ML111960050
| ML111960050 | |
| Person / Time | |
|---|---|
| Site: | Farley  |
| Issue date: | 07/02/2011 |
| From: | NRC/RGN-II |
| To: | Southern Nuclear Operating Co |
| References | |
| 50-348/11-301, 50-364/11-301 | |
| Download: ML111960050 (252) | |
Text
76. OOIAA2.03 076/NEW/SRO/C/A 3.9/4.5/APEOO1AA2.03/N/3/VAL O1 FIXED/MINOR ED Unit I is at 12% power controlling on the Steam Dumps with the-following conditions and sequence of events:
At 1000:
- The Main Turbine is rolling at 600 rpm.
- Control Bank (CB) D is at 165 steps.
- Rods are in Manual.
- RCS Tavg is 550°F.
AT 1010:
- CS D rods are pulled 2 steps and rods continue to step outward after releasing the IN-HOLD-OUT switch.
The following response occurred:
- AOP-19.0, Malfunction of Rod Control System, was implemented.
- Rods were placed in AUTO but continued to step outward.
- A Manual reactor trip was attempted with reactor power at 14%.
- NEITHER MCB RX TRIP handswitch caused the Reactor Trip Breakers to open.
- The CRDM supply breakers were opened and all rod bottom lights illuminated.
Which one of the following completes the statements below?
When the ROD CONTROL BANK SELECTOR SWITCH was placed in AUTO, CB D rods should have immediately stopped, (1)
An emergency classification threshold value (2) been exceeded per NMP-EP-1 1 0-GLOI, FNP EALS - ICs, Threshold Values And Basis.
(1) (2) then stepped IN HAS B. and remain stopped HAS C. then stepped IN has NOT D. and remain stopped has NOT
- 1. OO1AA2.03 076/NEW/SRO/C/A 3.9/45/APEOOIAA2.03/N/3/VAL 0-I FIXED/MINOR ED Feedback RCS temp is ABOVE the no load TAVG of 547°F by 4°F; NORMALLY Rod control would impose an inward rod motion signal with a temp mismatch of> 1.5°F.
C-5 Blocks OUTWARD rod withdrawal in AUTO.
NMP-EP-i I 0-GLOI, vi .0 under SA2 Failure of Reactor Protection System Instrumentation to Complete or Initiate an Automatic Reactor Trip Once a Reactor Protection System Setpoint Has Been Exceeded AND Manual Trip Was Successful provides the following guidance:
NOTE: Failure of both MCB Rx Trip switches to trip the reactor meets the TV criteria of a setpoint being exceeded with no automatic trip occurring.
A. Correct 1) See above. There is a 4°F temperature deviation from program, therefore Rods should drive INWARD when in auto.
- 2) Inability to manually trip the reactor using the Rx trip breakers is an ALERT classification.
Although NO automatic trip setpoints were exceeded, the MCB RX trip handswitches are part of the RPS AUTOMATIC trip circuitry and is included in the Emergency Classification regarding a failure of the RPS to trip the reactor, manual trip successful.
B. Incorrect 1) Although C-5 is active, it only stops OUTWARD rod motion, also TREE is 547°F due to PT 446/447 (selected) is at Zero LOAD value.
- 2) See A Plausible: AOP-19 requires placing Rods in AUTO if unexpected rod motion is occurring in an attempt to stop rod motion. IF TREF were calculated using Rx POWER vs Turb power (a common misconception), then one would find NO call for RODS IN.
F 5=z \
( ss7i_F (o100)%
RAGE 1
028 54i F 55DRAG.
ji 5476 550 36F1 IF there was an Outward ROD MOTION Called for, then C-5 would have stopped outward rod motion, or IF the examinee is not aware of the Zero POWER TREE.
C.lncorrect 1)SeeA
- 2) An automatic trip setpoint has not been exceeded but when a manual reactor trip is attempted, and the Rx Trip breakers fail to operate this is indicative of a RPS malfunction and is an ALERT.
- Ptausible: Since no AutomatIc reactor trip stpcint hs beeii -
exceeded, one might believe the threshold value has not been satisfied.
Alternatively, because the manual trip was SUCCESSFUL one might believe that a classification is not required.
D.lncorrect 1) See B.1
- 2) See C.2; A failure of the MCB RX trip handswitches is a failure of the RPS.
- 1. OO1AA2.03 076/NEWISROICIA 3.9/4i/APEOOIAA2.03/N/3/VAL 0-I FIXED/MINOR ED Notes -
K/A statement OOIAA2.03 Ability to determine and interpret Proper actions to be taken if automatic safety functions have not taken place as they apply to the Continuous Rod Withdrawal Importance Rating: 4.5 4.8 Technical
Reference:
AOP-1 9.0, v27.0 NMP-EP-110-GLO1, vl.0 FNP-0-SOP-0.3, v41 .0 References provided: None Learning Objective: EVALUATE plant conditions and DETERMINE if transition to another section of AOP-1 9, Malfunction of Rod Control System, or to another procedure is required.
(OPS-62520502)
Using plant procedures/references, ANALYZE a set of plant conditions and DETERMINE the proper classification of the emergency condition as being a NOUE, Alert, Site Area, or General Emergency. (OPS-63002C01). SRO objective Question origin: NEW Basis for meeting K/A: Ability to DETERMINE and INTERPRET proper actions to be taken is challenged by testing the expected automatic response of the system which determines whether or not a Reactor Trip is Needed or NOT per the lOAs of AOP-19.0.
(RD level)
Ability to DETERMINE proper [procedural] actions is testing the SRO level knowledge by interpreting whether or not the INABILITY of the RPS system to trip the RX without an AUTOMATIC setpoint being exceeded meets the requirements of the Classification Threshold values.
SRO justification: 10 CFR 55.43(b)(6), however could also be argued as DOES NOT explicitly MATCH one of the 10 CFR 55.43(b) items but FNP has classified the knowledge/ability as unique to the SRO position as documented within SAT process as ties the knowledge/ability to the licensees SRO job position duties.
The SRO is solely responsible to determining Classifications at FNP. see SRO only objective above.
2011 NRC exam Ill. Justification for Plant Specific Exemptions UNIQUE to the SRO position:
DOES NOT MATCF-1 one of the 10 CFR 5S.43(b) items but FNP has c[assified the knowledge/ability as unique to the SRO position as documented within SAT process as ties the knowledge/ability to the licensees SRO job position duties.
ALTERNATIVELY:
Procedures and limitations involved in initial core loading, alterations in core configuration, control rod programming, and determination of various internal and external effects on core reactivity. [10 CFR 55.43(b)(6)]
Some examples of SRO exam items for this topic include:
- Evaluating core conditions and emergency classifications based on core conditions.
- Administrative requirements associated with low power physics testing processes.
- Administrative requirements associated with refueling activities, such as approvals required to amend core loading sheets or administrative controls of potential dilution paths and/or activities.
- Administrative controls associated with the installation of neutron sources.
Knowledge of TS bases for reactivity controls.
07/13/10 8:07:08 FNP-1-AOP-19.O MALFUNCTLQN OF ROD CONTROL SYSTEM Version 27.0-Step Action/Expected Response Response Not Obtained NOTE: Steps 1 and 2 are IMMEDIATE OPERATOR actions.
1 Verify NO load change in progress. 1 Check for cause of load change.
1.1 IF load rejection in progress or has occurred, THEN go to FNP-1-AOP-17.0, RAPID LOAD REDUCTION.
1.2 IF secondary leakage is indicated, THEN go to FNP-1-AOP-14.0, SECONDARY SYSTEM LEAKAGE.
2 IF unexplained rod motion occurring, THEN stop rod motion.
2.1 IF rod control in AUTO, 2.1 IF rod control in MANUAL, THEN place rod control in MANUAL. THEN place rod control in AUTO NOTE: In AUTO rod control, rods will step OUT if TAVG less than TREF by at least 1.5 degrees, and Rods will step TN if TAVG greater than TREF by at least 1.5 degrees.
2.1.1 IF AUTO rod motion due to TAVG/TREF mismatch, THEN verify rod motion stops when TAVG is within 1 degree of TREF 2.2 IF unexplained rod motion NOT stopped, THEN perform the following.
2.2.1 Trip the reactor 2.2.2 Go to FNP-1-EEP-0, REACTOR TRIP OR SAFETY INJECTION
_Page Completed Page 2 of 9
NMP-EP-1 1 0-GLO1 FNP EALs ICs, Threshold Values and Basis
- Version 1.0 SA2 Initiating Condition (Back to Hot IC p. 105)
Failure of Reactor Protection System Instrumentation to Complete or Initiate an Automatic Reactor Trip Once a Reactor Protection System Setpoint Has Been Exceeded AND Manual Trip Was Successful.
Operating Mode Applicability: Power Operation (Mode 1)
Startup (Mode 2)
Hot Standby (Mode 3)
Threshold Value: (1)
NOTE: A successful manual trip for purposes of declaration is any action taken from the MCB that rapidly inserts the control rods. This can be accomplished by tripping the reactor using the Reactor Trip switches on the MCB OR by de-energizing both Rod Drive Motor Generator sets from the MCB.
NOTE Failure of both MCB Rx Trip switches to trip the reactor meets the TV criteria of a setpoint being exceeded with no automatic trip occurring.
- 1. Indication(s) exist that a reactor protection setpoint was exceeded and an automatic trip did not occur, and a manual trip resulted in the reactor being subcritical.
Basis:
This condition indicates failure of the automatic protection system to trip the reactor. This condition is more than a potential degradation of a safety system in that a front line automatic protection system did not function in response to a plant transient and thus the plant safety has been compromised, and design limits of the fuel may have been exceeded. An Alert is indicated because conditions exist that lead to potential loss of fuel clad or RCS. Reactor protection system setpoint being exceeded, rather than limiting safety system setpoint being exceeded, is specified here because failure of the automatic protection system is the issue. A manual reactor trip is considered to be a trip input to the automatic Reactor Protection System or de-energizing the MG sets should initiate a manual trip.
The Reactor should be considered subcritical when reactor power level has been reduced to less than 5% power and SUR is negative.
50
l0/08i. +/-0:15:13 FNP-G JP-O.3 APPENDIX G CONTROL INTERLOCKS Coincidence & Light Interlock Source Setpoint Status Function
- 1. C-I NIS 35, and 36 Current Eq. to 1/2> setpoint 1. Blocks auto and manual rod withdrawal.
IR Hi 0 Rod 20% Rx Power no light 2. May be manually blocked by turning Both IR Block Stop 3. May be bypassed by level trip at NIS rack
- 2. C-2 NIS 41, 42, 43, 103% Rx Power 1/4> setpoint 1. Blocks auto and manual rod withdrawal.
PR Hi 0 Rod and 44 no light 2. Each PR inst. input may be manually bypassed at the NIS Stop racks misc drawer
- 3. C-3 OTi\T Instr. Variable 3% 2/3 > setpoint 1. Blocks auto and manual rod withdrawal.
OTt\T 412, 422, and Below OTAT lit> setpoint 2. Cannot be blocked or bypassed.
Rod Stop 432 Rx Trip
- 4. 04 OPzT Instr. Variable 3% 2/3 > setpoint 1. Block auto and manual rod withdrawal.
OPLT Rod 412, 422, and Below OPAT lit> setpoint 2. Carmot be blocked or bypassed.
Stop 432 Rx Trip
- 5. C-5 Low Turb. Impulse 15% Turb. 1/1 > setpoint Above setpoint allows auto rod control.
Turb. Power Instr. 446 447 Power lit> setpoint Below setpoint blocks rod withdrawal in auto.
