achieve safety grade cold shutdown. In addition, the block valves are required to be OPERABLE to limit the potential for a small break LOCA through the flow path. The most likely cause for a PORV small break LOCA is a result of a pressure increase transient that causes the PORV to open. Imbalances in the energy output of the core and heat removal by the secondary system can cause the RCS pressure to increase to the PORV opening setpoint. The most rapid increases will occur at the higher operating power and pressure conditions of MODES 1 and 2. Pressure increases are less prominent in MODE 3 because the core input energy is reduced, but the RCS pressure is high.

Therefore, the LCO is applicable in MODES 1, 2, and 3. The LCO is not applicable in MODES 4, 5, and 6 with the reactor vessel head in place when both pressure and core energy are decreased and the pressure surges become much less significant. LCO 3.4.12 addresses the PORV (continued)

Vogtle Units 1 and 2 B 3.4.11-3 Rev. 1-2/00

Pressurizer PORVs 3.4.11 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.11 Pressurizer Power Operated Relief Valves (PORVs)

LCO 3.4.11 Each PORV and associated block valve shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS NOTE--

Separate Condition entry is allowed for each PORV.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more PORVs A.1 Close and maintain power 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> inoperable and capable to associated block valve.

of being manually cycled.

B. One PORV inoperable B.1 Close associated block 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and not capable of being valve.

manually cycled.

AND B.2 Remove power from 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> associated block valve.

AND B.3 Restore PORV to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> OPERABLE status.

(continued)

Vogtle Units I and 2 3.4.11-1 Amendment No. 137 (Unit 1)

Amendment No. 116 (Unit 2)

Approved By S. A. Phillips Vogtle Electric Generating Plant Procedure Number Rev Date Approved 17012-1 19.2 ANNUNCIATOR RESPONSE PROCEDURES FOR ALB 12 ON Page Number 0I5I07 PANEL 1C1 ON MCB 31 of 51 WINDOW E01 ORIGIN SETPOINT PRZR RELIEF 1-TE-0449 192°F DISCH 1 -TE-0463 HI TEMP 1.0 PROBABLE CAUSE Pressurizer (PRZR) Power Operated Relief Valves (PORV) 455A1 456A open or leaking.

2.0 AUTOMATIC ACTIONS NONE 3.0 INITIAL OPERATOR ACTIONS NONE Printed January 11, 2011 at 14:59

Approved By S. A. Phiilips VogUe Electric Generating Plant Procedure Number Rev Date Approved 17012-1 19.2 ANNUNCIATOR RESPONSE PROCEDURES FOR ALB 12 ON Page Number 10/5/07 PANEL 1C1 ON MCB 32 of 51 WINDOW E01 (Continued) 4.0 SUBSEQUENT OPERATOR ACTIONS

1. Check PRZR PORV 455A/456A position indicating lights on QMCB to determine if a valve has opened.

2. Check PRZR PORV 455A/456A Discharge Line temperatu res using 1 -TI-0449 and 0463 on the QMCB to determine the valve causing the alarm.

3. Check Pressurizer pressure and level.

4. IF a PRZR PORV 455A/456A has lifted due to an asso ciated instrument malfunction, Go To 18001-C, Primary System Instrumentatio n

Malfunction.

5. if a PRZR PORV 455A/456A fails to close following an actuation, Go To 18000-C Pressurizer Spray, Safety, Or Relief Valve Malfunction.

6. if a PRZR PORV 455A/456A is leaking following an actuation:

a. Place the Control Switch for the affected valve to the closed position,

b. Close the associated Block Valve,

c. Refer to Technical Specification LCO 3.4.11.

7. jf equipment failure is indicated, initiate maintenance as required.

5.0 COMPENSATORY OPERATOR ACTIONS NONE END OF SUB-PROCEDURE

REFERENCES:

1X4DB112, PLS Printed January 11, 2011 at 14:59

Approved By S. A. Phillips Vogtle Electric Generating Plant Procedure Number Rev Date Approved 1701 2-1 19.2 ANNUNCIATOR RESPONSE PROCEDURES FOR 10/5/07 ALB 12 ON Page Number PANEL 1C1 ON MCB 33 of 51 WINDOW E02 ORIGI N

SET POIN T

1-PT-0469 PRZR REL TANK 8 psig HI PRESS 1.0 PROBABLE CAUSE

1. One or more of the following valves has lifted or is leaking to the Pressurizer Relief Tank:

a. Pressurizer Safety Valves,

b. Pressurizer (PRZR) Power Operated Relief Valves (PORV)s,

c. Chemical and Volume Control System (CVCS) Letd own Relief Valve 1-PSV-8117,

d. CVCS Seal Return Relief Valve 1 -PSV-81 21,

e. Residual Heat Removal (RHR) Relief Valves 1 -PSV

-8708A and B during shutdown conditions.

2. Nitrogen Regulator malfunction.

3. Safety grade letdown in use and aligned to the Pres surizer Relief Tank.

2.0 AUTOMATIC ACTIONS NONE 3.0 INITIAL OPERATOR ACTIONS NONE Printed January 11, 2011 at 14:59

Approved By Procedure Number Rev S. A. Phillips Vogtle Electric Generating Plant 17012-1 Date Approved 19.2 ANNUNCIATOR RESPONSE PROCEDURES FOR ALB 12 ON Page Number 10/5/07 PANEL1C1ONMCB 34of 51 WINDOW E02 (Continued) 4.0 SUBSEQUENT OPERATOR ACTIONS CAUTION If PRT pressure increases the PRT rupture disk will fail at 86 to 100 psig, opening the PRT to containment.

1. Determine actual Pressurizer Relief Tank pressure using 1 -P1-0469 on the QMCB.

2. Monitor Pressurizer Relief Tank temperature, level, and pressure.

3. Check tailpipe temperatures for the Pressurizer Safety Valves, Power Operated Relief Valves, and CVCS Letdown Relief Valve.

4. IF a PRZR PORV OR Safety Valve has actuated, check valve closure when pressure is lowered in the Reactor Coolant System.

5. IF a nitrogen supply malfunction has occurred, isolate the supply by shutting valves 1 -HV-8033 and 1 -HV-8047.

6. IF a Pressurizer Safety Valve is open Q.E fails to close following an actuation, Go To 18004-C, Reactor Coolant System Leakage.

7. jf a PRZR PORV 455A1456A is open QE fails to close following an actuation:

a. Place the Control Switch for the affected valve to the closed position,

b. IF the affected valve will NOT close, close the associated Block Valve,

c. Refer to Technical Specification LCO 3.4.11.

8. if the pressure rise is due to the CVCS Letdown Relief Valve being open isolate letdown, and initiate 18007-C, Chemical And Volume Control System Malfunction.

Printed January 11,2011 at 14:59

Approved By Procedure Number Rev S. A. Phillips Vogtle Electric Generating Plant 17012-1 19.2 Date Approved ANNUNCIATOR RESPONSE PROCEDURES FOR ALB 12 ON Page Number i0I5/07 PANEL 1C1 ON MCB 35 of 51 I

WINDOW E02 (Continued)

9. IF the pressure rise is due to a failed RHR Relief Valve, isolate the affected Train of RHR and initiate 18019-C, Loss Of Residual Heat Removal.

10. IF the pressure rise is due to a failed Seal Return Relief Valve, attempt to isolate the leak.

11. if pressure rise is due to a hard bubble, i.e., no temperature or level change, notify Chemistry and place Pressurizer Steam Space Sample in service and control RCS pressure using 12004-C.

12. Restore pressure in the Pressurizer Relief Tank to normal per 13004-1, Pressurizer Relief Tank Operation.

13. IF equipment failure is indicated, initiate maintenance as required.

5.0 COMPENSATORY OPERATOR ACTIONS NONE END OF SUB-PROCEDURE

REFERENCES:

1X4DB112, PLS Printed January 11, 2011 at 14:59

TURKEY POINT NRC EXAM 03/1 2/09 Q #88 Unit 4 is at 100% power when the following annunciat ors alarm:

A 7/1 PRT HI/LO LEVEL HI PRESS/TEMP A 7/2 PZR PORV HI TEMP

• PRT pressure is above the alarm setpoint and slowly increasing.

• Pressurizer PORV temperature is above the alarm setpo int and slowly increasing.

• RCS leakage through Pressurizer PORV, PCV-4-45 6, is 5.0 gpm.

Which ONE of the following identifies the required operator action in accordance with 4-ONOP-041.5,Pressurizer Pressure Control Malfun ction and the subsequent operability status of PCV-4-456?

A. Close and remove power from PRZ PORV Block Valv e, MOV-4-535.

PCV-4-456 is INOPERABLE.

B. Close and remove power from PRZ PORV Block Valv e, MOV-4-535.

PCV-4-456 is OPERABLE.

C. Close and maintain power to PRZ PORV Block Valve, MOV-4-535.

PCV-4-456 is INOPERABLE.

D. Close and maintain power to PRZ PORV Block Valv e, MOV-4-535.

PCV-4-456 is OPERABLE.

Page 175

HL-16 NRC Written Examination KEY

79. 007EA2.02 002/1/IIRX TRIP-RECOVERY/4.6 C/AIBANK FARLEY 2010/SRO/NRC/GCW Unit 1 is in Mode 3, and the following conditions exist:

At 10:00

- The shutdown banks are withdrawn.

- A Cooldown per Technical Specification 3.4.10, Pressurizer Safety.

Valves, is in progress due to an inoperable PRZR code safety valve.

- Tcojd is 530°F.

At 10:10

- A complete Loss of Off-Site Power occurs with the following conditions.

- All emergency equipment operates normally.

- PCC reports that off-site power will be restored in 18 hrs.

Which ONE of the following describes the required action, if any, to open the Rx Trip Breakers and the procedure transition from ES-0.1, Reactor Trip Response after the plant is stabilized?

Manual action _.(1 )_ required to open the Rx Trip Breakers.

After the plant is stabilized the crew will transition to_(2)_from 19001-C, ES -0.1 Reactor Trip Response

__1)_ _(2)_

A IS 19002-C, ES-0.2, Natural Circulation Cooldown B. IS 19003-C, ES-0.3, Natural Circulation Cooldown With Void In Vessel (With RVLIS)

C. IS NOT 19002-C ES-0.2, Natural Circulation Cooldown D. IS NOT 19003-C, ES-0.3, Natural Circulation Cooldown With Void In Vessel (With RVLIS)

Feedback 007 Reactor Trip Ability to determine or interpret the following as they apply to a reactor trip:

(CFR 41.7/45.5/45.6)

EA2.02 Proper actions to be taken if the automatic safety functions have not taken place Page 159 of 208

HL-16 NRC Written Examination KEY K/A MATCH ANALYSIS Question is matched because the Loss of Offsite Power causes a loss of the RCPs, but the Reactor will not Auto trip due to power being below P-7 (10%). The procedure transition change requires SRO discretion.

SRO 10CFR55.43 (b5)

ANSWER I DISTRACTOR ANALYSIS A. Correct- (1) RX trip breakers will not open automatically therefore manual action is required.

(2) RCPs are not available and Cooldown to TcoId <220°F in 12h 15m is required per TS. 3.4.10. therefore Transition to ESP-O.2, Natural Circulation Cooldown.

B. Incorrect-i) The RTB will need to be manually operated but, 2) the transition to ESP-0.3 is incorrect since it would not be entered except from ESP-0.2.

Additionally, considering the transition to ESP-0.3 from ESP-O.2 (long term transition), it would not be warranted with the given information. CST level is not provided since the stem is directed at the transition FROM ESP-0.2 and is not needed to answer the question.

Transition to ESP-0.3 from step 13 is not likely to be required since IF a void in the vessel head DID develop, there is no condition demanding a rapid depressurization therefore, remaining in ESP-0.2 would be correct at this transition as well.

C. Incorrect-RX trip breakers will not open automatically, therefore manual action is required. However, the transition is correct See A.2.

Plausible: a LOSP would result in a loss of all RCPs and therefore would result in a RX trip if > P-7 D. lncorrect-(1) RX trip breakers will not open automatically therefore manual action is required. (2) the stated transition is also incorrect See B.

Plausible: See C.1 and B.2.

REFERENCES 19001-C Reactor Trip Response Functional Diagram 1 X6AAO2-00229 Farley NRC 2010-SRO Q # 77 VEGP learning objectives:

Page 160 of 208

HL-16 NRC Written Examination KEY LO-LP-3701 1-04 State and describe the major action categories of 19001, Reactor Trip Recovery.

Page 161 of 208

Procedure Number Rev t 31.1 Approved By Vogtle Electric Generating Plan 19001-C J.B. Stanley Page Number ONSE ES 0.1 REACTOR TRIP RESP 25 22/2008 OCEDURE EMERGENCY OPERATING PR CONTINUOUS USE PRB REVIEW REQUIRED PURPOSE owing a nec ess ary ins tru ctio ns to sta bilize and control the plant foll This procedure provides the 2.)

ction. (Applicable in Modes 1 and reactor trip without a safety inje ENTRY CONDITIONS SAFETY INJECTION

• 19000-C, E-0 REACTOR TRIP OR MAJOR ACTIONS bilizes at no-load conditions.

• Verify the primary system sta stabilizes at no-load conditions.

• Verify the secondary system s have power available.

• Verify necessary component ation of the RCS.

• Maintain/establish forced circul

• Maintain plant in a stable condition 4

Printed January 13, 2011 at 09:3

Procedure Number Rev t 31.1

[ App roved By Vogtle Electric Generating Plan 001-C J.B. Stanley Page Number SE

/

Approved ES 0.1 REACTOR TRIP RESPON 17 of 25 L22/20O8 RESPONSE NOT OBTAINED ACTION/EXPECTED RESPONSE s:

• 19 Maintain stable plant condition

. PRZR pressure AT 2235 PSIG.

• PRZR level AT 25%. -

• SG NR levels BETWEEN 10%

AND 65%.

• RCS temperature:

With RCP(s) running RCS -

AVERAGE TEMPERATURE AT 557°F.

-OR-Without RCP(s) running -

RCS WR COLD LEG TEMPERATURES AT 557°F.

wn

20. Check if natural circulation cooldo is required:

a. GotoStep2o.c.

_a. Any RCP - RUNNING.

_b. Go to 12006-C, RCS COOLDOWN TO COLD SHUTDOWN.

c. Go to 19002-C, ES-0.2

_c. At least one CST level -

NATURAL CIRCULATION GREATER THAN 66%. COOL DOWN.

Step 20 continued on next page 3

Pr,nted January 13, 2011 at 09:3

Procedure Number Rev Plant 19001-C 31.1 Approved By VogUe Electric Generating Page Number j

1 Stanley SPONSE Approved ES 0.1 REACTOR TRIP RE 18 of 25 ED

/2/2008 ONSE RESPONSE NOT OBTAIN ACTION/EXPECTED RESP

d. Perform one of the following Maintain hot standby conditions by returning to Step 19.

-OR-Go to 19002-C, ES-0.2 NATURAL CIRCULATION COOL DOWN based on RCP(s) restart status.

END OF PROCEDURE TEXT at 09:33 Printed January 13, 2011

0

77. 007EA2.02 002 exist:

Unit 1 is in Mode 3, and the following conditions At 10:00:

• The shutdown banks are withdrawn.

Pressurizer Safety Valves, is in

• A Cooldown per Technical Specification 3.4.10, valve.

progress due to an inoperable PRZR code safety

• TcoId is 530°F.

rs with the following conditions:

At 10:10, A complete Loss of Off-Site Power occu

• All emergency equipment operates normally.

in 18 hrs.

• ACC reports that off-site power will be restored action, if any, to open the Rx Trip Which one of the following describes the required

-0.1, Reactor Trip Response, after the Breakers and the procedure transition from ESP plant is stabilized?

Manual action (1) required to open the Rx Trip Breakers.

to (2) from ESP-0. 1, After the plant is stabilized the crew will transition Reactor Trip Response.

(1) (2)

A IS ESP-0.2, Natural Circulation Cooldown to Prevent Reactor Vessel Head Steam Voiding B. IS ESP-0.3, Natural Circulation Cooldown with ing Allowance for Reactor Vessel Head Steam Void (with RVLIS)

C. IS NOT ESP-0.2, Natural Circulation Cooldown to Prevent Reactor Vessel Head Steam Voiding D. IS NOT ESP-0.3, Natural Circulation Cooldown with ing Allowance for Reactor Vessel Head Steam Void (with RVLIS) 1/3/2011 Page: 66 of 88

HL-16 NRC Written Examination KEY

80. Ui 1EA2.08 001/1/I/LB LOCA-RECOVERY/3.9 C/A/LORQ BANKISRO/NRC/GCW A large break loss of coolant accident (LOCA) from one of the Cold Legs has occurred 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> ago and the crew is performing 19010-C, E-1 Loss of Reactor or Secondary Coolant.

Recovery actions are in affect and the control room staff is evaluating conditions for entry into 19014-C, ES-1.4 Transfer to Hot Leg Recirculation.

Which ONE of the following correctly describes conditions needed to go to Hot Leg Recirculation and the reason?

A. Enter 19014-C in t5 hours to terminate boiling in the core and to prevent boron precipitation in the core.

B Enter 19014-C in 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> to terminate boiling in the core and to prevent boron precipitation in the core.

C. Enter 19014-C in 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> to refill the reactor vessel and downcomer.

D. Enter 19014-C in 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> to refill the reactor vessel and downcomer.

Page 162 of 208

HL-16 NRC Written Examination KEY Feedback 011 Large Break LOCA Ability to determine or interpret the following as they apply to a Large Break LOCA:

(CFR 43.5 /45.13)

EA2.08 Conditions necessary for recovery when accident reaches stable phase K/A MATCH ANALYSIS Question is determining the time required to enter Hot Leg recirc and the reason for the recovery procedure at this stage.

SRO 10CFR55.43 (b5)

ANSWER I DISTRACTOR ANALYSIS A. Incorrect-Plausible for 1.5 hrs to enter because that is the time to PREPARE for Hot Leg Recirc. The reason is correct.

B. Correct C. Incorrect-Plausible for 1.5 hrs to enter because that is the time to PREPARE for Hot Leg Recirc. The reason is not correct, this is the purpose of the ECCS Accumulators.

D. Incorrect-Plausible because 2.5 hrs after the event is the time to enter the procedure. The reason is not correct, this is the purpose of the ECCS Accumulators.

REFERENCES 1901 0-C, Loss of Reactor or Secondary Coolant ES-i .4 Transfer to Hot Leg Recirculation Background Document VEGP learning objectives:

LO-LP-371 14-06 State the intent of EOP 19014-C, Hot Leg Recirc LO-LP-371 14-09 State the reasons for performing Hot Leg Recirc LO-LP-371 14-10 State when Hot Leg Recirc is performed Page 163 of 208

Approved By J. B. Stanley Vogtle Electric Generating Plant Procedure Number Rev Date Approved 19010-C 33.1 E-1 LOSS OF REACTOR OR SECONDARY Page Number

/18/1O COOLANT 21 of 26 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

30. Time after event initiation -

_30. Return to Step 28.

GREATER THAN 6.5 HOURS.

a. Prepare for hot leg recirculation:

1) Place the lockout selector switches for the following valves in the ON position and verify power to valves:

. HV-8840 RHR TO HL ISO VLV

. HV-8809A RHR PMP-A TO COLD LEG 1&2 ISO VLV HV-8809B RHR PMP-B TO COLD LEG 3&4 ISO VL

. HV-8802ASI PMP-A TO HOT LEG 1&4 ISO VLV

. HV-8802B SI PMP-B TO HOT LEG 2&3 ISO VLV

. HV-8835 CL INJ FROM SIS Step 30 continued on next page Printed January 18, 2011 at 15:37

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 1901 0-C 33.1 Date Approved E-1 LOSS OF REACTOR OR SECONDARY Page Number

/1 8/10 COOLANT 22 of 26 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

2) check porto the foIIdWIfl _2) Close circuit breakers valves VALVE POSITION as necessary.

INDICATORS LIT:

HV-8716A RHR TRAIN A TO HOT LEG CROSSOVER ISO

. HV-8716B RHR TRAIN B TO HOT LEG CROSSOVER ISO

. HV-8821A SI PMP-A TO COLD LEG ISO VLV HV-8821B SI PMP-B TO COLD LEG ISO VLV 3I. _31. Return to Step 28.

32. Consult the TSC to evaluate long term plant status.

END OF PROCEDURE TEXT Printed January 18, 2011 at 15:37

2. DESCRIPTION Hot leg recirculation is implemented to terminate boiling in the core and to prevent boron precipitation in the core. Following a large cold leg break in the RCS, conservative analyses have shown that the boric acid concentration limit established by the NRC (the boric acid solubility limit of 27.53% minus 4% for conservatism) would be exceeded if cold leg recirculation is maintained for an extended period (see Reference 1). The analysis considers the increase in boric acid concentration in the reactor vessel during the long-term cooling phase of a LOCA assuming a conservatively small effective vessel volume including only the free volumes of the reactor core and the upper plenum below the bottom of the hot leg nozzles. This assumption conservatively neglects the mixing of boric acid solutio n

with directly connected volumes, such as the reactor vessel lower plenum. The calculation of boric acid concentration in the reactor vessel considers a cold leg break of the reactor coolant system in which steam is generated in the core from decay heat while the boron associated with the boric acid solution is completely separated from the steam and remains in the effective vessel volume. The cold leg safety injection flow is not effective in counteracting this boiloff from the core since for larger breaks the downcomer level is low and the injection flow is primarily refilling the downcomer as opposed to the core, and no flushing of the core occurs. If the plant is transferred from cold leg to hot leg recirculation prior to the time the boric acid concentration limit is reached in the reactor vessel, the hot leg safety injection flow will dilute the vessel boron concentration by passing relatively dilute boron solution from the hot leg through the vessel to the cold leg break location and will terminate boiloff from the core. This will prevent boron precipitation in the core along with any resultant plate out on the fuel cladding which could reduce heat transfer from the fuel to the reactor coolant.

For a large hot leg break in the RCS, the safety injection flow delivered to the cold legs during cold leg recirculation will flow through the core and spill to the containment sump via the hot leg break. With the core being flushed there would be no boron buildu p

problem. After transfer to hot leg ES-1.4 Background 2 HP-Rev. 2, 4/30/2005 HES14BG. doc

HL-16 NRC Written Examination KEY

81. 022G2.2.42 OO1/2/1/CNMT COOLERS-TS/4.6 C/iVBANKJSROINRC/GCW Given the following:

- Plant is at 100% power.

- Containment Cooler # 2 High Speed fan trips.

- Electrical maintenance has determined the trip was due to a breaker problem.

- Containment Cooler # 2 Low Speed fans ability to auto function is unaffected.

- Containment Spray system for both trains is OPERABLE.

Which ONE of the following is CORRECT regarding the Containment Cooling system in accordance with Tech Specs 3.6.6 and the bases for the Containment Spray and Cooling System?

A Affected train is OPERABLE, Tech Spec bases does not require the High Speed fans to operate in the more dense atmosphere during DBA events.

B. Affected train is INOPERABLE, Tech Spec bases requires the High Speed fans to mitigate plant non-DBA events, such as feed or steam line breaks.

C. Affected train is OPERABLE, Tech Spec bases does not require the High Speed fans to operate as long as the associated Containment Spray train is operable.

D. Affected train is INOPERABLE, Tech Spec bases requires the High Speed fans to operate and maintain containment temperature limits following an LOSP event.

Feedback 022 Containment Cooling System (CCS)

Equipment Control 2.2.42 Ability to recognize system parameters that are entry-level conditions for Technical Specifications.

(CFR: 41 .7/41.10/43.2 /43.3/45.3)

KIA MATCH ANALYSIS Question gives a plausible scenario where the high speed an of a containment cooler trips on thermal overload and cant be reset. The candidate has to determine if the containment coolers are still operable. (high speed not Tech Spec, low speed is) in effect determining if an LCO entry is required or not.

Question meets 1 OCFR55.43(b) criteria item # 2 - Facility operating limits in Tech Page 164 of 208

HL-16 NRC Written Examination KEY Specs and their bases since the SRO has to determine operability and the bases.

SRO 10CFR55.43 (b2)

ANSWER I DISTRACTOR ANALYSIS A. Correct. High speed not required during DBA events which have a more dense atmosphere in containment. Low speed designed for this and is still OPERABLE.

B. Incorrect. High speed not required during DBA events which have a more dense atmosphere in containment. Feed and steam line are also DBA events. Plausbie candidate considers High Speed required since they do sequence on during LOSP.

C. Incorrect. High speed not required during DBA events which have a more dense atmosphere in containment. Whether or not Containment Spray is operable has no bearing on the High Speed or Low Speed fan requirements.

D. Incorrect. Although High Speed assists maintaining Containment Temperature limits in conjunction with other Containment Cooling Systems, there is no Tech Spec requirement for them to do so, LOSP event makes the choice evwen less correct as there is no requirement for High Speed to operate following an LOSP. Plausible candidate may think they are required since they do sequence during an LOS P.

REFERENCES Tech Spec 3.6.6 and Bases for Containment Spray and Cooling System.

SR-3.6.6.2 and 3.6.6.7 regarding the Containment Coolers.

LOIT Bank 022A2.03-O1 HL-14 Audit 0 #5 VEGP learning obiectives:

LO-PP-291 01-13, State why two speeds are provided for the Containment Coolers and when each speed is used.

Page 165 of 208

Containment Spray and Cooling Systems 3.6.6 3.6 CONTAINMENT SYSTEMS 3.6.6 Containment Spray and Cooling Systems LCO 3.6.6 Two containment spray trains and two containment cooling trains shall be OPERABLE.

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

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One containment spray A.1 Restore containment 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />s*

train inoperable, spray train to OPERABLE status.

6 days from discovery of failure to meet the LCO*

B. One containment 8.1 Restore containment 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> cooling train inoperable, cooling train to OPERABLE status. AND 6 days from discovery of failure to meet the LCO C. Required Action and C.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time not met. AND C.2 Be in MODE 5. 84 hours9.722222e-4 days <br />0.0233 hours <br />1.388889e-4 weeks <br />3.1962e-5 months <br /> For the VEGP Unit 2 June 23, 2008 entry into Technical Specification 3.6.6, the Containment Spray Pump B may be inoperable for a period not to exceed 7 days.

Vogtle Units 1 and 2 3.6.6-1 Amendment No. 96 (Unit 1)

Amendment No. 131 (Unit 2)

Containment Spray and Cooling Systems 3.6.6 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.6.1 Verify each containment spray manual, power 31 days operated, and automatic valve in the flow path that is not locked, sealed, or otherwise secured in position is in the correct position.

SR 3.6.6.2 Operate each containment cooling train fan unit 31 days for 15 minutes.

SR 3.6.6.3 Verify each pair of containment fan coolers 31 days cooling water flow rate is 1359 gpm.

SR 3.6.6.4 Verify each containment spray pumps developed In accordance with head at the flow test point is greater than or equal the Inservice Testing to the required dev&oped head. Program SR 3.6.6.5 Verify each automatic containment spray valve in 18 months the flow path that is not locked, sealed, or otherwise secured in position actuates to the correct position on an actual or simulated actuation signal.

SR 3.6.6.6 Verify each containment spray pump starts 18 months automatically on an actual or simulated actuation signal.

(continued)

Vogtle Units 1 and 2 3.6.6-2 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

Containment Spray and Cooling Systems 3.6.6 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.6.6.7 Verify each containment cooling train starts 18 months automatically on an actual or simulated actuation signal.

SR 3.6.6.8 Verify each spray nozzle is unobstructed. 10 years Vogtle Units 1 and 2 3.6.6-3 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

Containment Spray and Cooling Systems B 3.6.6 BASES SURVEILLANCE SR 3.6.6.4 (continued)

REQUIREMENTS pump performance is greater than or equal to the performance assumed in the safety analysis.

SR 3.6.6.5 and SR 3.6.6.6 These SRs require verification that each automatic containment spray valve actuates to its correct position and that each containment spray pump starts upon receipt of an actual or simulated actuation of a containment High-3 pressure signal. This surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls. The 18 month Frequency is based on the need to perform these Surveillances under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillances were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillances when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

The surveillance of containment sump isolation valves is also required by SR 3.5.2.5. A single surveillance may be used to satisfy both requirements.

SR 3.6.6.7 This SR requires verification that each containment cooling train actuates upon receipt of an actual or simulated safety injection signal and operates at low speed. The 18 month Frequency is based on engineering judgment and has been shown to be acceptable through operating experience. See SR 3.6.6.5 and SR 3.6.6.6, above, for further discussion of the basis for the 18 month Frequency.

SR 3.6.6.8 With the containment spray inlet valves closed and the spray header drained of any solution, low pressure air or smoke can be blown through test connections. This SR ensures that (continued)

Vogtle Units 1 and 2 B 3.6.6-9 Revision No. I

Containment Spray and Cooling Systems B 3.6.6 BASES BACKGROUND Containment Spray System (continued)

The Containment Spray System provides a spray of cold borated water into the upper regions of containment to reduce the containment pressure and temperature and to reduce fission products from the containment atmosphere during a DBA. The RWST solution temperature is an important factor in determining the heat removal capability of the Containment Spray System during the injection phase. In the recirculation mode of operation, heat is removed from the containment sump water by the residual heat removal coolers.

Each train of the Containment Spray System provides adequate spray coverage to meet the system design requirements for containment heat removal.

The Containment Spray System is actuated either automatically by a containment High-3 pressure signal or manually. An automatic actuation opens the containment spray pump discharge valves, starts the two containment spray pumps, and begins the injection phase. A manual actuation of the Containment Spray System requires the operator to actuate two separate switches on the main control board to begin the same sequence. The injection phase continues until an RWST empty tank level alarm is received (8% level). When the RWST level reaches the empty tank level, the operator manually aligns the system to the recirculation mode. The Containment Spray System in the recirculation mode maintains an equilibrium temperature between the containment atmosphere and the recirculated sump water. Operation of the Containment Spray System in the recirculation mode is controlled by the operator in accordance with the emergency operating procedures.

Containment Cooling System Two trains of containment cooling, each of sufficient capacity to supply 100% of the design cooling requirement, are provided. Each train of four fan units is supplied with cooling water from a separate train of nuclear service cooling water (NSCW). Air is drawn into the coolers through the fan and discharged to the steam generator compartments, pressurizer compartment, and instrument tunnel, and outside the secondary shield in the lower areas of containment.

(continued)

Vogtle Units I and 2 B 3.6.6-2 Rev. 2 7/08

Containment Spray and Cooling Systems B 3.6.6 BASES BACKGROUND Containment Coolincj System (continued)

During normal operation, four fan units are operating. The fans are normally operated at high speed with NSCW supplied to the cooling coils. The Containment Cooling System, operating in conjunction with the Containment Ventilation and Air Conditioning systems, is designed to limit the ambient containment air temperature during normal unit operation to less than the limit specified in LCO 3.6.5, Containment Air Temperature. This temperature limitation ensures that the containment temperature does not exceed the initial temperature conditions assumed for the DBAs.

In post accident operation following an actuation signal, the Containment Cooling System fans are designed to start automatically in slow speed if not already running. If running in high (normal) speed, the fans automaticaDy shift to slow speed. The fans are operated at the lower speed during accident conditions to prevent motor overload from the higher mass atmosphere. The temperature of the NSCW is an important factor in the heat removal capability of the fan units.

APPLICABLE The Containment Spray System and Containment Cooling System SAFETY ANALYSES limit the temperature and pressure that could be experienced following a DBA. The limiting DBAs considered are the loss of coolant accident (LOCA) and the steam line break (SLB). The LOCA and SLB are analyzed using computer codes designed to predict the resultant containment pressure and temperature transients. No DBAs are assumed to occur simultaneously or consecutively. The postulated DBAs are analyzed with regard to containment ESF systems, assuming the loss of one ESF bus, which is the worst case single active failure and results in one train of the Containment Spray System and Containment Cooling System being rendered inoperable.

The analysis and evaluation show that under the worst case scenario, the highest peak containment pressure is 36.5 psig (experienced during a LOCA). The analysis shows that the peak containment temperature is 303.1°F (experienced during an SLB). Both results meet the intent of the design basis. (See the Bases for LCO 3.6.4A, Containment Pressure, and (continued)

Vogtle Units I and 2 B 3.6.6-3 Revision No. 0

5. 022A2.03 001 Given the following:

- Plant at 100%.

- Containment Cooler # 2 High Speed fan trips.

- Electrical maintenance has determined the trip was due to a breaker problem.

- Containment Cooler # 2 Low Speed fans ability to auto function is unaffected.

- Containment Spray system for both trains is OPERABLE.

Which ONE of the following is CORRECT regarding the Containment Cooling system in accordance with Tech Specs 3.6.6 and the bases for the Containment Spray and Cooling System?

A Affected train is OPERABLE, Tech Spec bases does not require the High Speed fans to operate in the more dense atmosphere during DBA events.

B. Affected train is INOPERABLE, Tech Spec bases requires the High Speed fans to mitigate plant non-DBA events such as feed or steam line breaks.

C. Affected train is OPERABLE, Tech Spec bases does not require the High Speed fans to operate as long as the associated Containment Spray train is operable.

D. Affected train is INOPERABLE, Tech Spec bases requires the High Speed fans to operate and maintain containment temperature limits following an LOSP event.

Page: 9 of 12 1/15/2011

HL-16 NRC Written Examination KEY

82. 025AA2.05 001/1/1/LOSS OF RHRJ3.6 CIAJMOD BANK SURRY 2009/SRO/NRC/GCW Unit 2 Initial conditions:

- Time 0800 hrs.