Rod Stop Sel. Sw. on MCB Page 6 of 7 Version 41.0
- 77. 006G2 .4.9 O77INEW/SRO/C/A 3 .8/4.2/006G2.4.9/N/4/VER2.O/MINOR ED Unit I is in QD 4, th following conitionsexist:
- RCS temperature is 330°F and rising.
- RCS pressure is 350 psig.
- 1A and 1 B RCPs are running.
- Both RHR pumps are secured with the following alignment:
IA RHR is in the ECCS alignment.
1 B RHR is aligned for shutdown cooling.
The OATC starts the 1 B RHR pump to stop the RCS temperature rise.
Which one of the following completes the statements below per TS 3.5.2, ECCSOperating, and UOP-1.1, STARTUP OF UNIT FROM COLD SHUTDOWN TO HOT STANDBY?
(1) RHR system(s) is/are OPERABLE.
A mode change from Mode 4 to Mode 3 (2) currently allowed.
(1) (2)
A. BOTH IS B. BOTH is NOT C. ONLY1A IS D ONLY1A is NOT
- 2. 006G2.4.9 O77fNEWISROICIA 3 .81421006G2.4.9fN!4IVER2 .0/MINOR ED Feedback UOP-1 .1, ver 91.1, P&L 3.2 provides the following information:
RHR pumps shall NOT be operated in cooldown operation at RCS temperatures >225°F. If any RHR pump is operated in cooldown operation with RCS temperature >225°F, then declare the associated train of ECCS inoperable and do not enter Mode 3 until all portions of RHR piping is <225°F. One train of ECCS must be operable in Mode 4. (TS 3.5.3) (CR 2010106118)
A. Incorrect 1) See above. Starting the 1 B RHR pump causes the suction piping to fill with warm water. IF a LOCA were to occur and the lB RHR system subsequently re-aligned for ECCS operation (permitted by TS 3.5.3), the suction pressure would be below the saturation conditions for the 225° F and risk vapor binding the LHSI pump.
Plausible: TS 3.5.3 contains an amplifying NOTE which states that, An RHR train may be considered OPERABLE during alignment and operation for decay heat removal, if capable of being manually realigned to the ECCS mode of operation.
- 2) See C.2, This would be correct if I B RHR is shutdown and permitted to cool <225°F per UOP-1 .1, P&L 3.2.
Plausible if Part I were incorrectly assessed as OPERABLE, then one might consider MODE 3 entry permitted.
B. Incorrect 1)SeeA.1
- 2) TS 3.5.3 requires Both trains to be aligned for ECCS operation (automatic start) to be considered operable. This condition must be met prior to MODE change.
Plausible: IF one were to incorrectly asses operability of I B RHR per UOP-1 .1 guidance with regard to TS 3.5.3, but recognize that lB RHR must first be aligned to ECCS mode of operation and the autostart capability restored (SOP-7.0 Appendix 11).
C. Incorrect 1) see D.1
Plausible: A candidate might select this answer choice under a common misapplication of TS 3.O.4.b and the NOTE within SOP-0.13, v24.0 section 3.1.5 provides a NOTE which states:
LCO 3.O.4a. and 13.O.4a allows mode transition for inoperable equipment when the TSITR associated actions to be entered permit continued operation in the mode or other specified condition for an unlimited period of time.
TIA 2009-005 states that completion of those actions prior to entering the mode is not a requirement for compliance with LCO 3.0.4a or 13.0.4a. (Ref: CR2010106781)
ONE might jelieve that aJthough 1 is inoperabLe for auto start manual alignment could easily be achieved within the Completion time of Condition A.1 (72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />) of LCO 3.5.2.
D. Correct 1) The 1 B RHR system is inoperable due to running the pump
>225°F. IF operated in Cooldown alignment at this temp, the RHR pump is in danger of being vapor bound IF re-aligned for ECCS cooling.
- 2) UOP-1 .1, P&L3.2 specifically prevents advancing to MODE 3 until all RHR components have cooled to <225°F. Further, MODE 3 TS 3.5.2 requires BOTH trains to be aligned in the ECCS mode of operation and capable of AUTO-START from an SI signal. While aligned in the SOP-7.O, shutdown cooling mode of operation, the RHR pump Auto-start feature is disabled (SOP-7.O, Appendix 11).
- 2. 006G2.4.9 O77INEW/SRO/C/A 3 .8/4.2/006G2.4.9/N/4/VER2.OIMINOR ED Notes KJA statement 006 ECCS G2.4.9 Emergency Procedures/Plans Knowledge of low power I shutdown implications in accident (e.g. LOCA or loss of RHR) mitigation strategies Importance Rating: 3.8 4.2 Technical
Reference:
UOP-1.1, v91.1 TS 3.5.2 & TS 3.5.3 References provided: None Learning Objective: RECALL AND APPLY the information from the LCO BASES sections: BACKGROUND, APPLICABLE SAFETY ANALYSIS, ACTIONS, SURVEILLENCE REQUIREMENTS, for any Technical Specifications or TRM requirements associated with the Emergency Core Cooling System components and attendant equipment alignment, to include the following (OPS-62102B01): 10CFR55.43 (b) 2
- 3.5.2 ECCSOperating
- 3.5.3 ECCSShutdown Question origin: NEW Basis for meeting K/A: a) This involves the ECCS alignment of the LHSI system.
When changing modes and coming up in temperature the LHSI system (ECCS) suction piping has to remain <225°F to prevent voiding in the pump impeller.
b) This is a key part of the operability of the system. In mode 4 there only has to be one pump operable, and credit can be taken for Manual alignment to the ECCS mode of operation, whereas in mode 3 there has to be 2 LHSI pumps operable and each must be aligned for automatic ECCS mode of operation.
This question tests the operability call for the LHSI pumps during shutdown conditions (which is the mitigation strategy) and a subsequent mode change determination.
c) The accident mitigation strategy is to keep at least ONE RHR LOOP operable while in MODE 4 (or to prevent entering a MODE where the strategy could not be met),
such that upon the initiation of an accident (LOCA) the ECCS system could be aligned to makeup to the RCS.
SRO justification: 10 CFR 55.43(b)(2) meeting all of the following:
- Application of generic LCO requirements (3.0.4)
- Knowledge of TS bases that is required to analyze TS
required actions and terminology (where amplifying instrudiort is found within the PROCEDURES; KnowLedge af recently identified design/operational flaws) 2011 NRC exam 10 CFR 55.43(b)(2)
Facility operating limitations in the TS and their bases.
From the Clarification Guidance for SRO-only Questions Rev 1 dated 03/11/2010 flowchart:
- 1) can NOT be answered by knowing less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Tech Specs.
- 2) can NOT be answered solely by knowing information listed above-the-line.
ALTHOUGH above the line information ONLY is offered as distractors.
Without the knowledge of the PROCEDURE application of the TS would be incorrectly applied.
- 3) can NOT be answered by knowing the TS Safety Limits or their bases.
- 4) Does involve one or more of the following for TS, TRM or ODCM:
- Application of Required Actions (Section 3) and Surveillance Requirements (Section 4) in accordance with rules of application requirements (Section 1).
Requires assessment of TS 3.0.4 mode change allowance TS.
- Knowledge of TS bases that is required to analyze TS required actions and terminology EXCEPT the information discussed is not explicitly listed in the basis document. Rather the Corrective Action Program has placed this information throughout procedure guidance. This information is a recently discovered design weakness.
ECCS Shutdown
- 152 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.3 ECCSShutdown LCO 3.5.3 One ECCS train shall be OPERABLE.
NOTES
- 1. An RHR train may be considered OPERABLE during alignment and operation for decay heat removal, if capable of being manually realigned to the ECCS mode of operation.
- 2. Upon entry into MODE 4 from MODE 3, the breaker or disconnect device to the valve operators for MOVs 8706A and 8706B may be closed for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to allow for repositioning from MODE 3 requirements.
APPLICABILITY: MODE 4.
ACTIONS NOTE LCO 3.0.4b is not applicable to ECCS centrifugal charging subsystem.
CONDITION REQUIRED ACTION COMPLETION TIME A. Required ECCS residual A.1 Initiate action to restore Immediately heat removal (RHR) required ECCS RHR subsystem inoperable, subsystem to OPERABLE status.
B. Required ECCS centrifugal B.1 Restore required ECCS 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> charging subsystem centrifugal charging inoperable, subsystem to OPERABLE status.
AND At least 100% of the ECCS flow equivalent to a single OPERABLE ECCS train available.
Farley Units I and 2 3.5.3-1 Amendment No. 170 (Unit 1)
Amendment No. 163 (Unit 2)
12/01/10 14:12:43 FNP-1-UOP2.2 3.6 Residual Heat Removal:
3.6.1 Prior to starting or stopping a RHR pump with RCS under solid plant pressure control and the RHR system aligned for letdown, place LP LTDN PRESS PK 145 in MANUAL to prevent RCS pressure fluctuations.
3.6.2 Ensure that two RHR loops are aligned to the RCS any time temperature in any of the RCS cold legs is <325°F, unless the RCS is depressurized with an RCS vent of> 2.85 square inches, OR the reactor vessel head is removed.
3.6.3 The RHR loop suction valves shall be energized whenever the RCS temperature is greater than or equal to 180°F.
3.6.4 The RHR loop suction MOVs should be de-energized whenever RCS temperature is less than 180°F
- 1A RCS LOOP TO lB RHR PUMP Q1E1 1M0V8702B, Q1R17BKRFVV3 3.6.5 Locally caution tag the power supply breakers for the RHR loop suction valves when the suction valves are de-energized. The breakers are opened to prevent inadvertent isolation of the RCS overpressure protection relief valves.
3.6.6 Mode 5 entry requires two trains of RHR to be operable and one train of RHR to be in service. Three filled and vented RCS loops, capable of being pressurized AND at least two Steam Generators having levels 75% wide range indication (with an available source of makeup water) may be substituted for one RHR loop. (Tech. Spec. 3.4.7) 3.6.7 Operation of a train of RHR in cooldown operation when RCS temperature is between 225°F and 350°F will result in the associated train of ECCS being declared inoperable. One train of ECCS must be operable in Mode 4.
(TS 3.5.3) (RER C101206101) (Al 2010203800)
Version 88.0
- 78. 008AG2.4.41 078/NEW/SRO/C/A 2.9/4.6/008AG2.4.41/N/3IVER 3.0/MINOR ED Unit 1 is at 100% powe.r wi.th AQP-l .G, RCS Leakage 7 in progress. The following conditions exist:
- Containment Sump level is slowly rising.
- LI-3396, CTMT CLR DRN LVL, shows CTMT Cooler 1D level is 14.9 FT, significantly greater than the other coolers.
- The leak is located on a welded joint on the PZR at the location identified on the portion of DWG: D175037 Sh 002, v 34.0 shown below:
Which one of the following completes the statement below in accordance with NMP-EP-110-GLOI, FNP EALs ICs, Threshold Values and Basis?
The leak is defined as (1) LEAKAGE and its threshold value is (2) for a Notification of An Unusual Event (NOUE).
(1) (2)
A. IDENTIFIED 10 gpm B PRESSURE BOUNDARY 10 gpm C. IDENTIFIED 25 gpm D. PRESSURE BOUNDARY 25 gpm
- 3. 008AG2.4.4 1 O78INEW/SRO/C/A 2.9/4.6/OO8AG2A.4 IIN/3!VER 3 .0/MINOR ED Feedback NMP-EP-110-GLOI, V1.0, for SU5, RCS Leakage states the threshold values for declaring a NOUE is either:
- RCS Unidentified OR pressure boundary leakage greater than 10 gpm.
- RCS Identified leakage greater than 25 gpm.
The leak from the PRZR instrument line is PRESSURE BOUNDARY leakage.
PLAUSIBILITY OF IDENTIFEID LEAKAGE:
To be considered IDENTIFIED LEAKAGE it must meet one of the following criteria:
- 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;(Plausibility of distractor)
- 2. LEAKAGE into the containment atmosphere from sources that are both specifically located and known either a) not to interfere with the operation of leakage detection systems or b) not to be pressure boundary LEAKAGE; or
- 3. Reactor Coolant System (RCS) LEAKAGE through a steam generator (SG) to the Secondary System; There is leakage into the containment atmosphere that is specifically identified but does not meet the identified leakage definition.
The leakage indications for secondary is not provided, and since the examinee is directed that plant conditions are normal unless the question stem specifically states otherwise, this leakage limit is satisfied by omission.
A. Incorrect 1) See definitions above for Identified leakage; This leakage could be construed as Identified since it is specifically located and captured and conducted to collection systems. HOWEVER, it is not from packing or seals. ALSO does not meet all the requirements of definition #2.
- 2) Correct per NMP-EP-1 1 0-GLO1 B. Correct See above.
C. Incorrect 1) See A.1 and definitions above.
- 2) this is the threshold value for identified leakage.
D. Incorrect 1) See B.1 and definitions above.
- 2) this is the threshold value of unidentified leakage.
- 3. 008AG2.4.4 I O78INEW/SRO/C/A 2.9/4.6/008AG2.4.4 I/N/3/VER 3.0/MINOR ED Notes -
K/A statement 008A PRESSURIZER Vapor Space Accident G2.4.41 Knowledge of the emergency action level thresholds and classifications.
Importance Rating: 2.9 4.6 Technical
Reference:
TS 1.1-3 Definitions (rev 50)
NMP-EP-110-GLO1, ver 1, Figure 1 References provided: None.
Learning Objective: OPS-63002C01--Using plant procedures/references, Analyze a set of plant conditions and determine the proper classification of the emergency conditions as being a NOUE, Alert, Site Area, or General Emergency.
Question origin: NEW Basis for meeting KJA: Given a PZR steam space leak, the candidate must evaluate the leak against the definitions of TS, and the threshold criteria for entry into emergency classifications.
MEMORY level knowledge without reference since the information challenged is required knowledge for recognition of entry conditions to the EAL network.
SRO justification: 10 CFR 55.43(b)(6), however could also be argued as DOES NOT explicitly MATCH one of the 10 CFR 55.43(b) items but FNP has classified the knowledge/ability as unique to the SRO position as documented within SAT process as ties the knowledge/ability to the licensees SRO job position duties.
The SRO is solely responsible to determining Classifications at FNP.
2011 NRC exam Ill. Justification for Plant Specific Exemptions UNIQUE ot the SRO position:
DOES NOT MATCH one of the 10 CFR 55.43(b) items but FNP has classified the knowledge/ability as unique to the SRO position as documented within SAT process as ties the knowledge/ability to the licensees SRO job position duties.
ALTERNATIVELY:
Procedures and limitations involved in initial core loading, alterations in core configuration, control rod programming, and determination of various internal and external effects on core reactivity. [10 CFR 55.43(b)(6)}
Some examples of SRO exam items for this topic include:
- Evaluating core conditions and emergency classifications-based on core conditions.
- Administrative requirements associated with low power physics testing processes.
- Administrative requirements associated with refueling activities, such as approvals required to amend core loading sheets or administrative controls of potential dilution paths and/or activities.
- Administrative controls associated with the installation of neutron sources.
- Knowledge of TS bases for reactivity controls.
NMP-EP-110-GLOI FNP EALs lCs, Threshold Values and Basis Version 1.0 SU5 Initiating Condition (Back to Hot IC p. 105)
RCS Leakage.
Operating Mode Applicability: Power Operation (Mode 1)
Startup (Mode 2)
Hot Standby (Mode 3)
Hot Shutdown (Mode 4)
Threshold Values: (1 QE 2)
- 1. RCS Unidentified OR pressure boundary leakage greater than 10 gpm.
- 2. RCS Identified leakage greater than 25 gpm.
Basis:
This IC is included as a NOUE because it may be a precursor of more serious conditions and, as result, is considered to be a potential degradation of the level of safety of the plant. The 10 gpm value for the unidentified and pressure boundary leakage was selected as it is observable with normal control room indications. Lesser values must generally be determined through time consuming surveillance tests (e.g., mass balances). The Threshold Value for identified leakage is set at a higher value due to the lesser significance of identified leakag e in comparison to unidentified or pressure boundary leakage.
58
Definitions Li 1.1 Definitions ENGINEERED SAFETY The ESF RESPONSE TIME shall be that time interval from FEATURE (ESF) RESPONSE when the monitored parameter exceeds its ESF actuation TIME 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 (SG) to the Secondary System;
- b. Unidentified LEAKAGE All LEAKAGE (except RCP seal water injection or leakoff) that is not identified LEAKAGE; (continued)
Farley Units 1 and 2 1.1-3 Amendment No. 149 (Unit 1)
Amendment No. 141 (Unit 2)
Definitions 1J -
1.1 Definitions LEAKAGE c. Pressure Boundary LEAKAGE (continued)
LEAKAGE (except SG 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.
OPERABLEOPERABILITY 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:
- a. Described in Chapter 14, Initial Tests and Operation, of the FSAR;
- b. Authorized under the provisions of 10 CFR 50.59; or
- c. Otherwise approved by the Nuclear Regulatory Commission.
Farley Units 1 and 2 1 .1-4 Amendment No. 149 (Unit 1)
Amendment No. 141 (Unit 2)
CONTAINMENT STRUCTURE AND ISOLATION OpsCnmOO9 REMOVAa.E RATIPG RECOMBINER Leakage from the PZR steam space, would be superheated steam when released, and condensed mostly by the
- NMT Coolers. I D CNMT cooler would capture a greater amount of leakage simply due to proximity to the PZR All however, would rise.
ESS ILTER FUEL TRANSFER SYSTEM FIGURE 7 - Containment Plan at Elevation 155-O OPS-62102A/52102A/40302B/ESP52IQ2A Ver I
C D175037 1(J2)>
8 RC2505 3/4 X 3/8 RED.
CCD12 CCD241 3/4RC2501 R 175037 CCB38 L2(F6)
F 458B 3/4A7 8
)E387 SH.2 18053 LEAK LOCATION E8 r9 CCB38 REF 08D50 SRi 08D50 SH6 QVO23A 3/4RC25 3/4T78 AT \bUl
- fl A fl fl fin A fl r
,. * . , ,.... , ,- Ii%
- 79. 0 12A2.05 079/NEW/SRO/C/A 3.1/3.2/01 2A2.05fN/3//JAN 12 The following conditions exist on- Unit 1 -
- N 1-43, PR Nuclear Instrument, Axial Flux Comparator circuit withn the Detector Current Comparator Drawer has failed.
- ALL other functions within the Detector Current Comparator Drawer are unaffected.
- NI-43C, PR3 PERCENT FLUX DIFF, indicates a constant +20% A FLUX.
Which one of the following completes the statements below?
The Overpower Delta T (OPAT) reactor trip setpoint (1) affected by this failure.
The OPzT reactor trip function (2) OPERABLE per TS 3.3.1, Reactor Trip System (RTS) Instrumentation.
(1) (2)
A. IS IS is NOT IS C. IS is NOT D. is NOT is NOT
- 4. 01 2A2.05 O79INEW/SRO/C/A 3.1/3.2/01 2A2.05/N/3//JAN 12 Feedback The Overpower Delta T (OPDT) function requires input from AT, T, DT/dt (Rate of change of temperature (T) over time(t)) and Al. These signals are used to generate a variable setpoint calculated by the RPS system per TS 3.3.1 NOTE 1.
(1+z.s) ( 1 f 1 L
(
lt-l-r.
- Jr_i r
- lrS jt However per COLR Table 3, f 2 is zero for all power levels. Therefore Al will have NO impact on OPAT, regardless of magnitude.
OVERTEMPERATURE Delta T (OTAT) however, does penalize the setpoin t for values that are excessively high or low [(-)23% Al > (+)15%]
Nuclear instrument power (N43 or any other instrument) is not included as part of the OTAT or OPAT setpoints.
Also, B3.3.1 states:
In the event a channels Trip Setpoint is found nonconservative with respec t to the Allowable Value, or the transmitter, instrument loop, signal processing electronics, or bistable is found inoperable, then all affected Functions provided by that channel must be declared inoperable and the LCD Condition(s) entered for the protection Function(s) affected.
A. Incorrect 1) Al function is zeroed in the calculation for OPAT, therefore the setpoint would NOT lower or Raise.
- 2) The malfunction of Al function has no impact on the setpoint, or the parameter for which the trip is initiated (AT), therefore the OPAT functio n
Plausible: This combination is plausible in that PT1 would be true if OVERTEMPERATURE Delta T (OTAT) function was being challenged since Al is excessively high [Al> (+)1 5%] therefore penalizes the setpoint to a more conservative value (as long as actual -23% > Al <
+20%) AND if one were to apply the reverse of that logic stated in B3.3.1-36; if setpoint was MORE conservative then one could incorrectly presume the function remains operable.
B. Correct 1) f2 is zero for all power levels. Therefore Al will have NO impact on OPAT, regardless of magnitude.
- 2) The malfunction of Al function has no impact on the setpoint, or the parameter for which the trip is initiated (AT), therefore the OPAT function of TS 3.3.1 remains OPERABLE.
C. Incorrect 1)SeeA.1
- 2) Because the setpoint is unaffected, the function remains operable.
Plausthie: This answer would be selected if the affect on he setpaint were determined to move it in the NONCONSERVATIVE direction. IF one were to mistakenly believe a credit were applied to the setpoint because of the (+) 20% value. NOTE: OTAT has credits applied for Pressure and temperature.
D. Incorrect 1) see B.1
- 2) See C.2 Plausible: This combination is plausible in that it would be true if OVERTEMPERATURE Delta T (OTAT) function was bein g challenged and if Al were excessively high or low [(-)23% <Al > (+)1 5%] and/or the candidate decides to make inoperable due to the signal processing electronics is inoperable (IN THIS case OPAT setpoint or function is not impacted, only the A flux calculation) despite the allowance of TB 3.3.1 noted above.
- 4. 012A2.05 079/NEW/SRO/C/A 3.1/3.2/012A 2.051N/3!/JAN 12 Notes K/A statement: 012A2.05Reactor Protection Syst em (RPS)
Ability to (a) predict the impacts of Faulty or erratic operatIon of detectors and function generators on the RPS; and (b) based on those predictions, use procedur es to correct, control,or mitigate the consequences.
Importance Rating: 3.1 3.2 Technical
Reference:
TS 3.3.1 v51.O COLR Cy23 Rev I TB 3.3.1 vO.O References provided: None.
Learning Objective: RECALL AND APPLY the information from the LCD BASES sections: BACKGROUND, APPLICABLE SAFETY ANALYSIS, ACTIONS, SURVEILLANCE REQUIR EMENTS, for any Technical Specifications or TRM requirements associated with the TAVG, DT, and PIMP System, and attendant equipment, to include the following:
(OPS-62201J01): 10CFR55.43 (b) 2
- 3.3.1, Reactor Trip Instrumentation
- 3.3.2, Engineered Safety Features Actuation Instrumentation
- 2.1.1, Reactor Core Safety Limits Question origin: NEW Basis for meeting K/A: a) examinee must predict the impact from a malfunctioning M comparator drawer (function gene rator) on the OPAT setpoint function generator, then b) apply TS 3.3.1 and its basis to determine the operabili ty of the RPS function.
- Pt 1 can perhaps could be argued RO level of know ledge based on System knowledge
SRO justification: 10 CFR 55.43(b)(2): Knowledge of TS bases that is required to analyze TS required actions and terminolo gy The Requirements to assess the impact on this func tion is contained Below the LINE and is referenced in COLR.