- Plant is in Fueled Mid-Loop Operation for nozzle dam installation.

- Containment Equipment and Personnel Hatches are secured.

- Steam Generators are not available.

- RCS Temperature = 195 °F and stable.

- RCS level at 187 feet 6 inches and lowering.

- 18019-C, Loss of Residual Heat Removal, has been initiated.

Current plant conditions:

- Time 0825 hrs.

- The running RHR pump was secured due to vortexing.

- RCS temperature 225 °F and increasing.

- RVLIS Full Range = 70%

- Source Range Indications = Unstable.

Based on the above conditions: (1) Classify the event using the Emergency Plan and (2) once RCS level has been restored and RHR was adequately vented, state the Minimum Indicated RHR flow that must be established?

(Reference Provided)

Av (1) Alert Emergency (2) 3000 gpm B. (1) Site Area Emergency (2) 3000 gpm C. (1) Alert Emergency (2) 3200 gpm D. (1) Site Area Emergency (2) 3200 gpm Feedback 025 Loss of Residual Heat Removal System (RHRS)

Ability to determine and interpret the following as they apply to the Loss of Residual Heat Removal System:

Page 166 of 208

HL-16 NRC Written Examination KEY (CFR: 435I45.13)

AA2.05 Limitations on LPI flow and temperature rates of change K/A MATCH ANALYSIS This question test the knowledge of candidates on the limitation of RHR flow per 18019-C, Loss of RHR and their ability to interpret the emergency classification which puts this question at SRO level.

SRO-Justification-Not tied to 1 OCFR55.43(b), but is classified as SRO ONLY because the question is linked a SRO ONLY objective.

LO-LP-40101-13 Given an emergency scenario, and the procedure, classify the emergency (SRO only).

ANSWER I DISTRACTOR ANALYSIS A. Correct Classification is correct due to the heatup rate given will calculate to be greater 200 °F for at least 20 minutes, 3000 gpm is also correct per 18019-C after starting up RHR pump after being adequately vented prior to start.

B. Incorrect Classification is wrong because Site Area Threshold has not been crossed. (Mode 6 only) Since Containment Integrity has been established and RVLIS level is available and greater than 63% full range, Site Area emergency should not be declared. Plausible because could interpret Source Range being unstable alone would be indication of core uncovery. The second part of the answer is correct.

C. Incorrect Correct Classification but per 18019-C 3200 gpm indicated is only required if RHR had not been adequately vented. Tech Spec surveillance requirement of 3000 gpm is only applicable in Mode 6. Plausible, because indicated flow of 3200 gpm per the SOP 13011-1/2 ensures RHR flow requirement of 3000 gpm will be met at all temperatures.

D. Incorrect Because both the classification and the minimum flow rate are incorrect.

Classification is wrong because Site Area Threshold (Mode 6 only) has not been crossed. Since Containment Integrity has been established and RVLIS level is available and greater than 63% full range, Site Area emergency should not be declared. Per 18019-C 3200 gpm indicated is only required if RHR had not been adequately vented. Tech Spec surveillance requirement of 3000 gpm is only applicable in Mode 6. Plausible, because indicated flow of 3200 gpm per the SOP 13011-1/2 ensures RHR flow requirement of 3000 gpm will be met at all temperatures.

REFERENCES AOP 18019-C, Loss of Residual Heat Removal, see B19 and the note prior to step B17.

Page 167 of 208

HL-16 NRC Written Examination KEY Modified Surry 2009 Q # (12) 87 NMP-EP-1 10, Emergency Classification Determination and Initial Action (Needs to be provided)

NMP-EP-1 1 0-GLO3 NMP-EP-1 1 0-GLO3, Fission Product Barrier Evaluation Figure 1.

NMP-EP-1 1 0-GLO3, Emergency Classification Determination And Initial Action Figure 2.

NMP-EP-1 10-GLO3, Emergency Classification Determination And Initial Action Figure 3.

VEGP learning obiectives:

LO-LP-60315-01 Describe factors that can lead to a loss of RHR.

LO-LP-60315-04 Given the entire AOP, describe:

a. Purpose of selected steps

b. How and why the step is being performed

c. Expected response of the plant/parameter(s) for the step LO-LP-60315-06 Given the Cautions or Notes from AOP 18019-C, explain the reason for specific ones.

LO-LP-401 01-13 Given an emergency scenario, and the procedure, classify the emergency (SRO only).

Page 168 of 208

NMP-EP-1 10-GLO3 VEGP EALs ICs, Threshold Values and Basis Version 2.0 C82 Initiating Condition Loss of RPV Inventory Affecting Core Decay Heat Removal Capability with Irradiated Fuel in the RPV.

Operating Mode Applicability: Refueling Only (Mode 6)

Threshold Values: (1 OR 2)

1. WITH CONTAINMENT CLOSURE NOT established:

a. RPV level less than elevation 185-3.5 [6 below Bottom ID of loop] (72% on Full Range RVLIS)

OR

b. RPV level CANNOT be monitored WITH indication of core uncovery as evidenced by ANY of the following:

RE-002, 003, 004 greater than 3.1 mR/hr Erratic Source Range Monitor Indication WITH CONTAINMENT CLOSURE established

a. RPV level less than elevation 181-lO [TOAF] (63% on Full Range RVLIS)

QE

b. RPV level CANNOT be monitored WITH Indication of core uncovery as evidenced by ANY of the following:

RE-005 2E006 greater than 162 R/hr RE-0011 greater than 15 mR/hr Erratic Source Range Monitor Indication 91

NMP-EP-1 10-GLO3 VEGP EALs - ICs, Threshold Values and Basis Version 2.0 CA4 Initiating Condition Inability to Maintain Plant in Cold Shutdown with Irradiated Fuel in the RPV.

Operating Mode Applicability: Cold Shutdown (Mode 5)

Refueling (Mode 6)

Threshold Values: (1 OR 2 OR 3)

NOTE The Emergency Director should not wait until 20 minutes has elapsed, but should declare the event as soon as it is determined that the duration has or will likely exceed 20 minutes.

1. An UNPLANNED event results in RCS temperature exceeding 200°F with:

a. CONTAINMENT CLOSURE NOT established AND

b. RCS integrity 4QI established NOTE If an RCS heat removal system is in operation within this time frame and RCS temperature is being reduced then this Threshold Value is not applicable.

2. An UNPLANNED event results in RCS temperature exceeding 200°F for greater than 20 minutes (Note) with:

a. CONTAINMENT CLOSURE established AND

b. RCS integrity .42I established OR

c. RCS inventory reduced.

3. An UNPLANNED event results in:

a. RCS temperature exceeding 200°F for greater than 60 minutes (Note)

OR

b. RCS pressure increasing greater than 10 psig 87

Approved By . . Procedure Number Rev S. E. Prewitt Vogtle Electric Generating Plant 13011-1 69 Date Approved Page Number 6/15/2010 RESIDUAL HEAT REMOVAL SYSTEM 4 of 108 2.0 PRECAUTIONS AND LIMITATIONS 2.1 PRECAUTIONS 2.1.1 To prevent overheating the Component Cooling Water System (CCWS), cooling water flow to the RHR Heat Exchanger should not be throttled.

2.1 .2 To avoid thermal shock of the RCS components, the flow through the RHR should be initiated and reduced slowly.

2.1.3 The RCS pressure and temperature should not exceed 365 psig and 350°F when the RHR is in service.

2.1.4 Thoroughly fill and vent all applicable RHR components prior to returning them to service after maintenance. This minimizes system performance degradation and water hammer due to gas entrainment. Train A will be filled and vented using Section 6.1 and Train B will be filled and vented using Section 6.2. Steps are written such that the entire Train is considered drained including Hot Leg Injection and crossover piping. The Shift Supervisor is responsible for determining actual required filling and venting scope. He may authorize certain vent points to be added or omitted as deemed necessary based on actual portions of system drained. The omission of selected steps in Section 6.1 and 6.2 of this procedure is allowed.

2.1.5 If only an RHR pump and its associated piping, or only a portion of system piping has been drained for maintenance, Sections 6.7 and 6.8 should be performed as applicable to ensure the system is filled and vented.

2.1.6 Only one RHR train should be altered at a time when changing system configuration. This helps maintain RHR operability.

2.1.7 Whenevór Rc$Isat :ie8feet(o afoot a shøui Printed January 13, 2011 at 12:29

Approved By Procedure Number Rev S. E. Prewitt Vogtle Electric Generating Plant 13011-1 69 Date Approved Page Number 6/15/2O10 RESIDUAL HEAT REMOVAL SYSTEM 6 of 108 2.2 LIMITATIONS 2.2.1 In Modes 1, 2 & 3 the RHR is required to have an operable RHR pump and HX in each train per Technical Specification LCO 3.5.2.

2.2.2 In Mode 4 the RHR is required to be operable or in operation per Technical Specification LCO 3.4.6.

2.2.3 In Mode 4 one train of RHR is required to be operable per Technical Specification LCO 3.5.3.

2.2.4 In Mode 5 the RHR is required to be operable and in operation per Technical Specification LCO 3.4.7 and LCO 3.4.8.

2.2.5 During refueling operations, the RHR is required to be operable and in operation per Technical Specification LCO 3.9.5 and LCO 3.9.6.

2.2.6 MFdITUm HR 2.2.7 In Mode 6 only, one train of RHR may be used as an OPERABLE boron injection flow path provided a flow path is established from the OPERABLE RWST via an RHR pump through the cold legs with water level 23 feet above the reactor vessel flange. The RHR pump may not be the pump that is being applied to meet LCO 3.9.5. (TR 13.1.2, 13.1.4) (LDCR TM 97-004) 2.2.8 If required for Cold Overpressure Protection, two RHR Suction Relief Valves are required OPERABLE per Technical Specification LCO 3.4.12.

2.2.9 When in Mode 1, 2, or 3, 1 -HV-871 6A/B must remain open to ensure injection flow into all cold legs consistent with the Westinghouse Design Bases and FSAR Accident Analysis. However, one valve at a time may be closed for short periods during surveillance testing. 14825-1, Quarterly In service Valve Test governs these manipulations.

2.2.10 When in Mode 1, 2, or 3, 1 -HV-8809A/B must remain open to ensure injection flow into all cold legs consistent with the Westinghouse Design Bases and FSAR Accident Analysis. However, while in Mode 3, one valve at a time may be closed during surveillance testing per Technical Specification SR 3.4.14.1 as described in RER 87-1067. Procedure 14450-1, RCS Pressure Isolation Valve Leak Test governs these manipulations.

2.2.11 The RHR Suctions From Hot Legs Loops 1 and 4 (1-HV-8701A, 1-HV-8701B, 1 -HV-8702A, 1 -HV-8702B) are separately interlocked to prevent from being opened with RCS pressure greater than 365 psig.

Printed January 13, 2011 at 12:28

Approved By Procedure Number Rev C. S. Waidrup Vogtle Electric Generating Plant 18019-C 27.1 Qate Approved Page Number LOSS OF RESIDUAL HEAT REMOVAL 3/3/10 29 of 70 B. LOSS OF RHR MODE 5 CR6 BELOW PRZR IR OR SG NOZZLE DAMS INSTALLED ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

d. Check CCW cooling to RHR _d. Restore CCW cooling by system IN SERVICE, initiating 18020-C, LOSS OF COMPONENT COOLING WATER.

CAUTION Starting an RHR Pump may result in an RCS level reduction due to shrink or void collapse.

eeatxs

_d. Check RHR Pump NOT - d. Perform the following:

CAVITATING.

1) Reduce flow to stop cavitation.

_2) IF flow must be reduced to less than 1500 gpm to stop cavitation, THEN stop RHR Pump and return to Step B6.

e. Check RHR flow RESTORED. - e. Consult TSC if applicable and return to Step B6.

Printed January 13, 2011 at 12:32

Approved By Procedure Number Rev C. S. Waidrup Vogtle Electric Generating Plant 18019-C 27.1 1

ate Approved Page Number 3/3/1O LOSS OF RESIDUAL HEAT REMOVAL 26 of 70 B. LOSS OF RHR - MODE 5 CR6 BELOW PRZR IR OR SG NOZZLE DAMS INSTALLED ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

b. Use either of the following:

ATTACHMENT C Section A

- VALVE LINEUP FOR RHR PUMP COLD LEG INJECTION.

-OR-ATTACHMENT C Section B

- VALVE LINEUP FOR RHR PUMP HOT LEG INJECTION.

_c. Check RV Head - REMOVED. _c. GotoStepBl6.

_d. Use the Refueling Water Purification Pump per ATTACHMENT B.

_B16. Identify and isolate any RCS leakage.

NOTES

• The time to boiling in the RCS should be taken into consideration when determining how much time should be spent venting the RHR system prior to taking additional actions for alternate cooling sources.

• If adequate tiine to completely vent the RHR system is not available, air can t of the RHR lines by filling the RCS to 188 feet 3 inches and running an RHR tlowrate greater than 3000 gpm (3200 gpm indlcated B17. Vent any RHR Pump that experienced cavitation:

_a. Maintain RCS level while venting RHR system.

Step 17 continued on next page Printed January 13, 2011 at 12:32

AllJZ 15DL3 SRO Portion of Exam

12. Unit 1 initial conditions:

Time = 0800 Plant was on RHR following shutdown for refue ling Containment Closure has been established SGs are not available RCS temperature = 190°F stable RHR flow = 2200 gpm RCS level = 12.5 feet and decreasing RVLIS Full Range = 47% and decreasing Current plant conditions:

Time = 0825 1-AP-27.00 (LOSS OF DECAY HEAT REMOVA L CAPABILITY) has been initiated RHR pumps have been secured due to vortexing RCS temperature = 205°F increasing Based on the above conditions: (1) Classify the event using the Emergency Plan and (2) once RHR level and flow has been restored, state the MAXIMUM cooldown rate allowed per 1-AP-27.0O?

(Reference Provided)

A. (1) Alert (2) 25°F/Hr B. (1)Alert (2) 50 °F/Hr C. (1) Site Area Emergency (2) 50°F/Hr D. (1) Site Area Emergency (2) 25°F/Hr 12

HL-16 NRC Written Examination KEY

83. 026G2.2.44 002/1/1/LOSS OF CCW-CR INDIC/4.4 C/AINEW/SRO/NRC/EMT/GCW Unit 1 Large Break LOCA.

- Cold Leg Recirculation is in progress.

- Crew is performing 19010-C, Loss of Reactor or Secondary Coolant.

- The following alarms illuminate 30 seconds apart:

- ALB02-B05 CCW Train A Surge Tank HI/LO LVL

- ALB02-A05 CCW Train A Surge Tank LO/LO LVL Which ONE of the following CORRECTLY completes the following statement?

The given alarms indicate _(1 ) and the Control Room Crew should _(2).

A. (1) a failure of automatic makeup to the Train A CCW Surge Tank; (2) perform a makeup manually per ARP.

B. (1) a loss of Component Cooling Water Train A; (2) perform a makeup manually per ARP.

C. (1) a failure of automatic makeup to the Train A CCW Surge Tank; (2) perform actions of AOP 18020-C, Loss of CCW.

Dv (1) a loss of Component Cooling Water Train A; (2) perform actions of AOP 18020-C, Loss of CCW.

Feedback 026 Loss of Component Cooling Water (CCW)

Equipment Control 2.2.44 Ability to interpret Control Room indications to verify the status and operation of a system, and understand how operator actions and directives affect plant and system conditions.

(C FR: 41.5/43.5/45.12)

K/A MATCH ANALYSIS This question test the candidates ability to interpret Control Room alarms (indications) and determine the problem and the corrective procedure (actions I directives). This Page 169 of 208

HL-16 NRC Written Examination KEY meets the criteria for SRO only because this is the assessment of facility conditions and selection of appropriate procedures during abnormal and emergency situations.

SRO-10CFR55.43 (b5)

ANSWER I DISTRACTOR ANALYSIS A. Incorrect because this would be a catistrophic leak that exceeds the capacity of the makeup not a failure of the automatic action, ARP directs the crew to go to 18020-C.

Manual makeup with a leak still in progress would be an addtional flooding concern.

B. Correct Automatic action for Lo/Lo Surge Tank Level would trip of the CCW pumps on the associated train. The corrective actions would be covered in the AOP including tripping the train A RHR pump per the RNO because the pump seals would be damage during Cold Leg Recirculation mode. (Not in the Cold Leg Injection Mode).

C. Incorrect because this would be a catistrophic leak that exceeds the capacity of the makeup not a failure of the automatic action, this is plausible because the ARP directs the crew to go to 18020-C and makeup is addressed in the AOP.

D. Incorrect a loss of train A CCW is correct however, this is a catistrophic leak that exceeds the makeup capacity not a failure of automatic makeup. This is plausible because the ARP addresses failure of Automatic makeup and the automatic tripping on Lo/Lo level.

REFERENCES Procedure 17002-1 ARP for ALB 02 on Panel 1A1 on the QMCB Procedure 18020-C Loss of Component Cooling Water VEGP learning objectives:

LO-LP-60316-04 Given the entire AOP, describe:

a. Purpose of selected steps.

b. How and Why the step is being performed.

c. Expected response of the plant/parameter(s) for the step.

Page 170 of 208

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 17002-1 23 Date Approved ANNUNCIATOR RESPONSE PROCEDURES FOR ALB 02 ON PANEL 1A1 Page Number 11/04/20l0 ONMCB 14of42 WINDOW A05 ORIGIN SETPOINT CCW TRAIN A 1-LSLL-1 852 4.75 in. below CL SURGE TK 1 -LSLL-1 854 (equal to 42%) LO-LO LVL 1 -LSLL-1 856 1.0 PROBABLE CAUSE

1. Failure of automatic make-up from Deminerallzed Water System

2. Failure of manual make-up from Reactor Makeup Water System

3. .. Leak In Component 000hng. Water Systei 2.0 AUTOMATIC AC11ON LO-LO lvél tiiCCmpOneht aólIng Watr .PÜ1Y 3.0 INITIAL. OPERATOR ACTIONS Go. To 1 80204 Loss Of Campónént Cooling Water 4.0 SUBSEQUENT OPERATOR ACTIONS NONE 5.0 COMPENSATORY OPERATOR ACTIONS NONE END OF SUB-PROCEDURE

REFERENCES:

1 X4DB1 36, 1 X3D-BD-L01 A, 1 X3D-BD-L01 C, 1 X3D-BD-L01 E, 1X5DNO91-1, -2, -3, 1X5DT0022, CX5DT1O1-96 Printed January 13, 2011 at 14:49

Approved By Procedure Number Rev S. A. Phillips Vogtle Electric Generating Plant 18020-C 10 LOSS OF COMPONENT COOLING WATER Page Number ABNORMAL OPERATING PROCEDURE CONTINUOUS USE PURPOSE PRB REVIEW REQUIRED This procedure addresses the loss of one CCW train with either RHR or SFPC System in operation.

SYMPTOMS

• ALBO2(03) A06 CCW TRAIN A(B) LO HDR PRESS

• ALBO2(03) B06 CCW TRAIN A(S) LO FLOW

• ALBO2(03) A05 CCW TRAIN A(b) SURGETANK O-LQ L!.VL

• ALBO2(03) E05 CCW TRAIN A(S) RHR PMP SEAL LO FLOW

• ALBO2(03) BOl NSCW TRAIN A(S) LO HDR PRESS

• ALB61 -AOl (A02) NSCW CCW ACCW TRAIN A(B) TEMP ALARM

• ALBO2(03) C06 CCW TRAIN A(B) RHR HX HI FLOW

• ALBO2(03) D06 CCW TRAIN A(B) RHR HX LO FLOW MAJOR ACTIONS

• Respond to loss or degraded operation of CCW.

• Transfer RHR and SFPC to unaffected train.

Pnnted January 13, 2011 at 14:53

Approved By I S. A. Phillips Vogtle Electric Generating Plant Procedure Number Rev Date Approved 18020-C 10 (il2/16/o8 LOSS OF COMPONENT COOLING WATER Page Number I 2of5 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

_1. Check CCW pumps in the affected _1. Start two CCW pumps in the train TWO RUNNING.

affected train.

2. Check CCW train operation: 2. Perform the following:

. Flow APPROXIMATELY 9000 GPM. _a. Stop the CCW pumps in the affected train.

. Pressure APPROXIMATELY 90 PSIG.

b. Place the UNAFFECTED train in service by initiating 13715A/B, COMPONENT COOLING WATER SYSTEM.

_c. IF one train of CCW can NOT be placed in normal two pump operation, THEN attempt to place one train of CCW in single pump operation by initiating 1371 5A/B, COMPONENT COOLING WATER SYSTEM.

_d. GotoStep4.

_3. Return to procedure and step in effect.

_4. Verify NSCW supply header flow _4. Initiate 18021-C, LOSS OF FI-1640B(1641B) -

NUCLEAR SERVICE COOLING APPROXIMATELY 17000 GPM.

WATER SYSTEM.

5. Check RHR REQUIRED FOR

5. Go to Step 9.

SHUTDOWN COOLING.

_6. Check the AFFECTED RHR system - _6. Stop AFFECTED RHR Pump. Go to OPERATING NORMALLY.

Step 8.

7. Go to Step 9.

Printed January 13, 2011 at 14:53

lApproved By S. A. PhWips VogUe Electric Generating Plant ocedu Number Rev Date Approved 1 8020-C 10 1 211 6/08 LOSS OF COMPONENT COOLING WATER Page Number 3 of 5 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

_8. Place the UNAFFECTED RHR train 8. Perform the following:

in operation by initiating 13011, RESIDUAL HEAT REMOVAL SYSTEM. _a. Initiate 18019-C, LOSS OF RESIDUAL HEAT REMOVAL.

_b. Initiate applicable ACTION items for:

TS 3.4.6 TS 3.4.7 TS 3.4.8 TS 3.5.2 TS 3.5.3 TS 3.9.5 TS 3.9.6

10. Check the toIIowin JQ. Va1fy DEMHL WTR TO CCW TK-1 (2) opefl Both extinguished:

UNIT 1 UNIT2 ALBO2(03)-A05 CCW TRAIN A(B SURGE TK LO-LO LEVEL ALBO2(03)-B05 cCW TRAIN A(B SURGE TK HI/LO LEVEL WrwrO COW

-OR-UNIT 1 UNIT2 CCW TRAIN A(B) Surge Tank level LV-1 848 AB-203 AB-227 RISING. LV-1849 AB-202 AB-226 Printed January 13, 2011 at 14:53

Approved By Procedure Number Rev S. A. Phillips Vogtle Electric Generating Plant 18020-C 10 Date Approved 2/16/08 LOSS OF COMPONENT COOLING WATER Page Number 4of5 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

_1 1. Check affected CCW train NO -

11. Isolate the leak by performing the ABNORMAL LEAKAGE. following:

a. Stop pumps in affected train and place control switches in PULL-TO-LOCK.

_b. Isolate makeup water to the affected train surge tank.

_c. Close system isolation valves as necessary.

12. Restore the affected CCW loop to 12. Initiate applicable ACTION items for:

service by initiating 1371 5A/B, COMPONENT COOLING WATER TS 3.4.6 SYSTEM.

TS 3.4.7 TS 3.4.8 TS 3.5.2 TS 3.5.3 TS 3.7.7 TS 3.9.5 TS 3.9.6

_1 3. Locally check spent fuel pool _1 3. Place the UNAFFECTED SFPC temperature LESS THAN 130°F.

train in service by initiating 13719, SPENT FUEL POOL COOLING AND PURIFICATION SYSTEM.

14. Verify Fuel Handling Building normal _1 4. Start fuel pool area recirculating air HVAC units IN OPERATION:

handling unit 1541 -A7-003(004) by initiating 13320-C, FUEL

• 1541 -A7-001 (002) HANDLING BUILDING HVAC SYSTEM.

-AND

• 1541-N7-001 (002)

Printed January 13, 2011 at 14:53

Approved y I S. A. Phillips Vogtle Electric Generating Plant Procedure Number Rev Date Approved 18020-C 10 12/16/08 LOSS OF COMPONENT COOLING WATER I Page Number 5of5 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

15. Return to procedure and step in effect.

END OF PROCEDURE TEXT Printed January 13, 2011 at 14:53

Approved By J. B. Stanley Vogtle Electric Generating Plant Procedure Number Rev Date Approved ANNUNCIATOR RESPONSE PROCEDURES FOR 17002-1 23 11/04/2010 ALB 02 ON PANEL 1A1 Page Number ONMCB 18 of 42 ORIGIN WINDOW B05 SETPOINT 1-LIT-i 846 CCW TRAIN A Hi: 27 in. above CL SURGE TK (equal to 96%) HI/LO LVL Lo: Centerline (50%)

1.0 PROBABLE CAUSE

1. Leakage from Component Coollng.Wah.r Systét

2. Leakage into Component CUthWatEi Ssén

3. Make-up Valve 1 -LV-1 850 frothfl Z lzedWØer4. tern tailed.

2.0 AUTOMATIC ACTIONS IF level continues to lower, all Trai A at LO-LO levei 3.0 INITIAL OPERATOR ACTIONS NONE 4.0 SUBSEQUENT OPERATOR ACTIONS

1. Check surge tank level to verify high or low level

using.iL 18.450 computer point L2671.

2. if surge tank level is low

a. Verify 1-LV-1 850 is open for normal makeup;

b. I.E normal make-up is not available, open 1 -LV-1848 using 1-HS-1848 on QMCB c.. Check Floor Drain Sumps for indication of Ieaks Monitor all Component Cooling Water heat load s for Increasing temperature Printed January 13, 2011 at 14:47

HL-16 NRC Written Examination KEY

84. 034K 1 .04 00412/2/FM EQUIP-NIS/35C/A!NEW/SRO/NRC/EMT/GCW Unit 1 is in Mode 6:

- Preparations for core offload are completed.

- 1 BD1 is removed from service for planned maintenance.

- Source Range Nl-32 is powered with temporary power from 1 NLP39.

- Audible indication is in service in the Control Room and Containment from NI-32.

Which ONE of the following CORRECTLY completes the following statement?

CORE ALTERATIONS _(1) proceed based on _(2)__.

A. (1)Can (2) only one Source Range is required to be OPERABLE in this Mode.

B (1) Can (2) both Source Ranges are OPERABLE, only one may be on temporary non-safety related power.

C. (1)Can NOT (2) Nl-31 must be selected to provide audible indication for audible indication to be OPERABLE.

D. (1)Can NOT (2) N 1-32 must be returned to its normal power supply to be OPERABLE.

Feedback 034 Fuel Handling Equipment System (FHES)

Knowledge of the physical connections and/or cause effect relationships between the Fuel Handling System and the following systems:

(C FR: 41.2 to 41.9/45.7 to 45.8)

K1.04 NIS K/A MATCH ANALYSIS The question test the knowledge of the candidate on the requirements for Nj during refueling (Fuel Handling) per Tech Spec. This is a SRO only question becaus it e

Page 171 of 208

HL-16 NRC Written Examination KEY and their bases.

SRO-10CFR55.43 (b2 and 5)

ANSWER I DISTRACTOR ANALYSIS A. Incorrect CORE ALTERATIONS can proceed but the reason that it is incorre ct is because Tech Spec states that CORE ALTERATIONS may continue as long as both NIs indication are available in the Control Room. This is a plausible choice because the candidate may consider that since the Control Rods can not be withdrawn with the plants configuration. Two source range detectors would not be required for the trip function, therefore only one source range would be require d for CORE ALTERATIONS.

B. Correct Tech Spec requires two Sources detectors to be OPERABLE while CORE ALTERATIONS are in progress. With one of the detectors is powered by its safety related power source, the other may be powered by a non-safety related source and still be considered OPERABLE. Per Tech Spec CORE ALTERATIONS may continue as long as both NIs indication are available in the Control Room. Per the TRM at least one source range shall provide audible indication in the Contai nment and Control Room. Both of the requirements are met.

C. Incorrect CORE ALTERATIONS can proceed with this alignment, the TRM states at least one source range shall provide audible indication in the Containment and Control Room. Since both are still considered OPERABLE it does not matter which one is selected. This choice is plausible because the candidate may consid er the Source Range with temp non-safety related power is only functional not OPERABLE, therefore should not be selected to meet the TRM.

D. Incorrect CORE ALTERATIONS can proceed with one of the detectors is powered by its safety related power source, the other may be powered by a non-safety related source and still be considered OPERABLE. This choice is plausible because the candidate may consider the Source Range with temp non-safety related power is only functional not OPERABLE.

REFERENCES Technical Specification 3.9.3 Nuclear Instrumentation Technical Specification Bases 3.9.3 Nuclear Instrumentation Technical Requirement Manual 13.9.6 Source Range Monitor Audible Indicat ion VEGP learning objectives:

LO-PP-1 7201-05 Discuss all applicable Technical Specification associated with the Source & Intermediate Range Nuclear Instrumentation to include (from memor y):

a. All LCOs Page 172 of 208

HL-16 NRC Written Examination KEY

b. Appilc ability

c. All 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> actions Page 173 of 208

Nuclear Instrumentation 3.9.3 3.9 REFUELING OPERATIONS 3.9.3 Nuclear Instrumentation LCO 3.9.3 Two source range neutron flux monitors shall be OPERABLE.

APPLICABILITY: MODE 6.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One source range neutron A.1 Suspend CORE Immediately flux monitor inoperable. ALTERATIONS.

AND A.2 Suspend positive Immediately reactivity additions.

B. ------

NOTE B.1 Initiate action to restore Immediately Condition A entry is one source range required when Condition B neutron flux monitor to is entered. OPERABLE status.

AND Two source range neutron flux monitors inoperable. B.2 Perform SR 3.9.1.1 Once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> (verify boron concentration).

Vogtle Units 1 and 2 3.9.3-1 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

Nuclear Instrumentation 3.9.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.3.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.9.3.2 NOTE Neutron detectors are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION. 18 months Vogtle Units 1 and 2 3.9.3-2 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

Nuclear Instrumentation B 3.9.3 B 3.9 REFUELING OPERATIONS B 3.9.3 Nuclear Instrumentation BASES BACKGROUND The source range neutron flux monitors are used during refueling operations to monitor the core reactivity condition. The installed source range neutron flux monitors (N 1-0031 and N 1-0032) are part of the Nuclear Instrumentation System (NIS). These detectors are located external to the reactor vessel and detect neutrons leaking from the core. Temporary neutron flux detectors which provide equivalent indication may be utilized in place of installed instrumentation.

The installed source range neutron flux monitors are fission chamber detectors. The detectors monitor the neutron flux in counts per second. The instrument range covers seven decades of neutron flux (1 E-1 cps to I E +6 cps) with a 2% instrument accuracy. The detectors also provide continuous visual indication in the control room.

The NIS is designed in accordance with the criteria presented in Reference 1.

APPLICABLE Two OPERABLE source range neutron flux monitors are required SAFETY ANALYSES to provide a signal to alert the operator to unexpected changes in core reactivity such as an improperly loaded fuel assembly. The need for a safety analysis for an uncontrolled boron dilution accident is minimized by isolating all unborated water sources except as provided for by LCO 3.9.2, Unborated Water Source Isolation Valves.

The source range neutron flux monitors satisfy Criterion 3 of 10 CFR 50.36 (c)(2)(ii).

LCO This LCO requires that two source range neutron flux monitors be OPERABLE to ensure that redundant monitoring capability is available to detect changes in core reactivity. To be OPERABLE each monitor must provide visual indication.

When any of the safety-related busses supplying power to one of the detectors (NI-0031 or N 1-0032) associated with the source range neutron flux monitors are taken out of service, the corresponding source range neutron flux monitor may be considered OPERABLE when its detector is powered from a temporary nonsafety-related (continued)

Vogtle Units I and 2 B 3.9.3-1 Rev. 3-4/09

Nucear Instrumentation B 3.9.3 BASES LCO source of power, provided the detector for the opposite source range (continued) neutron flux monitor is powered from its normal source.

APPLICABILITY In MODE 6, the source range neutron flux monitors must be OPERABLE to determine changes in core reactivity. There are no other direct means available to check core reactivity levels. In MODES 2, 3, 4, and 5, the operability requirements for the installed source range detectors and circuitry are specified in LCO 3.3.1, Reactor Trip System (RTS) Instrumentation.

ACTIONS A.1 and A.2 With only one source range neutron flux monitor OPERABLE, redundancy has been lost. Since these instruments are the only direct means of monitoring core reactivity conditions, CORE ALTERATIONS and positive reactivity additions must be suspended immediately. Performance of Required Action A.1 shall not preclude completion of movement of a component to a safe position or normal cooldown of the coolant volume for the purpose of system temperature control.

B.1 Condition B is modified by a Note to clarify the requirement that entry into or continued operation in accordance with Condition A is required for any entry into Condition B. The Note reinforces conventions of LCO applicability as stated in LCO 3.0.2 and as reflected in examples in 1.3, Completion Times.

With no source range neutron flux monitor OPERABLE, action to restore a monitor to OPERABLE status shall be initiated immediately.

Once initiated, actions shall be continued until a source range neutron flux monitor is restored to OPERABLE status.

B.2 With no source range neutron flux monitor OPERABLE, there are no direct means of detecting changes in core reactivity. However, since CORE ALTERATIONS and positive reactivity additions are not to be (continued)

Vogtle Units 1 and 2 B 3.9.3-2 Rev. 1-4/09

Nuclear Instrumentation B 3.9.3 BASES ACTIONS B.2 (continued) made, the core reactivity condition is stabilized until the source range neutron flux monitors are OPERABLE. This stabilized condition is determined by performing SR 3.9.1.1 to ensure that the required boron concentration exists.