2011 NRC exam From the Clarification Guidance for SRO-only Questions Rev 1 dated 03/11/2010 flowchart:
- 1) can NOT be answered by knowing less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Tech Specs.
- 2) can NOT be answered by knilwing information-li sted abovethe-line.
The Requirements to assess the impact on this func tion is contained Below the LINE; understanding of how the setpoint is calculated is in an amplifying NOTE for Table 3.3.1 and requires knowledge of the COLR table 3.
- 3) can NOT be answered by knowing the TS Safe ty Limits or their bases.
- 4) Does involve one or more of the following for TS, TRM or ODCM:
- Application of Required Actions (Section 3) and Surveillance Requirements (Section 4) in accordance with rules of application requirements (Section 1).
- Knowledge of TS bases that is required to analy ze TS required actions and terminology
RTS Instrumentation Table 3.3.1-1 (page 7 of 8)
Reactor Trip System Instrumentation Note 1: Overtemi,erature LT The Overtemperature LXT Function Allowable Valu shall e not exceed the following Trip Setpoint by more than 0.4% of T span.
(1+ 4S) 0 K1-K2 AT 1 (1+ s) r T 1
3
-T
(
1 P
(+ s) (1+ j s)[ (1+ r 2 I÷K- 1 P
( A )-f I)
L s) 6 J Where: txT is measured loop T, °F.
1T is the indicated loop T at RTP and reference 0
Tavg, °F.
s is the Laplace transform operator, sec .
1 T is the measured loop average temperature, °F.
T is the reference Tavg at RTP, *
°F.
P is the measured pressurizer pressure, psig.
P is the nominal pressurizer operating pressure = psig
- 1 K =
2 = */OF K 3 = */
K 1
t
- sec
- sec sec 5 t
- sec 6 t
- sec (f
1Ll) is a function of the indicated difference between top and bottom detectors of the power-range nuclear ion chambers; with gain s to be selected based on measured instrument response during plant startup tests such that:
(f 1Ll) = *{*
+ (q qj}
- when (q qb) % RTP of RTP when *% RTP <(q qb) *%
- } -
when (q q)> *% RTP
- q) -
Where q and q are percent RTP in the upper and lower halves of the core, respectively, and q + q is the total THERMAL POW ER in percent RTP.
- as specified in the COLR Farley Units 1 and 2 3.3.1-20 Amendment No. 151 (Unit 1)
Amendment No. 143 (Unit 2)
RTS Instrumentation 33.1 Table 3.3.1-1 (page 8 of 8)
Reactor Trip System Instrumentation Note 2: Overpower tT The Overpower T Function Allowable Value shall not exceed the following Trip Setpoint by more than 0.4% of LiT span.
(1÷ 4 s) 1 1 AT T 6 -K r T 1
-T -f
(
2 A I)
(1+ 5 s) 1+ S 3
1+
S 6 } 1+ S 6
L ]
Where: LiT is measured loop LiT, °F.
LiT is the indicated loop LiT at RTP and reference Tavg, °F.
0 s is the Laplace transform operator, sec 1
T is the measured loop average temperature, °F.
T is the reference Tavg at RTP, * °F.
=
- K = *IoF for increasing Tavg 5 K */OF when T> T 6
5 = *IoF for decreasing Tavg K 6 = *IoF when T T K
3 t
- sec sec 5
t
- sec s sec (f
2 Lil) = *% RTP for all Lii.
as specified in the COLA Farley Units 1 and 2 3.3.1-21 Amendment No. 151 (Unit 1)
Amendment No. 143 (Unit 2)
- CORE OPERATTNG L1MIT REPORT, FNP UNIT 1 CYCLE 23, REVISION 1 YIJLY 2010 2.7 Nuclear Enthalpy Rise Hot Channel Factor - F, (Specification 3.2.2) 2.7.1 FF*(1+PF*(1_P))
THERMAL POWER where: P RATED THERMAL POWER 2.7.2 F =1.70 2.7.3 PF = 0.3 2.8 Axial Flux Difference (Specification 3.2.3) 2.8.1 The Axial Flux Difference (AFD) acceptable operation limits are provided in Figure 3.
2.9 Boron Concentration (Specification 3.9.1) 2.9.1 The boron concentration shall be greater than or equal to 2000 ppm.
2 2.10 Reactor Core Safety Limits for THERMAL POWER (Specification 2.1.1) 2.10.1 Tn MODES 1 and 2, the combination of THERMAL POWER, Reactor Coolant System (RCS) highest loop average temperature, and pressurizer pressure shall not exceed the safety limits specified in Figure 4.
2.11 Reactor Trip System Instrumentation Overtemperature AT (OTAT) and Overpower AT (OP4fl Setpoint Parameter Values for Table 3.3.1-1 (Specification 3.3.1) 2.11.1 The Reactor Trip System Instrumentation Overteinperature AT (OTAT) and Overpower AT (OPAT) setpoint parameter values for TS Table 3,3.1-1 are listed in COLR Tables 2 and 3.
2.12 RCS DNB Parameters for Pressurizer Pressure. RCS Average Temperature. and RCS Total Flow (Specification 3.4.1) 2.12.1 RCS DNB parameters for pressurizer pressure, RCS average temperature, and RCS total flow rate shall be within the limits specified below:
- a. Pressurizer pressure 2209 psig;
- b. RCS average temperature 580.3°F; and
- c. The minimum RCS total flow rate shall be 263,400 GPM when using the precision heat balance method and 264,200 GPM when using the elbow tap method.
2 This concentration bounds the condition of kff 0.95 (all rods in less the most reactive rod) and subcriticality (ajj rods out) over the entire cycle. This concentration includes additional boron to address uncertainties and B ° depletion.
1 Page 4 of 12
CORE OPERATING LIMITS REPORT FNP UMT 1 CYCLE 2, PVIION 1 JULY 2010 Table 2 Reactor Trip System Instrumentation Overtemperature AT (OTAT)
Setpoint Parameter Values T 577.2°F P = 2235 psig
= 1.17 1<2 0.017/°F 1<3 = 0.000825Ips 3Osec 1
t t24sec t
O 4 sec t56sec t 6
6 sec (f
1AI) = -2.48 {23 ÷ (qt q)}
when (qt qi) -23% RTP 0% of RTP when 23% RTP < (qt qtj 15% RTP 2.05 {(qt q) 15) when (qt qj)> 15% RTP Page 6 of 12
CORE OPE1AT1NG LIMITS REPORT FNP UNIT 1 CYCLE 23. REVIS ION 1 JULY 2010 Table 3 1eactor Trip System Instrumentation Overpower AT (OPAT
)
Setpoint Parameter Values T 577.2°F K4= tb K = 0.021°F for increasihg T 5 89 5 = 0.00109/°F when T K > T 5 = 0/°F for decreasing Tavg K K = 0/°F when T V 6
t lOsec r
0 4 sec t5 6 sec t66 sec (f
2Al) = 0% RTP for all Al Page 7 of 12
RTS Instrumentation 3.3.1 BASES APPLICABLE 20. Automatic Trip Logic (continued)
SAFETY ANALYSES, LCO, and The LCO requires two trains of RTS Automatic Trip Logic to be APPLICABILITY OPERABLE. Having two OPERABLE trains ensures that random failure of a single logic train will not prevent reactor trip.
These trip Functions must be OPERABLE in MODE 1 or 2. In MODE 3, 4, or 5, these RTS trip Functions must be OPERABLE when the RTBs or associated bypass breakers are closed, and the CRD System is capable of rod withdrawal.
The RTS instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
ACTIONS A Note has been added to the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed in Table 3.3.1-1.
In the event a channels Trip Setpoint is found nonconservative with respect to the Allowable Value, or the transmitter, instrument loop, signal processing electronics, or bistable is found inoperable, then all affected Functions provided by that channel must be declared inoperable and the LCO Condition(s) entered for the protection Function(s) affected.
When the number of inoperable channels in a trip Function exceed those specified in one or other related Conditions associated with a trip Function, then the unit is outside the safety analysis. Therefore, LCO 3.0.3 must be immediately entered if applicable in the current MODE of operation.
A.1 Condition A applies to all RTS protection Functions. Condition A addresses the situation where one or more required channels for one or more Functions are inoperable at the same time. The Required Action is to refer to Table 3.3.1-1 and to take the Required Actions for the protection functions affected. The Completion Times are those from the referenced Conditions and Required Actions.
(continued)
Farley Units 1 and 2 B 3.3.1-36 Revision 0
RTS Instrumentation BASES APPLICABLE 5. Source Range Neutron Flux (continued)
SAFETY ANALYSES, LCO, and The Source Range Neutron Flux Function provides protection for APPLICABILITY control rod withdrawal from subcritical, boron dilution and control rod ejection events. The Function also provides visual neutron flux indication in the control room.
In MODE 2 when below the P-6 setpoint during a reactor startup, the Source Range Neutron Flux trip must be OPERABLE. Above the P-6 setpoint, the Intermediate Range Neutron Flux trip and the Power Range Neutron FluxLow Setpoint trip will provide core protection for reactivity accidents. Above the P-6 setpoint, the NIS source range high Flux reactor trip is blocked and the detectors are manually de-energized.
In MODE 3, 4, or 5 with the reactor shut down, the Source Range Neutron Flux trip Function must also be OPERABLE. If the CRD System is capable of rod withdrawal, the Source Range Neutron Flux trip must be OPERABLE to provide core protection against a rod withdrawal accident. If the CRD System is not capable of rod withdrawal, the source range detectors are not required to trip the reactor. However, their monitoring Function must be OPERABLE to monitor core neutron levels and provide indication of reactivity changes that may occur as a result of events like a boron dilution.
The requirements for the NIS source range detectors in MODE 6 are addressed in LCO 3.9.3, Nuclear Instrumentation.
- 6. Overtemperature zT The Overtemperature .T trip Function is provided to ensure that the design limit DNBR is met. This trip Function also limits the range over which the Overpower T trip Function must provide protection.
The inputs to the Overtemperature T trip include pressure, coolant temperature, axial power distribution, and reactor power as indicated by loop tT assuming full reactor coolant flow. Protection from violating the DNBR limit is assured for those transients that are slow with respect to delays from the core to the measurement system when pressure is between the high and low pressure reactor trips. The core thermal power is correlated to the differential temperature across the vessel by measurement of Loop AT values at approximately full power with reactor coolant average temperature at the approximate cycle-specific full power reference temperature. The Overtemperature AT trip Function uses each (continued)
Farley Units 1 and 2 B 3.3.1-14 Revision 0
RTS Instrumentation B 3.3.1 BASES APPLICABLE 6. Overtemerature AT (continued)
SAFETY ANALYSES, LCO, and loops AT as a measure of reactor power and is compared APPLICABILITY with a setpoint that is automatically varied with the following parameters:
- reactor coolant average temperaturethe Trip Setpoint is varied to correct for changes in coolant density and specific heat capacity with changes in coolant temperature;
- pressurizer pressurethe Trip Setpoint is varied to correct for changes in system pressure; and
- axial power distributionf(AI), the Trip Setpoint is varied to account for imbalances in the axial power distribution as detected by the NIS upper and lower power range detectors.
Dynamic compensation is included for system piping delays from the core to the temperature measurement system and for RTD response time delays.
The Overtemperature AT trip Function is calculated for each loop as described in Note 1 of Table 3.3.1-1. Trip occurs if the indicated AT equals or exceeds the calculated Overtemperature AT setpoint in two channels. Since the temperature signals are used for other control functions, the actuation logic must be able to withstand an input failure to the control system, which may then require the protection function actuation, and a single failure in the other channels providing the protection function actuation. Control and Protection System interaction design requirements are addressed by implementation of Tavg and AT median selector circuits as discussed in FSAR Chapter 7.2. Note that this Function also provides a control interlock signal to prevent rod withdrawal prior to reaching the Trip Setpoint. Limiting further rod withdrawal may terminate the transient and prevent a reactor trip.