The Completion Time of once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is sufficient to obtain and analyze a reactor coolant sample for boron concentration and to ensure that unplanned changes in boron concentration would be identified. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time is reasonable, considering the low probability of a change in core reactivity during this time period.

SURVEILLANCE SR 3.9.3.1 REQUIREMENTS SR 3.9.3.1 is the performance of a CHANNEL CHECK, which is a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that the two indication channels should be consistent with core conditions.

Changes in fuel loading and core geometry can result in significant differences between source range channels, but each channel should be consistent with its local conditions.

The Frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is consistent with the CHANNEL CHECK Frequency specified similarly for the same instruments in LCO 3.3.1, Reactor Trip System (RTS) Instrumentation.

SR 3.9.3.2 SR 3.9.3.2 is the performance of a CHANNEL CALIBRATION every 18 months. This SR is modified by a Note stating that neutron detectors are excluded from the CHANNEL CALIBRATION. The CHANNEL CALIBRATION for the source range neutron flux monitors includes obtaining the detector preamp discriminator curves and evaluating those curves. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage. Operating experience has shown these components usually pass the Surveillance when performed at the 18 month Frequency.

(continued)

Vogtle Units I and 2 B 3.9.3-3 Rev. 2-4/09

Source Range Monitor Audible Indication TR 13.9.6 13.9 Refueling Operations TR 13.9.6 Source Range Monitor Audible Indication TR 13.9.6 At least one source range monitor shall provide audible indication in the containment and control room.

APPLICABILITY: M ODE 6 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Required source range A.1 ---------N OTE--------

monitor audible indication Makeup to the reactor inoperable or not coolant system (RCS) is operating. allowed, provided the makeup source has been verified to be greater than the required refueling boron concentration (reference Technical Specifications Paragraph 3.9.1)

Suspend all operations Immediately involving CORE ALTERATIONS or positive reactivity changes.

TECHNICAL REQUIREMENT SURVEIL LANCES SURVEILLANCE FREQUENCY TRS 13.9.6.1 Perform CHANNEL CHECK 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> TRS 13.9.6.2

-- NOTE Neutron detectors are excluded from CHA NNEL CALIBRATION.

Perform CHANNEL CALIBRATION 18 months Vogtle Units 1 and 2 13.9 - 10 Technical Requirement Rev. 2 4121/04

HL-16 NRC Written Examination KEY

85. 036AA2.02 001/1/2/FUEL HAND ACCIDENT/4. I C/A/NEW/SRO/NRC/GCW Core offload is in progress during a refueling outage when the following annunciator window illuminates on the QMCB.

SPENT FUEL PIT LOW LEVEL

- Personnel in the FHB report SFP level at 216 feet 2 inches and lowering.

- Attempts to raise SEP level via normal makeup methods are unsuccessful.

- RE-008 Area Monitors are NOT in alarm but radiation levels are slowly rising.

Which one of the following is correct regarding:

1) if notification to state and local authorities is required per NMP-EP-1 10 Emergency Classification Determination and Initial Notification, and

2) what qualifies as an Alternate Source of Makeup during Emergency Conditions per Attachment C of AOP-18030-C, Loss of Spent Fuel Pool Cooling or Level?

Reference Provided A. 1) non-event, no classification or notification of offsite agencies is required.

2) Fire Water via hose cabinets.

B. 1) non-event, no classification or notification of offsite agencies is required.

2) Recycle Holdup Tank to the transfer canal.

Cs 1) Notification of Unusual Event (NOUE), notify state and local authorities.

2) Fire Water via hose cabinets.

D. 1) Notification of Unusual Event (NOUE), notifly state and local authorities.

2) Recycle Holdup Tank to the transfer canal.

Feedback 036 Fuel Handling Incidents Ability to determine and interpret the following as they apply to the Fuel Handling Incidents:

(CFR: 43.5/45.13)

AA2.02 Occurrence of a fuel handling incident Page 174 of 208

HL-16 NRC Written Examination KEY K/A MATCH ANALYSIS The question presents a plausible scenario where an uncontrolled loss of SFP level is in progress during a refueling outage. The candidate must determine if an Emergency Classification is required.per NMP-EP-1 10 and a possible source of emergency makeup to the SFP per AOP-1 8030-C.

SRO-Justification-Not tied to 10CFR55.43(b), but is classified as SRO ONLY because the question is linked a SRO ONLY objective.

LO-LP-40101-13 Given an emergency scenario, and the procedure, classify the emergency (SRO only).

ANSWER I DISTRACTOR ANALYSIS A. Incorrect. Level lowering with makeup unsuccessful implies uncontrolled lowering.

The SFP low level alarm indicates LSHL-0625 is offscale low. Fire water via hose cabinets is specified as emergency makeup per AOP-18030, Attachment C. This is also unborated water which candidate may rule out if not familiar with attachment.

B. Incorrect. Level lowering with makeup unsuccessful implies uncontrolled lowering.

The SEP low level alarm indicates LSHL-0625 is offscale low, RHUT is an alternative method that is borated but is not the method specified per the AOP for emergency makeup C. Correct. NOUE (RU2). Fire water via hose cabinets is specified as emergency makeup per AOP-18030, Attachment C. This is also unborated water which candidate may rule out if not familiar with attachment.

D. Incorrect. NOUE (RU2) part is correct. The SFP low level alarm indicates LSHL-0625 is offscale low.RHUT is an alternative method that is borated but is not the method specified per the AOP for emergency makeup.

REFERENCES 18030-C, Loss of Spent Fuel Pool Level or Cooling 13703-C, Boron Recycle System, Section 4.4.14 Transferring a Recycle Hold-Up Tank to a Spent Fuel Pit Transfer Canal NMP-EP-1 10, Emergency Classification Determination and Initial Action (Needs to be provided)

NMP-EP-110-GLO3, Fission Product Barrier Evaluation Figure 1.

NMP-EP-110-GLO3, Emergency Classification Determination And Initial Action Figure 2.

NMP-EP-110-GLO3, Emergency Classification Determination And Initial Action Page 175 of 208

HL-16 NRC Written Examination KEY Figure 3.

VEGP learning objectives:

LO-LP-40401 -13, Given an emergency scenario, and the procedure, classify the emergency (SRO only).

Page 176 of 208

Approved By J. B. Stanley Vogtle Electric Generating Plant Procedure Number Rev Date Approved 18030-C 19.1 LOSS OF SPENT FUEL POOL LEVEL OR

( )122/o9 COOLING Page Number 15 of 18 ATTACHMENT C Sheet 1 of 2 ALTERNATE SOURCES OF MAKEUP TO THE SPENT FUEL POOLS DURING EMERGENCY CONDITIONS NOTE For a loss of SFP inventory, FHB R-608 may be flooded.

Deploy hose from the following fire hos e cabinets and route to Spent Fuel Pool necessary. , as SDent Fuel Pool Area

• 1-2301 -R4-042

• 1-2301 -R4-043 2-2301 -R4-042 2-230 1 -R4-043 Unit 1 Aux Bldn (R-122 Unit 2 Aux Bldg (R-139)

• 1-2301-R4-128

• 2-2301-R4-128

• 1-2301-R4-129

• 2-2301-R4-129

• 1-2301-R4-158

• 2-2301-R4-154 Unit 1 EguiDment Building (R-120)

Unit 2 EpuiDment Building (R-120)

• 1-2301 -R4-024

• 2-230 1 -R4-024 Crane Bay Area (R-127)

• A-2301 -R4-1 60

• 1-2301 -R4-1 30

• 2-230 1 -R4-1 30

2. Remove nozzles and add additional hos e lengths, as necessary.

3. Restrain hoses, as necessary.

4. Obtain additional 1-1/2 inch hose from fire brigade equipment lockers and the fire equipment carts, as necessary. hose Printed January 15, 2011 at 17:34

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18030-C 19.1 jDate Approved Page Number LOSS OF SPENT FUEL POOL LEVEL OR

)/22/09 COOLING 16 of 18 ATTACHMENT C Sheet 2 of 2 ALTERNATE SOURCES OF MAKEUP TO THE SPENT FUEL POOLS DURING EMERGENCY CONDITIONS CAUTION Besides the use of the normal fire water system, the Seismic Category I standpipe may also be used as a last resort.

5. Operate the Seismic Category I Standpipe using 13903-C, FIRE PROTECTION SYSTEM OPERATION.

a. Obtain 2-1/2 inch hose sections from the fire brigade equipment lockers and fire hose carts, as necessary.

b. Connect 2-1/2 inch hoses to hose station valves located on level 1 of the Crane Bay area (next to the central stairwell):

• A-2303-U4-009 for the A-Train standpipe.

• A-2303-U4-006 for the B-Train standpipe.

c. Unlock and open the following valves to operate these standpipes, as necessary:

• 1-1 202-U4-089 (R-A4OA) for the A-train standpipe.

• 1-1 202-U4-1 53 (FHB R-B08) for the B-train standpipe.

d. Request Engineering, with the support of Chemistry, to analyze the long term affects of NSCW additives to the spent fuel stored in the SFPs.

° OF ATTACHMENT C Printed January 15, 2011 at 18:18

Procedure Number Rev

[proved By J. B. Stanley VogUe Electric Generating Plant 13703-C 50.3 Page Number

- Date Approved

/18/10 BORON RECYCLE SYSTEM 3of 66 4.4.13 Recycle Hold-up Tank Transfer to Refueling Water Storage Tank 4 4 14 Transferring a Recycle HoldUp Tank to a Spent Fuel Pit Transfer Can, 4.4.15 Makeup to a Recycle Hold-Up Tank from the BAST Not Blended 4.4.16 Makeup to a Recycle Holdup Tank from the BAST with Normal Make-up Controls Out of Service 2.0 PRECAUTIONS AND LIMITATIONS 2.1 PRECAUTIONS 2.1.1 Adhere to all applicable radiological controls.

2.1.2 Health Physics should sample all tanks to determine H2 and 02 concentrations prior to opening the tanks for maintenance.

2.1.3 Transfer only the out of service Recycle Holdup Tank to the selected Spent Fuel Pit Transfer Canal.

2.1.4 In the event of a planned/unplanned outage of the Auxiliary Building HVAC, all processing from the Recycle Holdup Tank to a Waste Monitor Tank shall be terminated to prevent an H2 buildup.

2.2 LIMITATIONS 2.2.1 The in-service Recycle Holdup Tank should be vented approximately every six months.

2.2.2 The gas volume under the recycle holdup tank diaphragm should be confirmed nonflammable or vented before and after an RCS loop drain or a drain from the fuel storage area (or fuel transfer canal).

Printed January 18, 2011 at 16:45

reumev Vogtle Electric Generating Plant ON Page Number Date Approved ANNUNCIATOR RESPONSE PROCEDURES FOR ALB 05 43 of 66

125/10 PANEL 1A2 ON MCB WINDOW E02 ORIGIN SETPOINT SPENT FUEL PIT 1-LSHL-625 217 feet elevation LO LEVEL 1.0 PROBABLE CAUSE

1. Insufficient inventory during filling or refueling operation.

2. Normal evaporation.

3. System leak.

ing Pit Gate

4. Loss of air to the Fuel Transfer Canal and/or Cask Load Seals.

2.0 AUTOMATIC ACTIONS NONE 3.0 INITIAL OPERATOR ACTIONS NONE Printed January 15, 2011 at 17:50

Procedure Number Rev Approved By C. S. Waidrup VogUe Electric Generating Plant 17005-1 32.1 Page Number ALB 05 ON Date Approved ANNUNCIATOR RESPONSE PROCEDURES FOR 4 of 66

/25/10 PANEL 1A2 ON MCB WINDOW E02 (Continued) 4.0 SUBSEQUENT OPERATOR ACTIONS ly.

1. Dispatch an operator to determine actual level local (see Figure 1 in this procedure).

a security patrol to

2. Notify the Security Alarm Station (CAS) to dispatch check for any indications of sabotage.

fication and return

3. Refer to 13719-1, Spent Fuel Pool Cooling And Puri the Spent Fuel Pit to normal level (218.5 feet).

ter than 217 feet with fuel movement in

4. jf level cannot be maintained grea t Fuel Pool Gate containment in progress or 216.5 feet with the Spen iated fuel assemblies in Valve closed, THEN suspend movement of irrad the Spent Fuel Pool.

the Spent Fuel Pool and all crane operations over Cooling and Initiate 18030-C, Loss Of Spent Fuel Pool Level Or 18006-C Fuel Handling Event.

Service Air System

5. Check service air to gate seals and refer to 13710-1, to restore service air if lost.

6. Refer to Technical Specification LCO 3.7.15.

5.0 COMPENSATORY OPERATOR ACTIONS NOTE the cask loading pit, Unit 1 If the East and West pools are connected through ition for both pools.

annunciator ALBO5EO2 will detect a low level cond 3-1, Radwaste Rounds Verify Spent Fuel Pool Level every 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> per 1188 Sheets.

END OF SUB-PROCEDURE Technical Specifications LCO 3.7.15

REFERENCES:

1X4DB13O, PLS, 1X5DT0037, Printed January 15, 2011 at 17:50

Approved By Procedure Number Rev C. S. Waidrup Vogtle Electric Generating Plant 17005-1 32.1 Date Approved ANNUNCIATOR RESPONSE PROCEDURES FOR ALB 05 ON Page Number 4/25/10 PANEL 1A2 ON MCB 45 of 66 Figure 1 - Spent Fuel Pool Local Water Level Indication

1) LEVEL NUMBERS ARE PLANT ELEVATIONS IN FEET

2) POOL VOLUME APPROX.

453,000 GALS AT N ELEV.

3)1 FOOT OF POOL (ONLY) I ELEVATION EQUALS APPROX.

11,408 GALS HIGH ALARM 219 NORMAL LEVEL H 218 6 218 H 2176 LOW ALARM 217 Printed January 15, 2011 at 17:50

HL-16 NRC Written Examination KEY

86. 037G2.4.4 OO1/1/2/SGT ENTR L Y/4.7 CIAJMOD SUMMER O6ISRO/NRCIGCW Given the following plant conditions:

- A Steam Generator Tube leak has been identified on SG # 2.

- The crew has entered AOP-1 8009-C, Steam Generator Tube Leak.

Based on RE-0724 and RE-OSlO reading, the following trend is develo ped:

-2115 62 gallons per day

- 2215 68 gallons per day

- 2315 109 gallons per day

- 0015 362 gallons per day

- 0045 leakage is rising noticeably

- Pressurizer level is currently stable.

- VCT level is 8.2% and trending down with makeup initiated.

Which of the following actions is correct in accordance with AOP-1 8009-C?

A. Isolate CVCS letdown by closing the Letdown Orifice and Letdown Isolati on Valves.

lnitate 12004-C, Power Operation (Mode 1) and be in Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

B. Swap charging suction to the RWST and re-align CCP alternate & norma l mini-flow.

Trip the reactor, when reactor trip verified, actuate SI, then go to 19000

-C, E-0.

C. Isolate CVCS letdown by closing the Letdown Orifice and Letdown Isolati on Valves.

Initiate 12004-C, Power Operation (Mode 1) and be in Mode 3 within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

D Swap charging suction to the RWST and re-align CCP alternate & normal mini-flow.

Trip the reactor, go to 19000-C, E-0 and continue actions of AOP-1 8009-C.

Feedback 037 Steam Generator (SIG) Tube Leak Emergency Procedures I Plan 2.4.4 Ability to recognize abnormal indications for system operating parameters that are entry-level conditions for emergency and abnormal operati ng procedures.

(CFR: 41.10/43.2/45.6)

Page 177 of 208

HL-16 NRC Written Examination KEY K/A MATCH ANALYSIS The questions presents a scenario where a SGTL is in progress with an upward trend developing on SG tube leakage. The candidate must choose corrective actions to perform per 1 8009-C and any appropriate procedural transitions.

SRO 10CFR55.43 (b5)

ANSWER I DISTRACTOR ANALYSIS A. Incorrect. Plausible to isolate letdown as it is the first steps in the RNO for inability to maintain PRZR level. Being in Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> using 12004-C, is the actions in the RNO for leakage> 150 GPD which the conditions in the stem state.

However, the inability to maintain VCT level as a continuous action from step 4 RNO would trump these actions.

B. Incorrect. Shifting charging pump suction to RWST and CCP miniflo ws is the correct actions. However, tripping the reactor and actuating SI is wrong as PRZR level is being maintained. This would be the actions for inability to maintain PRZR level, not VCT level.

C. Incorrect. Plausible to isolate letdown as it is the first steps in the RNO for inability to maintain PRZR level. Being in Mode 3 within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> is the RNO for leakag e less than 75 GPD which the conditions in the stem state. This would be contro lled by 18013-C, Rapid Downpower, not 12004-C, the time for shutdown is slightl y wrong as a reduction of power to 50% then shutdown in 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> is the proper time.

However, the inability to maintain VCT level as a continuous action from step 4 RNO would trump these actions too.

D. Correct. Swapping VCT to RWST essentially is an emergency boratio n requiring a plant shutdown and is the proper RNO response. Tripping the reactor, go to E-0 is the proper action. SI is not required as PRZR level is being maintained and continuing with AOP-18009-C is also a proper action.

REFERENCES 18009-C, Steam Generator Tube Leak VC Summer 2006 October NRC SRO Retake exam, question # 38 used as inspiration.

VEGP learning objectives:

LO-LP-60309-04 Given conditions and/or indications, determine the required AOP to enter (including subsections, as applicable).

LO-LP-60309-05 Given the entire AOP, describe:

a. Purpose of selected steps Page 178 of 208

HL-16 NRC Written Examination KEY

b. How and why the step is being performed

c. Expected response of the plant/parameter(s) for the step LQ-LP-60309-13 Describe the major actions taken for a SG tube leak that does not meet unit shutdown requirements.

Page 179 of 208

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18009-C 28.2 Paqe Number STEAM GENERATOR TUBE LEAK ABNORMAL OPERATING PROCEDURE CONTINUOUS USE PURPOSE This procedure provides operator actions for responding to a Steam Generator Tube Leak in Modes 1, 2, or 3 that may require a controlled plant shutdown, and actions to be taken while operating with a minor tube leak.

SYMPTOMS

• ARP 17100 upon indication of a Steam Generator Tube Leak.

• Report from Chemistry of abnormal secondary activity.

• Leakage in excess of TS 3.4.13.

• Secondary specific activity in excess of TS 3.7.16.

• Both of the following:

• Rising secondary radiation levels.

-AND-

• Any of the following symptoms:

PRZR level lowering.

Charging flow higher than normal.

Unexplained/unexpected rise in VCT makeup frequency.

MAJOR ACTIONS

• Maintain PRZR and VCT levels.

• Check if unit shutdown is required.

• Initiate boration.

• Identify and isolate affected SG.

• Concurrently cooldown and depressurize the RCS to affected SG pressure.

• Cooldown and depressurize the RCS and affected SG (using blowdown) to cold shutdown conditions.

Printed January 16, 2011 at 12:45

Approved By I Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18009-C 28.2 Date Approved Paqe Number STEAM GENERATOR TUBE LEAK 2 of 34

(/30/09 CONTINUOUS ACTIONS Step Actions MAIN BODY 2 Maintain PRZR at program level.

3 Try to identify affected SG.

4 Maintain VCT level using automatic or manual makeup control.

14 Maintain RCS temperature using steam dumps or SG ARVs.

18 Maintain VCT level greater than 20%.

22 Monitor affected SG NR level to isolate feed flow.

25 Maintain cooldown rate less than 100°F/hr and PRZR level between 19% and 75%.

27 Control feed flow to maintain UNAFFECTED SG NR levels between 60% and 70%.

28 Continue RCS depressurization concurrent with RCS cooldown maintaining RCS subcooling between 24°F and 34°F and RCS pressure at affected SG pressure.

29 Monitor RCS pressure for accumulator isolation.

32 Maintain RCS temperature and pressure stable.

42 Maintain RCS pressure at affected SG pressure.

43 Monitor affected SG NR level for refill criteria.

ATTACHMENT A, OPERATION WITH A MINOR TUBE LEAK 3 Monitor primary to secondary leakage using RE-0724 and RE-0810.

Printed January 16, 2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley VogUe Electric Generating Plant 18009-C 28.2 Page NUmber STEAM GENERATOR TUBE LEAK ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

_1. Initiate the Continuous Actions Page.

• 2. Maintain PRZR leve:

a. Adjust charging flow as necessary to maintain program level.

_b. Check PRZR level STABLE QE b. Perform the following:

RISING.

1) Isolate letdown by closing:

_a) Letdown Orifice Valves.

_b) Letdown Isolation Valves.

_c) Excess Letdown Valves.

• _2) Start an additional Charging Pump as necessary.

3) IF PRZR level can NOT be maintained greater than 9%,

THEN perform the following:

_a) Trip the Reactor.

_b) WHEN Reactor trip verified, THEN actuate SI.

_c) Go to 19000-C, E-0 REACTOR TRIP OR SAFETY INJECTION.

Printed January 16, 2011 at 12:45

Approved By I Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18009-C 28.2 sate Approved Page Number STEAM GENERATOR TUBE LEAK 3/30/09 4 of 34 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

• 3 Try to identify affected SG:

a. Direct Chemistry to attempt to identify the leaking SG by initiating 31120-C, CHEMISTRY STEAM GENERATOR TUBE LEAK ACTIONS.

_b. Check SG level indications stable or rising with relatively lower feedflow rate.

CAUTION The NCP will NOT have miniflow when the CCP normal miniflow valves are closed.

_*4 Maintain VCT level using automatic Shift charging suction to the or manual makeup control. RWST:

a. Open RWST TO CCP A&B SUCTION valves:

• LV-112D LV-112E

b. Close VCT OUTLET ISOLATION valves:

. LV-0112B

-... LV-0112C

c. Place CCP alternate mini-flow valves in ENABLE PTL:

• HV-8508A HV-8508B Step 4 continued on next page Printed January 16, 2011 at 12:45

Approved By J. B. Stanley Vogtle Electric Generating Plant Procedure Number Rev Date Approved 1 8009-C 28.2 STEAM GENERATOR TUBE LEAK Page Number 3/30/09 5 of 34 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

d. Close CCP normal miniflow valves:

• HV-81 10 CCP-A & B COMMON MINIFLOW

• HV-81 1 1A CCP-A MINIFLOW

• HV-81 11 B CCP-B MINIFLOW

_e. Trip the reactor.

_f. Initiate 1 9000-C, E-0 REACTOR TRIP OR SAFETY INJECTION.

g. GotoStepli.

_5. Check leakrate less than 5 gpm as 5. Perform the following:

determined by [charging (letdown

- +

seal leakoff)] mismatch. _a. Initiate 18013-C, RAPID POWER REDUCTION.

_b. Be in Mode 3 within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

_c. GotoStepil.

Printed January 16, 2011 at 12:45

Approved By J. B. Stanley Vogtle Electric Generating Plant Procedure Number Rev Date Approved 18009-C 28.2

/30/09 STEAM GENERATOR TUBE LEAK Page Number 6 of_34 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE If available, both RE-0810 and RE-0724 shou ld be used to determine the leakage rate change in Step 6 RNO; however, if only one of of the two radiation monitors is OPERABLE, then the reading from the OPERABLE monitor should be used to determine leakage rate of change.

6. Check leakage rate of change:

a. Greater than or equal to 30

a. Perform the following:

GPD/HR based on a 20 minute trend:

1) After a 20 minute trend has elapsed, determine the leakage rate of change.

IPC Points:

jf leakage rate of RE-0810: UR6810(GPD) change is greater than UR681 1 (ROC) or equal to 30 gpd/hr, THEN go to Step 7.

RE-0724: UR6724(GPD)

UR6725(ROC) -OR jf leakage rate of change is less than 30 gpd/hr, THEN go to Step 8.

Printed January 16, 2011 at 12:45

-I Procedure Number Rev enerating Plant I18009 28.2 Page Number ACTI

_7. Check leakage rate LESS THAN

- 7. Perform the following:

75 GPD.

_a. Initiate 18013-C, RAPID POWER REDUCTION.

_b. Be less than 50% power within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

_c. Be in Mode 3 within the next 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

_d. GotoStepli.

_8. Check leakage rate LESS THAN

- 8. Perform the following:

150 GPD.

_a. Initiate 12004-C, POWER OPERATION (MODE 1).

b. Be in Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

c. GotoStepil,

9. Check leakage rate LESS THAN 9.

if Ieakrate has remained greater 75 GPO. than or equal to 75 gpd for one hour, THEN perform the following:

_a. Initiate 12004-C, POWER OPERATION (MODE 1).

b. Be in Mode 3 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

c. GotoStepii.

nted Janua 16, 2011 at 1245

1. 037 G2.4.6 002/NEW/IHIGHERJ/1/2/SROINO Given the following plant conditions:

• A Steam Generator Tube Leak was identified on B SG.

• The crew is performing actions of AOP-1 12.2, SG Tube Leak Not Requiring SI.

• Based on RM-A9 indications, the following trend is deve loped:

- 0915 52 gallons per day

-1015 58gallonsperday

-1115 89gallonsperday

-1215 356gallonsperday

- 1245 leakage is rising noticeably

• Pressurizer level is currently stable.

• VCT level is 8% and trending down with makeup initiated.

Which ONE (1) of the following describes the action required in accordance with AOP-1 12.2?

A. Align Charging Pump suction to the RWST; Direct the crew to trip the reactor, and enter EOP-1 .0, Reactor Trip/Safety Injection Actuation.

B. Trip the reactor and enter EOP-1 .0; initiate safety injec tion upon verification of immediate actions C. Align Charging Pump suction to the RWST; Continue in AOP

-1 12.2, and be less than 50% power within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and in Mode 3 within the next 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. (3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> total)

D. Initiate a plant shutdown to Hot Standby; Continue in AOP-1 12.2, be in Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

HL-16 NRC Written Examination KEY

87. 056G2.2.42 001 / I/I /LOSP-TS/4.6 C/A/BANKJSRO/NRC/GCW Given the following conditions:

- The crew is in 18031-C due to an LOSP on 2BA03 with DG2B tying to the bus.

- Various CCW Train B low flow and pressure alarms annunciate, then clear.

- The crew notes 3 CCW train B pump red lights illuminated on the QMCB.

Which ONE of the following is CORRECT regarding CCW Train B and the actions the SS should take?

A. CCW pump locked rotor has occurred. Monitor pump amps on the QEAB to determine which pump to stop. Enter LCO 3.7.7 for CCW.

B. CCW pump locked rotor has occurred. Monitor pump amps on the QEAB to determine which pump to stop. Enter INFO LCO 3.7.7 for CCW.

C. CCW pump shaft shear has occurred. Monitor pump amps locally at 2BA03 to determine which pump to stop. Enter LCO 3.7.7 for CCW.

D CCW pump shaft shear has occurred. Monitor pump amps locally at 2BA03 to determine which pump to stop. Enter INFO LCO 3.7.7 for CCW.

Feedback 056 Loss of Offsite Power Equipment Control G2.2.42 Ability to recognize system parameters that are entry-level conditions for Technical Specifications.

(CFR: 41.7/41.10/43.2/43.3/ 45.3)

K/A MATCH ANALYSIS Question gives a plausible scenario during an LOSP on a class 1 E electrical bus which starts the DG and the bus is re-energized. Three CCW pumps will be running due to low pressure. The candidate must determine which pump to stop and if an LCO entry is required.

SRO-Question meets 1 OCFR55.43(b) criteria for item # 2 - Facility operating limits in Tech Specs and their bases.

ANSWER I DISTRACTOR ANALYSIS A. Incorrect. Locked rotor would result in a breaker trip. Pump amps not available on Page 180 of 208

HL-16 NRC Written Examination KEY the QEAB. Plausible the candidate may think amps available on QEAB or an LCO entry is required.

B. Incorrect. Locked rotor would result in a breaker trip. Pump amps not available on the QEAB. Plausible the candidate may think amps available on QEAB and know an INFO LCO entry is required.

C. Incorrect. Plausible the candidate may know pump amps monitored at swgr and think an LCO entry is required.

D. Correct.

REFERENCES Tech Spec 3.7.7 for CCW and the Bases.

AOP 18031-C, Loss of Class 1 E Electrical Systems section B for Loss of Power With DG Tying to Bus.

VEGP learning objectives:

LO-LP-3921 1-02, Given a set of Tech Specs and the bases, determine for a specific set of plant conditions, equipment availability, and operational mode.

a. Whether any Tech Spec LCOs of section 3.7 are exceeded.

LO-LO-3921 1-04, Describe the bases for any given Tech Spec in section 3.7 Page 181 of 208

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18031-C 27.1 e APproved t

çDa Page Number LOSS OF CLASS 1 E ELECTRICAL SYSTEMS B. LOSS OF POWER WITH DG TYING TO BUS ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

_B1. Dispatch an operator to the Diesel Generator to perform 131 45A1B section for Diesel Generator Operation Under Emergency Conditions.

B2. Perform the following for the affected bus:

_a. Verify bus frequency AT 60 HZ.

_b. Verify bus voltage AT 41 60V AC.

_B3. Check charging pumps ONLY ONE

- _B3. Perform the following:

OPERATING.

a. Start or stop pumps as necessary to establish one running charging pump.

b. charging pump can NOT be started, THEN perform the following:

_1) Isolate normal letdown.

2) Initiate 18007-C, CHEMICAL AND VOLUME CONTROL SYSTEM MALFUNCTION.

_B4 Check CCW pumps on affected train - B4 Perform the foflowing TWO RUNNING.

a. Start or stop PUmPS as necessaiy to establish twq pumps running rn the affected traift, 4 continued on next page Printed January 16, 2011 at 13:26

Procedure Number 1ev Approved By J. B. Staney Vogtle Electric Generating Plant 18031-C 27.1 Page Number LOSS OF CLASS 1 E ELECTRICAL SYSTEMS Date Approved 15 of 33

)/2/lO B. LOSS OF POWER WITH DG TYING TO BUS ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED Ji1&FNOT be

..-C, LOSS J COOLING B5. Check RHR status:

_a. Check RHR REQUIRED FOR -

a. GotoStepB6.

SHUTDOWN COOLING.

_b. Start RHR pumps aligned for _b. Initiate 18019-C, LOSS OF shutdown cooling as needed. RESIDUAL HEAT REMOVAL.

B6. Initiate the Continuous Actions Page.

• B7. Check AFW status:

_a. Check AFW system NEEDED -

a. Perform the following:

TO MAINTAIN SG LEVELS.

_1) Shutdown running AFW pumps and align for standby readiness by initiating 13610, AUXILIARY FEEDWATER SYSTEM.

_2) GotoStepB8.

_b. Verify MDAFW pumps -

RUNNING.

_c. Check TDAFW pump -

_c. Start TDAFW pump.

RUNNING IF NECESSARY.

_d. Check TDAFW pump NEEDED - _d. Reduce TDAFW pump speed to TO MAINTAIN SG LEVELS. not less than 1535 rpm.

Step 7 continued on next page 0

Printed January 16, 2011 at 13:27

CCW System 3.7.7 3.7 PLANT SYSTEMS 3.7.7 Component Cooling Water (CCW) System LCO 3.7.7 Two CCW trains shall be OPERABLE.

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

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One CCW train A.1 -NOTE inoperable. Enter applicable Conditions and Required Actions of LCO 3.4.6, RCS Loops MODE 4, for residual heat removal loops made inoperable by CCW.

Restore CCW train to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> OPERABLE status.

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

B.2 Be in MODE 5. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> Vogtle Units 1 and 2 3.7.7-1 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

CCW System 3.7.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.7.1 NOTE Isolation of CCW flow to individual components does not render the CCW System inoperable.

Verify each CCW manual, power operated, and 31 days automatic valve in the flow path servicing safety related equipment, that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.7.7.2 Verify each CCW pump starts automatically on an 18 months actual or simulated actuation signal.

Vogtle Units I and 2 3.7.7-2 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

CCW System B 3.7.7 B 3.7 PLANT SYSTEMS B 3.7.7 Component Cooling Water (CCW) System BASES BACKGROUND The CCW 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, the CCW System also provides this function for the spent fuel storage pool. The CCW System serves as a barrier to the release of radioactive byproducts between potentially radioactive systems and the Nuclear Service Cooling Water System, and thus to the environment.

The CCW System is arranged as two independent, full capacity cooling loops. Each safety related train includes (three) 50%

capacity pumps, surge tank, heat exchanger, piping, valves, and instrumentation. Each safety related train is powered from a separate bus. An open surge tank in the system provides pump trip protective functions to ensure that sufficient net positive suction head is available. The pumps in each train are automatically started on receipt of a safety injection signal. Only two out of the three available pumps are required OPERABLE.

The third pump serves as a standby to allow maintenance.

Additional information on the design and operation of the system, along with a list of the components served, is presented in the FSAR, Subsection 9.2.2 (Ref. 1). The principal safety related function of the CCW System is the removal of decay heat from the reactor via the Residual Heat Removal (RHR) System. This may be during a normal or post accident cooldown and shutdown.

APPLICABLE The CCW System design satisfies the cold shutdown SAFETY ANALYSES requirements of Regulatory Guide 1.139 (Ref. 2) and Branch Technical Position 5.1 (Ref. 3). The CCW System is designed to meet the cold shutdown requirements within the specified time (36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />) using a single CCW train. During accident conditions, the calculated CCW system heat load (Btu/hr) is less than the peak heat load experienced during a single train cooldown to cold shutdown conditions (Ref. 1).

(continued)

Vogtle Units 1 and 2 B 3.7.7-1 Revision No. 0

CCW System B 3.77 BASES APPLICABLE Therefore, the CCW system has the heat removal capacity to SAFETY ANALYSES perform its design function under normal as well as accident (continued) conditions. The maximum CCW heat exchanger outlet temperature is designed to be less than 120°F during normal cooldown and accident conditions, based upon a Nuclear Service Cooling Water temperature of 100°F (Ref. 4). Normal CCW operating temperature is 100°F at the outlet of the heat exchanger with 105°F at the inlet (Ref. 1). The Emergency Core Cooling System (ECCS) loss of coolant accident (LOCA) analysis and containment OPERABILITY LOCA analysis each model the maximum and minimum performance of the CCW System, respectively. The operation of the CCW System prevents the containment sump fluid from increasing in temperature during the recirculation phase following a LOCA, and provides a gradual reduction in the temperature of this fluid as it is supplied to the Reactor Coolant System (RCS) by the ECCS pumps.

The CCW System is designed to perform its function with a single failure of any active component, assuming a loss of offsite power.

The CCW System also functions to cool the unit from RHR entry conditions (TCOId < 350° F), to MODE 5 (TCOd < 200° F), during normal and post accident operations. The time required to cool from 350° F to 200° F is a function of the number of CCW and RHR trains operating. One CCW train is sufficient to remove decay heat during subsequent operations with TC d <200°F.

0 The CCW System satisfies Criterion 3 of 10 CFR 50.36 (c)(2)(ii).

LCO The CCW trains are independent of each other to the degree that each has separate controls and power supplies and the operation of one does not depend on the other. In the event of a DBA, one CCW train is required to provide the minimum heat removal capability assumed in the safety analysis for the systems to which it supplies cooling water. To ensure this requirement is met, two trains of CCW must be OPERABLE. At least one CCW train will operate assuming the worst case single active failure occurs coincident with a loss of offsite power.

(continued)

Vogtle Units 1 and 2 B 3.7.7-2 Rev. 1-10/01

CCW System B 3.7.7 BASES LCO A CCW train is considered OPERABLE when:

(continued)

a. Two pumps and associated surge tank are OPERABLE; and

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

The isolation of CCW from other components or systems not required for safety may render those components or systems inoperable but does not necessarily make the CCW System inoperable. Consideration should be given to the size of the load isolated and the impact it will have on the rest of the CCW system before determining OPERABILITY.

APPLICABILITY In MODES 1, 2, 3, and 4, the CCW System is a normally operating system, which must be prepared to perform its post accident safety functions, primarily RCS heat removal, which is achieved by cooling the RHR heat exchanger.

In Modes 5 or 6, there are no TS OPERABILITY requirements for the CCW System. However, the functional requirements of the CCW System are determined by the systems it supports.

ACTIONS Required Action A.1 is modified by a Note indicating that the applicable Conditions and Required Actions of LCO 3.4.6, RCS Loops MODE 4, be entered if an inoperable CCW train results in an inoperable RHR loop. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components.

If one CCW train is inoperable, action must be taken to restore OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. In this Condition, the remaining OPERABLE CCW train is adequate to perform the heat removal function. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time is reasonable, based on the redundant capabilities afforded by the OPERABLE train, and the low probability of a DBA occurring during this period.

(continued)

Vogtle Units 1 and 2 B 3.7.7-3 Rev. 1-8/05

CCW System B 3.7.7 BASES ACTIONS B.1 and B.2 (continued)

If the CCW train 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 <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in MODE 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. 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.

SURVEILLANCE SR 3.7.7.1 REQUIREMENTS This SR is modified by a Note indicating that the isolation of the CCW flow to individual components may render those components inoperable but does not affect the OPERABILITY of the CCW System.

Verifying the correct alignment for manual, power operated, and automatic valves in the CCW flow path provides assurance that the proper flow paths exist for CCW operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves are verified to be in the correct position prior to locking, sealing, or securing. This SR also does not apply to valves that cannot be inadvertently misaligned, such as check valves. This Surveillance does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position.

The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions.

SR 3.7.7.2 This SR verifies proper automatic operation of the CCW pumps on an actual or simulated actuation signal. The CCW System is a normally operating system that cannot be fully actuated as part of routine testing during normal operation. The (continued)

Vogtle Units 1 and 2 B 3.7.7-4 Revision No. 0

CCW System B 3.7.7 BASES SURVEILLANCE SR 3.7.7.2 (continued)

REQUIREMENTS 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, the Frequency is acceptable from a reliability standpoint.

REFERENCES 1. FSAR, Subsection 9.2.2.

2. Regulatory Guide 1.139, Guidance for Residual Heat Removal, May 1978.

3. Branch Technical Position RSB 5-1, Design Requirements of the Residual Heat Removal System, Rev. 2, July 1981.

4. FSAR, Subsection 5.4.7.

Vogtle Units 1 and 2 B 3.7.7-5 Revision No. 0

HL-16 NRC Written Examination KEY

88. 062G2.1.20 001/I/I/LOSS OF NSCW/4.6 C/AINEW/SRO/HL.-16 NRC/GCW Given the following conditions at full power.

- NSCW pump # 4 is danger tagged.

An LOSP occurs with both 4160 1 E buses load shedding, then being re-energized from their respective DGs.

NSCW Train A Status NSCW Train B Status Catastrophic leakage occurs Only 1 pump is running and and all pumps are now in PTL the other pump wont start In accordance with 18021-C, Loss of Nuclear Service Cooling Water System:

1) which is the appropriate action to take, and

2) the appropriate Tech Spec actions?

A. 1) Remain in 18021-C, place NSCW train B in single pump operations.

2) Perform the actions of LCD 3.7.8, NSCW and 3.8.1, AC Sources Operating.-

B. 1) Remain in 18021-C, place NSCW train B in single pump operations.

2) within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> initiate actions to place the unit in a mode or specified condition where LCD 3.7.8, NSCW is not applicable.

C. 1) Trip the reactor and initiate 19000-C, E-0 Reactor Trip or Safety Injection.

2) Perform the actions of LCD 3.7.8, NSCW and 3.8.1, AC Sources Operating.-

D 1) Trip the reactor and initiate 19000-C, E-0 Reactor Trip or Safety Injection.

2) Within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> initiate actions to place the unit in a mode or specified condition where LCD 3.7.8, NSCW is not applicable.

Feedback 062 Loss of Nuclear Service Water 2.1 Conduct of Operations 2.1.20 Ability to interpret and execute procedure steps.

(CFR: 41.10/43.5/45.12)

Page 182 of 208

HL-16 NRC Written Examination KEY K/A MATCH ANALYSIS The question gives a scenario where both trains of NSCW have been lost. The candidate must determine the correct procedural actions to take and the correct Tech Spec actions to apply.

SRO 10CFR55.43 (b5)

ANSWER I DISTRACTOR ANALYSIS A. Incorrect. When at least one train of NSCW cant be placed in single pump operations, 18021-C requires a reactor trip. Therefore, remain in 18021-C is wrong.

The Tech Spec actions are correct for one train of NSCW inoperable, but not both.

B. Incorrect. When at least one train of NSCW cant be placed in single pump operations, 18021-C requires a reactor trip. Therefore, remain in 18021-C is wrong.

This is the correct Tech Spec actions for both NSCW trains inoperable (3.0.3)

C. Incorrect. Trip the reactor and initiate E-0 is the correct procedure action. However, the Tech Spec actions are correct for one train of NSCW inoperable, but not both.

D. Correct. A reactor trip is required with initiation of E-O. This is the correct Tech Spec actions for both NSCW trains inoperable (3.0.3).

REFERENCES 18021-C, Loss of Nuclear Service Cooling Water System Tech Spec 3.7.8, Nuclear Service Cooling Water System Tech Spec 3.8.1, AC Sources Operating.

LCO 3.0.3, Motherhood VEGP learning objectives:

LO-PP-60328-07, Given the entire AOP, describe:

a. The purpose of selected steps.

b. How and why the step is being performed.

c. Expected response of the plantlparameter(s) for the step.

LO-LP-3921 1-02, Given a set of Tech Specs and the bases, determine for a specific set of conditions, equipment availability, and operational mode:

a. Whether any Tech Spec LCOs of section 3.7 are exceeded.

Page 183 of 208

HL-16 NRC Written Examination KEY

b. The required actions for all section 3.7 LCOs.

LO-LP-3921 1-01, For any given item in section 3.7 of Tech Specs, be able to:

a. State the LCQ

b. State any one hour or less required actions.

LQ-LP-39204-02, State the required action when an LCO is not met, except as in the associated action requirements.

Page 184 of 208

Approved 8y Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18021 -C 17 Date Approved Paqe Number LOSS OF NUCLEAR SERVICE COOLING WATER

/24/09 1 of 13 SYSTEM ABNORMAL OPERATING PROCEDURE CONTINUOUS USE PURPOSE This procedure addresses the loss or degraded operation of one or more trains of Nuclear Service Cooling Water.

SYMPTOMS

• Trip of operating NSCW pumps and failure of standby pump to start.

• Dropping NSCW Supply Header pressure.

• Large difference between Supply Header flow and Return Header flow, indicating a large leak.

• NSCW Tower Basin temperature rising above 90°F.

• High temperature or low flow alarms on any components or systems cooled by NSCW.

MAJOR ACTIONS

• Determine condition causing loss or degraded operation of NSCW.

• Transfer loads to unaffected train.

• Correct or repair condition causing loss or degraded operation of NSCW.

Printed January 16, 2011 at 17:04

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18021-C 17 Date Approved LOSS OF NUCLEAR SERVICE COOLING WATER Page Number 713/24/09 SYSTEM 2 of 13 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

_1. Check if catastrophic leakage from _1. Go to Step 6.

NSCW system EXISTS. -

_2. Place affected train NSCW pump handswitches in PULL-TO-LOCK.

_3. Depress both Emergency Stop pushbuttons for the affected DG.

4. Verify proper operation of 4. if neither NSCW train can be placed UNAFFECTED NSCW train: in normal, two pump operation, THEN perform the following:

• Two pumps running.

_a. Trip the reactor.

• Supp header pressure greater p g. _b. Initiate 19000-C, E-0 REACTOR TRIP OR SAFETY INJECTION.

Train A: P1-1636 Train B: P1-1637 _c. Trip all reactor coolant pumps.

• Supply header temperature computer indication less than _d. Isolate letdown.

90°F:

Train A: T2601 _e. Place one train of NSCW in Train B: T2602 single pump operation by initiating 13150, NUCLEAR

. Supply header flow SERVICE COOLING WATER approximately 17,000 gpm: SYSTEM.

Train A: Fl-1640B _f. Verify train-related CCP or NCP Train B: Fl-i 641B running and seal injection flow established using 13006, CHEMICAL AND VOLUME CONTROL SYSTEM.

Step 4 continued on next page Printed January 16, 2011 at 17:04

NSCW 3.7.8 3.7 PLANT SYSTEMS 3.7.8 Nuclear Service Cooling Water (NSCW) System LCO 3.7.8 Two NSCW trains shall be OPERABLE.

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

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One NSCW train --------------------NOTES inoperable. 1. Enter applicable Conditions and Required Actions of LCO 3.8.1, AC Sources Operating, for emergency diesel generator made inoperable by NSCW system.

2. Enter applicable Conditions and Required Actions of LCO 3.4.6, RCS Loops MODE 4, for residual heat removal loops made inoperable by NSCW system.

A.1 Restore NSCW system to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> OPERABLE status.

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

B.2 Be in MODE 5. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> Vogtle Units 1 and 2 3.7.8-1 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

N SCW B 3.7.8 BASES APPLICABLE The NSCW System, in conjunction with the CCW System, also SAFETY ANALYSES cools the unit from residual heat removal (RHR), as (continued) discussed in the FSAR, Subsection 5.4.7, (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 CCW and RHR System trains that are operating.

One NSCW System train is sufficient to remove decay heat during subsequent operations in MODES 5 and 6. This assumes a maximum NSCW System temperature of 95°F occurring simultaneously with maximum heat loads on the system.

The NSCW System satisfies Criterion 3 of 10 CFR 50.36 (c)(2)(ii).

LCO Two NSCW System trains are required to be OPERABLE to provide the required redundancy to ensure that the system functions to remove post accident heat loads, assuming that the worst case single active failure occurs coincident with the loss of offsite power.

An NSCW System train is considered OPERABLE during MODES 1, 2, 3, and 4 when:

a. Two pumps are OPERABLE; and

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

APPLICABILITY In MODES 1, 2, 3, and 4, the NSCW System is a normally operating system that is required to support the OPERABILITY of the equipment serviced by the NSCW System and required to be OPERABLE in these MODES.

In MODES 5 or 6, there are no TS OPERABILITY requirements for the NSCW System. However, the functional requirements of the NSCW System are determined by the systems it supports.

(continued)

Vogtle Units I and 2 B 3.7.8-2 Rev. 2-8/05

N SCW B 3.7.8 BASES (continued)

ACTIONS If one NSCW System train is inoperable, action must be taken to restore the train to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. In this Condition, the remaining OPERABLE NSCW System train is adequate to perform the heat removal function. However, the overall reliability is reduced because a single failure in the OPERABLE NSCW System train could result in loss of NSCW System function. Required Action A.1 is modified by two Notes. The first Note indicates that the applicable Conditions and Required Actions of LCO 3.8.1, AC SourcesOperating, should be entered if an inoperable NSCW System train results in an inoperable emergency diesel generator. The second Note indicates that the applicable Conditions and Required Actions of LCO 3.4.6, RCS LoopsMODE 4, should be entered if an inoperable NSCW System train results in an inoperable decay heat removal train. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time is based on the redundant capabilities afforded by the OPERABLE train, and the low probability of a DBA occurring during this time period.

B.1 and B.2 If the NSCW System train 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 <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in MODE 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

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.

SURVEILLANCE SR 3.7.8.1 REQUIREMENTS This SR is modified by a Note indicating that the isolation of the NSCW System components or systems may render those components inoperable, but does not necessarily affect the OPERABILITY of the NSCW System.

(continued)

Vogtle Units 1 and 2 B 3.7.8-3 Revision No. 0

LCO Applicability 3.0 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY LCO 3.0.1 LCOs shall be met during the MODES or other specified conditions in the Applicability, except as provided in LCO 3.0.2 and LCO 3.0.8.

LCO 3.0.2 Upon discovery of a failure to meet an LCO, the Required Actions of the associated Conditions shall be met, except as provided in LCO 3.0.5 and LCO 3.0.6.

If the LCO is met or is no longer applicable prior to expiration of the specified Completion Time(s), completion of the Required Action(s) is not required unless otherwise stated.

LCO 3.0.3 When an LCO is not met and the associated ACTIONS are not met, an associated ACTION is not provided, or if directed by the associated ACTIONS, the unit shall be placed in a MODE or other specified condition in which the LCO is not applicable. Action shall be initiated within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to place the unit, as applicable, in:

a. MODE 3 within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />;

b. MODE 4 within 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />; and

c. MODE 5 within 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br />.

Exceptions to this Specification are stated in the individual Specifications.

Where corrective measures are completed that permit operation in accordance with the LCO or ACTIONS, completion of the actions required by LCO 3.0.3 is not required.

LCO 3.0.3 is only applicable in MODES 1, 2, 3, and 4.

LCO 3.0.4 When an LCO is not met, entry into a MODE or other specified condition in the Applicability shall only be made:

a. When the associated ACTIONS to be entered permit continued operation in the MODE or other specified condition in the Applicability for an unlimited period of time; or (continued)

Vogtle Units I and 2 3.0-1 Amendment No. 141 (Unit 1)

Amendment No. 121 (Unit 2)

AC Sources Operating 3.8.1 3.8 ELECTRICAL POWER SYSTEMS 3.8.1 AC Sources Operating LCO 3.8.1 The following AC electrical sources shall be OPERABLE:

a. Two qualified circuits between the offsite transmission network and the onsite Class 1 E AC Electrical Power Distribution System; and

b. Two diesel generators (DGs) capable of supplying the onsite Class I E power distribution subsystem(s).

Automatic load sequencers for Train A and Train B ESF buses shall be OPERABLE.

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

ACTIONS LCO 3.O.4b is not applicable to DGs.

CONDITION REQUIRED ACTION COMPLETION TIME A. One required offsite A.1 Perform SR 3.8.1.1 for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> circuit inoperable, required OPERABLE offsite circuit. AND Once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter AND (continued)

Vogtle Units 1 and 2 3.8.1-1 Amendment No. 137 (Unit 1)

Amendment No. 116 (Unit 2)

AC Sources Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2 Declare required feature(s) 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from with no offsite power discovery of no offsite available inoperable when power to one train its redundant required concurrent with feature(s) is inoperable. inoperability of redundant required feature(s)

AND A.3 Restore required offsite 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> circuit to OPERABLE status. AND 14 days from discovery of failure to meet LCO (continued)

Vogtle Units I and 2 3.8.1-2 Amendment No.100 (Unit 1)

Amendment No. 78 Unit 2)

AC Sources Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. One DG inoperable. B.1 Perform SR 3.8.1.1 for the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> required offsite circuit(s).

AND Once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter AND B.2 Verify SAT available. 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> AND Once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter AND B.3 Declare required feature(s) 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> from supported by the discovery of inoperable DG inoperable Condition B when its required concurrent with redundant feature(s) is inoperability of inoperable, redundant required feature(s)

AND B.4.1 Determine OPERABLE DG 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is not inoperable due to common cause failure.

OR B.4.2 Perform SR 3.8.1.2 for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> OPERABLE 0G.

AND (continued)

Vogtle Units I and 2 3.8.1-3 Amendment No.100 (Unit 1)

Amendment No. 78 Unit 2)

AC Sources Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) --------------NOTE---------------

Required Action B.5.1 is only applicable if the combined reliability of the enhanced black-start combustion turbine generators (CTG) and the black-start diesel generator is 95%. Otherwise, Required Action B.5.2 applies.

B.5.1 Verify an enhanced black- 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> start CTG is functional by verifying the CTG and the Q black-start diesel generator starts and Within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> achieves steady state prior to entry into voltage and frequency. Condition B OR B.5.2 Start and run at least one 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> CTG while in Condition B.

OR Prior to entry into Condition B for preplanned maintenance AND (continued)

Vogtle Units 1 and 2 3.8.1-4 Amendment No.100 (Unit 1)

Amendment No. 78 Unit 2)

AC Sources Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.6 Restore DG to OPERABLE 14 days from status. discovery of failure to meet LCO C. Required Actions B.2, C.1 Restore DG to OPERABLE 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> B.5.1, or B.5.2 and status.

associated Completion Times not met.

D. Two required offsite D.1 Declare required feature(s) 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from circuits inoperable, inoperable when its discovery of redundant feature(s) is Condition D inoperable, concurrent with inoperability of redundant required features D.2 Restore one required 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> offsite circuit to OPERABLE status E. One required offsite ------------------NOTE------------

circuit inoperable. Enter applicable Conditions and Required Actions of LCO 3.8.9, AND Distribution Systems Operating, when Condition E is entered with no One DG inoperable. AC power source to one or more trains.

(continued)

Vogtle Units I and 2 3.8.1-5 Amendment No.100 (Unit 1)

Amendment No. 78 Unit 2)

AC Sources Operating 3.8.1 ACTIONS (continued CONDITION REQUIRED ACTION COMPLETION TIME E. (continued) E.1 Restore required offsite 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> circuit to OPERABLE status.

OR E.2 Restore DG to OPERABLE 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> status.

F. Two DGs inoperable. F.1 Restore one DG to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> OPERABLE status.

G. One automatic load G.1 Restore automatic load 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> sequencer inoperable, sequencer to OPERABLE status.

H. Required Action and H.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition A, C, AND D, E, F, orG not met.

H.2 Be in MODE 5. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> OR Required Action B.I, B.3, B.4.1, B.4.2, or B.6 and associated Completion Time not met.

Three or more required LI Enter LCO 3.0.3. Immediately AC sources inoperable.

Vogtle Units I and 2 3.8.1-6 Amendment No.100 (Unit 1)

Amendment No. 78 Unit 2)

HL-16 NRC Written Examination KEY

89. 064A2. 14 002/2/1/EDG-STOP UNDER LOAD/2.9 C/A/NEW/SRO/NRC/GCW Unit 2 is at 100% power with all systems in normal alignment.

- RAT 2A trips.

- DG2A starts and ties to 2AA02 and load sequencing is complete.

- Only NSCW pump 1 is running and attempts to start either pump 3 or 5 is NOT successful.

- The UO depresses both EMERGENCY STOP pushbuttons for DG2A.

- The crew has performed AOP-1 8031-2, Loss of Class 1 E Electrical Systems, taken appropriate actions, and have reached the steps for addressing Technical Specifications.

When DG2A trips, during the load shed, the transformers to the 480V 1 E switchgear (1) breakers trip open.

The FIRST LCD to require the plant to be placed in Mode 3 would be _(2)_.

A. (1) high side (2) 3.8.1, AC Sources Operating B. (1)lowside (2) 3.8.1, AC Sources Operating C. (1) high side (2) 3.7.5, Auxiliary Feedwater (AFW) System D (1) low side (2) 3.7.5, Auxiliary Feedwater (AFW) System Feedback 064 Emergency Diesel Generator (EDIG) System Ability to (a) predict the impacts of the following malfunctions or operations on the EDIG system; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those malfunctions or operations:

(C FR: 41.5/43.5/45.3/45.13)

A2.1 4 Effects (verification) of stopping EDIG under load on isolated bus Page 185 of 208

HL-16 NRC Written Examination KEY K/A MATCH ANALYSIS The question present a plausible scenario where an offsite source to a class 1 E 4160 bus is lost resulting in a DG start. The DG is required to be manually tripped due to inadequate cooling water. The candidate must determine the effect on supply breakers to the 1 E 480V Switchgear and the Tech Spec LCO with a time period of greater than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> which requires a unit shutdown.

SRO 1 OCFR55.43 (b2)

ANSWER I DISTRACTOR ANALYSIS A. Incorrect. There is a 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> shutdown on LCO 3.7.5, AFW. Also, the tow side breakers open on the UV load shed.

B. Incorrect. There is a 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> shutdown on LCO 3.7.5, AFW. The low side breakers opening part is correct.

C. Incorrect. The 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> shutdown for LCO 3.7.5, AFW part is correct. The low side breakers open on the UV load shed.

D. Correct. LCO 3.7.5 is most restrictive and the low side breakers open.

REFERENCES Technical Specification 3.8.1, AC Sources Operating.

Technical Specification 3.7.5, Auxiliary Feedwater System (AFW)

AOP-1 8031-C, Loss of Class 1 E Electrical Systems.

VEGP learning objectives:

LO-LP-39212-02, Given a set of Tech Specs and the bases, determine for a specific set of plant conditions, equipment availability, and operational mode:

a. Whether any Tech Spec LCOs of section 3.8 are exceeded.

b. The required actions for all section 3.8 LCOs.

LO-LP-3921 1-02 Given a set of Tech Specs and the bases, determine for a specific set of plant conditions, eqiupment availability, and operational mode:

a. Whether any Tech Spec LCOs of section 3.7 are exceeded.

b. The required actions for all section 3.7 LCOs.

Page 186 of 208

AC Sources Operating 3.8.1 3.8 ELECTRICAL POWER SYSTEMS 3.8.1 AC Sources Operating LCO 3.8.1 The following AC electrical sources shall be OPERABLE:

a. Two qualified circuits between the offsite transmission networ k

and the onsite Class 1 E AC Electrical Power Distribution System; and

b. Two diesel generators (DGs) capable of supplying the onsite Class 1 E power distribution subsystem(s).

Automatic load sequencers for Train A and Train B ESF buses shall be OPERABLE.

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

ACTIONS

--NOTE LCO 3.O.4b is not applicable to DGs.

CONDITION REQUIRED ACTION COMPLETION TIME A. One required offsite A.1 Perform SR 3.8.1.1 for circuit inoperable, 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> required OPERABLE offsite circuit. AND Once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter AND (continued)

Vogtle Units 1 and 2 3.8.1-1 Amendment No. 137 (Unit 1)

Amendment No. 116 (Unit 2)

AC Sources Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2 Declare required feature(s) 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from with no offsite power discovery of no offsite available inoperable when power to one train its redundant required concurrent with feature(s) is inoperable. inoperability of redundant required feature(s)

AND A.3 Restore required offsite 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> circuit to OPERABLE status.

14 days from discovery of failure to meet LCO (continued)

Vogtle Units 1 and 2 3.8.1-2 Amendment No. 100 (Unit 1)

Amendment No. 78 Unit 2)

AC Sources Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. One DG inoperable. B.1 Perform SR 3.8.1.1 for the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> required offsite circuit(s).

AND Once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter AND B.2 Verify SAT available. 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> AND Once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter AND B.3 Declare required feature(s) 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> from supported by the discovery of inoperable DG inoperable Condition B when its required concurrent with redundant feature(s) is inoperability of inoperable. redundant required feature(s)

AND B.4.1 Determine OPERABLE DG 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is not inoperable due to common cause failure.

OR B.4.2 Perform SR 3.8.1.2 for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> OPERABLE DG.

AND (continued)

Vogtle Units I and 2 3.8.1-3 Amendment No.100 (Unit 1)

Amendment No. 78 Unit 2)

AC Sources Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) ----------

NOTE Required Action B.5.1 is only applicable if the combined reliability of the enhanced black-start combustion turbine generators (CTG) and the black-start diesel generator is 95%. Otherwise, Required Action B.5.2 applies.

B.5.1 Verify an enhanced black- 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> start CTG is functional by verifying the CTG and the QB black-start diesel generator starts and Within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> achieves steady state prior to entry into voltage and frequency. Condition B OR B.5.2 Start and run at least one 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> CTG while in Condition B.

OR Prior to entry into Condition B for preplanned maintenance AND (continued)

Vogtle Units 1 and 2 3.8.1-4 Amendment No. 100 (Unit 1)

Amendment No. 78 Unit 2)

AC Sources Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.6 Restore DG to OPERABLE 14 days from status. discovery of failure to meet LCO C. Required Actions B.2, C.1 Restore DG to OPERABLE 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> B.5.1, or 8.5.2 and status.

associated Completion Times not met.

D. Two required offsite D.1 Declare required feature(s) 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from circuits inoperable, inoperable when its discovery of redundant feature(s) is Condition D inoperable, concurrent with inoperability of redundant required AND features D.2 Restore one required 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> offsite circuit to OPERABLE status E. One required offsite --------

NOTE circuit inoperable. Enter applicable Conditions and Required Actions of LCO 3.8.9, AND Distribution Systems Operating, when Condition E is entered with no One DG inoperable. AC power source to one or more trains.

(continued)

Vogtle Units I and 2 3.8.1-5 Amendment No.100 (Unit 1)

Amendment No. 78 Unit 2)

AFW System 3.7.5 3.7 PLANT SYSTEMS 3.7.5 Auxiliary Feedwater (AFW) System LCO 3.7.5 Three AFW trains shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS

-NOTE---

LCO 3.0.4b is not applicable.

CONDITION REQUIRED ACTION COMPLETION TIME A. One steam supply to A.1 Restore steam supply to 7 days turbine driven AFW OPERABLE status.

pump inoperable. AND 10 days from discovery of failure to meet the LCO B. One AFW train B.1 Restore AFW train to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> inoperable for reasons OPERABLE status.

other than Condition A. AND 10 days from discovery of failure to meet the LCO (continued)

Vogtle Units 1 and 2 3.7.5-1 Amendment No. 142 (Unit 1)

Amendment No. 122 (Unit 2)

AFW System 3.7.5 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and C.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time for Condition A AND or B not met.

C.2 Be in MODE 4. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> OR Two AFW trains inoperable.

D. Three AFW trains D.1 NOTE inoperable. LCO 3.0.3 and all other LCO Required Actions requiring MODE changes are suspended until one AFW train is restored to OPERABLE status.

Initiate action to restore Immediately one AFW train to OPERABLE status.

Vogtle Units 1 and 2 3.7.5-2 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18031-C 27.1 Da Approved Page Number LOSS OF CLASS 1 E ELECTRICAL SYSTEMS ABNORMAL OPERATING PROCEDURE CONTINUOUS USE PURPOSE This procedure addresses the loss of 41 60V and 480V AC Class 1 E Electrical System, with the affected train either being reenergized by the Diesel Generator or remaining de-energized due to the Diesel Generator failing to tie to the 4160V AC bus.

SYMPTOMS

• Loss of offsite power to the 1 E Electrical System (1 AAO2, 1 8A03, 2AA02, 2BA03) concurrent with diesel failure to tie on affected train.

• Electric fault on AAO2 OR BAO3.

• Loss of 480V Class 1 E power.

• Loss of offsite power to the 1 E Electrical System (1 AAO2, 1 8A03, 2AA02, 2BA03) concurrent with diesel tying on affected train.

MAJOR ACTIONS

• Respond to loss of 41 60V and 480V AC Class 1 E Electrical System with the DG failing to tie to the 4160V AC bus.

• Respond to loss of 41 60V and 480V AC Class 1 E Electrical System with the DG tying to the 41 60V AC bus.

Printed January 17, 2011 at 10:14

Approved By . Procedure Number Rev J. B. Staney Vogtle Electric Generating Plant 18031-C 27.1 Page Number LOSS OF CLASS 1 E ELECTRICAL SYSTEMS CONTINUOUS ACTIONS Step Actions INITIAL ACTIONS 1 Check power to 1 E 41 60V Emergency busses AT LEAST ONE ENERGIZED.

2 Maintain Reactor power LESS THAN 100%.

SECTION A. LOSS OF POWER WITH DG FAILING TO TIE TO BUS A6 Control AFW to maintain SG NR levels 60% TO 70%.

A17 Monitor all 1E battery bus voltages REMAIN GREATER THAN 105V DC.

Al 9 Monitor 1 E battery voltage to open battery breaker for any battery whose terminal voltage drops to 1 05V DC or less.

SECTION B. LOSS OF POWER WITH DG TYING TO BUS B7 Control AFW to maintain SG NR levels 60% TO 70%.

Printed January 17, 2011 at 10:14

1Aoved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18031-C 27.1 Page Number ePPProved t

c)a LOSS OF CLASS 1E ELECTRICAL SYSTEMS ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

• 1. Check power to 1 E 4160V 1. Perform one of the following as Emergency busses AT LEAST applicable:

ONE ENERGIZED:

IF in Modes 1, 2, or 3, trip the

. 41 60V AC 1 E Busses actor and Go to 19000-C, E-0 REACTOR TRIP OR SAFETY INJECTION.

IF in Mode 4, Go to 19100-C, ECA-0.0 LOSS OF ALL AC POWER.

IF in Modes 5 or 6, Go to Section C.

• 2. Check Reactor power LESS THAN

• 2. Perform the following:

100%:

a. Reduce TDAFW pump speed to

. UQ1 118 LESS THAN not less than 1535 rpm.

EQUAL TO 100% MWT for the applicable unit.

b. Throttle affected MDAFW pump

. NIS LESS THAN Q EQUAL discharge valves.

TO 100%.

IF Reactor power is still greater

. AT LESS THAN Qfl EQUAL TO than 100%,

100%. THEN reduce turbine load at approximately 10 megawatt increments to maintain Reactor power less than 100%.

3. Check affected train Diesel Generator 3. Go to Section A. LOSS OF POWER

- RUNNING. WITH DG FAILING TO TIE TO BUS.

Printed January 17, 2011 at 10:14

1 Approved By J.StanIey Vogtle Electric Generating Plant IProcedure Number Rev 1

1 8031-C 27.1 Date Approved

/2bo i LOSSOFCLASS1EELECTRICALSYSTEMS Page Number 4f33 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

4. Check NSCW status on affected 4. Perform the following:

train:

a. Pumps TWO RUNNING.

1) Trip affeted DG by depressing both EMERGENCY STOP

_b. Discharge valves OPEN.

- pushbuttons

_c. Supply and return flows -

_2) Go to Section A. LOSS OF NORMAL. POWER WITH DG FAILING TO TIE TO BUS.

_5. Go to Section B. LOSS OF POWER WITH DG TYING TO BUS.

Printed January 17, 2011 at 10:14

HL-16 NRC Written Examination KEY

90. 068AA2.04 003/1/2/CR EVACUATION/4.0 MEM!NEW/SRO/NRC/GCW The Main Control Board indicators for various Steam Generator (SG) pressure channels display a RED Bezel on the bottom of the indicator. SG pressures are also displayed on the Remote Shutdown Panels A and B.

Which of the following is correct concerning both (1) the Control Room indicators and (2) the Remote Shutdown Panel indicators for SG Pressure?

A& (1) The Control Room indicator is Post Accident Monitoring qualified and will provide sufficient information available to monitor following an accident.

(2) The B Remote Shutdown Panel indicator will ensure enough information is available to place and maintain the unit in a safe shutdown condition.

B. (1) The Control Room indicator is Post Accident Monitoring and Fire Event qualifed and will provide sufficient information available to monitor following an accident.

(2) The B Remote Shutdown Panel indicator is Fire Event qualifed and will provide electrical isolation protection which prevents it from having spurious actuations.

C. (1) The Control Room indicator is Post Accident Monitoring qualified and will provide sufficient information available to monitor following an accident.

(2) The A Remote Shutdown Panel indicator is Fire Event qualifed and will provide electrical isolation protection which prevents it from having spurious actuations.

D. (1) The Control Room indicator is Fire Event qualified and will will provide electrical isolation protection which prevents it from having spurious actuations.