The LCO requires all three channels on the Overtemperature AT trip Function to be OPERABLE. The channels are combined in a 2-out-of-3 trip Logic. Note that the Overtemperature AT Function receives Tavg, AT, pressure, and upper and lower flux (continued)
Farley Units 1 and 2 B 3.3.1-15 Revision 0
RTS Imentation B.1 BASES APPLICABLE 6. Overtemperature AT (continued)
SAFETY ANALYSES, LCO, and inputs from channels shared with Overpower AT, pressurizer APPLICABILITY pressure, and NIS power range RTS/ESFAS Functions. Failures that affect multiple Functions require entry into the Conditions applicable to all affected Functions.
In MODE 1 or 2, the Overtemperature AT trip must be OPERABLE to ensure that the DNB design basis is met. In MODE 3, 4, 5, or 6,
this trip Function does not have to be OPERABLE because the reactor is not operating and there is insufficient heat production to be concerned about DNB.
- 7. Overpower AT The Overpower AT trip Function provides protection for Condition I
and It transients to ensure the integrity of the fuel (i.e., no fuel pellet melting and less than 1% cladding strain) under all possible overpower conditions. This trip Function also limits the required range of the Overtemperature AT trip Function and provides a backup to the Power Range Neutron Flux High Setpoint trip. The Overpower AT trip Function ensures that the allowable heat generation rate (kW/ft) of the fuel is not exceeded. This trip functio n
is explicitly credited in the safety analyses to mitigate the Consequences of small Steam Line breaks at full power. It uses the AT of each loop as a measure of reactor power with a setpoint that is automatically varied with the following parameters:
- reactor coolant average temperaturethe Trip Setpoint is varied to correct for changes in coolant density and specific heat capacity with changes in coolant temperature; and
- rate of change of reactor coolant average temperature including dynamic compensation for the delays between the core and thetemperature measurement system including RTD response time delays.
The Overpower AT trip Function is calculated for each loop as per Note 2 of Table 3.3.1-1. Trip occurs if the indicated AT equals or exceeds the calculated Overpower AT setpoint in two loops. Since the temperature signals are used for other control functions, the actuation logic must be able to withstand an input failure to the control system, which may then require the (continued)
Farley Units 1 and 2 B 3.3.1-16 Revision 0
RTS Instrumentation 3.3. 1 BASES APPLICABLE 7. Overnower AT (continued)
SAFETY ANALYSES, LCO, and protection function actuation and a single failure in the remaining APPLICABILITY channels providing the protection function actuation. Control and Protection System Interaction design requirements are addressed by implementation of Tavg and AT median selector circuits as discussed in FSAR Chapter 7.2. Note that these channels also provide a control interlock signal prior to reaching the Trip Setpoint which limits rod withdrawal. Limiting rod withdrawal may terminate the transient.
The LCO requires three channels of the Overpower AT trip Function to be OPERABLE. The channels are combined in a 2-out-of-3 trip Logic. Note that the Overpower AT trip Function receives Tavg and AT inputs from channels shared with the Overtemperature AT RTS Function. Failures that affect multiple Functions require entry into the Conditions applicable to all affected Functions.
In MODE 1 or 2, the Overpower AT trip Function must be OPERABLE. These are the only times that enough heat is generated in the fuel to be concerned about the heat generation rates and overheating of the fuel. In MODE 3, 4, 5, or 6, this trip Function does not have to be OPERABLE because the reactor is not operating and there is insufficient heat production to be concerned about fuel overheating and fuel damage.
- 8. Pressurizer Pressure The same transmitters provide input to the Pressurizer Pressure High and Low trips and the Overtemperature AT trip and the ESFAS (low pressure SI and P-i 1 interlock). A Dedicated Pressurizer Pressure control channel provides input to the Pressurizer Pressure Control System, therefore there are no control/protection interaction concerns. This trip Function is credited in several safety analyses.
- a. Pressurizer Pressure Low The Pressurizer Pressure Low trip Function ensures that protection is provided against violating the DNBR limit due to low pressure. The Trip Setpoint limits the required range of (continued)
Farley Units 1 and 2 B 3.3.1-17 Revision 0
Definitions Li-1.1 Definitions LEAKAGE c. Pressure Roundry LEAKAGE (continued)
LEAKAGE (except SG 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.
OPERABLEOPERABILITY 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:
- a. Described in Chapter 14, Initial Tests and Operation, of the FSAR;
- b. Authorized under the provisions of 10 CFR 50.59; or
- c. Otherwise approved by the Nuclear Regulatory Commission.
Farley Units 1 and 2 1.1-4 Amendment No. 149 (Unit 1)
Amendment No. 141 (Unit 2)
- 80. 028A2.02 080/NEW/SRO/C/A 3.5/3 .9/028A2.02/N/2/VER2.O/REPLACEMENT Unit ihas experienced a LOCA. The following conditions exist:
- EEP-1 .0, Loss of Reactor or Secondary Coolant, is in progress.
- The RCS is being cooled to <200°F.
- Containment pressure has remained <20 psig.
- Hydrogen Analyzers have been placed in service.
- Containment Hydrogen is 4.1% by volume of dry air.
Which one of the following describes the hydrogen concentration within containment and the actions required per EEP-1 .0?
The hydrogen concentration (1) exceed the limit which could cause a concern for containment integrity.
Hydrogen concentration will be lowered using (2)
(1) (2)
A. does NOT SOP-i 0, POST LOCA Containment Pressurization and Vent System.
B. does NOT Attachment 3 of EEP-1 .0, Post LOCA Hydrogen Recombiner Operation.
C DOES SOP-I 0, POST LOCA Containment Pressurization and Vent System.
D. DOES Attachment 3 of EEP-l .0, Post LOCA Hydrogen Recombiner Operation.
- 5. 028A2.02 080/NEW/SRO/C/A 3.5/3 .9/028A2.02/N/2/VER2.O/REPLACEMENT Feedback -
EEP-1.0, v30 step 6.4 Caution states:
Fire or explosion may occur if post LOCA hydrogen recombiners are placed 11 in service when containment hydrogen concentration is greater than 4%.
FNP-EEB-iO, v2.O ERP step 6 basis:
[...J The hydrogen concentration is of concern since a flammable mixture can burn, if an ignition source is available, and cause a sudden rise in containment pressure which may challenge containment integrity.
A determination is made of the flammability of the hydrogen mixture with[...} respect to the possible containment pressure rise. If the hydrogen mixture is betwee n 0.5 volume percent and 6.0 volume percent in dry air, either no hydrogen burn is possible or a limited burn may occur which does not produce a signifi cant pressure rise.
ERG FOOTNOTE BASIS DOCUMENT (T.06)
Hydrogen concentration is monitored to determine when to take corrective action to maintain or reduce the concentration of hydrogen to below the flamm ability limit, If the hydrogen concentration is greater than the ERG Footnote value (6
volume percent in dry air), the hydrogen recombiners should not be operate d since a flammable situation is imminent and operation of the recombiners could cause a hydrogen burn or explosion.
FSAR section 6.2.5.3.1 Electric Hydrogen Recombiners design evaluation states [...]
the lower flammability limit of 4 volume percent and control measures are necessary to prevent hydrogen accumulation to this limit. (FSAR pg 6.2-82
)
OPS-52102D student text provides the following:
The recombiners are only allowed in service when the hydrogen concentration in containment is less than 3.5 percent by volume. Placing them in service at higher concentrations could result in fire or possibly an explosion should the explosive limit of 8 percent volume be exceeded.
A. Incorrect 1) The hydrogen concentration is of concern since a flammable mixture can burn, if an ignition source is available, and cause a sudden rise in contatinment pressure which may challenge containment integrity.
Plausible: The concentrations necessary to initiate an explosion are>
6-8% (depending on concentrations of Oxygen and instrumentation variables) by volume of DRY air. One may believe that an explosion is necessary to challenge containment integrity, the value is below the explosive limits.
- 2) See C.2.
Plausible: The hydrogen recombiner operation is limited to 3.5% (vendo r
manual) to ensure the recombiner is not damaged, and capable of
operation after hydrogen is restored to less than flammable limits. IF one were not aware that Containment Integrity was the basIs of This action (match with Part 1) and confuse it with the premise of protecing the recombiner from damage, this procedure would be selected.
SOP-i 0 contains all necessary guidance to Pressurize (dilute) and Vent containment atmosphere, AS WELL as guidance to operate the recombiners when levels are restored to < 3.5% hydrogen concentration.
B. Incorrect 1) See A.l
- 2) EEP-1 .0 does not direct placing any Recombiners in service for hydrogen concentrations> 35%. Both Recombiners are placed in service per this attachment ONLY if concentration is >0.5% but <3.5%.
Plausible: Since the value is below the 8% explosive limit, if the candidate believes that there is not a concern for Contianment integrity, or hydrogen burn, then they would implement EEP-l .0 attachment 3..
C. Correct 1) See Above. Hydrogen concentration is above the lower flammability limit, which offers a concern for Containment integrity. See EEB-1 excerpt above.
- 2) The recombiner is NOT permitted to be placed in service when hydrogen is> 3.5%, and Attachment 3 of EEP-i will NOT be utilized.
Instead, SOP-b will be utilized to vent containment to lower containment pressure, or pressurize containment to dilute the hydrogen concentration.
SOP-i 0 would be implemented regardless of the mechanism chosen if the recombiners could not be placed in service in EEP-i. This procedure ALSO directs operation of the RECOMBINERS when levels are restored to those acceptable for operation.
D.lncorrect 1) See C.i
- 2) See 8.2 Plausible: This answer choice is plausible if one were not aware of the limitations of placing the POST LOCA recombiners in service but AWAR E
of the concerns of the POTENTIAL. EEP-i .0 directs considering other methods of hydrogen control.
NOTE TO Chief EXAMINER:
- 1) Chief Examiners RECOMMENDATION to change answer choice for part 2 to read, SOP-b transition IS/IS NOT required, or conversely, EEP-l attachment 3 IS/IS NOT required, was NOT implemented for the following reasons:
o SOP-i 0.0 contains sections that could be used in lieu of EEP-1 Attachment 3 to accomplish the same task of that attachment. Furthermore, SOP-b is not REQUIRED by EEP-1.0, the wording in EEP-1.0 RNO steps directs considering other means, such as ... rather than a direction to perform a
specific action. Therefore, the facility Authors believe that in the format of SOP-10.0 (IS uS NOT) required wot.ild Ieiid the opportunity for appe1s.
EEP1 .0 Attachment 3 (is I is NOT) required format also was NOT utilized since EEP-1 .0 attachment 3 WOULD NOT be implemented and this aspect of this answer choice (transition) is the portion of this question which meets 10 CFR 55.43(b)(5). The facility Authors believe that by implementing the EEP-1 .0 attachment 3 (IS! is NOT) required format would remove the SRO tie since no actual transition would be made.
- 5. 028A2.02 080/NEW/SRO/C/A 3.5/3.9/028A2.02/N/2IVER2.O/REPLACEMENT Notes K/A statement 028A2.02 Ability to a) predict impact of LOCA condition and related concern over hydrogen on the operation HRPS; and (b) based on those predictions, use procedures to correct, control or mitigate the consequences of those malfunctions or operations Importance Rating: 3.5 3.9 Technical
Reference:
FSAR chapter 6.2.5.3.1, v23 FNP-0-EEB-1.0, v2.0 EEP-1 .0, v29.0 Lesson text OPS-52102D, POST LOCA Atmosphere Control, v2 References provided: None Learning Objective: PT 1)LIST AND IDENTIFY any special considerations such as safety hazards and plant condition changes that apply to the Post LOCA Atmospheric Control System (OPS-521 02D04)
PT 2) ASSESS the facility conditions associated with the Post LOCA Atmospheric Control System components, and based on that assessment, SELECT the appropriate procedure(s) for normal or abnormal situations.