(2) Both A and B Remote Shutdown Panel indicators are Post Accident Monitoring and will provide sufficient information available to monitor following an accident.

Feedback 068 Control Room Evacuation Ability to determine and interpret the following as they apply to the Control Room Evacuation:

(CFR: 43.5/45.13)

AA2.04 S/G pressure K/A MATCH ANALYSIS Question relates SG pressure indicators on both the Control Room and Remote Page 187 of 208

HL-16 NRC Written Examination KEY Shutdown Panels and detemines which are Post Accident and Fire Event Qualified.

SRO 10CFR55.43 (b2)

ANSWER I DISTRACTOR ANALYSIS A. Correct-The Control Red Bezel indicates PAM instrument. The PSDB for SG pressure has no Red Bezel. The Red Bezel on the PSD Panels are Fire Isolated instruments.

B. Incorrect-Plausible because the control room has a Red Bezel which is PAM and not Fire Qualified. B Train PSD Panel is Fire Qualifed in itself but not for all instruments.

C. Incorrect-The Control Red Bezel indicates PAM instrument. A Train PSD Panel is NOT Fire Qualified.

D. Incorrect-Control Room Red Bezel is for PAM and not Fire protection. The Shutdown panels are not post accident.

REFERENCES Tech Spec 3.3.3 Post Accident Monitoring (PAM) Instrumentation and Bases Tech Spec 3.3.4 Remote Shutdown System and Bases VEGP-FSAR-7 Alternate Shutdown Indication System (page 7.4-14)

VEGP-FSAR-18.1 .2.11 Labeling (page 18.1-12)

V-LO-TX-60327 Remote Shutdown Equipment Procedure 18038-1 Operation From Remote Shutdown Panels VEGP learning objectives:

LO-PP-60327-02 List the instruments and controls that are fire event qualified and how they are identified.

LO-PP-60327-03 In the event of a Control Room fire which Remote Shutdown Panel is preferred for fire event operation? Why?

Page 188 of 208

PAM Instrumentation 3.3.3 Table 3.3.3-1 (page 1 Post Accident Monitoring Instrofume 1) ntation FUNCTION REQUIRED CHANNELS CONDITIONS

1. Reactor Coolant System (RCS) Pressure (wide range) 2

2. RCS T B,G,H,I 1 (wide range) 1/loop C,G,H,I

3. RCS Td (wide range)

I/loop D,G,H,I

4. Steam Generator (SG) Water Level (wide range) 1/SG

5. EG,H,I SG Water Level (narrow range) 2/SG 8,G,H,I

6. Pressurizer Level 2 B,G,H,I

7. Containment Pressure 2 B,G,H,l

8. Steam line Pressure 2/steam line B,GH,I

9. Refueling Water Storage Tank (RWST)

Level 2

10. Containment Normal Sumps Level (narrow B,G,H,I range) 2

11. Containment Water Level (wide rang BG,H,I e) 2

12. Condensate Storage Tank Level B,G,H,I 2/tankw

13. Auxiliary Feedwater Flow B,G,H,I 2/SG B,G,H,I

14. Containment Radiation Level (high range) 2

15. Steam line Radiation Monitor B,G,H,J 1/steam line F,G,H,I

16. RCS Subcoolinq 2 B,G,H,I

17. Neutron Flux (extended range) 2 B,G,I-I,I

18. Reactor Vessel Water Level (RVLIS) 2 B,G,H,J

19. Deleted

20. Containment Pressure (extended range) 2 B,G,H,I

21. Containment Isolation Valve Positio n 2/penetration flow pathd>

22. Core Exit Temperature Quadrant 1 B,G,H,I 2 B,G,H,I

23. Core Exit Temperature Quadrant 2 2

24. Core Exit Temperature Quadrant B,G,H,I 3

25. Core Exit Temperature Quadrant 4 B,G,H,I 2u) 8,G,H,l (a) Only required for the OPERABLE tank.

(b) Not required for isolation valves whose valve, closed manual valve, blind flang associated penetration is isolated by at least e, or check valve with flow through the valve one closed and deactivated automatic secured.

Applicable for containment isolation valv (containment isolation valves which receie position indication designated as post-accident monitoring instrumentati ve containment isolation phase A or cont on ainment ventilation isolation signals).

(c) Only one position indication channel is channel. required for penetration flow paths with only one installed control room indication (d) A channel consists of two core exit therm ocouples (CET5).

Vogtle Units 1 and 2 3.3.3-6 Amendment No. 134 (Unit 1)

Amendment No. 113 (Unit 2)

PAM Instrumentation B 3.3.3 BASES LCO 5. Steam Generator Water Level (Narrow Range)

(continued)

Narrow range SG water level (Loops 517-519, 527-529, 537-539, & 547-549) is a Type A variable used to determine if an adequate heat sink is being maintained through the SGs for decay heat removal and to maintain the SG level and prevent overfill. It is also used to determine whether SI should be terminated and may be used to diagnose an SG tube rupture event.

6. Pressurizer Level Pressurizer Level (Loops 459, 460, & 461) is used to determine whether to terminate SI, if still in progress, or to reinitiate Slit it has been stopped. Knowledge of pressurizer water level is also used to verify the unit conditions necessary to establish natural circulation in the RCS and to verify that the unit is maintained in a safe shutdown condition.

7,20. Containment Pressure and Containment Pressure (Extended Range)

(Containment Pressure Type A Loops 934, 935, 936, & 937; Containment Pressure extended range loops 10942 & 10943)

Containment Pressure is provided for verification of RCS and containment OPERABILITY.

Containment pressure is also used to verify closure of main steam isolation valves (MSIVs) actuation of containment spray, and for accident diagnosis.

8. Steam Line Pressure Steam Line Pressure (Loops 514, 515, 516, 524, 525, 526, 534, 535, 536, 544, 545, & 546) is a Type A variable provided for the following:

• Determining if a high energy secondary line rupture occurred and which steam generator is faulted; (continued)

Vogtle Units 1 and 2 B 3.3.3-7 Revision No. 0

PAM Instrumentation B 3.3.3 BASES LCO 8. Steam Line Pressure (continued)

• Maintaining an adequate reactor heat sink;

• Verifying Auxiliary Feedwater flow to the faulted steam generator is isolated;

• Verifying operation of pressure control steam dump system;

• Maintaining the plant in a cold shutdown condition;

• Monitoring the RCS cooldown rate; and

• Providing diverse indication to Cold Leg temperature for natural circulation determination.

Three channels per steam line are installed with sufficient accuracy to determine the faulted steam generator and to verify Cold Leg temperature for natural circulation.

9. Refueling Water Storage Tank (RWST) Level The RWST level (Loops 990, 991, 992, & 993) is a Type A variable provided for verifying a water source to the Emergency Core Cooling Systems (ECCS) and Containment Spray, determining the time for initiation of Cold Leg recirculation following a LOCA and event diagnosis.

The RWST level accuracy is established to allow an adequate supply of water to the safety injection and spray pumps during the switchover to Cold Leg recirculation mode. A high degree of accuracy is required to maximize the time available to the operator to complete the switchover to the sump recirculation phase and ensure sufficient water is available to avoid losing pump suction.

(continued)

Vogtle Units 1 and 2 B 3.3.3-8 Revision No. 0

Remote Shutdown System 3.3.4 Table 3.3.4-1 (page 1 of 1)

Remote Shutdown System Instrumentation and Controls FUNCTION/INSTRUMENT REQUIRED OR CONTROL PARAMETER NUMBER OF CHANNELS MONITORING INSTRUMENTATION

1. Source Range Neutron Flux 1

2. Extended Range Neutron Flux 1

3. RCS Cold Leg Temperature 1/loop

4. RCS Hot Leg Temperature 2

5. Core Exit Thermocouples 2

6. RCS Wide Range Pressure 2

7. Steam Generator Level Wide Range 1/loop

8. Pressurizer Level 2

9. RWST Level 1

10. BAST level i

11. CST Level 1/tankt

12. Auxiliary Feedwater Flow 1/loop

13. Steam Generator Pressure i/loop TRANSFER AND CONTROL CIRCUITS

1. Reactivity Control (b)

2. RCS Pressure Control (b)

3. Decay Heat Removal

a. Auxiliary Feedwater (b)

b. Steam Generator Atmospheric Relief Valve (b)

4. RCS Inventory/Charging System (b)

5. Safety support systems required for the above functions (b)

(a) Alternate local level indication may be established to fulfill the required number of channels.

(b) The required channels include the transfer switches and control circuits necessary to place and maintain the unit in a safe shutdown condition using safety grade components.

(c) Only required for the OPERABLE tank.

(d) Refer also to LCO 3.7.4.

Vogtle Units 1 and 2 3.3.4-3 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

Remote Shutdown System B 3.3.4 BASES (continued)

TABLE B 3.3.4-1 REMOTE SHUTDOWN SYSTEM MONITORING INSTRUMENTATION READOUT 1 CHANNELS INSTRUMENT FUNCTION LOCATION AVAILABLE

1. Source Range Neutron Flux A 1 (Nl-31E)

2. Extended Range Neutron Flux B 1 (NI-13135 C&D)

3. RCS Cold Leg Temperature A, B 1/Loop (Loop 1 TI-0413D, Panel A)

(Loop 2 TI-0423D, Panel B)

(Loop 3 TI-0433D, Panel B)

(Loop 4 TI-0443D, Panel A)

4. RCS Hot Leg Temperature A 2 (Loop 1 Tl-0413C Loop 4 TI-0443C)

5. Core Exit Thermocouples B 2 (Loop 2 Core Quadrant 1TI-10055)

(Loop 3 Core Quadrant 1TI-10056)

(Loop 1 Core Quadrant 2T1-10055)

(Loop 4 Core Quadrant 2T1-1 0056)

6. RCS Wide Range Pressure A, B 2 (PI-405A, Panel A)

(Pl-403A, Panel B)

7. Steam Generator Level Wide Range A, B 1/Loop (Loop 1 LI-501 B, Panel A)

(Loop 2 LI-502B, Panel B)

(Loop 3 Ll-503B, Panel B)

(Loop 4 LI-504B, Panel A)

8. Pressurizer Level A, B 2 (Ll-459C, Panel A)

(Ll-460C, Panel B)

9. RWST Level L 1 (LI-0990C)

10. BAST Level L 1 (P1-10115) 2

11. CSTLeveI L 2 (Tank 1 LI-5100)

(Tank 2 LI-5115)

(continued)

Vogtle Units 1 and 2 B 3.3.4-6 Rev. 1-3/98

Remote Shutdown System B 3.3.4 BASES TABLE B 3.3.4-1 (continued)

REMOTE SHUTDOWN SYSTEM MONITORING INSTRUMENTATION READOUT 1 CHANNELS INSTRUMENT FUNCTION LOCATION AVAILABLE

12. Auxiliary Feedwater Flow A, B 1/LOOP (LOOP 1 FI-5152B, Panel A)

(LOOP 2 Fl-5151B, Panel B)

(LOOP 3 FI-5153B, Panel B)

(LOOP 4 FI-5150B, Panel A)

13. Steam Generator Pressure A, B 1/LOOP (LOOP 1 PI-0514C, Panel A)

(LOOP 2 PI-0525B, Panel B)

(LOOP 3 PI-0535B, Panel B)

(LOOP 4 PI-0544C, Panel A)

A Remote

- Shutdown Panel PSDA B Remote Shutdown Panel PSDB L Local Indication 2

Graph will be provided to determine level from pressure reading.

Vogtle Units 1 and 2 B 3.3.4-7 Revision No. 0

VEGP-FSAR-1 8 181.2.11 Labeling (Grouping. Marking)

This is defined as alphanumeric, color, and other visual methods used for controls and displays to improve the performance of control room personnel.

A color coding scheme for the switchplates on the QMCB, QEAB, QHVC, QPCP, PSDA, and PSDB is implemented in a plant procedure.

Additionally:

A. Controls located on the bench board section of the QMCB are grouped by subsystems divided by the demarcation lines (paragraph 18.1.1.2.A) and enveloped, where room permits, with hierarchical labels for subsystems at the top center of the envelopes to improve recognition of functional grouping.

B. Labels are located to minimize interference with operator view and to avoid interference with other control functions.

C. Labels are designed for legibility and visibility based on the contrast between the lettering and its background.

D. Labels are designed to have white letters on black tags. Black on white is sometimes used to highlight a display.

E. Labels are designed with 3/16-in, capital letters. Annunciator window engravings are designed with 1/4-in, or 3/16-in, letters. The 1/4-in, letters are used to improve readability when message length permits.

F. Controls and displays are labeled with service description and tag number engravings. In addition, the control switch modules shall contain engravings for switching development functions, equipment-actuated functions, and train, if applicable.

G. Labels are placed above the instruments and on the escutcheon plates for control switches to allow adequate viewing from a distance of about 3 ft.

H. Labels for similar devices throughout a board are designed to be uniform in style, size, lettering, and use of abbreviations, with the exception of integral panels supplied by the vendor and inserted into the boards or panels as a unit.

I. Labels are designed and mounted so that they cannot easily be damaged or removed.

J. Labels and tag numbers are designed for accessibility and visibility during maintenance.

K. Labels are concise with minimum repetitive information and are directly usable with minimum decoding and interpretation of the service descriptions and abbreviations. A hierarchical label is used to highlight functional grouping.

L. Labels are not designed to describe engineering characteristics, name of manufacturer, trademarks, or nonfunction-related nomenclatures of the equipment.

M. Shades of colors used for mimics on the QEABs are designed to have maximum contrast between the mimic bus and the boards.

N. Safety-related post-accident monitoring instrumentation is identified by a dark red line on the black bezel base of each instrument.

18.1-12 REV 14 10/07

Local control, the ass ociated plant equipment operator control, i.e... is under direct No auto starts or stops protection are availab other than electrical le.

There are other local con trol stations that are not know n as shutdown panels but are necessary for safe shutdown outside the con trol room.

Electrical power required for safe shutdown of the plant is ensured by having local controls for each Emergency Diesel generator and its associated 1E electrical buses.

Pressurizer inventory is maintained by the local controller located in the Auxiliary building for CVCS chargin Temperature control is g.

manual ARV stations (in also ensured by the loc conjunction with Turbin al Water Pump) if for som e Driven Auxiliary Feed e reason electrical pow If the control room is er is not available.

evacuated due to fire, controlling the plant are the methods of different. Controllers are genera remote control until act lly left in ually needed to maintain functions. However in the event of automatic transferred to local imm a fire all controls are ediately to prevent spu actuations. rious Most instruments and con the Main Control Room. tro l cir cui ts run through Damage from fire and smo shorts and or open cir ke could cause cuits making instrume unreliable. ntation and control The remote shutdown pro shutdown panel is prefer cedure states that the able for a control room B This is because it is fire event.

the only remote shutdo Fire Event qualified wn panel that has instruments and contro Qualified means can be ls. (Fire Event divorced from the Con controls on the B shu trol Room) Not all tdown panel are Fire The fire event qualifi Event qualified.

ed instruments on the are designated by having B shutdown panel a red lower bezel. (Not mistaken by the instrum to be ents with red bezels Control Board, this ide on the Main ntifies them as Post Monitoring systems PAM Accident s)

The means by which thes e instruments are imm Ccntrol Room fire is by une to a the use of fiber optics instruments are powered . Most all controls and and processed by the 7300 control cabinets locate protection and d in the Main Control system is called Eagle room. This fiber optic 21, which is located out room is used to supply side the Main Control power to the dedicated The process signals from instrument transmitters.

Eagle 21 are sent direct Shutdown Panel B and ly to both the to the 7300 protection the control through opt and control cabinets in ical isolators. (Se the Eagle 21 cabinet) e Chapter 28 for details The Fire Event Qualifie of controls that are provid d instruments and ed by the Eagle 21 sys tem are as follows:

• RCS Wide Range Cold Leg Temperature for loops

• RCS Wide Range Pressure 2&3 Loop 1 4

Local control, the associated plant equipment is under direct operator control, i.e... No auto starts or stops other than elect protection are available. rical There are other local control stations that are not known as shutdown panels but are necessary for safe shutdown outside the control room.

Electrical power required for safe shutdown of the plant is ensured by having local controls for each Emergency Diesel generator and its associated lE electrical buses.

Pressurizer inventory is maintained by the local controller . .

located in the Auxiliary building for CVCS charging.

Temperature control is also ensured by the local manual ARV stations (in conjunction with Turbine Driven Auxiliary Peed Water Pump) if for some reason electrical power is not available.

If the control room is evacuated due to fire, the methods of controlling the plant are different.

Controllers are generally left in remote control until actually needed to maintain automatic functions. However in the event of a fire all cont rols are transferred to local immediately to prev ent spurious actuations. Most instruments and control circuits run through the Main Control Room. Damage from fire and smoke could caus shorts and or open circuits making instr e umentation and control unreliable. The remote shutdown procedure states that the B shutdown panel is preferable for a cont rol room fire, event.

This is because it is the only remote shutdown panel that has Fire Event qualified instruments and controls. (Fire Event Qualified means can be divorced from the Con trol Room) Not all controls on the B shutdown panel are Fire Event qualified.

The fire event qualified instruments on the B shutdown panel are designated by having a red lower bezel. (Not to be mistaken by the instruments with red beze ls on the Main Control Board, this identifies them as Post Accident Monitoring systems PAWs)

The means by which these instruments are immune to a Control Room fire is by the use of fiber optics. Most all controls and instruments are powered and processed by the 7300 protection and control cabinets located in the Main Con trol room. This fiber optic system is called Eagle 21, which is locat ed outside the Main Control room is used to supply power to the dedi cated instrument transmitters.

The process signals from Eagle 21 are sent directly to both the Shutdown Panel B and to the 7300 prote ction and control cabinets in the control through optical isolators.

(See Chapter 28 for details of the Eagle 21 cabinet) The Fire Event Qualified instruments controls that are provided by the Eagle and 21 system are as follows:

• RCS Wide Range Cold Leg Temperature for loops 2&3

• RCS Wide Range Pressure Loop 1 4

- --i - I L

1 I I

1 4

1 S

-T V I Lr-rnrT F S

VEGP-FSAR-7 To prevent interaction between the redundan t systems, the redundant control channels are wired independently and sep arated with no electrical connections between them. Non-Class 1 E circuits avail able for safe shutdown are electrically isolated from Class 1 E circuits.

D. Conformance to Other Guides, Criteria, and Standards The additional guides, criteria, and standar ds listed in table 7.1.1-1 apply only to the essential instrumentation and control required for safe shutdown from outside the control room.

7.4.3.3 Alternate Shutdown Indication System 7.4.3.3.1 Description The alternate shutdown indication system is designed to provide indication and controlle OlMs, necessary for cold shutdown that are rs; i.e.,

independent from the control room in the control room fire. No other events are postulate event of a d

fire; consequently, the design is exempted from to occur either during or after a control room the single failure criteria, Seismic Category criteria, and the other design basis accident 1 criteria, except where required for other reas (e.g., due to interfacing with or impacting on ons existing systems).

The plant safety monitoring system (PSMS)

(refer to paragraph 7.5.3.6) and the alternate shutdown indication system cabinet are used to process and output isolated signals whic the control room and the train B shutdown h go to panel. The PSMS provides isolated signals alternate shutdown indication parameters for for the which the PSMS performs data acquisitio display. The alternate shutdown indication n and system cabinet isolates signals which in the process cabinets and the OIM control are required loops.

The reactor may be tripped from the main control board before leaving the control room tripped from either of the shutdown panels or immediat rooms. Both shutdown panels are fully equipped ely after entering the shutdown panel panels that may act as the point of cont performing a shutdown and cooldown of the rol plant given that the control room is inaccessib for However, only the train B shutdown panel is le.

provided with electrically isolated instrume and controls for use as the alternate shutdow ntati on n point of control following a control room tire.

7.4.3.3.2 Design Bases Information The alternate shutdown indication system is designed to meet Branch Technical Posi CMEB 9.5-1 requirement C.5.C (see appendix tion 9B).

7.4.3.3.2.1 Sat etv Design Bases. The alternate shutdow compromise safety-related systems and asso n indication system shall not ciated inputs nor prevent sate shutdown.

7.4.3.3.2.2 Power Generation Design Basis. The provides electrically isolated signals into the alternate shutdown indication system control room during power generation. It designed to function during and after a cont is rol room fire.

A. The alternate shutdown indication syste m controls, in conjunction with remote shutdown panel B controls, are used to achie ve and maintain hot standby condition and achieve cold shutdown from full pow er conditions in 72 h following a control room fire and maintain cold shutdown cond itions thereafter.

7.4-14 REV 14 10/07

VEGP-FSAR-7 B. The alternate shutdown indication sys tem instrumentation, in conjunction with remote shutdown panel B instrumentation

, provides direct readings and controls monitor the process variables necessary to to perform and control the following shutdown functions:

1. Reactivity control.

2. Reactor coolant makeup/inventory.

3. Reactor heat removal.

C. The alternate shutdown indication sys tem consists of the following require parameters and OlMs (see table 7.4.2-1 d

):

1. Neutron flux.

2. Reactor coolant system wide range TOd (loops 2 and 3).

3. Incore thermocouples in the quadrants corresponding to loops 2 and 3 (Unit 1) and loops 1 and 4 (Unit 2).

4. Reactor coolant system wide range pressure.

5. Steam generator wide range level (loo ps 2 and 3).

6. Pressurizer level.

7. Head vent throttle valve (OIM).

8. Accumulator tank gas vent valve (QIM

).

D. The alternate shutdown indication sys tem accommodates post-fire conditions offsite power is available and where offsi where te power is not available for 72 h.

E. The alternate shutdown indication sys tem is not damaged by a control room fire.

F. The alternate shutdown indication sys tem and associated circuits design are exempted from Seismic Category I crit eria, single failure criteria, or other des basis accident criteria, except where req ign uired for other reasons (e.g., because interface with or impact on existing safe of ty systems).

G. The alternate shutdown indication sys tem is electrically isolated from the con room so that a fire-induced, hot short, trol open circuit, or short to ground in the shutdown control room indication circuits alte rnate will not prevent operation of the alterna shutdown indication at the shutdown pan te el.

H. Access to the alternate shutdown indic ation system is under administrative con trol.

I. The alternate shutdown indication system OlMs are activated manually follo evacuation of the control room. This actu wing ation does not disturb control, process, protection, or nuclear instrumentation circuits except those associated with the alternate shutdown indication system.

J. The alternate shutdown indication sys tem is room so that a fire-induced hot short, ope electrically isolated from the control n circuit, or short to ground in any of Class 1 E circuits will not prevent ope the ration of the alternate shutdown equipm from the shutdown panel. ent K. An alarm is provided in the control room to provide an indication in the eve alternate shutdown OlMs are bypasse nt that the d from the main control board to the shu panel. tdown 7.4-15 REV 14 10/07

VEGP-FSAR-7 7.4.3.3.2.3 Guides, Criteria, and Standards. The alternate shutdown indicat conforms to GDC 19, the applicable portions of IEEE Standards ion system 279-1971, 323-1974, and 344-1975, Regulatory Guide 1.22, and Branch Technical Position CMEB 9.5-1.

7.4-16 REV 14 10/07

Approved By J. B. Stanley VogUe Electric Generating Plant Procedure Number Rev Date Approved 18038-1 32 OPERATION FROM REMOTE SHUTDOWN Page Number I

2 f

O 2 lO7 PANELS 10 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE ATTACHMENT H is to be used at SS discreti on as an aid for operators dispatched to perform local actions.

CAUTION Fire event qualified instrumentation is only available on Shutdown Panel B and marked red in

_8. Make a page announcement that the Control Room is being evacuated and perform the following:

a. Dispatch Operators to the following locations: a. jf insufficient personnel are available, THEN use the following priority:

1) Shutdown PaneiB (CB-A43): 1) Shutdown Panel B.

• Shift Supervisor

. Extra Shift Personnel 2) Shutdown Panel A.

2) Shutdown Panel A (CB-A75): 3) Shutdown Panel C (TDAFW Pump Room).

• Reactor Operator 4) TSC Plant Computer Terminal.

3) Shutdown Panel C (TDAFW Pump Room):

• System Operator Step 8 continued on next page Printed January 162011 at 14:54

Approved By J. B. Stanley Vogtle Electric Gen Date Approved erating Plant Procedure Number Re v

/27/201 0 OPERATION FROM 18038-1 32 REMOTE SHUTDO WN Page Number PANELS ACTION/EXPECTED 43 of 123

RESPONSE

RESPONSE NOT O BTAINED

_c. After approximately 2 minutes start the sele cted RCP.

if offsite power NOT available OR ACCW Pump NO T in service, THEN:

Verify that the RCS is be cooled by natural circ ing ulation:

. RCS subcooling grea ter than 50°F.

. SG pressures stable Iowenng -

or  :

. RCS WR Hot Leg temperatures stable or lowering.

• RCS WR Cold Leg temperatures at satu ration for SG pressure.

Refer to ATTACHMEN T D, RCS PRESSURE TEMPE RATURE LIMITS.

41. IF a Control Room fir e,

THEN prevent spurio us actions from occurring:

• Secure Containmen t Spray Pumps by racking to the disconnect position:

• 1AAO2-14 (CB-A48)

• 1BAO3-14 (CB-A50) 4 Printed January 16, 2011 at 14:51

HL-16 NRC Written Examination K

91. 072G2.4.46 OOl/2/2/ARM-ALARMS/4. CIA I JMOD BAN K/SRO/NRC/GCW EY A dropped fuel assembly in the Unit 2 Spent Fuel Pool has resulted in the indications on the FHB Effluent Radiati following on Monitors:

- ARE-2533A is in HIGH alarm.

- ARE-2532A, 2532B, and 2533B are all in INTERMEDIATE alarm.

In addition:

- 2RE-0008, Fuel Handling Building Are a Monitor is in HIGH alarm.

The crew enters AOP-1 8006-C, Fue l Handling Event and is at the step proper FHB HVAC alignment. to check Which ONE of the following would be CORRECT regarding:

1) how many FHB Post Accident Filt ration Units would auto start, and

2) operator actions to take per the AO P and the bases for the actions?

A 1) two auto start

2) stop one unit, to limit the offsite dos e release B. 1) one auto starts

2) start an additional unit, to limit the offsite dose release.

C. 1)twoautostart

2) take no action, both running limits airborne concentrations in FHB atmosp here.

D. 1) one autostarts

2) start an additional unit, to limit airb orne concentrations in the FHB atmosp here.

Feedback 072 Area Radiation Monitoring (AR M) System Emergency Procedures I Plan 2.4.46 Ability to verify that the alarm s are consistent with the plant con (CFR: 41.10! 43.5 I 45.3 / 45.12) ditions.

K/A MATCH ANALYSIS Page 189 of 208

HL-16 NRC Written Examination KEY Question gives a plausible scenario where a FHB event causes one of the FHB effluent radiation monitors goes into high alarm along with the FHB area rad monitor on the affected unit. Several other FHB effluent monitors are in intermediate (alert) alarm. The candidate must determine the proper amount of FHB units which would start and the bases behind ensuring the proper amount of units end up running (one due to manual actions).

SRO 10CFR55.43 (b4,7)

ANSWER I DISTRACTOR ANALYSIS A. Correct. Two units start, one should be stopped to limit offsite dose release.

B. Incorrect. Two units start. Starting an additional unit would raise the amount of offsite dose release, not lower it.

C. Incorrect. Two units start, while both running would limit the airborne concentrations in the FHB atmosphere, one unit should be stopped to limit offsite dose release.

D. Incorrect. Two units start. Starting an additional unit would limit the airborne concentrations in the FHB atmosphere but is an incorrect action as only one unit should run to limit the offsite dose release.

REFERENCES LOIT Bank question # 034A2.02 18006, Fuel Handling Event, steps # 6 and # 7 17102-1, page 39 and 40 for SRDC QRM2 for ARE-2533A 13320-C, Fuel Handling Building HVAC System pages # 39-41, and page # 21 V-LO-PP-231 01 FHB/Aux Building HVAC Systems (Slides 98, 114)

VEGP learning obiectives:

LO-PP-231 01-09, Explain how the Fuel Handling Building HVAC system responds to a Fuel Handling Building Isolation Signal.

Page 190 of 208

Approved By T. E. Tynan Vogtle Electric Generating Plant Procedure Number Rev 18006-C 8.1 FUEL HANDLING EVENT Page Number ABNORMAL OPERATING PROCEDURE CONTINUOUS USE PURPOSE This procedure describes the actions to be taken durin g potential damage of an irradiated fuel assembly.

SYMPTOMS

• Radiation alarms in the Fuel Handling Building.

• Radiation alarms in Containment.

• Report of a damaged irradIated fuel assembly by hand ling persnnel

• High containment particulate, iodine, or gaseous activ ity.

• Visual observation of the unexpected release of bubbles from an irradiated fuel assembly.

• Unexplained lowering of Spent Fuel Pool or Reac tor Cavity level.

MAJOR ACTIONS Suspend activities.

Evacuate area.

Isolate area.

Determine recovery plan.

Printed January 17, 2011 at 10:50

Approved By T. E. Tynan Vogtle Electric Generating Plant Procedure Number Rev 1 8006-C 8.1 2/i7i205 FUEL HANDLING EVENT PageNumb ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

c. Initiate 13125, CONTAINMENT PURGE SYSTEM to:

_1) Shut down the Containment Purge System.

2) Start the Preaccess Filter Units.

6. Check affected area FUEL -

_6. Go to Step 8.

HANDLING BUILDING

7. Perform the following:

_a. Verify both large and small missile doors closed.

_b. Verify FHB isolation has actuated on AHS-2532A or AHS-2533A.

C. Initiate 1 3320-C, FUEL HANDLING BUILDING HVAC SYSTEM to:

_1) Verify proper FHB HVAC alignment. J

_2) Verify only one FHB Post Accident Exhaust Filtration Unit is operating.

_8. Notify Shift Supervisor and Reactor Engineering of the damaged fuel assembly location.

9. Initiate NMP-EP-1 10, EMERGENCY CLASSIFICATION DETERMINATION AND INITIAL ACTION.

Printed January 17, 2011 at 10:50

Approved By S. A. Phillips Vogtle Electric Generating Plant Procedure Number Rev Date Approved 13320-C 31.2 1/08 FUEL HANDLING BUILDING HVAC SYSTEM Page Number 39 of 51 INITIALS 4.12 SHUTDOWN OF A FHB POST ACCIDENT FILTER UNIT AS DIRECTED FROM 18006-C FUEL HANDLING EVENT 4.12.1 Check FHB Isolation Signal NOT present on QHV C:

• Red Light at FHB ISOLATION MANUAL ACTUAT ION, AHS-2532A (A54) NOT LIT

• Red Light at FHB ISOLATION MANUAL ACTUAT ION, AHS-2533A (A55) NOT LIT 4.12.2 j[ any red lights are LIT, verify at SRD C that FHB Radiation Monitors are NOT in high alarm:

• A-RE-2532A

• A-RE-2532B

• A-RE-2533A

• A-RE-25338 Printed January 17, 2011 at 10:56

Approved By S. A. Phillips Vogtle Electric Generating Plant Procedure Number Rev Date Approved 13320-C 31.2 FUEL HANDLING BUILDING HVAC SYSTEM Page Number 2/1/O8 40 of 51 INITIALS NOTES

• The FHB Isolation Signal must be reset prior to starting the Norma l HVAC System.

• If a FHB Isolation Signal is present as a result of a failed on inoper able radiation monitor it may be necessary to block its input per 13508-1 prior to placing FHB Normal HVAC system into service.

• If a FHB Isolation Signal is still present and either trains handsw itch is taken to reset, then that Trains Isolation logic is rendered inoperable.

A corresponding White Light will be LIT on AHS-2532B (AHS-2533B

), and a corresponding alarm is received on the Unit One and Unit Two SSMP Panels and will bring in annunciators on BOTH Unit One and Unit Two (1/2ALBO4-E01(E02) TRAIN A(B) SYS STATUS MON PNL ALER T.

4.12.3 IF any Red lights in Step 4.12.1 are lit AND any FHB Rad monitors are in high alarm, it will be necessary to over ride the actuation signal to shutdown a Post Accident Filter Unit. If required, perform the following steps, otherwise proceed to Step 4.12.4:

a. NotIfy SS that over riding the FHB Isolation Signal will INOP that train(s) of FHB activation logic and may require entry into TR 13.3.6.

NOTE The SSMP annunciator and FHB Actuation logic override white light indication will clear when the FHB Rad Monitor high rad condition is reset.

b. Notify Unit One and Unit Two control room operators that annunciator 1/2ALBO4-E01 TRAIN A SYS STATUS MON PNL ALERT and/or annunciator 1/2ALBO4-E02, TRAIN B SYS STATUS MON PNL ALERT will illuminate.

Printed January 17, 2011 at 10:56

Approved By Procedure Number Rev S. A. Phillips Vogtle Electric Generating Plant Date Approved 13320-C 31.2 Page Number 42/1/08 FUEL HANDLING BUILDING HVAC SYSTEM 41 of 51 INITIALS Critical

c. Reset the actuation signal using the associated handswitch:

• Train A AHS-2532B (B54) RESET OVERRIDE CV

• Train B AHS-2533B (B55) RESET OVERRIDE CV

d. Verify Associated FHB Isolation Signal is over ridden on QHVC:

(1) Train A LAMP SWITCH STATUS

• RED AHS-2532A (A54) NOT LIT

• GREEN AHS-2532A (A54) LIT

• WHITE AHS-2532B (B54) LIT (2) Train B LAMP SWITCH STATUS

• RED AHS-2533A (A55) NOT LIT

• GREEN AHS-2533A (A55) LIT

• WHITE AHS-2533B (B55) LIT

e. Proceed to Step 4.12.5 Printed January 17, 2011 at 10:56

Approved By I J. B. Stanley Vogtle Electric Generating Plant Procedure Number Rev Date Approved 17102-1 19.3 ANNUNCIATOR RESPONSE PROCEDURES FOR THE SAFET 8/2/09 Y Page Number RELATED DISPLAY CONSOLE QRM2 39 of 42 WINDOW CDCA C6 ORIGIN SETPOINT Fuel Handling A- RE-2533A As determined (RED LAMP LIT)

Building Effluent by Chemistry (HIGH)

Radiogas Monitor Department ARE-2 533A NOTE For other than HIGH conditions see Pages 5 and 6.

1.0 PROBABLE CAUSE

1. High airborne radioátivity in the Fuel Handling. Bu1tdIng

2. Equipment malfunction.

2.0 AUTOMATIC ACTIONS Switches the Normal Fuel Handling Building Ventilation to Accident Mod6 Ventllatiofk 3.0 INITIAL OPERATOR ACTIONS Evacuate the Fuel Handling Building.

Printed January 18, 2011 at 17:38

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 17102-1 19.3 Date Approved ANNUNCIATOR RESPONSE PROCEDURES FOR THE SAFETY Page Number t8/2I09 RELATED DISPLAY CONSOLE QRM2 40 of 42 WINDOW CDCA C6 (Continued) 4.0 SUBSEQUENT OPERATOR ACTIONS

1. Verify Fuel Handling Building is in the Accident Mode of ventilation per manual actuation of FHB isolation section of 13320-C, Fuel Handling Building HVAC System.

2. Refer to 91001-C, Emergency Classification And Implementing Instructions.

3. Notify Health Physics to sample and analyze the Fuel Handling Building exhaust air.

4. if the alarm is an actuation resulting from Fuel Handling, initiate 18006-C, Fuel Handling Event, as appropriate.

NOTE Exhaust gasses are again monitored at the plant vent by Plant Vent Monitors 1-RE-12442 A, B and C.

5. Check the Radiation Monitor CRT or QRM1 Control Console for level of radiation read by 1-RE-12442 A, B and C.

6. if sampling and analysis determine that the channel has malfunctioned:

a. Comply with Technical Requirement TR 13.3.6.

b. Place A-HS-2532C on QESF to TEST BLOCK CHAN II.

c. Request Chemistry to investigate and take corrective action.

5.0 COMPENSATORY OPERATOR ACTIONS NONE END OF SUB-PROCEDURE

REFERENCES:

AX4DB2O4-2, 1 X4DB203, AX3D-BG-EO2M, AX5DNO29-1, AX5DX31 01 Printed January 18, 2011 at 17:39

Approved By . Procedure Number Rev S. A. Phillips Vogtle Electric Generating Plant 13320-C 31.2 Date Approved Page Number 2/1/08 FUEL HANDLING BUILDING HVAC SYSTEM 21 of 51 INITIALS 4.6 POST ACCIDENT CLEANUP OF THE FHB USING THE NORMAL EXHAUST UNITS NOTE This section would normally be used to expedite clean up in the spent fuel pool area during accident conditions. It should be expected that the FHB rad monitors may initially be in high alarm and a FHB isolation signal be present.

CAUTION The Train B Post Accident Filter Unit and the normal HVAC System discharge to a Common Exhaust stack. They should not be aligned to discharge to the exhaust stack at the same time.

4.6.1 Verify FHB Post Accident Filter Unit Train A is operating, otherwise start per Section 4.2, Manual Actuation of FHB Isolation.

4.6.2 Verify the following damper alignment:

a. FHB NORM HVAC SPLY DMPRS:

• A-HV-2529 AHS-2529 (A56) CLOSED

• A-HV-2528 AHS-2528 (A57) CLOSED

b. NORM HVAC UNIT SPLY HDR ISO DMPRS:

• A-HV-2535 AHS-2535 (856) CLOSED

• A-HV-2534 AHS-2534 (B57) CLOSED

c. FHB ISO DMPRS TO NORM EXH:

• A-HV-12479 AHS-12479 (D56) CLOSED

• A-HV-12480 AHS-12480 (D57) CLOSED Printed January 17, 2011 at 11:00

0 FHB Actuation Signals

• Manual (objective 2) 1/2 switches on Unit 1 HVAC Panel

• Note only one required to satisfy TRM instrumentation requirements.

• Hi Radiation on any of the following: (objective 2) 1/4 exhaust duct radiation detectors RE-2532A, B RE-2533A, B

• Note: 4 channels and only one required to satisfy TRM instrumentation requirements.

V-LO-PP-231 01-02.1 98

Q FHB Actuation Signals

• Air is drawn from the FHB and discharged to the Unit 1 plant vent.

• Negative pressure is maintained to ensure no unfiltered air escapes the FHB.

Note: SOP will stop one of the FHB Post Accident Filter Units after actuation to limit plant radiation discharge.

V-LO-PP-23101-02.1 114

1. 034A2.02 OO1/2/2IFH-DROPPED CASKJC/A 3.9/BANK-LOIT/SROIHL-15 AUDIT/DS/TNT A dropped spent fuel cask in the FHB has resulted in the following radiation monitor L alarms:

ARE-2532B is in HIGH alarm.

ARE-2532A, 2533A and 2533B are all in INTERMEDIATE alarm.

2RE-0008, Fuel Handling Building Area Monitor is in HIGH alarm.

Which ONE of the following would be a CORRECT response to the Area Radiation Monitor alarms?

A. Only Train A Fuel Handling Building Post Accident Filter system starts.

Start up Train B to maximize clean up of the FHB.

B. Only Train B Fuel Handling Building Post Accident Filter system starts.

Start up Train A if desired to limit airborne concentrations in the FHB.

C Both trains of the Fuel Handling Building Post Accident Filter systems start.

Shutdown one train of the filter units to limit off-site release.

D. Neither Train of the Fuel Handling Building Post Accident Filter systems starts.

Manually actuate FHBI and ensure only Train B starts to limit off-site release.

Feedback KIA 001 Control Rod Drive System:

K6.03 Knowledge of the effect of a loss or malfunction on the following CRDS components.

Reactor trip breakers, including controls.

K/A MATCH ANALYSIS Question gives a plausible scenario where a Reactor Trip Breaker fails to open after a reactor trip. Candidate must determine the effects on a plant control system (steam dump controls) to determine the final RCS Tave and method of control.

ANSWER I DISTRACTOR ANALYSIS Page: 1 of 2 1/18/2011

A. Incorrect. Steam dumps would arm on 0-7. Plausible candidate may recall P-4 train A arms dumps but not recall C-7 would also arm the dumps. Dump s should control Tave at 559 degrees F in this situation and not ride on the ARVs at 562 degrees F.

B. Incorrect. Steam dumps would arm on C-7 and P-4 Train A.

Plausible candidate may confuse which train arms dumps and not recall C-7 also arms the dumps.

Dumps should control Tave at 557 degrees F in this situation and not ride on the ARVs at 562 degrees F.,;

C. Correct. Steam dumps would arm on C-7 and P-4 Train B would shift their operation to the plant trip mode. Dumps should control Tave at 557 degrees F in this situation.

D. Incorrect. Steam dumps would arm on 0-7 and P-4 Train A.

Plausible candidate may confuse which train shifts dumps to the plant trip mode. If Train B trip breaker failed to open, steam dumps operate in the load reject mode. Dump s would control Tave at 559 degrees F in this situation.

REFERENCES Power Point Presentation, V-LO-PP-21 201, Revision # 2, Steam Dump s (slides 59 88 in particular cover this question) -

Vogtle Text, V-LO-TX-21 201, Revision # 1, Steam Dumps (pages #

14, 20 22, 34 36 in particular cover this question) -

VEGP learning oblectives:

LO-PP-21201-07, Discuss how the Steam Dump System will respon d to a Reactor Trip from Reactor Power level.

LO-PP-21201-1 1, Identify all the conditions that will arm the Steam Dump System and when theyre normally activated.

LO-PP-21201-17, Discuss how the Steam Dump System will respon d to a large tern_perature error signal in the Tavg Mode of operation.

Categories Task Number (LO-TA): 2 Objective/Source: 2 KIA: FH-DROPPED CASK Exam/Question Type: C/A 3.9 Cognitive Level: BANK-LOIT Origin/Rev Info: SRO Reference 1: HL- 15 AUDIT Reference 2: DS/TNT Page: 2 of 2 1/18/2011

HL-16 NRC Written Examination KEY

92. 073A2.02 OO1/2/IIPRM-DETECTOR FAIL/3.4 C/AINEW/SRO/NRC/GCW A Containment Pressure relief is in progress on Unit 1.

A lightning strike on Unit 1 containment causes a detector failure for each of the following radiation monitors:

- 1 RE-2562A, Containment Atmosphere Gaseous

- 1 RE-2562C, Containment Particulate Radiation Which ONE of the following states CORRECT actions to take for these failures?

A. Enter Tech Spec LCO 3.0.3 and within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> initiate the actions to place the unit in Mode 3 within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />, Mode 4 within 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />, and Mode 5 within 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br />.

B. Effluent releases may continue provided grab samples are taken at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and these samples are analyzed for radioactivity within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

C. Effluent releases may continue provided samples are continously collected with auxiliarly sampling equipment OR immediately suspend purging of Containment.

D Analyze grab samples of the Containment Atmosphere OR perform an RCS Leak Rate once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> AND restore the monitors to operable status in 30 days.

Feedback 073 Process Radiation Monitoring (PRM) System Ability to (a) predict the impacts of the following malfunctions or operations on the PRM system; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those malfunctions or operations:

(CFR: 41.5/ 43.5 I 45.3 I 45.13)

A2.02 Detector failure K/A MATCH ANALYSIS Question presents a scenario where both Containment Leak Detection Rad Monitors are rendered inoperable by a lightning strike. The SRO has to choose between various really plausible actions, the correct one for the condition.

SRO 10CFR55.43 (b2)

ANSWER / DISTRACTOR ANALYSIS A. Incorrect. Plausible the candidate may think that with both monitors inoperable that LCO 3.0.3 may apply. Tech Spec LCO 3.4.15 has a specific action for both mop.

B. Incorrect. Plausible the candidate may relate this to the Containment pressure relief Page 191 of 208

HL-16 NRC Written Examination KEY in progress. This is a correct ODCM action #47 if both RE-i 2442 and RE-12444 were inoperable during a pressure relief.

C. Incorrect. Plausible the candidate may relate this to the Containment pressur relief in progress. This is a combination of correct actions # 48 and # 51 if both RE-12442 and RE-12444 were inoperable during the pressure relief.

D. Correct. These are the correct actions for both RE-2562A and C inoperable per LCD 3.4.15, RCS Leak Detection Instrumentation (Condition C)

REFERENCES LCD 3.4.15, RCS Leak Detection Instumentation, Condition C LCD 3.4.13, RCS Operational Leakage ODCM Table 3-i Radioactive Gaseous Effluent Monitoring Instrumentation SOP-13125-i, Containment Purge System section 4.4.1 Containment Pressure Relief VEGP learning objectives:

LO-LP-39208-02, Given a set of Tech Specs and the bases, determine for a specific set of plant conditions, equipment availability, and operational mode:

a. Whether any Tech Spec LCOs of section 3.4 are exceeded.

b. The required actions for all section 3.4 LCOs.

Page 192 of 208

Approved By Procedure Number Rev S. E. Prewiff Vogtle Electric Generating Plant 13125-1 52 Date Approved Page Number

/2O/201O CONTAINMENT PURGE SYSTEM 22 of 36 INITIALS 4.4 NON PERIODIC OPERATION NOTE When monitoring and changing containment pressure during this procedure, computer point P-9871 OR 1 -P1-10945 (QHVC) should be used. These are the only containment pressure instruments that will indicate a negative pressure.

4.4.1 Containment Pressure Relief 4.4.1.1 IF the Unit is in MODE 1, 2, 3 or 4:

a. Review Limitations 2.2.5c, 2.2.7, 2.2.8, and 2.2.10.

b. Place additional containment cooling units in service jf required, to correct the high pressure condition.

4.4.1.2 Notify Chemistry of the upcoming Mini-Purge operation OR Pressure Relief operation:

a. Obtain the current approved Containment Gaseous Release Permit.

OR

b. jf an updated permit is unavailable, request that Chemistry sample the containment atmosphere and prepare for the gaseous release.

Printed January 17, 2011 at 7:57

Approved By Procedure Number Rev S. E. Prewitt Vogtle Electric Generating Plant 13125-1 52 Date Approved Page Number 9/20/2O1O CONTAINMENT PURGE SYSTEM 23 of 36 INITIALS 4.4.1.3 WHEN a current approved Containment Gaseous Release Permit is obtained, perform the following:

a. Verify at least TWO of the following radiation monitors are operable for CVI purposes (TS 3.3.6):

• 1 -RE-2565A&B QB 1 -RE-2565C

• 1 -RE-002

• 1-RE-003

b. Verify at least ONE of the following radiation monitors is operable for ODCM purposes:

• 1-RE-12442C

• 1-RE-12444C CAUTION The pressure relief should NOT be initiated until the current approved Containment Gaseous Release Permit is obtained.

4.4.1.4 Releases may not continue beyond the date /time on the Release may not continue beyond (Date/Time) block indicated on 36022-C Data Sheet 1.

Printed January 17, 2011 at 7:57

RCS Leakage Detection Instrumentation 3.4.15 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.15 RCS Leakage Detection Instrumentation LCO 3.4.15 The following RCS leakage detection instrumentation shall be OPERABLE

a. The containment normal sumps level and reactor cavity sump monitors;

b. One containment atmosphere radioactivity monitor (gaseous or particulate); and

c. Either the containment air cooler condensate flow rate or a containment atmosphere gaseous or particulate radioactivity monitoring system not taken credit for in item b.

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

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME One containment sump A.1 Perform SR 3.4.13.1. Once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> A.

monitor inoperable.

B. Two or more B.1 Perform SR 3.4.13.1 Once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> containment sump monitors inoperable B.2 Restore at least two 30 days containment sump monitors to OPERABLE status.

(continued)

Vogtle Units I and 2 3.4.15-1 Amendment No. 137 (Unit 1)

Amendment No. 116 (Unit 2)

RCS Leakage Detection Instrumentation 3.4.15 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. Required containment C.1.1 Analyze grab samples of Once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> atmosphere radioactivity the containment monitor(s) inoperable, atmosphere.

OR C.1.2 Perlomi SR 3.4.13.1. Once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> AND C.2.1 Restore required 30 days containment atmosphere radioactivity monitor(s) to OPERABLE status.

OR C.2.2 Verify containment air 30 days cooler condensate flow rate monitor is OPERABLE.

D. Required containment 0.1 Perform SR 3.4.15.2. Once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> air cooler condensate flow rate monitor inoperable.

D.2 Perform SR 3.4.13.1. Once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (continued)

Vogtle Units I and 2 3.4.15-2 Amendment No. 137 (Unit 1)

Amendment No. 116 (Unit 2)

RCS Leakage Detection Instrumentation 3.4.15 ACTIONS (continued CONDITION REQUIRED ACTION COMPLETION TIME E. Required containment E.1 Restore required 30 days atmosphere radioactivity containment atmosphere monitor inoperable, radioactivity monitor to OPERABLE status.

AND OR Required containment air cooler condensate E.2 Restore required 30 days flow rate monitor containment air cooler inoperable, condensate flow rate monitor to OPERABLE status.

F. Required Action and F.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time not met. AND F.2 Be in MODE 5. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> G. All required leakage G.1 Enter LCO 3.0.3. Immediately detection systems inoperable.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.15.1 Perform CHANNEL CHECK of containment 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> normal sumps level and reactor cavity sump level monitors.

(continued)

Vogtle Units I and 2 34.15-3 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

RCS Leakage Detection Instrumentation 3.4.15 d)

SURVEILLANCE REQUIREMENTS (continue SURVEILLANCE FREQUENCY 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.4.15.2 Perform CHANNEL CHECK of the required containment atmosphere radioactivity monitor.

92 days SR 3.4.15.3 Perform COT of the required containment atmosphere radioactivity monitor.

18 months SR 3.4.15.4 Perform CHANNEL CALIBRATION of the containment sump monitors.

18 months SR 3.4.15.5 Perform CHANNEL CALIBRATION of the ity required containment atmosphere radioactiv monitor.

18 months SR 3.4.15.6 Perform CHANNEL CALIBRATION of the flow required containment air cooler condensate rate monitor.

3.4.15-4 Amendment No. 96 (Unit 1)

Vogtle Units I and 2 Amendment No. 74 (Unit 2)

RCS Operational LEAKAGE 3.4.13 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.13.1 ----------------------NOTES------------

1. Not required to be performed in MODE 3 or 4 until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of steady state operation.

2. Only required to be performed during steady state operation.

3. Not applicable to primary to secondary LEAKAGE.

Perform RCS water inventory balance. Once within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after achieving steady state operation AND 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> thereafter SR 3.4.13.2 Not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishment of steady state operation.

Verify primary to secondary LEAKAGE is 150 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> gallons per day through any one SG.

Vogtle Units 1 and 2 3.4.13-2 Amendment No. 144 (Unit 1)

Amendment No. 124 (Unit 2)

VEGP ODCM Table 3-i. Radioactive Gaseous Effluent Monitoring Instrumentation OPERABILITY Requirements Minimum Instrument Channels OPERABLE Applicability ACTION

1. GASEOUS RADWASTE TREATMENT SYSTEM (Common)

a. Noble Gas Activity Monitor, with Alarm and Automatic Termination of 45 1 During 8releases Release (ARE-0014)

b. Effluent System Flowrate Measuring Device (AFT-0014) 1 During releasesa 46

2. Turbine Building Vent (Each Unit)

a. Noble Gas Activity Monitor (RE-i 2839C) 1 During releasesa 47

b. Iodine and Particulate Samplers (RE-12839A & B) 1 During releasesa 51

c. Flowrate Monitor (FT-12839 or ses 46 FlSi2862)b 1 During relea 8

d. Sampler Flowrate Monitor ses 46 (1FI-13211, 2FIT-13211) 1 During relea 8

3. Plant Vent (Each Unit)

a. Noble Gas Activity Monitor 47,48 (RE-i 2442C or RE-i 2444C) 1 At all times

b. Iodine Sampler/Monitor (RE-i 2442B 51 orRE-i2444B) 1 At all times

c. Particulate Sampler/Monitor 51 (RE-12442A or RE-12444A) 1 At all times

d. Flowrate Monitor (FT-12442 or 46 12835) 1 At all times

e. Sampler Flowrate Monitor (FI-12442 46 or FI-12444) 1 At all times

4. Radwaste Processing Facility Vent (Common)

a. Particulate Monitor (ARE-i 6980) 1 During releasesa 51 pathway.

a. During releases means During radioactive releases via this

b. During emergency filtration.

3-3 VER 26

VEGP ODCM Table 3-1 (contd). Notation for Table 3-1 ACTION Statements ACTION 45 With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, the contents of the tank(s) may be released to the environment for up to 14 days provided that prior to initiating the release:

a. At least two independent samples of the tanks contents are analyzed, and

b. At least two technically qualified members of the Facility Staff independently verify the discharge line valving, and verify the release rate calculations.

Otherwise, suspend release of radioactive effluents via this pathway.

ACTiON 46 With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue provided the flowrate is estimated at least once per 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

ACTION 47 With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue provided grab samples are taken at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and these samples are analyzed for radioactivity within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

ACTION 48 With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, immediately suspend containment purging of radioactive effluents via this pathway.

ACTION 49 (Not Used)

ACTION 50 (Not Used)

ACTION 51 With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent releases via the affected pathway may continue provided samples are continuously collected with auxiliary sampling equipment.

3-4 VER 26

HL-16 NRC Written Examination KEY

93. 086A2.02 002/2/2/FP-LOW HEADER PRESSI3 .3 C/A/NEW/SRO/NRC/GCW Both units are at 100% power

- Both Diesel Fire Pumps and Jockey Pump C-2301 -P4-004 are danger tagged for maintenance.

- The following alarms are received on the Fire Computer:

FPH #1 ELEC FIRE PUMP LOW HEADER PRESSURE FPH #1 ELEC FIRE PUMP FAILURE Which one of the following correctly completes the following statement?

The Fire Protection System has had a (1 )_ and the Fire Protection LCO action is to establish a backup fire suppression supply sytem using (2)

A. (1) loss of Jockey pump C-2301 -P4-001 (2) the portable B.5.B pump within 7 days.

B. (1) loss of Jockey pump C-2301 -P4-001 (2) the Burke County EMA pumper Truck within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

C. (1) loss of fire water header pressure (2) the portable B.5.b pump within 7 days.

D (1) loss of fire water header pressure (2) the Burke County EMA pumper Truck within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Feedback 086 Fire Protection System (FPS)

Ability to (a) predict the impacts of the following malfunctions or operations on the Fire Protection System; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those malfunctions or operations:

(CFR: 41.5/43.5/45.3! 45.13)

A2.02 Low FPS header pressure K/A MATCH ANALYSIS Page 193 of 208

HL-16 NRC Written Examination KEY The question is directed toward a loss of Fire Header Pressure and loss of all Fire Pumps. The student must determine the loss and the applicable FP LCO actions to perform.

SRO 10CFR55.43 (b2)

ANSWER I DISTRACTOR ANALYSIS A. Incorrect-Normal Jockey Pump operation should maintain Fire Header Pressure approximately 125 psig. Fire Header low pressure alarm comes in a 110 psig.

Pressure has dropped below the point of just losing a Jockey Pump. Plausible because the B.5.b pump can be used in the interim until the arrival of Burke County EMA pumper truck.

B. Incorrect-Same as A above for the Jockey Pump. Burke County EMA pumper truck is the only credited backup fire suppression system.

C. Incorrect-Fire Header pressure has low enough to be below the loss of just a Jockey Pump. Other problems are occurring (i.e. leak). Pausible because the B.5.b pump can be used in the interim until the arrival of Burke County EMA pumper truck.

D. Correct-See all of above.

REFERENCES Procedure 13903-C Fire Protection System Operation Procedure 171 03A-C Annunciator Response Procedure for the Fire Alarm Computer Procedure 92040-C Fire Protection Operability and LCO Requirements VEGP learning objectives:

LO-PP-43101-04 Discuss normal operation of system jockey pumps including where they are operated from.

Page 194 of 208

Approved By S. E. Prewitt Vogtle Electric GeneratIng Plant Procedure Number Rev Date Approved 13903-C 41 Page Number

,1O/25/2010 FIRE PROTECTION SYSTEM OPERATION 3 of 88 2.0 PRECAUTIONS AND LIMITATIONS 2.1 PRECAUTIONS Ear protection should be worn in the Diesel Fire Pump Rooms when the diesels are running.

2.2 LIMITATIONS 2.2.1 The Fire Suppression Water System shall be operable with:

a. Two Fire Suppression Pumps, each with a rated capacity of 2500 gpm, with their discharge aligned to the Fire Suppression Head er.

b. Separate water supplies, each with a minimum contained volum e of 302,400 gallons (27.84 ft) as indicated on C-Ll-7955 (7956) on QPCP.

2.2.2 The Electric Fire Pump discharge relief valve is sized to provid e an adequate miniflow path.

2.2.3 Fire Water is an alternate supply for TPCW Pump Seal water.

Upon loss of Utility Water, the firewater system will automatically supply seal water to the TPCW pumps, this will result in an automatic start of the Electric Fire Pump on low header pressure.

2.2.4 The auto start of a fire water pump provides a means of detec ting system leakage. With a fire water pump already operating, this adva ntage is lost.

Therefore, when a fire water pump is operating, the operating crew should remain attentive to alarms on the fire computer and/or the plant leak detection systems as well as outside areas where buried piping exists.

Additionally, Operators should be aware that a drop in tank level indication without any accompanying alarms indicates a demand of water greater that the tank makeup, which may indicate a leak or rupture in the yard main, personnel should be dispatched to determine the source of if this occurs, the leakage.

2.2.5 To the extent possible, operators should remain clear of the Diesel Fire Pumps during start of the engine.

Per DOEJ-SM-C070400401 -001, the Portable B 5 b Pump cannot be considered a backup fire suppression system as required by FP LCO 43 Cond A or B The Portable B 5 b Pump is a defense in depth contingency for the interim period between total loss of suppression capability and arrival of Burke County EMA A, Burke County EMA pumper truck is the credited backup Printed January 14, 2011 at 14:20

Vogtle Electric Generating Plant A 1 9

Procedure Number Rev 2040-C 35 1.0 PURPOSE OPERABILITY AND LCO REQUIREMENTS 1 Page Number 5 of 256 This procedure identifies Fire Protection Limiting Conditio ns for Operation (LCD) for VEGP Fire Protection (FP) systems in accordan ce with the requirements of FSAR Table 9.5.1-10 and Nuclear Electric Insurance Limited (NEIL) insurance. It also specifies the compensatory actio ns to be taken for indications of inoperable equipment, documentation, and FP surveillances required to prove FP system equipment operability.

These FP LCOs are not a part of the VEGP Technical Spec ifications They are related in that the FSAR prescribes FP for safety-related equi pment be operable when the Tech Spec equipment is required oper abte Inoperable FSAR required FP equipment does not cause inoperability of the (VEGP Tech Spec) equipment it protects. There are also some interfaces where the Special Conditions Log, 14915, is implemented as a REQUIRED ACTION of a FP LCO.

This procedure also describes the method and documen tation necessary to document and compensate other FP impairments (non

-FSAR), because they protect personnel and property and are tracked by insu rer NEIL.

CAUTION REVISION TO THIS PROCEDURE REQUIRES SOFTWARE UPDATE TO PTC PROGRAM 2.0 DEFINITIONS 2.1 PLANNED IMPAIRMENT Intentional disabling of the Fire Protection (FP) system to prevent unwanted actuations during planned work activities. This is typical ly done by, but is not limited to, removing fuses from LSIPs and/or switchin g off zones on LZIPs.

The compensatory actions and documentation requirem ents for Planned Impairments are the same as for Discovered Impairme nts. (See Section 6.0 for Surveillances) 2.2 DISCOVERED IMPAIRMENT FP system failure to meet an LCD due to malfunction.

For the purpose of this procedure, 92040-C, a system failure is defined as any condition which requires the initiation of a fire protection LCO not due to planned maintenance or purposely taking a component out of service.

Printed January 18, 2011 at 17:57

Approved ey I I Procedure Number Rev S. E. Prewitt I Vogtle Electric Generating Plant 13903-C 41 Date Approved I Page Number 10/25/2010 I FIRE PROTECTION SYSTEM OPERATION 34 of 88 INITIALS 4.3 JOCKEY PUMP OPERATION NOTES

• Normal Jot, ration is with c maintainingr System in OFF However, . it may be necL.... j to run two Jo. to maintain header pressure above 125 psig.

• Per limitation 2.2.8, a Condition Report should be generated if two jockey pumps are required to maintain Fire Protection System pressure.

• With fire water system supplying seal water to the TPCW pumps the electric fire pump should be operated, a second Jockey Pump will not meet this demand.

4.3.1 WHEN directed to place Jockey Pump C-2301-P4-004 (in Diesel Pump House) in service, perform the following:

a. Verify FIRE WATER STORAGE TANK NO. 2 OUTLET C-HV-7930 is open.

b. Start Jockey Pump 0-2301 -P4-004 by placing C-HS-7902 to ON at PFH2.

4.3.2 WHEN directed, stop Jockey Pump C-2301 -P4-001 by placing C-HS-7901 to OFF on PFH1.

4.3.3 WHEN directed to place Jockey Pump C-2301 -P4-001 (in Electric Pump House) in service, perform the following:

a. Verify FIRE WATER STORAGE TANK No. 1 OUTLET C-HV-7933 is open.

b. Start Jockey Pump C-2301 -P4-001 by placing C-HS-7901 to ON at PFH1.

4.3.4 WHEN directed, stop Jockey Pump C-2301 -P4-004 by placing C-HS-7902 to OFF on PFH2.

Printed January 15, 2011 at 14:27

Approved by . Procedure Number Rev T. G. Petrak Vogtle Electric Generating Plant 92040-C 35 Date Approved FIRE PROTECTION OPERABILITY AND LCO REQUIREMENTS Page Number 2/28/2010 21 of 256 FP LCO 4.3 - SUPPRESSION SYSTEM OPERABILITY The Fire Suppression Water System shall be OPERABLE with:

1. At least two (2) fire suppression pumps, excluding the jockey pumps, with their discharge aligned to the fire suppression header.

2. Separate water supplies, each with a minimum contained volume of 302,000 gallons (27.84 feet) as shown on Plant Technical Data Book (PTDB) Tab 4.6.

3. An OPERABLE flow path capable of taking suction from the north tank or the south tank and transferring the water through distribution piping with OPERABLE sectionalizing control or isolation valves to the yard hydrant curb valves, the last valve ahead of the water flow alarm device on each sprinkler, and the last valve ahead of the control valve on each Sprinkler System required to be OPERABLE per Tables D, E, and F of this procedure.

FSAR / NEIL APPLICABILITY: At all times ACTIONS CONDITION REQUIRED ACTION DOMPLETION TIME A. One of the required two fire A.1 Restore operable 7 days pumps inoperable OR AND/OR A.2 Establish backup fire One water supply tank suppression supply inoperable system OR A.3 Begin plant shutdown B. Three fire pumps inoperable 8.1 Establish backup fire 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> suppression supply QE system Both water supply tanks inoperable B.2 Begin plant shutdown 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Printed January 15, 2011 at 14:04

Approved by I T. G. Petrak Date Approved Vogtle Electric Generating Plant I FIRE PROTECTION OPERABILITY AND LCO REQUIREMENTS A I Procedure Number Rev 92040-C 35 Page Number 1 2/28/2010 I 22 of 256 (continued)

CONDITION REQUIRED ACTION OMPLETION TIME C. Fire suppression water system C.1 Establish alternate fire 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> otherwise inoperable suppression water supply to the inoperable portion SURVEILLANCE REQUIREMENTS - SUPPRESSION SYSTEM SURVEILLANCE FREQUENCY 4.3.1 The fire suppression water system shall be demonstrated OPERABLE:

4.3.1.1 By verifying the contained water supply volume. 7 days 4.3.1.2 By verifying that each valve that is accessible during Quarterly plant operation (manual, power-operated, or automatic) in the flow path is in its correct position.

4.3.1.3 By Cycling each testable valve in the flow path through 12 months at least one complete cycle of full travel.

4.3.1.4 By performing a system functional test, which includes 18 months simulated automatic actuation of the system throughout its operating sequence.

4.3.1 .5 By flushing the yard loop portions that feed systems 18 months protecting safe shutdown capability.

4.3.1.6 By cycling each valve in the flow path that is not 18 months testable during plant operation through at least one complete cycle of full travel.

4.3.1 .7 By performing a flow test of the system in accordance 5 years with Section 16, Chapter 8 of the Fire Protection handbook, 15th Edition, published by the National Fire Protection Association.

(continued)

Printed January 15, 2011 at 14:04

Approved by T. G. Petrak Date Approved I Vogtle Electric Generating Plant A I Procedure Number Rev I 92040-C 35 FIRE PROTECTION OPERABILITY AND LCO REQUIREMENTS Page Number 12/28/2010 I 23 of 256 (continued SURVEILLANCE FREQUENCY 4.3.1 .8 During each cold shutdown exceeding 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, by Cold Shutdown verifying that each inaccessible valve in the flowpath is in its correct position, unless performed in the previous month.

4.3.2 Each diesel engine driven fire pump shall be demonstrated OPERABLE by:

4.3.2.1 a. Verifying each fuel storage tank contains at 31 days least 90 gallons of fuel.

b. Verifying each diesel starts from ambient conditions and operates for at least 30 minutes on recirculation flow.

4.3.2.2 Verifying that a sample of diesel fuel from each fuel 92 days storage tank, obtained in accordance with ASTM-D4057-81, has a kinematic viscosity between 1.9 and 4.1 centistokes at 40°C when tested in accordance with ASTM-D445-82 and an acceptable clear and bright appearance when tested in accordance with ASTM-D41 76-82.

4.3.2.3 Subjecting each diesel to an inspection in accordance 18 months with procedures prepared in conjunction with the manufacturers recommendations for its class of service.

4.3.2.4 Verifying that each pump starts within its design 18 months setpoint range.

(continued)

Printed January 15, 2011 at 14:04

I Procedure Number Rev Vogtle Electric Generating Plant PERABILITY AND LCO REQUIREMENTS I 92040-C 35 Page Number 12/28/2010 I of 256 24 (continued)

SURVEILLANCE FREQUENCY 4.3.3 Each fire pump diesel starting 24-volt battery bank and charger shall be demonstrated OPERABLE:

7 days 4.3.3.1 When not using sealed batteries by verifying that:

a. The electrolyte level of each battery is above the plates if applicable.

b. The overall battery voltage is greater than or equal to 24 volts.

4.3.3.2 Verify that the specific gravity is appropriate for 92 days continued service of the battery when not using sealed batteries.

4.3.3.3. Verify the batteries, the top of the cell plates when 18 months not using sealed batteries, and battery racks show no visual indication of physical damage or abnormal deterioration.