(OPS-621 02D02)
Question origin: NEW Basis for meeting K/A: a) Test knowledge of the hydrogen concentration limit, which is the concern related to hydrogen concentration within containment POST-LOCA b) knowledge of EEP-1 .0 step 6.4 & 6.5 which provides the decision point to implement one of two procedure flowpaths to mitigate the hydrogen concentration.
SRO justification: 10 CFR 55.43(b)(5)
Knowledge of when to implement attachments and appendices, including how to coordinate these items with procedure steps.
2011 NRC exam Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations [10 CFR 55.43(b)(5)], involving BOTH:
- 1) assessing plant conditions and then
- 2) selecting a procedure or section of a procedure to mitigate, recover, or with
which to proceed.
One atea of SRO [eve] know1edg i knowledge of content of the proced ure vs. the procedures overall mitgative strategy or purpose.
EXAMPLE:
- Knowledge of when to implement attachments and appendices, including how to coordinate these items with procedure steps.
- Knowledge of diagnostic steps and decision points in the emerge ncy operating procedures (EOP) that involve transitions to event specific sub-procedur es or emergency contingency procedures.
- Knowledge of administrative procedures that specify hierarchy, implem entation, and/or coordination of plant normal, abnormal, and emergency proced ures.
Using the flowchart, this question can:
- NOT be answered solely by knowing systems knowledge, i.e., how the system works, flowpath, logic, component location.
Knowledge of the Hydrogen RECOMBINER limitations (pt 2) can be answer ed using system knowledge.
PTI is a fundamental/system knowledge regarding the basis for actions of EEP-1, Limitations/purpose of POST Accident Recombiners.
- NOT be answered solely by knowing immediate operator actions.
- NOT be answered solely by knowing entry conditions for AOPs or plant parameters that require direct entry to major EOPs.
- NOT be answered solely by knowing the purpose, overall sequen ce of events, or overall mitigative strategy of a procedure.
Knowledge of the existence of the problem is required RO knowledge.
HOWEVER, knowledge of which strategy to implement is beyond OVERALL sequence of events.
- CAN be answered with knowledge of ONE or MORE of the following:
Assessing plant conditions (normal, abnormal, or emergency) and then selecting a procedure or section of a procedure to mitigate, recover, or with which to proceed.
The knowledge challenged in Pt 1 of this question is more with regard to the consequence of NOT performing an action. Knowledge necessary to properly evaluate a procedure deviation, or task prioritization beyond the generic process of procedural compliance.
Knowledge of when to implement attachments and appendices, includi ng how to coordinate these items with procedure steps.
Knowledge of diagnostic steps and decision points in the EOP5 that involve transitions to event specific sub-procedures or emergency contingency procedures.
SOP-i 0 contains portions that are implemented SPECIFICALLY after a
LOCA, thereby equivalent to an event specific sub-procedure (albeit not the WOG defined ESP5).
Knowledge of administrative procedures that specify hierarchy, implementation, and/or coordination of plant normal, abnormal, and emergency procedures.
2/14/2011 11:07 FNP1-EEP-1 LOSS OF REACTOR OR SECONDARY COOLANT Revision 30 Step Action/Expected Response Response NOT Obtained III I I 1 CAUTION: Fire or explosion may occur if post LOCA hydrogen recomb iners are placed in service when containment hydrogen concentration is greater than 4%.
CAUTION: To prevent diesel generator overloading, at least 0.075 MW (75 kW) of diesel generator capacity must be available prior to starting a hydrogen recoinbiner.
SOP-I 0, provides the guidance to reduce Hydrogen concentrations for step 6.4 6.4 Check containment hydrogen 6.4 Evaluate other methods of concentration - LESS THAN hydrogen control such as post 3.5%. LOCA containment pressurization and vent system.
6.5 Check containment hydrogen 6.5 Establish both post LOCA concentration - LESS THAN containment hydrogen 0.5%. recombiners in service using ATTACHMENT 3, POST LOCA HYDROGEN RECOMBINER OPERATION.
Distractor This ACTION would NOT be permitted to be completed.
Although strict procedure compliance actually would direct performing step 6.5 RNO, CAUTION and background.
would REQUIRE the SRO to recognize a procedure deviation (SOP-0.8) may be required.
See FRP-C.1 step 10 (next page) for equivalent step--- and per basis document is more likely to encounter a hydrogen problem after a LOSS OF CORE COOLING event.
Page 7 of 20
FNP-l-FRP-C.l RESPONSE TO INADEQUATE CORE COOLING Revision 17 Step Action/Expected Response Response NOT Obtained III I NOTE: The procedure should be continued while determining the containment hydrogen concentration.
10 Check containment hydrogen concentration.
10.1 Verify 1A and lB post LOCA 10.1 at least one analyzer in containment hydrogen analyzers service,
- IN SERVICE USING ATTACHMENT THEN proceed to step 10.2, 2, POST LOCA CONTAINMENT IF NOT, direct Chemistry to HYDROGEN ANALYZER OPERATION, sample containment atmosphere for hydrogen using FNP-0-CCP-1300, CHEMISTRY AND ENVIRONMENTAL ACTIVITIES DURING A RADIOLOGICAL ACCIDENT.
CAUTION: Fire or explosion may occur if post LOCA hydrogen recombiners are placed in service when containment hydrogen concen tration is greater than 4%.
10.2 Check containment hydrogen 10.2 Perform the following.
concentration - LESS THAN 3.5%. 10.2.1 Consult TSC for additional recovery actions.
10.2.2 Proceed to Step 11.
10.3 Check containment hydrogen 10.3 Establish both post LOCA concentration - LESS THAN containment hydrogen 0.5%. recombiners in service using ATTACHMENT 3, POST LOCA HYDROGEN RECOMBINER OPERATION.
NOTE: in FRP-C.1 step 10.3 is properly bypassed--- PROCEDURE error of EEP-1 discovered during the writing of this test question. --- NOTED for post-exam enhancement. However, the operation of the RECOMBINER in EEP-1 .0 when value >3.5% would NOT be in compliance 1
P age Completed of FSARIFSD/or BKGD data.
Page 10 of 33
09/28/07 13:10:11 FNP-0-EEB-1.0 LOSS OF REACTOR OR SECONDARY COOLANT Plant Specific Background Information Section: Procedure Unit 1 ERP Step: 6 Unit 2 ERP Step: 6 ERG Step No: 17 ERP StepText: Perform the following within 1 of start of event.
ERG Step Text: Check Containment Hydrogen Concentration.
Purpose:
To check if an excessive containment hydrogen concentration is present Basis: This step instructs the operator to obtain a current hydrogen concentration measurement.
Depending upon the magnitude of the hydrogen concentration, the operator will either continue with guideline E- 1, turn on the hydrogen recombiners or notify the plant engineering staff to determine additional recovery actions before continuing with the guideline. When inadequate core cooling has occurred, the containment hydrogen concentration may be as much as 10 to 12 volume percent, depending on the amount of metal-water reaction (to produce hydrogen) that has occurred in the core. The hydrogen concentration is of concern since a flammable mixture can burn, if an ignition source is available, and cause a sudden rise in containment pressure which may challenge containment integrity. The operator is instructed to obtain a current containment hydrogen concentration measurement at this point in order to ascertain the potential flammability of the combustible gases in the contaimnent.
Note that in order to have the potential for flammable hydrogen concentrations, an inadequate core cooling situation must have already existed. Without an inadequate core cooling situation, sufficient hydrogen would not be expected to have been produced to cause potentially flammable mixtures. A determination is made of the flammability of the hydrogen mixture with respect to the possible containment pressure rise. If the hydrogen mixture is between 0.5 volume percent and 6.0 volume percent in dry air, either no hydrogen bum is possible or a limited burn may occur which does not produce a significant pressure rise. A hydrogen concentration not to exceed 6.0 volume percent in dry air corresponds to the upper limit of operability for the hydrogen recombiner, represented by the footnote (T.05). If containment hydrogen concentration is between 0.5 volume percent and (T.05), the operator is instructed to start the hydrogen recombiner system to slowly reduce containment hydrogen concentration. If the hydrogen concentration is less than 0.5 volume percent in dry air, a flammable situation is not imminent and the operator continues with guideline E- 1. If the concentration is greater than (T.05) volume percent in dry air, the operator is instructed to immediately notify the plant engineering staff of the situation. In this case the operator is instructed to consult the plant engineering staff for additional recovery actions while proceeding with this guideline. STEP DESCRIPTION TABLE FOR E-IStep 17 All hydrogen measurements are referenced to concentrations in dry air even though the actual containment environment may contain significant steam concentrations. The reason for this is twofold: 1) most hydrogen measurement systems remove moisture from the sample thus approximating a dry air condition and 2) the indication of the potential of hydrogen flammability is conservative when based upon using hydrogen concentration in dry air.
15 of 65 Version: 2.0
UNIT I I Farley Nuclear Plant A Procedure Number Ver 10/8/2010 10:21:42 I POST LOCA CONTAINMENT PRESSURIZATION AND VENT SYSTEM FNP-1 -SOP-i 0.0 Page Nrner.
37.0 5of23 4M INSTRUCTIONS NOTE Pressurizing or venting of containment is initiated when the containment hydrogen concentration projected for the next day is estimated to equal or exceed 3.5%.
4.1 Determining Estimated Containment Hydrogen Concentration.
4.1.1 Determine hydrogen generation rate as follows:
4.1.1.1 Obtain values of hydrogen concentration (C) vs. time from FNP-i-EEP-i Figure 1, Containment Hydrogen Concentration Plot (if available), OR Figure 1 of this procedure. LI 4.1 .1.2 Calculate the average daily containment hydrogen generation rate (G) by the following expression:
1 2
C C 1
2 T
G-T 100 WHERE: G = hydrogen generation rate (SCFIDAY)
V = containment volume (2.03 x 106 ft )
3 T T 2 - 1 = time lapse between C 2 and C1 (days) 2 = containment H C 2 concentration at T 2 (vol. %)
2 = containment H C 1 (vol. %)
2 concentration at T 4.1.2 Determine estimated containment hydrogen concentration (C3) for one day from the time of the last data point (T3 = T2 + 1 day) 2 3
C
+
C I- 2 GxlOO 3
) Tx(T L vc WHERE: G = hydrogen generation rate (SCFIDAY) from 4.1.1 V containment volume (2.03 x 106 ft
)
3 T T 2 - 1 = time lapse between C 3 and C 2 (days) 2 = containment H C 2 (vol. %) from 2 concentration at T FNP-1-EEP-1 Figure 1 (preferred) or FNP-1 -SOP-I 0.0 Figure 1 3 = containment H C 2 concentration at T 3 (vol. %)
4.1.3 IF the estimated containment hydrogen concentration (C3) is less than 3.5%, THEN exit this procedure.
LI 4.1.4 JE containment pressure is less than 2 psig, THEN go to Section 4.2, Pressurizing Containment.
4.1.5 E containment pressure is greater than or equal to 2 psig, THEN go to Section 4.3, Venting Containment.
FNP-FSAR-6 downward flow from the upper containment volume through grating located around the periphery of the containment. This convective flow into and out of the lower containment, coupled with the mixing action of the sprays and containment air coolers above the operating floor, will complement the action of the post-LOCA mixing fans.
The undersides of all floors inside the containment have been sloped to augment this natural convec tion. Inverted pockets that might tend to encourage stagnant accumulations of containment atmosphere have been avoided by design.