4.3.3.4 The battery-to-battery and terminal connections are 18 months clean, free of corrosion, and coated with anticorrosion material.

4.3.4 The electric motor driven fire pump shall be demonstrated OPERABLE by:

4.3.4.1 Starting and operating it for at least 15 minutes on 31 days recirculation flow.

4.3.4.2 By verifying the pump starts within its design 18 months setpoint range.

Printed January 15, 2011 at 14:04

Approved By 11 Rev S. E. Prewitt Vogtle Electric Gerating Plant I 17103A-C 34.1 Date Approved Page Number 9/17/2010 ANNUNCIATOR RESPONSE PROCEDURES FOR FIRE ALARM COMPUTER 108 of 182 I

TABLE 2 SECTION C - WATER SUPPLY SYSTEM (Refer to 11 903-C, 1 3903-C, 17221 -C or 1 7222-C for Guidance)

DESCRIPTION INITIATING SETPOINT PANEL] PROBABLE CAUSE CORRECTIVE ACTION DEVICE DEVICE LOCATION FIRE PUMP LOCKED IN STOP CHS-7904B F P H #1 TAMPER, MAINTENANCE DETERMINE CAUSE AND SEE 11903-C F P I-i #1 JOCKEY PUMP STOPPED CHS-7901 F P H #1 TAMPER, MAINTENANCE DETERMINE CAUSE AND SEE 13903-C F P H #1 LOW HEADER PRESSURE CPSL-7905 110 PSIG F P H #1 LEAK, Seal flow to TPCW system, LOCATE WATER RELEASE AND SEE 1 3903-C SYSTEM ACTUATION ATTACHMENT 1 FOR TROUBLESHOOTING AND TAKE NECESSARY ACTIONS FIRE WATER STORAGE TANK 1 LOW CLSHL-18073 14.5 FEET F P H #1 LEAK SYSTEM ACTUATION INCREASE MAKEUP TO TANK LEVEL FIRE WATER STORAGE TANK HIGH CLSHL-1 8073 29.1 FEET F P H #1 TANK LEVEL NOT MONITORED STOP TANK MAKEUP LEVEL ELEC FIRE PUMP LOW HEADER CPSL-7953 110 PSIG F P H #1 L.EAK, SYSTEM ACTUATION LOCATE WATER RELEASE AND SEE 13903-C PRESSURE FPH #1 ATTACHMENT 1 FOR TROUBLESHOOTING AND TAKE NECESSARY ACTIONS F P H #1 ELEC FIRE PUMP FAILURE CPFHI TROUBLE F P H #1 TAMPER.PUMP INOPERABLE INVESTIGATE CAUSE OF PUMP FAILURE DIESEL PUMP #1 C-2301-P5-FP1 TROUBLE F P H #2 TAMPER, PUMP INOPERABLE INVESTIGATE CAUSE OF PUMP FAILURE DIESEL FP#1 HANDSWITCH NOT IN CHS-7790B F P H #2 TAMPER, MAINTENANCE DETERMINE CAUSE AND SEE 11903-C AUTO DIESEL PUMP #1 RUNNING C-2301-P5-FP1 95 PSIG F P H #2 LEAK, SYSTEM ACTUATION DETERMINE CAUSE AND SEE 13903-C DIESEL PUMP #1 LOW FUEL CLSL-7992 29 INCHES F P H #2 TANK LEVEL LOW INITIATE TANK REFILL DIESEL PUMP #2 C-2301-P5-FP2 TROUBLE F P H #2 TAMPER, PUMP INOPERABLE INVESTIGATE CAUSE OF PUMP FAILURE DIESEL FP#2 HANDSWITCH NOT IN CHS-7907B F P H #2 TAMPER, MAINTENANCE DETERMINE CAUSE AND SEE 1 1903-C AUTO DIESEL PUMP #2 RUNNING C-2301-P5-FP2 85 PSIG F P H #2 LEAK, SYSTEM ACTUATION DETERMINE CAUSE AND SEE 13903-C DIESEL PUMP #2 LOW FUEL CLSL-9076 29 INCHES F P I-I #2 TANK LEVEL LOW INITIATE TANK REFILL FIRE WATER STORAGE TANK 2 LOW CLSHL-7989 14.5 FEET F P H #2 LEAK, SYSTEM ACTUATION INCREASE MAKEUP TO TANK LEVEL

HL-16 NRC Written Examination KEY

94. G2. 1.23 003/3/N/AJCOND OF OPS/4.4 C/A/NEW/SROINRC/GCW The following conditions exist on Unit 2:

- Charging flow at 93 gpm.

- Letdown flow at 75 gpm.

- Seal leakoff flow at 12 gpm.

- 2RE-0724 Rate of Change (ROC) indicates 75 gpd/hr and has maintained that value for the last 21 minutes.

- Chemistry has identified SG #2 has having the leak.

- The operators have entered 18009-C, Steam Generator Tube Leakage.

Which ONE of the following would be the CORRECT (1) procedure response to take and (2) the required Tech Spec actions and completion times for LCO 3.4.13 RCS Operational LEAKAGE?

A. (1) Initiate to 18013-C, Rapid Power Reduction.

(2) Identified leakage has been exceeded. Be in Mode 3 in 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

B (1) Initiate to 18013-C, Rapid Power Reduction.

(2) Primary to secondary leakage has been exceeded. Be in Mode 3 in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

C. (1) Initiate 12004-C, Power Operation (Model).

(2) Identified leakage has been exceeded. Be in Mode 3 in 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

D. (1) Initiate 12004-C, Power Operation (Model).

(2) Primary to secondary leakage has been exceeded. Be in Mode 3 in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

Feedback 2.1 Conduct of Operations 2.1.23 Ability to perform specific system and integrated plant procedures during all modes of plant operation.

(CFR: 41.10/43.5/45.2/45.6)

K/A MATCH ANALYSIS Question tests the ability of the student to determine the proper procedure transition Page 195 of 208

HL-1 6 NRC Written Examination KEY with the parameters given and Tech Spec implications with shutdown time.

SRO 10CFR55.43 (b2)

ANSWER I DISTRACTOR ANALYSIS A. Incorrect-Plausible because 18013-C is the correct procedure beca use the leak rate is 6 gpm (>5 gpm in 18009-C for 18013-C use). TS Identified Leakag e limit is 10 gpm and this is not exceeded. ID leakage completion time is 4 hrs Condition A, but to reduce leakage to within limits and not shutdown to Mode 3.

B. Correct-i 8013-C is proper procedure because of the leak rate Primary to Secondary leakage through any one SG has been exce (> 5 gpm).

eded (150 gpm limit) with 6 gpm which equals 8640 gpd. Condition B is entered in 3.4.13.

C. Incorrect-i 2004-C is plausible if the student miscalculates the leakag e and moves to the RE-724 Rate of Change value. ID leakage plausible per A above.

D. Incorrect-12004-C above in C. Plausible because Primary to Second ary leakage is exceeded. Condition B is entered in 3.4.13 and shutdown to Mode 3 in 6 hrs.

REFERENCES Tech Spec 3.4.13 RCS Operational Leakage Tech Spec Definition of Leakage 18009-C Steam Generator Tube Leakage 18013-C Rapid Power Reduction VEGP learning objectives:

LO-LP-60309-05 Given the entire AOP, describe:

a. Purpose of selected steps

b. How and why the step is being performed

c. Expected response of the plant/parameter(s) for the step LO-LP-60309-12 Discuss the major actions taken for a leaking SG for a leak exceeding shutdown requirements.

Page 196 of 208

Approved By J. B. Stanley VogUe Electric Generating Plant Procedure Number Rev 18009-C 28.2 STEAM GENERATOR TUBE LEA Page Number K

ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

d. Close CCP normal miniflow valves:

• HV-811OCCP-A&B COMMON MINIFLOW HV-81 1 1A CCP-A MINIFLOW

. HV-8111BCCP-B MINIFLOW

_e. Trip the reactor.

_f. Initiate 19000-C, E-0 REACTOR TRIP OR SAFETY INJECTION.

_g. GotoStepli.

_5. Check Ieakrate less than 5 gpm as 5. Perform the following:

determined by [chargIng (letdown

- +

seal leakoff)] mismatch.

_a. Initiate 18013-C, RAPID POWER REDUCTION.

_b. Be in Mode 3 within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

_c. GotoStepli.

Printed January 15, 2011 at 18:06

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18009-C 28.2 Page Numbe; STEAM GENERATOR TUBE LEAK CI3o/o9 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE If available, both RE-081 0 and RE-0724 should be used to determine the leakage rate of change in Step 6 RNO; however, if only one of the two radiation monitors is OPERABLE, then the reading from the OPERABLE monitor should be used to determine leakage rate of change.

6. Check leakage rate of change:

a. Greater than or equal to 30 a. Perform the following:

GPD/HR based on a 20 minute trend: _1) After a 20 minute trend has elapsed, determine the leakage rate of change.

IPC Points:

jf leakage rate of RE-0810: UR6810(GPD) change is greater than UR681 1 (ROC) or equal to 30 gpd/hr, THEN go to Step 7.

RE-0724: UR6724(GPD)

UR6725(ROC) -OR IF leakage rate of change is less than 30 gpd/hr, THEN go to Step 8.

Printed January 15, 2011 at 18:06

Approved By Tprocefjure Number Rev J. B. Stanley Vogtle Electric Generating Plant 118009-C 28.2 Date Approved Page Number

/30/09 STEAM GENERATOR TUBE LEAK 7 of 34 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

_7. Check leakage rate LESS THAN

7. Perform the following:

75 GPD.

_a. Initiate 18013-C, RAPID POWER REDUCTION.

_b. Be less than 50% power within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

_c. Be in Mode 3 within the next 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

_d. GotoStepil.

_8. Check leakage rate LESS THAN

8. Perform the following:

150 GPD.

_a. Initiate 12004-C, POWER OPERATION (MODE 1).

_b. Be in Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

_c. GotoStepli.

9. Check leakage rate LESS THAN 9.

if leakrate has remained greater 75 GPD. than or equal to 75 gpd for one hour, THEN perform the following:

_a. Initiate 12004-C, POWER OPERATION (MODE 1).

_b. Be in Mode 3 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

c. GotoStepil.

Printed January 15, 2011 at 18:06

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18009-C 28.2 Page Number STEAM GENERATOR TUBE LEAK ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

10. Perform the following:

a. Check leakage rate GREATER _a. Return to procedure and THAN 5 GPD. step in effect.

_b. Check continued operation b. Perform the following:

allowed by Operations Management. _1) Initiate 12004-C, POWER OPERATION (MODE 1).

_2) Shutdown to Mode 3.

_3) GotoStepli.

_c. Go to ATTACHMENT A, OPERATION WITH A MINOR TUBE LEAK.

1 1. Evaluate plant conditions and initiate NMP-EP-1 10, EMERGENCY CLASSIFICATION DETERMINATION AND INITIAL ACTION if necessary.

Printed January 15, 2011 at 18:06

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 11801 3-C 7.2 DateApproved 4j/24/o9 RAPID POWER REDUCTION I PageNumber 1 of 11 ABNORMAL OPERATING PROCEDURE CONTINUOUS USE PURPOSE This procedure provides instructions when plant conditions require a rapid load reduction or plant shutdown in a controlled manner in the judgment of the SS.

£ntry Condition Target Approx. Time @ 3-5°/JmIn 1701 5-D05 MFPT High Vibrations <70% RTP 6-10 minutes 1701 5-E01 1701 9-B04 Condenser Low Vacuum Vacuum >22.42 Hg and STABLE 18025-C orCirc Water Pump Trip or RISING or Loss of Utility Water 18009-C SG Tube Leak (75 gpd with an <50% RTP within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 10-17 minutes ROC 30 gpdlhr) 18009C SG Tube Leak (5 gpm) 20% RTP within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> & trip 16-27 minutOS .:.

reactor ..

18039-C Confirmed Loose Part 20% RTP quickly 16-27 minutes SS determination based on As determined by the SS plant conditions MAJOR ACTIONS

• Perform Pre-job Brief.

• Perform rapid power reduction.

Printed January 15, 2011 at 18:07

RCS Operational LEAKAGE 3.4.13 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.13 RCS Operational LEAKAGE LCO 3.4.13 RCS operational LEAKAGE shall be limited to:

a. No pressure boundary LEAKAGE;

b. 1 gpm unidentified LEAKAGE;

c. 10 gpm identified LEAKAGE; and

d. 150 gallons per day primary to secondary LEAKAGE through any one steam generator (SG).

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

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. RCS operational A.1 Reduce LEAKAGE to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> LEAKAGE not within within limits.

limits for reasons other than pressure boundary LEAKAGE or primary to secondary LEAKAGE.

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

B.2 Be in MODE 5. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> OR Pressure boundary LEAKAGE exists.

OR Primary to secondary LEAKAGE not within limit.

Vogtle Units 1 and 2 3.4.13-1 Amendment No. 144 (Unit 1)

Amendment No. 124 (Unit 2)

RCS Operational LEAKAGE 3.4.13 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR ------------ ----------*

3.4.13.1 -----------

1. Not required to be performed in MODE 3 or 4 until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of steady state operation.

2. Only required to be performed during steady state operation.

3. Not applicabe to primary to secondary LEAKAGE.

Perform RCS water inventory balance. Once within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after achieving steady state operation AND 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> thereafter SR 3.4.13.2 ---- NOTE Not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishment of steady state operation.

Verify primary to secondary LEAKAGE is 150 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> gallons per day through any one SG.

Vogtle Units 1 and 2 3.4.13-2 Amendment No. 144 (Unit 1)

Amendment No. 124 (Unit 2)

Definitions 1.1 1.1 Definitions (continued)

E AVERAGE

- E shall be the average (weighted in proportion to DISINTEGRATION ENERGY the concentration of each radionuclide in the reactor coolant at the time of sampling) of the sum of the average beta and gamma energies per disintegration (in MeV) for isotopes, other than iodines, with half lives> 14 minutes, making up at least 95% of the total noniodine activity in the coolant.

ENGINEERED SAFETY The ESF RESPONSE TIME shall be that time FEATURE (ESF) RESPONSE interval from when the monitored parameter exceeds its TIME ESF actuation setpoint at the channel sensor until the ESF equipment is capable of performing its safety function (i.e.,

the valves travel to their required positions, pump discharge pressures reach their required values, etc.). Times shall include diesel generator starting and sequence loading delays, where applicable. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured.

In lieu of measurement, response time may be verified for selected components provided that the components and the methodology for verification have been previously reviewed and approved by the NRC.

LEAKAGE LEAKAGE shall be:

a. Identified LEAKAGE

1. LEAKAGE, such as that from pump seals or valve packing (except reactor coolant pump (RCP) seal water injection or leakoff), that is captured and conducted to collection systems or a sump or collecting tank;

2. LEAKAGE into the containment atmosphere from sources that are both specifically located and known either not to interfere with the operation of leakage detection systems or not to be pressure boundary LEAKAGE; or

3. Reactor Coolant System (RCS) LEAKAGE through a steam generator to the Secondary System (primary to secondary LEAKAGE);

(continued)

Vogtle Units 1 and 2 1.1-3 Amendment No. 144 (Unit 1)

Amendment No. 124 (Unit 2)

Definitions 1.1 1.1 Definitions LEAKAGE b. Unidentified LEAKAGE (continued)

All LEAKAGE (except RCP seal water injection or leakoff) that is not identified LEAKAGE;

c. Pressure Boundary LEAKAGE LEAKAGE (except primary to secondary LEAKAGE) through a nonisolable fault in an RCS component body, pipe wall, or vessel wall.

MASTER RELAY TEST A MASTER RELAY TEST shall consist of energizing each master relay and verifying the OPERABILITY of each relay.

The MASTER RELAY TEST shall include a continuity check of each associated slave relay.

MODE A MODE shall correspond to any one inclusive combination of core reactivity condition, power level, average reactor coolant temperature, and reactor vessel head closure bolt tensioning specified in Table 1.1-1 with fuel in the reactor vessel.

OPERABLE OPERABILITY A system, subsystem, train, component, or device shall be OPERABLE or have OPERABILITY when it is capable of performing its specified safety function(s) and when all necessary attendant instrumentation, controls, normal or emergency electrical power, cooling and seal water, lubrication, and other auxiliary equipment that are required for the system, subsystem, train, component, or device to perform its specified safety function(s) are also capable of performing their related support function(s).

PHYSICS TESTS PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of the reactor core and related instrumentation. These tests are:

(continued)

Vogtle Units I and 2 1.1-4 Amendment No. 144 (Unit 1)

Amendment No. 124 (Unit 2)

HL-16 NRC Written Examination KEY

95. G2. 1.44 OO1/31N/A/COND OF OPS-R O DUTIE/3.8 C/A/BANK HARRIS2009/SRO/NRC/GCW The unit is in Mode 6 with core reload in progress with the follow ing conditions.

- Rx Cavity level flooded to 220 foot elevation.

- RHR pump B in service.

- RHR pump A tagged out for outage maintenance work.

The Fuel Handling Supervisor (FHS) requests the Shift Supe rvisor to turn off RHR pump B to perform core loading. The FHS estimates it will take 20 30 minutes to load the required assemblies.

The Shift Supervisor should(1)____ and the basis for this action is to perform core alterations in the vicinity of the Reactor Vessel (2)

A (1) agree to stop the running RHR pump (2) Hot Legs B. (1) not allow the running RHR pump to be stopped (2) Hot Legs C. (1) not allow the running RHR pump to be stopped (2) Cold Legs D. (1) agree to stop the running RHR pump (2) Cold Legs Page 197 of 208

HL-16 NRC Written Examination KEY Feedback 2.1 Conduct of Operations 2.1.44 Knowledge of RO duties in the control room during fuel handling, such as responding to alarms from the fuel handling area, communication with the fuel storage facility, systems operated from the control room in support of fueling operations, and supporting instrumentation.

(CFR: 41.10/43.7/45.12)

K/A MATCH ANALYSIS Questions presents a scenario during refueling where and RHR pump has been requested to shut down for fuel movement in the area of Hot Leg # 4. The FHS estimates 20 30 minutes required. The SS has to determine whether or not to allow stopping the RHR pump.

SRQ 10CFR55.43 (b2)

ANSWER I DISTRACTOR ANALYSIS A. Correct. Pump may be stopped to allow movement in the vicinity of the Hot Legs.

B. Incorrect. Pump may be stopped to allow movement in the vicinity of the Hot Legs.

C. Incorrect. Pump may be stopped to allow movement in the vicinity of the Hot Legs.

D. Incorrect. Pump may be stopped to allow movement in the vicinity of the Hot Legs.

REFERENCES Tech Spec 3.9.5 and bases Residual Heat Removal (RHR) and Coolant Circulation High Water Level.

Harris 2009 SRO Q #94 VEGP learning objectives:

LO-PP-39213-01 For any given item in section 3.9 of Tech Specs, be able to:

a. State the LCQ

b. State any 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or less actions Page 198 of 208

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

---

NOTE The required RHR loop may be removed from operation for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> per 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> period, provided no operations are permitted that would cause a reduction of the Reactor Coolant System boron concentration.

APPLICABILITY: MODE 6 with the water level 23 ft above the top of reactor vessel flange.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. RHR loop requirements A.1 Suspend operations Immediately not met. involving a reduction in reactor coolant boron concentration.

AND A.2 Suspend loading Immediately irradiated fuel assemblies in the core.

AND A.3 Initiate action to satisfy Immediately RHR loop requirements.

AND (continued)

Vogtle Units I and 2 3.9.5-1 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

2.1 Conduct of Operations 2.1.44 Knowledge of RO duties in the control room during fuel handling, such as responding to alarms from the fuel handling area, communication with the fuel storage facility, systems operated from the control room in support of fueling operations, and supporting instrumentation.

(CFR: 41.10/43.7/45.12)

K!A MATCH ANALYSIS ANSWER I DISTRACTOR ANALYSIS A. Correct. Allowed up to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> out of every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> per Tech Specs for RHR mode 6 with cavity flooded up.

B. Incorrect. Stopping RHR is allowed per Tech Specs for fuel movement. This is a correct reason per Tech Spec bases that RHR system should remain running.

C. Incorrect. Stopping RHR is allowed per Tech Specs for fuel movement. RHR flow should be > 3000 gpm (>3200 gpm indicated in mode 6). Plausible candidate may consider reducing flow for fuel movement. Flow should be >3200 indicated.

D. Incorrect. Plausible, time limit is 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> per 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> time period per Tech Specs.

RHR is required to be operating and SFP cooling could help remove decay heat.

Added to make distractor seem more plausible.

REFERENCES Tech Spec 3.9.5 and bases Residual Heat Removal (RHR) and Coolant Circulation High Water Level.

Vogtle 2006 NRC SRO exam (HL-14, not in last 2)

VEGP learning objectives:

LO-PP-39213-01 For any given item in section 3.9 of Tech Specs, be able to:

a. State the LCO

b. State any 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or less actions Page: 186 of 187 1/14/2011

RHR and Coolant Circulation High Water Level B 3.9.5 BASES APPLICABLE RHR and Coolant Circulation High Water Level satisfies Criterion 4 SAFETY ANALYSES of 10 CFR 50.36 (c)(2)(ii).

(continued)

LCO Only one RHR loop is required for decay heat removal in MODE 6, with the water level 23 ft above the top of the reactor vessel flange.

Only one RHR loop is required to be OPERABLE, because the volume of water above the reactor vessel flange provides backup decay heat removal capability. At least one RHR loop must be OPERABLE and in operation to provide:

a. Removal of decay heat;

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

c. Indication of reactor coolant temperature.

An OPERABLE RHR loop includes an RHR pump, a heat exchanger, valves, piping, instruments, and controls to ensure an OPERABLE flow path and to determine the low end temperature. The flow path starts in one of the RCS hot legs and is returned to the RCS cold legs.

The LCO is modified by a Note that allows the required operating RHR loop to be removed from service for up to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> per 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> period provided no operations are permitted that would cause a reduction of the RCS boron concentration. Boron concentration reduction is prohibited because uniform concentration distribution cannot be ensured without forced circulation. This permits operations such as core mapping or alterations in the vicinity of the reactor vessel hot leg nozzles and RCS to RHR isolation valve testing.

During this 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> period, decay heat is removed by natural convection to the large mass of water in the refueling cavity.

APPLICABILITY One RHR loop must be OPERABLE and in operation in MODE 6, with the water level 23 ft above the top of the reactor vessel flange, to provide decay heat removal and mixing of the borated coolant. The 23 ft water level was selected (continued)

Vogtle Units 1 and 2 B 3.9.5-2 Rev.1-10/01

DQ 2009B NRC SRO Rev Final (9-

94. Given the following plant conditions:

- The Plant is in Mode 6

- GP-009, Refueling Cavity Fill, Refueling and Drain of the Refueling Cavity, is in progress

• A RHR pump is in service to provide core cooling during refueling operations

- B RHR pump is operable and in standby The Refueling Team has requested that the A RHR pump be secured temporarily lAW Technical Specifications for the above conditions, which ONE of the following completes the statement below?

The operating RHR loop may be secured for a maximum of up to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> per (1) to perform Core alterations in the vicinity of the Reactor Vessel (2 A. (1) 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> period (2) cold legs B. (1) 4hourperiod (2) cold legs C. (1) 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> period (2) hot legs D. (1) 4hourperiod (2) hot legs Wednesday, December 09, 2009 12:18:32 PM 94

HL-16 NRC Written Examination KEY

96. G2.2. 12001 /31N/AJSURV PROCEDURES/4. 1 C/AILOIT BANKJSRO/NRC/GCW Initial conditions:

- The unit is at 100% power

- A surveillance has a specified periodicity of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />

- The surveillance was last performed 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br /> ago

- It normally takes approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> to complete the surveillance Which one of the following demonstrates the correct use of Surveillance Requirement (SR) Applicability (SR 3.0.2) of the VEGP Technical Specifications for this situation?

A Ensure the surveillance is performed in the next 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />.

B. Ensure that the surveillance is promptly completed in the next hour.

C. Declare the LCO not met if the surveillance is not completed in the next hour.

D. Apply the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> delay rule to allow time to properly complete the surveil lance.

Page 199 of 208

HL-16 NRC Written Examination KEY Feedback 2.2 Equipment Control 2.2.12 Knowledge of surveillance procedures.

(CFR: 41 .10/45.13)

K/A MATCH ANALYSIS The question applies the use of general Tech Spec surveillance requirement knowledge and the ability to apply it.

SRO 10CFR55.43 (b2)

ANSWER I DISTRACTOR ANALYSIS A. Correct-SR 3.0.2 states that an SR is met if it is performed within 1.25 times the interval specified in the Frequency. This is measured from the previous performance or as measured from the time a specified condition of the Frequency is met. 24 hr periodicity allows for a 30 hr time. The surveillance was performed 23 hrs ago, so allowance would be within the 7 hrs.

B. Incorrect-Completion time extensions are allowed per SR 3.0.2 C. Incorrect-See A.

D. Incorrect-SR 3.0.3 would allow a 24 hr delay time if the surveillance is missed.

Plausible if 3.0.2 and 3.0.3 become crossed. The surveillance in the question is not late for the Frequency and therefore the 24 delay time cannot be used.

REFERENCES Tech Spec 1.0 Use and Application (1.4 Frequency example 1.4-1)

Tech Spec SR 3.0.2 VEGP learning objectives:

LO-LP-39204-04 State the allowable time intervals for extension of surveillances.

State the result of failure to perform surveillances within this period.

Page 200 of 208

Frequency 1.4 1.4 Frequency EXAM PLES EXAMPLE 1.4-1 SINGLE FREQUENCY (continued)

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY Perform CHANNEL CHECK. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Example 1.4-1 contains the type of SR most often encountered in the Technical Specifications (TS). The Frequency specifies an interval (12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />) during which the associated Surveillance must be performed at least one time. Performance of the Surveillance initiates the subsequent interval. Although the Frequency is stated as 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, an extension of the time interval to 1.25 times the stated Frequency is allowed by SR 3.0.2 for operational flexibility. The measurement of this interval continues at all times, even when the SR is not required to be met per SR 3.0.1 (such as when the equipment is inoperable, a variable is outside specified limits, or the unit is outside the Applicability of the LCO). If the interval specified by SR 3.0.2 is exceeded while the unit is in a MODE or other specified condition in the Applicability of the LCO, and the performance of the Surveillance is not otherwise modified (refer to Example 1.4-3), then SR 3.0.3 becomes applicable.

If the interval as specified by SR 3.0.2 is exceeded while the unit is not in a MODE or other specified condition in the Applicability of the LCO for which performance of the SR is required, then SR 3.04 becomes applicable. The Surveillance must be performed within the Frequency requirements of SR 3.0.2, as modified by SR 3.0.3, prior to entry into the MODE or other specified condition or the LCO is considered not met (in accordance with SR 3.0.1) and LCO 3.0.4 becomes applicable.

(continued)

Vogtle Units I and 2 1.4-2 Amendment No.137 (Unit 1)

Amendment No. 116 (Unit 2)

SR Applicability 3.0 3.0 SURVEILLANCE REQUIRE MENT (SR) APPLICABILITY SR 3.0.1 SRs shall be met during the MO DES or other specified conditions Applicability for individual LCOs, in the unless otherwise stated in the SR.

Failure to meet a Surveillance, whe ther such failure is experienced dur the performance of the Surveillanc ing e or between performances of the Surveillance, shall be failure to mee t the LCO. Failure to perform Surveillance within the specified a Frequency shall be failure to mee LCO except as provided in SR 3.0 t the

.3. Surveillances do not have to performed on inoperable equipment be or variables outside specified limits.

SR 3.0.2 The specified Frequency for each SR performed within 1.25 times the inte is met if the Surveillance is rva measured from the previous perform l specified in the Frequency, as ance or as measured from the tim specified condition of the Freque ea ncy is met.

For Frequencies specified as on ce, the above interval extension not apply. does If a Completion Time requires per iodic basis, the above Frequency extensio performance on a once per. .

n applies to each performance afte the initial performance. r Exceptions to this Specification are stated in the individual Specificati ons.

SR 3.0.3 If it is discovered that a Surveillanc e was not performed within its spe Frequency, then compliance with cified the requirement to declare the met may be delayed, from the time LCO not of the limit of the specified Frequency discovery, up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or up to

, whichever is greater. This dela period is permitted to allow perform y ance of the Surveillance. A risk evaluation shall be performed for any Surveillance delayed greater 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and the risk impact sha than ll be managed.

If the Surveillance is not performed within the delay period, the LCO immediately be declared not met must

, and the applicable Condition(s) entered. must be (continued)

Vogtle Units I and 2 3.0-4 Amendment No. 125 (Unit 1)

Amendment No. 103 (Unit 2)

HL-16 NRC Written Examination KEY

97. G2.2.44 001/3/N/A/CR INDICATIONS/4.4 MEM JNEW/SRO/NRC/GCW Given the following plant conditions:

- Reactor power is being held stable at 4%.

- The crew is awaiting for the oncomimg crew to return from JIT training.

Both Intermediate Range Nis are starting to show erratic indications. Engineering has determined the Nis have experienced a com mon mode failure.

Which of the following is the correct Tech Spe c actions for the conditions?

A. Reduce THERMAL POWER to < P-6 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

B. Increase THERMAL POWER to> P-1O with in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

C. Restore channel(s) to OPERABLE status prior to increasing THERMAL POWER to> P-1O.

D Suspend operations involving positve react ivity changes AND reduce THERMAL POWER to < P-6 within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

Page 201 of 208

HL-16 NRC Written Examination KEY Feedback 2.2 Equipment Control 2.2.44 Ability to interpret control room indications to verify the status and operation of a system, and understand how operator actions and directives affe plant and system conditions. ct (CFR: 41.5/43.5145.12)

KIA MATCH ANALYSIS Question directs the student to the indication s of failing IR NIS channels and determining the operational status of the sys tem. Also determination of the required actions to take.

SRO 10CFR55.43 (b2)

ANSWER I DISTRACTOR ANALYSIS A. Incorrect-Plausible because this is the actio n performed with one IR channel mop. (TS 3.3.1 RTS Instrumentation-Condition F, Required Action F.1)

B. Incorrect-Plausible because this is the actio n performed with one IR channel mop. (TS 3.3.1 RTS Instrumentation-Co ndition F, Required Action F.2)

C. Incorrect-Plausible because this is the actio n for one or two IR channels mop, but with power < P-6 and increasing power to> P-6 instead of P-lU. (TS 3.3.1 RTS Instrumentation-Condition H, Require d Action H.1)

D. Correct-Power> P-6 and < P-lU with two IR channels mop, this action is true.

(TS 3.3.1 RTS Instrumentation-Condition G, Required Action G.1 and G.2)

REFERENCES Tech Spec 3.3.1 Reactor Trip System (RTS

) Instrumentation, Conditions F, G and H VEGP learning objectives:

LO-PP-1 7201-05 Discuss all applicable Tec hnical Specification associated with the Source & Intermediate Range Nuclear Inst rumentation to include (from memory):

a. All LCOs

b. Applicability

c. All 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> actions Page 202 of 208

RTS Instrumentation 3.3.1 3.3 INSTRUMENTATION 3.3.1 Reactor Trip System (RTS) Instrumentation LCO 3.3.1 The RTS instrumentation for each Function in Table 3.3.1-1 shall be OPERABLE.

APPLICABILITY: According to Table 3.3.1-1.

ACTIONS Separate Condition entry is allowed for each NOTE Function.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more Functions A.1 Enter the Condition Immediately with one or more referenced in required channels Table 3.3.1-1 for the inoperable, channel(s).

B. One Manual Reactor Trip B.1 Restore channel to 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> channel inoperable. OPERABLE status.

OR B.2 Be in MODE 3. 54 hours6.25e-4 days <br />0.015 hours <br />8.928571e-5 weeks <br />2.0547e-5 months <br /> C. NOTE C.1 Restore channel or train While this LCO is not met 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> to OPERABLE status.

for Functions 1, 17, 18, or 19 in MODES 3, 4, OR or 5, closing the reactor trip breakers is not C.2 Open RTBs.

permitted. 49 hours5.671296e-4 days <br />0.0136 hours <br />8.101852e-5 weeks <br />1.86445e-5 months <br /> One channel or train inoperable.

(continued)

Vogtle Units 1 and 2 3.3.1-1 Amendment No. 137 (Unit 1)

Amendment No. 116 (Unit 2)

RTS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. One Power Range ----

NOTES Neutron Flux High 1. A channel may be channel inoperable, bypassed for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for surveillance testing and setpoint adjustment.

2. Refer to LCO 3.2.4 for an inoperable power range channel.

D.1 Place channel in trip. 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> OR D.2 Be in MODE 3. 78 hours9.027778e-4 days <br />0.0217 hours <br />1.289683e-4 weeks <br />2.9679e-5 months <br /> (continued)

Vogtle Units 1 and 2 3.3.1-2 Amendment No. 143 (Unit 1)

Amendment No. 123 (Unit 2)

RTS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME E. One channel inoperable. ------ -NOTE A channel may be bypassed for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for surveillance testing.

E.1 Place channel in trip. 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> OR E.2 Be in MODE 3. 78 hours9.027778e-4 days <br />0.0217 hours <br />1.289683e-4 weeks <br />2.9679e-5 months <br /> F. THERMAL POWER F.1 Reduce THERMAL 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />

> P-6 and < P-b, one POWER to < P-6.

Intermediate Range Neutron Flux channel OR inoperable.

F.2 Increase THERMAL 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> POWER to> P-b.