To determine the design capacities of the post-LOCA mixing fans, the containment was sectionalized into specific compartments as shown in figures 6.2-92 and 6.2-93. The lower compartment was defined as the summation of compartments 2, 3, 4, 5, 6, and 8.
Figures 6.2-96 and 6.2-97 give the calculated volume percent of hydrogen in each compartment as a function of time assuming no intercompartmental mixing. Figure s 6.2-98 and 6.2-83 give the hydrogen generation rates as a function of time. For each compa rtment, the ventilation sweep rate required to maintain the compartmental hydrogen concen tration below 3.5 volume percent was calculated. The post-LOCA mixing fans were selected so that they have a design flow that exceeds the calculated required sweep rate for the lower compartments.
6.2.5.3 Design Ev&uation 6.2.5.3.1 Electric Hydrogen Recombiners The prediction of hydrogen generation following a LOCA is shown in figures 6.2-83 and 6.2-98, which demonstrate that the hydrogen production rate decreases with time after the accident. As discussed in paragraph 15.4.1.6.5, and as can be determined from these figures, the total hydrogen accumulation can exceed the lower flammability limit of 4 volum e percent and control measures are necessary to prevent hydrogen accumulation to this limit.
The electric recombiner provides the means to prevent unsafe levels of hydrog en concentration from being reached in the containment following a LOCA.
For the purpose of showing that the electric recombiner is capabl e of maintaining safe hydrogen concentrations, analysis was performed using the NRC Regulatory Guide No. 1.7 Model. The result is shown in figure 6.2-94. The Regulatory Guide No. 1.7 Model is based upon assuming a fission product activity release specified in TID-14844 and the values for post-accident hydrogen generation specified in this guide. The results using the Westin ghouse model are also shown on this figure.
Each electric recombiner is capable of continually processing a minim um of 100 sft /min 3
(standard conditions of 68°F and 1 ATM) of containment atmosphere.
All of the hydrogen contained in the processed atmosphere is converted to steam, thus reducing the overall containment hydrogen concentration. The hydrogen concentration in the containment was calculated for the models described above based on a recombiner capabi lity of processing 93 sft/min of containment atmosphere at modeled conditions of 32°F 3
and 1 ATM. This calculation shows that the maximum hydrogen concentration will be much less than the lower flammability limit of 4 volume percent if the recombiner is started I day following the accident.
Therefore, one of these units meets the design criterion of maintaining a safe hidrogen 6.2-82 REV 23 4/10
ERG FOOTNOTE BASIS DOCUMENT NUMBER T.05 PARAMETER Containment Hydrogen Concentration DESCRIPTION Containment hydrogen concentration corresponding to the limit of the operability of the hydrogen recombiners, not to exceed 6%.
footnote states 6% but 4% is the value stated in the procedure DETAILED ERG USAGE background! procedure NOTE and FSAR and lesson text -->
This ERG footnote is used in guid such as E-l, ES-l.2, ECA-3.l, ECA-3.2 and FR-C.1. In this category of events, hydrogen may be generated and released to the containment atmosphere. Hydrogen concentration is monitored to determine when to take corrective action to maintain or reduce the concentration of hydrogen to below the flammability limit. If the hydrogen concentration is greater than the ERG Footnote value (6 volume percent in dry air), the hydrogen recombiners should be operated since a flammable situation is imminent and operation of the recombiners could cause a hydrogen burn or explosion. If the recombiner is designed for operation at concentrations less than 6%. that limit should be used as the upper limit in the EOPs. If the recombiner operability limit is greater than 6%. 6% should be used as the upper limit in the EOPs.
CALCULATIONAL METHODOLOGY The following provides a step-by-step methodology for determining the plant-specific EOP setpoint value:
Step 1 - determine the plant-specific operating limit on hydrogen in the containment atmosphere for Hydrogen Recombiner operation from plant design information (Reference 2)
If the Hydrogen Recombiner is designed (Reference 2) for operation at concentrations less than 6%, then the more conservative limit should be used as the upper limit in the EOPs. If the Hydrogen Recombiner operability limit is greater than 6%, then 6% should be used as the upper limit in the EOPs. Typically, it is not necessary to include instrument uncertainty in the determination of this EOP setpoint value. Refer to DW-99-056. 4% is the design of the recombiners--- -0.5% = 3.5%
Step 2 round off for readability of EEP-1 step 6 /FRP-C. I step 10 The value calculated in step 1 should be rounded down to the nearest 1/2 division to obtain the EOP setpoint value.
Footnote Basis Page 273 HP/LP-Rev. 2, 4/30/2005 FN Basis,doc
training documentation process a flow of containment atniupiiic wiiii a nyuiugcii uiiiciii Lypn.a1 UI UI avLaac concentration in the containment. In the recombiner, the air-hyd rogen mixture, heated to approximately 1200°F, will cause the hydrogen to combine with the free oxygen in the air and form water vapor. The air-vapor mixture will exit the recombiner due to natural convection. The recombiners are only allowed in service when the hydrogen concentration in containment is less than 3.5 percent by volume.
Placing them in service at higher concentrations could result in fire or possibly an explos ion should the explosive limit of 8 percent volume be exceeded. If high concentrations do exist, other methods of reduction should be employed.
The post accident venting system provides a backup to the hydrog en recombiner system. The system consists of a supply line through which hydrogen-free air can be admitted to the containment and an exhaust line through which hydrogen bearing gases can be vented from the containment. The gas filtering limits the discharge of particulates and iodine.
The post accident combustible gas sample system consists of two independent trains. Each train has two sample inlet lines, one removable sample container, one hydrogen analyzer, and a return line routed to containment.
This system obtains post accident grab samples for analysis, continuously monitors containment hydrogen concentration following a LOCA, and provides a means of monitoring hydrogen recombiner effectiveness. The supply lines in the containment are located in missile-protected areas. They terminate so as to prevent either spray or sump water from entering the pipe.
The sample exhaust line in the containment is located in a missile-protec ted area.
It is terminated in a well ventilated area in a manner which preven ts either spray or sump water from obstructing the pipe. The hydrogen analyzers can be controlled and monitored from the control room.
The post LOCA air mixing system is employed to ensure that the hydrogen concentration remains uniform throughout the containment. Four fans are provided to circulate the containment atmosphere through the lower contain ment elevation, the volume above the operating floor, and the reactor cavity. These fans are placed on the 9 OPS-62102D 52102D 40302E Version 2
U.S. N .RC. Site-Specific Written Examination McGuire 1/2 Senior Reactor Operator Question 092 idea source-- BANK question Farley is not equipped with igniters. Therefore Given the following:
needs modification to acquire balance.
- A LOCA has occurred on Unit 2.
- Due to subsequent failures, the crew is performing actions contained in FR-C.1, Response to Inadequate Core Cooling.
- Hydrogen Igniters and Recombiners are OFF.
- NF AHUs are OFF.
- Containment Hydrogen Concentration is currently 3% and rising slowly.
Which ONE (1) of the following describes the action required, and the reason for the action, in accordance with FR-C.1?
A. Place Hydrogen lgniters in service ONLY, because Hydrogen Recombiner operating temperatures may cause a challenge to containment integrity due to hydrogen ignition.
B. Place Hydrogen Igniters and Hydrogen Recombiners in service because containment hydrogen concentration is below the limit which could cause a concern for containment integrity violations due to hydrogen ignition.
C. Do NOT place either Hydrogen Igniters or Hydrogen Recombiners in service because containment hydrogen concentration is above the limit which could cause a concern for containment integrity violations due to hydrogen ignition.
D. Place Hydrogen Recombiners in service ONLY, because placing Hydrogen Igniters in service when containment hydrogen is above 0.5% may cause a challenge to containment integrity due to hydrogen ignition.
Page 95 of 103 Rev Final
- 81. 035A2.O1 O8IINEW/SRO/C!A4.5/4.6/035A2.O1IN/2//JAN 12 Unit I has a steam leak. The following contions exist
- AOP-14.O, Secondary System Leakage, is in progress.
- The steam leak is in the MSVR upstream of the MSIVs and is unisolable.
- Rxpoweris29%.
- PT-446, TURB FIRST STG PRESS, is 125 psig.
1A lB 1C Fl-474 Fl-484 Fl-494 1.21 1.23 1.23 Which one of the following completes the statements below?
AOP-14.O requires a (1) to be initiated.
The Containment Barrier (2) INTACT per NMP-EP-GLO1, Figure 1, Fission Product Barrier Evaluation.
(1) (2)
A. power reduction using the UOP5 is NOT B. power reduction using the UOPs IS C. RxTrip is NOT D RxTrip IS
- 6. 035A2.O1 O8IINEW/SRO/C/A 4.5/4.6/035A2.O1IN/2/!JAN 12 Feedback AOP-14.0 step I and step 2.3 RNO requires the operator to evaluate Turbin e power vs Rx power. IF there is a mismatch of 10% OR if there is a >1% misma tch with the leak inside the MSVR and NOT isolable, then a Rx Trip is required. The
>1 %
MSVR leak requirement is to ensure protection of Environmentally Qualif ied (EQ) instrumentation/components contained in the MSVR from HIGH temperatures.
(REF FSAR Appendix 3J).
AOP-14 step 5, directs the operator to evaluate EAL5 if primary to second ary leakage exists.
AOP-14.O step 7, IF MSVR leakage is noted as impacting Secondary Leakage posing a Threat to vital equipment as stated in the FSAR would direct a shutdo wn (STEP 7 RNO).
AOP-14.0 step 9, if not previously required to trip, would direct a shutdo wn using the UOPs.
OPS-52521 0 lesson material provides this information: In determining turbine power, turbine impulse pressure is generally the most accurate, but generator output can also be used for a quick estimate of turbine power. It should be recognized that though the impulse pressure curve is linear, it does not extend down to zero power.
Turb Power can be calculated using 1ST Stage pressure.
f 100% 5% \
6O0 psig 0 pszg.) 125 psg -r 5% = 248%
This leads to a power mismatch of 5%. This calculation proves that power is significantly> 1% but < 10% power mismatch between the RX and the Turb.
These are the values needed to determine if a R)( trip is required prior to a power reduction STEPS 1 and 2.
The steam lines and the shell side of the steam generator are basically considered as an extension of the containment boundary (FSAR 10.3.1.2) and provide a barrier from the containment atmosphere provided the integrity of the SG is satisfied internal to containment or the MSSS lines are intact up to and including the MSIVs
. In this example, the INSIDE containment integrity is maintained.
NMP-EP-110-GLOI, v2.0 (REF pg 38) provides the criteria for a LOSS of the Containment FPB under the situation where the SG is BOTH:
- 1) Faulted and
- 2) Either a) Ruptured SG or b) has a >10 gpm leak.
A. Incorrect 1)IF the leak were <1% or ISOLABLE, OR IF <10% and located in the Turbine building
THEN a shutdown would be required per step 7 and/or 9 of AOP-14.0.
Plausible: IF the examinee is unaware of the >1% unisolable steam leak in MSVR trip requirement of step 2.3 RNO action, this answer would be selected. Additionally, if the Turbine/Rx power mismatch is not properly calculated then one might find value <1%
- 2) the integrity of the containment barrier is maintained as long as the Secondary Side of the SG and steam lines within containment remain intact. There would be no means for Containment atmosphere to escape to the environment.
Plausible: The steam lines and the shell side of the steam generator are basically considered as an extension of the containment boundary (FSAR 10.3.1.2). This statement alone could lead one to believe that the CONTAINMENT FPB is considered Breached.
Further, the threshold value requires a FAULT AND either a primary to secondary leak OR a rupture. One might believe that the Fault alone is sufficient to meet this threshold value.