G. THERMAL POWER G.1 Suspend operations Immediately

> P-6 and < P-b, two involving positive reactivity Intermediate Range additions.

Neutron Flux channels inoperable.

G.2 Reduce THERMAL 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> POWER to < P-6.

H. THERMAL POWER H.1 Restore channel(s) to Prior to increasing

< P-6, one or two OPERABLE status. THERMAL POWER Intermediate Range to> P-6 Neutron Flux channels inoperable.

(continued)

Vogtle Units 1 and 2 3.3.1-3 Amendment No. 116 (Unit 1)

Amendment No. 94 (Unit 2)

RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 1 of 9)

Reactor Trip System Instrumentation I

APPLICABLE MODES OR OTHER NOMINAL SPECIFIED TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT Manual Reactor 1,2 2 B SR 3.3.1.13 NA NA Trip (3a) (4 a) 5 (a) 2 C SR 3.3.1.13 NA NA

2. Power Range Neutron Flux

a. High 1,2 4 D SR3.3.1.1 111.3%RTP 109%RTP SR 3.3.1.2 SR 3.3.1.7 SR 3.3.1.11 SR 3.3.1.15

b. Low (1 b) 2 E SR 3.3.1.1 27.3% RTP 25% RTP SR3.3.1.8 SR 3.3.1.11 SR 3.3.1.15

3. PowerRange 1,2 4 E SR3.3.1.7 6.3%RTP 5%RTP Neutron Flux High SR 3.3.1.11 with time with time Positive Rate constant constant 2sec 2sec

4. Intermediate (1 b) (2 c) 2 F,G SR 3.3.1.1 41.9% RTP 25% RTP Range Neutron SR 3.3,1.8 Flux SR3.3.1.11 2 H SR3.3.1.1 41.9%RTP 25%RTP 2 (d)

SR 3.3.1.8 SR 3.3.1.11 (continued)

(a) With Reactor Trip Breakers (RTBs) closed and Rod Control System capable of rod withdrawal.

(b) Below the P-1Q (Power Range Neutron Flux) interlocks.

(c) Above the P-6 (Intermediate Range Neutron Flux) interlocks.

(d) Below the P-6 (Intermediate Range Neutron Flux) interlocks.

(n) A channel is OPERABLE with an actual Trip Setpoint value outside its calibration tolerance band provided the Trip Setpoint value is conservative with respect to its associated Allowable Value and the channel is readjusted to within the established calibration tolerance band of the Nominal Trip Setpoint. A Trip Setpoint may be set more conservative than the Nominal Trip Setpoint as necessary in response to plant conditions.

Vogtle Units 1 and 2 3.3.1-14 Amendment No. 128 (Unit 1)

Amendment No. 106 (Unit 2)

HL-16 NRC Written Examination KEY

98. G2.3.6 001/3/N/A/APPROVE RELEASE P/3.8 MEMJBK VOGTLE 2005 NRC/SRO/NRC/GCW The SS has received a completed release permit for the following tanks:

- Waste Monitor Tank 009 (Unit 1)

- Waste Monitor Tank 010 (Unit 2)

Due to the plant schedule, Operations Management would like both tanks to be realeased at the same time in accordance with 1321 6-1 and 13216-2, Liquid Waste Release.

Which ONE of the following correctly states the procedure requirements given the above conditions?

A. Two tanks may never be released at the same time under any conditions.

B. Two tanks may be released without additional authorization because they are on different Units.

C The two tanks may be released simultaneously as long as the SS receives authorization from the Chemistry Manager.

D. The two tanks may be released simultaneously as long as the SS receives authorization from the Health Physics Supervisor.

Page 203 of 208

HL-16 NRC Written Examination KEY Feedback 2.3 Radiation Control 2.3.6 Ability to approve release permits.

(CFR: 41.13/43.4/45.10)

K/A MATCH ANALYSIS The SS has the responsibility for approving liquid radwaste release permits. KA level for SRO is 3.8 versus RO which is 2.0.

SRO 10CFR55.43 (b4)

ANSWER I DISTRACTOR ANALYSIS A. Incorrect. Two tanks may be released at the same time with Chem Superintendent permission. Plausible because it is logical that part of a controlled release would be one tank at a time.

B. Incorrect. Two tanks may be released at the same time with Chem Superintendent permission. Plausible because applicant may think that as long as each tank meets specifications for release, that it would be OK to authorize both at the same time.

C. Correct. See Step 2.1 .6 of both referenced procedures.

D. Incorrect. Chem Superintendent permission must be received. Plausible because applicant may think that HP Supv has authority to approve releases that may contain certain levels of radioactivity REFERENCES

1. 13216-1, Liquid Waste Release, Rev. 44, 09/28/2010.

2. Vogtle 2005 NRC SRO Exam (not in last 2)

VEGP learning objectives:

LO-PP-471 01-08, Describe the major steps required for operations to release a WMT.

Page 204 of 208

Approved By Procedure Number Rev S. E. Prewitt Vogue Electric Generating Plant 13216-1 44 Date Approved Page Number 9/28/2010 LIQUID WASTE RELEASE 3 of 86 2.0 PRECAUTIONS AND LIMITATIONS 2.1 PRECAUTIONS 2.1.1 The Liquid Waste Processing System is potentially radioactive. Caution should be exercised to avoid spillage and to minimize exposure.

2.1.2 Once a Waste Monitor Tank (WMT) has been placed on recirculation for sampling, the tank shall remain isolated to prevent introduction of liquids that could alter the concentration of the contained volume.

2.1.3 Radiation Monitor 1 -RE-001 8 reading should be observed at least once every 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> during the release to assure that the activity does not exceed the setpoint on the Batch Liquid Release Permit.

2.1.4 If a high alarm is received from 1 -RE-001 8 while releasing a tank, the release shall be stopped immediately and the Shift Supervisor and Chemistry notified.

2.1.5 If 1-RE-0018 reads less than expected, release can continue provided Chemistry is notified and 1 -RX-001 8 does not show a trouble condition.

I QQ NOT release more than ste Monitor Tank per plant site at the same time, unless authorized by I Manager.

2.1.7 If a high alarm is received from 1 -RE-001 8 while flushing with tank water, flush with demin water per Section 4.8.

2.1.8 If required to reset Dilution Flow Totalizer A-FQI-7620 prior to starting a release, Chemistry should be notified and Dilution Flow Totalizer A-FQI-7620 value recorded in Auto Log for the purpose of tracking tritium.

Printed January 14, 2011 at 15:02

Approved By Procedure Number Rev S. E. Prewitt Vogtle Electric Generating Plant 13216-1 44 Date Approved Page Number 9I28/2O1O LIQUID WASTE RELEASE 7 of 86 INITIALS CAUTION Excessive running of the WMT pumps on recirc can shorten the life of the pump. The normal recirc time for a sample is approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

4.1.6 Stop WASTE MONITOR TANK PUMP 09 using 1 -HS-1 082 AFTER chemistry has taken the required sample.

4.1.7 IF Waste Monitor Tank 09 is NOT acceptable for release, notify SSS.

4.1.8 Perform the following:

a. Contact Chemistry and verify Savannah River Flow Rate has NOT decreased by more than 10% from the permit generation time.

NOTE Chemistry procedure 36015-OEMS Data Sheet 5 is the Batch Liquid Discharge Permit

b. Obtain: SSS áorth eofwMr.

Record SS1SSS notification and approval on Sectioti Three of the Btøh Uqjk. RtéaseFermlL NOTE If directed by SS the following step may be marked N/A based on power level, outside air temp, or duration of release.

d. IF both units are at power, notify unit one control room to start a third river water pump per 13727-C.

4.1.9 Start WASTE MONITOR TANK PUMP 09 using 1-HS-1082.

4.1.10 jf 1-RE-0018 is operable, perform Step 4.1.12 and mark Step 4.1.13 N/A.

Printed January 18, 2011 at 18:41

HL-16 NRC Written Examination KEY

99. G2.4. 18 001131N/AJEOP BASIS/4.O C/AINEW//NRC/GCW 19231-C, FR-Hi, Response To Loss of Secondary Heat Sink is in effect.

- All SG WR levels are 8%.

- PORV 455 is open.

- PORV 456 Block Valve is shut and cannot be opened.

- All Reactor Vessel Head Vent valves are open.

- All COPs and SIPs are running.

- CETs are 562°F and stable.

- Restoration of feed capability is imminent.

Which ONE of the following is CORRECT regarding:

1) the current RCS bleed path, and

2) the proper procedural action to take when feed flow is restored?

RCS Bleed Path Feed Restoration A. adequate remain in 19231 until at least one SG NR level> 10%

B. adequate immediately exit to an optimal recovery procedure C not adequate remain in 19231 until at least one SG NR level> 10%

D. not adequate immediately exit to an optimal recovery procedure Page 205 of 208

HL-16 NRC Written Examination KEY Feedback 2.4 Emergency Procedures! Plan 2.4.18 Knowledge of the specific bases for EOPs.

(CFR: 41.10/43.1 /45.13)

K/A MATCH ANALYSIS The candidate is presented with a scenario where RCS feed and bleed is required with the inability to open one PORV and RCS Head Vents are in open. In addition, when feed capability is restored with Hot Dry SGs he must determine how many SGs to feed.

The information regarding this is found in the WOG Background Documents for FR-H.1 Loss of Secondary Heat Sink.

SRO 10CFR55.43 (b5)

ANSWER! DISTRACTOR ANALYSIS A. Incorrect. Per WOG BG documents, both PORVs must be open for adequate heat removal. Crew must remain in 19231 until feed and bleed is terminated.

B. Incorrect. Per WOG BG documents, both PORVs must be open for adequate heat removal. Crew must remain in 19231 until feed and bleed is terminated.

C. Correct. Per WOG BG documents, both PORVs must be open for adequate heat removal. Crew must remain in 19231 until feed and bleed is terminated.

D. Incorrect. Bleed path is inadequate and Crew must remain in 19231 until feed and bleed is terminated.

REFERENCES FR-H.1, WOG Background Documents for Loss of Secondary Heat Sink V-LO-HO-37051, Loss of Secondary Heat Sink VEGP learning objectives:

LO-LP-37051 -05, State the precautions which should be taken in feeding a hot, dry steam following recovery from a loss of heat sink accident.

LO-LP-37051 -08, Using EOP 19231 as a guide, briefly describe how each major step is accomplished. Describe the bases for each. (commitment).

Page 206 of 208

Procedure Number Rev Approved By J. B. Stanley Vogtle Electric Generating Plant 19231 -C 33.4 Page Number Date Approved FR-H.1 RESPONSE TO LOSS OF SECONDARY 38 of 54

• 2/18/1O HEAT SINK ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

_67. Open Main Feed Pump discharge 67. IE discharge valves can NOT be valves. opened, THEN locally open MFP bypass valve 1 305-U4-655. (TB-Lvl 2)

_68. Open BFIV for selected SG. _68. Open MFIV on selected SG.

_JF MFIV will NOT open, THEN dispatch an operator to locally open the selected BFIV.

IF neither BFIV or MFIV will open, THEN return to Step 49.

_69. Slowly open BFRV for the selected 69. Open MFRV for the selected SG.

SG to establish feed flow.

_JF MFRV will NOT open, THEN dispatch an operator to locally open the BFRV.

jf neither BFRV or MFRV will open, THEN return to Step 49.

70. Check siniC

_a. NA Ii _a. IE feed flow to at least one SG verified THEN do NOT continue until NR level is restored to r1rat9rthn 10%

Printed January 18, 2011 at 19:22

held open continuously by 2405 psig and, thus, safety valves did not open. However, the PORVs are now being this condition will persist until the system boils off all the liquid inventory the steam generation rate in the core, and core damage will follow above the core and partial core uncovery occurs. Significant core uncovery and potential unless operator action is taken to initiate bleed and feed or feedwater capability is restored.

have been generated. If Sl During the time interval covered by Periods 1 through 6, an automatic SI signal will not the limited capability of the SI were manually actuated, it would not be effective in preventing core uncovery due to The mass flow rate out of the pumps to inject when RCS pressure is at or above the pressurizer PORV setpoint.

can inject about 40 Ibm/sec (290 pressurizer PORVs is anywhere from 50 to 100 Ibm/sec. The charging pumps psig. Since makeup flow from the charging pumps gpm), with both trains operating, at an RCS pressure of 2300 PORVs, the RCS will eventually dry out enough to cause will not keep up with inventory lost out of the pressurizer core uncovery.

action will lead to a loss of In summary, the loss of all feedwater transient from a power condition without operator inventory through the pressurizer PORVs. Core uncovery will secondary heat sink followed by a loss of RCS flow, if manually to or greater than the pressurizer PORV setpoint and charging/SI result at an RCS pressure equal initiated late in the transient, will not be sufficient to prevent core uncovery.

LOSS OF SECONDARY HEAT SINK WITH OPERATOR ACTION TRANSIENT ANALYSIS -

RCS Bleed and Feed Heat Removal heat removal can prevent or For a loss of all secondary heat sink, operator action to establish RCS bleed and feed and feed heat removal, the operator must initiate and verify high minimize core uncovery. To establish RCS bleed fluid to the RCS and then manually open all pressurizer PORVs to bleed hot pressure SI flow to feed subcooled will be effective, at least reactor coolant out of the RCS. To be certain that the bleed and feed heat removal path two PORVs must open.

s. These are the:

The effectiveness of RCS bleed and feed heat removal depends on four basic consideration o timeliness of operator action to initiate bleed and feed following indications of the symptoms of loss of all secondary heat sink o core decay heat at the time of RCS bleed and feed initiation o capacity of the pressurizer PORVs (i.e., number open) o capacity of the centrifugal charging pumps and safety injection pumps (i.e., number running) after These considerations govern the RCS depressurization, repressurization, and pressure stabilization The fourth consideration also governs the amount of SI RCS bleed and feed heat removal is established.

pressure. RCS bleed and feed effectiveness is maximized by a flow delivered to the RCS at any RCS the combination of these considerations which maximizes the initial RCS depressurization, minimizes subsequent RCS repressurization and the pressure stabilization point, and maximizes SI flow to the RCS at any RCS pressure.

power, 120% of the 1971 Generic analyses were performed on a 4-loop, 3411 MWt plant, assuming loss of off-site charging pump and one SI ANS 5.1 standard decay heat, and minimum safeguards SI flow availability (i.e., one in evaluating plant response to pump) with no spilling lines and an SI temperature of l000F. The key parameter The analyses in Figure 2 show curves for a ratio of bleed and feed cooling is the PORV flow to core power ratio.

(Ibm/hr)IMW t each for a total of 118 (lbmlhr)IMW t).

157 (lbm/hr)/MWt (the Vogtle PORVs are rated at 59 increased SI flow capacity through the operation of all high Although not evaluated in the generic analyses, RCS bleed and feed pressure SI pumps (i.e., two charging/SI pumps and two high-head SI pumps) will increase flow capacity is effectiveness by providing increased SI flow at all RCS pressures. Safety Injection system 1-5

ty to absorb some quantity of heat in important for two basic reasons. First, cold SI water has available heat capaci initial subcoo ling helps to reduce the repressurization rate reaching the existing average RCS temperature. This

, water replace s the mass lost throug h the open pressurizer and the point of pressure stabilization. Second SI In the analyses presented, SI is not PORVs and helps prevent or decrease the severity of any core uncovery.

the PORVs are opened rather than initiated until the low PZR pressure SI setpoint is reached. This occurs after before PORVs are opened as is instructed in the guideline.

delivery, and manually opening all Bleed and feed is initiated by starting all high pressure SI pumps, verifying SI the pressurizer steam bubble pressurizer PORVs. This will result in rapid RCS depressurization (Figure 2C) as a large subcooled liquid flow is and saturated liquid are quickly vented, the pressurizer fills (Figure 2D) and ature when the pressurizer PORVs are established through the pressurizer PORVs. The core exit fluid temper se until saturation is e the RCS pressu re will decrea opened will govern the degree of depressurization becaus reached at the hottest point in the system.

to heat up (Figures 2A and 28)

Once the saturation pressure is reached in the core, the RCS fluid will begin due to core decay heat genera tion will initially exceed the energy because the energy addition and volume swell tor liquid mass inventory and volume removal capability of the pressurizer PORVs and any steam genera s will not remove enough remaining (Figure 2G). The flow of saturated liquid through the pressurizer PORV rise until a balance between pressurizer volume to make up for the RCS fluid swell; RCS pressure will continue to

d. At that point, the RCS pressure will PORV volumetric flow rate and RCS fluid swell plus SI addition is reache to all steam flow out the pressu rizer PORVs increases stabilize and remain relatively stable until either a change uncove rs reducin g the core heat transfe r and steam generation the volumetric removal rate or the core partially ation point will depend upon RCS fluid rate. The magnitude of the RCS repressurization and the pressure stabiliz along with pressurizer PORV flow temperature and core decay heat level at the time bleed and feed is initiated held open to minimize both the RCS capacity and SI delivery rates. Therefore, all pressurizer PORVs must be flow into the RCS may be maximized. During the repressurization and RCS pressure stabilization point so that SI rizer PORV s should be mainta ined open and all available high pressure stabilization period, all available pressu pressure SI pumps should continue to run to maxim ize RCS feed flow.

ng in an eventual emptying of the Even with SI flow maximized, RCS inventory will continue to decrease resulti down to the hot leg elevati on (Figur e 2E). At that time, steam will begin to reactor vessel upper head and a drain may decrease. When a large fraction of be vented out through the hot leg to the pressurizer and pressurizer level steadily. This pressure decrease will the PORV flow becomes steam, the RCS pressure will begin to decrease core decay heat generation permit an important increase in SI flow to prevent or minimize core uncovery. As volum e remov al capabi lity of the pressurizer PORVs continues to decrease with time and SI flow increases, the steam genera tion from core decay heat. This will be accompanied will start to exceed the volume addition due to flow.

by increasing net inventory in the RCS because SI flow will now exceed PORV and greater SI flow rate and An early initiation of bleed and feed permits a maximum depressurization of the RCS Period 5 (a period when ensures effective heat removal. The further the transient is allowed to advance into initial depressurization will be. This subcooling is being reduced) before bleed and feed is initiated, the smaller the losses.

results in lower SI flow rate, greater repressurization, and higher net inventory will still be available to remove a If bleed and feed is initiated earlier than Period 5, steam generator liquid mass urization. The liquid mass limited amount of energy. This liquid mass can help reduce the extent of repress s of bleed and feed in preventing significant remaining in the steam generator is important to the eventual succes core uncovery.

not prevent significant core If action is withheld until the start of Period 6, establishing bleed and feed will within the system due to boiling in the core. The volumetric uncovery. This is a result of the steam generation rate generation of steam and the resultant pressu rizatio n of the RCS will fully open the PORVs and will hold them in a high pressu re condition until the core uncovers enough to reduce the continuously open. The RCS will remain 50-100 lbm/sec, which exceeds the steam generation rate. The mass flow rate out the PORVs during Period 6 is possible means for pumped SI capacity of about 40 Ibm/sec (290 gpm) for the reference plant. The only 1-6

system would begin to boil after a short period of time (see Period 6, subsection 2.1). Once boiling began, depressurization of the RCS using PORVs without having core uncovery would be highly unlikely.

Core uncovery would be necessary to reduce the steam generation rate to a rate that permitted RCS depressurization using pressurizer PORV5.

Thus, the use of feed and bleed precludes the use of bleed and feed without core uncovery and possible core damage. Therefore, based on the above arguments, feed and bleed is not recommended to provide an alternative heat removal method during a loss of secondary heat sink condition.

2.4 Feeding a Dry Steam Generator If bleed and feed has been initiated, during restoration of secondary heat sink, feeding a dry steam generator may be necessary. If the event was initiated from high temperature and high decay heat conditions it is likely that feedwater flow will have to be established to a hot, dry steam generator. A hot, dry steam generator is defined as a steam generator in which the primary side of the steam F* and the secondary side has no liquid generator is above 550 0

inventory. Reestablishment of feedwater is the more desirable mode of recovery from a loss of secondary heat sink than remaining on bleed and feed and establishing cold leg recirculation for long term cooling because this will be more likely to avoid core uncovery. However, care must be taken when re-establishing feedwater flow to minimize the effects of thermal shock consistent with the urgency of the need to restore the secondary side heat sink.

Since the heat removal capability of one steam generator is always greater than decay heat, it is advisable to reestablish feedwater to only one steam generator regardless of the size of the plant or number of loops. Thus, if a failure in an SG occurs due to excessive thermal stresses, the failure is isolated to one steam generator.

• 550°F is a temperature evaluated to be low enough that thermal stress would not lead to a failure when feedwater is established to any remaining FR-H.1 Background 57 HP-Rev. 2, 4/30/2005 HFRH1BG .doc

HL-16 NRC Written Examination KEY 100. G2.4.3 1 00 II3INIAJEMERG PROC-ARPI4. I CIA/BANK WOLF CREEK O7ISROINRCIGCW Given the following:

- The plant is at 100% power.

- SSPS testing in progress on Train A.

- The following alarm is received:

- PROT SYSTEM TRAIN A TROUBLE

- The OATC acknowledges the alarm as expected.

- The alarm window is in solid.

- Subsequently, the following alarm is received:

- PROT SYSTEM TRAIN B TROUBLE Which one of the following describes the status of the alarm and the action required?

A. The alarm is expected because of the cross-train logic testing with the Reactor Trip and Bypass Breakers.

Refer to the alarm response procedure to ensure no unexpected conditions exist.

B. The alarm is expected because of the cross-train logic testing with the Reactor Trip and Bypass Breakers.

Refer to Tech Specs for actions required related to the testing.

C. The alarm is unexpected for SSPS testing.

Suspend testing and return Train A to OPERABLE status from having two SSPS trains inoperable.

D The alarm is unexpected for SSPS testing.

Reactor Trip should have occurred. Direct a reactor trip and performance of 19000-C, Reactor Trip or Safety Injection.

Page 207 of 208

HL-16 NRC Written Examination KEY Feedback 2.4 Emergency Procedures I Plan 2.4.31 Knowledge of annunciator alarms, indications, or response procedures.

(CFR: 41.10 /45.3)

K/A MATCH ANALYSIS The question deals with SSPS testing and General Warning input into SSPS and the ocurrence of another General Warning requiring a Reactor Trip SRO 10CFR55.43 (b5)

ANSWER I DISTRACTOR ANALYSIS A. Incorrect-Alarm is not expected. There are no cross train testing of SSPS. SSPS in test causes a General Warning. Two trains in test will generate a Reactor Trip.

B. Incorrect-Same as A for first part. Tech Spec referencing is plausible although initiating a Reactor Trip should be done.

C. Incorrect-Plausible because the alarm is unexpected. Suspension of testing is plausible, but a Reactor Trip is required.

D. Correct-See above.

REFERENCES Procedure 17005 Window E06 and F06, Protection System Train A(B) Trouble Procedure 14420-1 SSPS Train A Operability Test Tech Spec 3.3.1 Wolf Creek 2007 NRC VEGP learning obiectives:

LO-PP-281 02-07 State the purpose of the Master Test switch and describe when it would be used.

LO-PP-281 03-03 List all reactor trip set points, coincidences, permissives, and blocks.

Page 208 of 208

RTS Instrumentation 3.3.1 Table 33.1-1 (page 6 of 9)

Reactor Trip System Instrumentation I

APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINTO)

17. ReactorTrip 1,2 2 trains T,V SR 3.3.1.4 NA NA BreakersQ) SR 3.3.1.4 NA NA (3 (a) (5 a) 4 a) 2 trains C

18. ReactorTrip 1,2 1 each per U,V SR 3.3.1.4 NA NA Breaker RTB Undervoltage and Shunt Trip (3a) (4 a) a) (5 1 each per C SR 3.3.1.4 NA NA Mechanisms RTB

19. AutomaticTrip 1,2 2 trains Q,V SR 3.3.1.5 NA NA Logic a) (4 (3 a) a) (5 2 trains C SR 3.3.1.5 NA NA (a) With RTBs closed and Rod Control System capable of rod withdrawal.

(k) Including any reactor trip bypass breakers that are racked in and closed for bypassing an RTB.

(n) A channel is OPERABLE with an actual Trip Setpoint value outside its calibration tolerance band provided the Trip Setpoint value is conservative with respect to its associated Allowable Value and the channel is readjusted to within the established calibration tolerance band of the Nominal Trip Setpoint. A Trip Setpoint may be set more conservative than the Nominal Trip Setpoint as necessary in response to plant conditions.

Vogtle Units 1 and 2 3.3.1-19 Amendment No. 128 (Unit 1)

Amendment No. 106 (Unit 2)

Procedure Number Rev Approved y C. S. Waidrup Vogtle Electric Generating Plant 17005-1 32.1 Page Number Date Approved ANNUNCIATOR RESPONSE PROCEDURES FOR ALB 05 ON 52 of 66 4/25/10 PANEL 1A2 ON MCB WINDOW E06 ORIGIN SETPOINT PROT SYSTEM Solid-State Not Applicable TRAIN A Protection TROUBLE System 1.0 PROBABLE CAUSE

1. Protection System Train A 48V DC or 1 5V DC power supply failure.

2. Loose or removed circuit card.

3. One or more of the following switches mispositioned:

NORMAL SWITCH LOCATION POSITION Input Error Inhibit Logic Test Panel NORMAL Logic A Logic Test Panel OFF Multiplexer Test Logic Test Panel NORMAL Permissives Logic Test Panel OFF Memories Logic Test Panel OFF Mode Relay Selector Output Relay Test Panel OPERATE Master Relay Selector Output Relay Test Panel OFF

4. Train A Reactor Trip Bypass Breaker closed.

5. Loss of AC power to either Output Relay Cabinet.

6. Logic problem.

2.0 AUTOMATIC ACTIONS NONE 3.0 iNITIAL OPERATOR ACTIONS NONE Printed January 16, 2011 at 18:45

Procedure Number Rev Approved By C. S. Waidrup Vogtle Electric Generating Plant 17005-1 32.1 Page Number Date Approved ANNUNCIATOR RESPONSE PROCEDURES FOR ALB 05 ON p5/10 PANEL 1A2 ON MCB 53 of 66 WINDOW E06 (Continued) 4.0 SUBSEQUENT OPERATOR ACTIONS NOTE No action is necessary if alarm is expected.

1. Dispatch an operator to Solid State Protection System Train A Logic Cabinet to determine and, if possible, correct cause of alarm.

NOTE There are nine Light-Emitting Diodes (LEDs) on lower front edge of PC Board Assembly 1 A5A4A1 08. The first four LEDs indicate logic inputs from Logic Test Panel and are normally lit. The next five LEDs are normally out and depending on which one is lit will indicate source of problem. The nine LED functions are:

(1) C logic input, (2) D logic input, (3) A logic input, (4) B logic input, (5) Input Error Inhibit Switch not in normal, (6) Logic A Switch not in OFF or Multiplexer Test Switch is in inhibit, (7) Permissives, Memories or Output Relay Selector Switch not in off; Mode Selector Switch not in operate; Train Bypass Breaker closed; or loss of AC to Output Relay Cabinets, (8) Printed circuit card loose or removed, (9) Power supply failure.

2. Reference Technical Specification LCO 3.3.1 and 3.3.2 for actions required on loss of Automatic Trip and Actuation Logic, if necessary.

3. Initiate maintenance as required to correct cause of alarm.

4. jf necessary, return the Train A Protection System to normal per 13503A-1, Reactor Control Solid-State Protection System.

Printed January 16, 2011 at 18:45

I Approved By Procedure Number Rev IC. S. Waidrup Vogtle Electric Generating Plant 17005-1 32.1 I Date Approved ANNUNCIATOR RESPONSE PROCEDURES FOR ALB 05 ON Page Number PANEL 1A2 ON MCB 54 of 66 WINDOW E06 (Continued) 5.0 COMPENSATORY OPERATOR ACTIONS

1. Check SSPS Train A Logic Cabinet once per shift, and initiate appropriate Subsequent Operator Actions if any LED is indicating an off-normal condition.

2. Log corrective actions to repair the disabled annunciator or reasons for no action on 10018-C, Annunciator Control, Figure 2.

3. Log compensatory actions on 10018-C, Annunciator Control, Figure 5.

END OF SUB-PROCEDURE

REFERENCES:

1X6AXO1-466 Printed January 16, 2011 at 18:45

Procedure Number Rev Approved By C. S. Waidrup Vogtle Electric Generating Plant 17005-1 32.1 Page Number Date Approved ANNUNCIATOR RESPONSE PROCEDURES FOR ALB 05 ON (Ji/25/10 PANEL 1A2 ON MCB 64 of 66 WINDOW F06 ORIGIN SETPOINT PROT SYSTEM Solid-State Not Applicable TRAIN B Protection System TROUBLE ALARM 1.0 PROBABLE CAUSE

1. Protection system Train B 48V DC or 1 5V DC power supply failure.

2. Loose or removed circuit card.

3. One or more of the following switches mispositioned:

NORMAL SWITCH LOCATION POSITION Input Error Inhibit Logic Test Panel NORMAL Logic A Logic Test Panel OFF Multiplexer Test Logic Test Panel NORMAL Permissives Logic Test Panel OFF Memories Logic Test Panel OFF Mode Relay Selector Output Relay Test Panel OPERATE Master Relay Selector Output Relay Test Panel OFF

4. Train B Reactor Trip Bypass Breaker closed.

5. Loss of AC power to either Output Relay Cabinet.

6. Logic problem.

2.0 AUTOMATIC ACTIONS NONE 3.0 INITIAL OPERATOR ACTIONS NONE Printed January 16, 2011 at 18:46

Procedure Number Rev Approved By C. S. Waidrup VogtIe Electric Generating Plant 17005-1 32.1 Page Number Date Approved ANNUNCIATOR RESPONSE PROCEDURES FOR ALB 05 ON (j/25/10 PANEL 1A2 ON MC8 65 of 66 WINDOW F06 (Continued) 4.0 SUBSEQUENT OPERATOR ACTIONS NOTE No action is necessary if alarm is expected.

1. Dispatch an operator to Solid State Protection System Train B Logic Cabinet to determine and, if possible, correct cause of alarm.

NOTE There are nine Light-Emitting Diodes (LED5) on lower front edge of PC Board Assembly 2A5A4A1 08. The first four LEDs indicate logic inputs from Logic Test Panel and are normally lit. The next five LEDs are normally out and depending on which one is lit will indicate source of problem. The nine LED functions are:

(1) C logic input, (2) D logic input, (3) A logic input, (4) B logic input, (5) Input Error Inhibit Switch not in normal, (6) Logic A Switch not in OFF or Multiplexer Test Switch is in inhibit, (7) Permissives, Memories or Output Relay Selector Switch not in off; Mode Selector Switch not in operate; Train Bypass Breaker closed; or loss of AC to Output Relay Cabinets, (8) Printed circuit card loose or removed, (9) Power supply failure.

2. Reference Technical Specification LCO 3.3.1 and 3.3.2 for actions required on loss of Automatic Trip and Actuation Logic, if necessary.

3. Initiate maintenance as required to correct cause of alarm.

4. If necessary, return the Train B Protection System to normal per 1 3503B-1, Reactor Control Solid-State Protection System.

Printed January 16, 2011 at 18:46

Procedure Number Rev rApproved By C. S. Waidrup Vogtle Electric Generating Plant 17005-1 32.1 Page Number Date Approved ANNUNCIATOR RESPONSE PROCEDURES FOR ALB 05 ON 66 of 66 4/25/10 PANEL 1A2 ON MC5 WINDOW F06 (Continued) 5.0 COMPENSATORY OPERATOR ACTIONS

1. Check SSPS Train B Logic Cabinet once per shift, and initiate appropriate Subsequent Operator Actions if any LED is indicating an off-normal condition.

2. Log corrective actions to repair the disabled annunciator or reasons for no action on 10018-C, Annunciator Control, Figure 2.

3. Log compensatory actions on 10018-C, Annunciator Control, Figure 5.

END OF PROCEDURE TEXT

REFERENCES:

1X6AXO1-466 Printed January 16, 2011 at 18:46

QUESTIONS REPORT for 2007 WOLF CREEK NRC WORKSHEET REV FINAL

7. 029 G2.4.31 001 /NEW!/HIGHER//SRO/WOLF CREEK! 10/2007/NO Given the following:

• The plant is at 100% power.

• SSPS testing is in progress on Train A.

• The following alarm is received:

ALR 00-75A, SSPS Train A General Warning

• The RO acknowledges the alarm as expected.

• The alarm is currently locked in.

• Subsequently, the following alarm is received:

ALR 00-76A, SSPS Train B General Warning

• The RO acknowledges the alarm.

• NO other alarms are present.

Which ONE (1) of the following describes the status of the alarm, and the action required?

A. The alarm is expected due to the cross-train logic testing for Reactor Trip and Bypass breakers. Refer to the alarm response to ensure no unexpected conditions exist.

B. The alarm is expected due to the cross-train logic testing for Reactor Trip and Bypass breakers. Refer to technical specifications for action required related to the testing.

C. The alarm is unexpected for SSPS testing. Suspend the testing and return Train A to OPERABLE due to two SSPS trains inoperable.

D The alarm is unexpected for SSPS testing. Reactor Trip should have occurred.

Direct a reactor trip and performance of EMG E-0, Reactor Trip or Safety Injection.

D is correct. Both Train alarms in, reactor should trip, due to general warnings on both trains.

A, B, and C are incorrect because they do not refer to a trip. They are credible because they contain plant response that is seen during different phases of SSPS testing.

Wednesday, October 24, 2007 6:29:12 AM 13