B. Incorrect 1) See A.1
- 2) See D.2 C. Incorrect 1)SeeD.1
- 2) See A.2 D. Correct 1) there is a 4.8% power mismatch between the Main Turbine and the Rx power. Since the leak is in the MSVR and it is unisolable then the criteria of RNO step 2.3.c) is satisfied requiring a RX trip.
- 2) See NMP-EP-1 1 0-GLO1 Containment Barrier Threshold Values above.
- 6. 035A2.O1 O8IINEW/SRO/C/A 4.5/4.6/035A2.OIIN/2/!JAN 12 Notes K/A statement 035A2.01Ability to (a) predict the impa cts of Faulted or ruptured SIG on the GS; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those malfunctions or operations.
Importance Rating: 4.5 4.6 Technical
Reference:
AOP-14, v9.O NMP-EP-1 1 0-GLO1, v2.O FSAR v23 References provided: NONE Learning Objective: EVALUATE plant conditions and CLASSIFY the even t, as appropriate, per the Emergency Implementation Plan (OPS-62521 003)
Question origin: NEW Basis for meeting K/A: a) requires assessment of the impact on the GS beca use of a Faulted MS line inside the MSVR, upstream of the MSIVs and RECALL (tie to prediction) the AOP strategy for this size/location STEAM leak; Also addresses some prediction on the impact on the FPB performance as it relates to the MSSS.
b) Pt 2 specifically requires knowledge of NMP-EP-110-GLO1 threshold values to assess the integ rity of the Containment barrier which would lead to the corre ct classification of the event in progress which will help to mitigate the event.
SRO justification: 10 CFR 55.43(b)(6)
Procedures and limitations involved in initial core loading, alterations in core configuration, control rod programm ing, and determination of various internal and external effects on core reactivity.
Some examples of SRO exam items for this topic inclu de:
Evaluating core conditions and emergency classifications 2011 NRC exam 10 CFR 55.43(b)(6)
Procedures and limitations involved in initial core loading, alterations in core configuration, control rod programming, and determination of various internal and external effects on core reactivity. [10 CFR 55.43(b)(
6)j Some examples of SRO exam items for this topic include:
- Evaluating core conditions and emergency classifica tions based on core
conditions.
- Administrative requirements associated with low powerphysics testi ng processes.
- Administrative requirements associated with refueling activities, such as approvals required to amend core loading sheets or administrativ e controls of potential dilution paths and/or activities.
- Administrative controls associated with the installation of neut ron sources.
- Knowledge of TS bases for reactivity controls.
07/13/10 8:06:56 FNP-1-AOP-14.0 SECONDARY SYSTEM LEAKAGE Version 9.0 Step Action/Expected Response Response Not Obtained NOTE:
- If the secondary leakage is upstream of the MSIVs, closing the MSIVs in step 1 may result in a safety injection.
- Step 1 assumes attempts have been made to stabilize plant status in accordance with normal operating procedure(s) in effect.
- A rule of thumb for steam dumps is 0.5% reactor power equates to 1% steam dump demand. This reflects the fact that the steam dumps will handle greater than design flow.
- [CAl is a continuing action step.
1 CAI Evaluate plant status for safe Perform the following.
operation.
- Pressurizer level GREATER THAN 15% 1.1 Verifr reactor tripped.
AND 1.2 IF reactor tripped,
- Pressurizer pressure GREATER THAN 2000 THEN CLOSE SG main steam isolation psig and bypass valves.
AND
- Steam generator pressure GREATER THAN SG 1A lB 1C 650 psig 1A(1B,IC) SG AND MSIV TRIP
- [j3369A []3369B []3369C
- Containment pressure LESS THAN 2 psig Q1N11HV [j3370A [j3370B [j3370C 1A(1B,1C) SG AND MSIV BYPASS Q1NIIHV []3368A {]3368B []3368C
- IF main generator on line, THEN (check
[]3976A [J3976B [J3976C reactor power) (turbine power + any steam dump power) mismatch LESS THAN 10%.
1.3 IF SG main steam isolation and bypass valves did not close, AND THEN place associated test switch to TEST
- IF main generator off line, THEN check position.
reactor power less than 15%.
AffectedSG 1A lB 1C 1A(1B,1C) SG MSIV TEST Q1N1 1HV [J3369A/ {]3369B/ [J3369C1 70A 70B 70C Step I continued on next page
_Page Completed Page 2 of 24
07/13/10 8:06:56 FNP-l-AOP-14.0 SECONDARY SYSTEM LEAKAGE - Version 90 Step Action/Expected Response Response Not Obtained II CAUTION: Main Steam Valve room entry should be performed cautiously.
NOTE: Flooding in the Main Steam Valve Room may result in a SGFP trip.
2.3 Check no abnormal steam leakage in Main 2.3 Perform the following.
Steam Valve Room.
2.3.1 Check Main Steam Valve Room by a) isolate affected components consistent observing external grating pri.c to with plant operating requirements.
entry.
2.3.2 IF accessible, b) j steam leakage cannot be isolated THEN check Main Steam Valve AND the plant is in Mode 3, Room. THEN verify the reactor is tripped.
c) steam leakage cannot be isolated AND the steam leakage has resulted in a reactor power increase of> 1%,
THEN verify the reactor tripped.
d) fl reactor tripped, THEN CLOSE SG main steam isolation and bypass valves.
SG 1A lB 1C 1A(1B,1C) SG MSIV TRIP
[}3369A []3369B [j3369C Q1N11HV [}3370A [j3370B []3370C 1A(1B,1C) SG MSIV BYPASS {]3368A
[]3368B [13368C Q1N11HV [j3976A [}3976B [j3976C Step 2 continued on next page Page Completed Page 6 of 24
07/13/10 8:06:56 FNP-1-AOP-14.0 - SECONDARY SYSTEM LEAKAGE Version 9.0 Step Action/Expected Response Response Not Obtained II NOTE: The intent of step 9 is to reduce reactor power to within the capacity of the AFW system if possible.
9 Reduce Unit load to point of transfer to auxiliary feedwater using FNP-1-UOP-3.1, POWER OPERATION, and FNP-1-UOP-2.1, SHUTDOWN OF UNIT FROM MINIMUM LOAD TO HOT STANDBY.
10 Check reactor power below capability of 10 secondary leak upstream of MSIVs OR auxiliary feedwater ( 5%). downstream of main feed stop valves identified, THEN perform the following, OTHERWISE proceed to step 11 observe caution prior to step 11.
10.1 Trip the reactor.
10.2 reactor tripped, THEN CLOSE SG main steam isolation and bypass valves.
SG 1A lB IC 1A(IB,1C) SG MSIV TRIP
- []3369A []3369B []3369C Q1N11HV [J3370A []3370B {13370C 1A(1B,1C) SG MSIV BYPASS QIN11HV [j3368A []3368B [J3368C
[]3976A [J3976B [J3976C Step 10 continued on next page Page Completed Page 14 of24
07/13/10 8:06:56 FNP-1-AOP-14.0 SECONDARY SYSTEM LRAKAGE Version 9.0 -
Step Action/Expected Response Response Not Obtained 10.3 IF SG main steam isolation and bypass valves did not close, THEN place associated test switch to TEST position.
AffectedSG 1A lB 1C 1A(1B,1C) SG MSIV TEST Q1N11HV [}3369A/ [j3369B/ {]3369C/
70A 70B 70C 10.4 Go to FNP-1-EEP-0, REACTOR TRIP OR SAFETY INJECTION.
CAUTION: Unisolable secondary leaks (leaks upstream of t MSIV or downstream of main feed stop s
valves) greater than the capacity of the auxiliary feedwa ter system will result in loss of steam generator level when main feedwater is secured.
11 Transfer from main feedwater to auxiliary 11 Establish maximum available AFW flow.
feedwater using FNP-l-UOP-2.l, SHUTDOWN OF UNIT FROM MINIMUM LOAD TO HOT STANDBY. 11.1 Verify all available AFW pumps started.
[j 1AMDAFWP
[j 1BMDAFWP
[J TDAFWP Step 11 continued on next page
_Page Completed Page 15 of24
07/1 3/10 8:06:56 FNP-1-AOP-14.0 SECONDARY SYSTEM LEAKAGE -
Version 9.0 Step Action/Expected Response Response Not Obtained I I I CAUTION: Delay in reducing reactor power to within the capacity of the AFW system per step 13 will result in loss of steam generator level.
12 Close all main steam isolation and bypass 12 IF any MSIV failed to close, valves. THEN place the associated test switch in the TEST position.
SG 1A lB 1C SG 1A lB IC 1A(IB,1C) SG MSIV TRIP
- []3369A [j3369B []3369C IA(1B,IC) SG Q1N11HV {]3370A [J3370B {]3370C MSIV-TEST 1A(1B,1C) SG Q1N1 1HV {]3369A/ {]3369B/ []3369C/
MSIV -
70A 70B 70C BYPASS []3368A []3368B [j3368C Q1NI 1HV []3976A [J3976B [}3976C 13 Reduce reactor power to within the capacity of the AFW pumps ( 4%)
using FNP-1-UOP-2.1, SHUTDOWN OF UNIT FROM MINIMUM LOAD TO HOT STANDBY.
Page Completed Page 18 of24
07/13/10 8:06:56 FNP-1-AOP-14.0 SECONDARY SYSTEM LEAKAGE Version 9.0 Step Action/Expected Response Response Not Obtained 19.1.3 Open TDAFWP STM SUPP ISO b) 1C SG TDAFWP steam supply to be Q1N12HV3226 by failing air supply. isolated and unable to isolate from the (100 if, AUX BLDG TDAFWP room) hot shutdown panel, THEN locally unlock and close STM 19.1.4 Isolate TDAFWP steam supply from LINE 1C TO TDAFWP ISO VLV lB SG at hot shutdown panel. Q1NI2VOO5B (Master key Z) (127 Aux Bldg main steam valve room).
TDAFWP STM SUPP 2) IF lB SG faulted AND steam supply from FROM lB SG lB SG NOT required,
[] Q1N12HV3235A/26 in LOCAL THEN isolated lB SG TDAFWP steam (HSDP-F) supply TDAFWP STM SUPP a) Isolate lB TDAFWP steam supply from FROM lB SG the hot shutdown panel
[] Q1N12HV3235A/26 closed (HSDP-D) TDAFWP STM SUPP FROM lB SG
[) Q1N12HV3235A/26 in LOCAL 19.1.5 Adjust TDAFWP SPEED CONT SIC (HSDP-F) 3405 as required when starting or stopping TDAFWP. TDAFWP STM SUPP FROM lB SG
[1 Q1N12HV3235A/26 closed (HSDP-D) 19.2 fl unable to isolate lB SG steam supply from the hot shutdown panel, b) j lB SG TDAFWP steam supply to be THEN locally unlock and close STM isolated and unable to isolated from the LINE lB TO TDAFWP ISO VLV hot shutdown panel, QIN12VOO6A. (Master key Z) (127 ft,
- THEN locally unlock and close STM AUX BLDG main steam valve room) LINE lB TO TDAFWP ISO VLV Q1NI2VOO6A (Master key Z) (127 Aux Bldg main steam valve room).
20 Check steam leak isolated. 20 Continue reactor shutdown and cooldown to cold shutdown, go to FNP-1-UOP-2.1, SHUTDOWN OF UNIT FROM MINIMUM LOAD TO HOT STANDBY.
Page Completed Page 23 of 24
JMP-EP-1 lO-GLO1 FNP EALs - ICs, Threshold Values and Bat Th Version 2.0 Figure 1 FARLEY NUCLEAR PLANT Figure 1 Fission Product Barrier Evaluation NMP-EP-11O- GLOI Rev 2.0 General Emergency Site Area Emergency Alert Unusual Event FG1 FS1 FA1 FU1 Loss of ANY Two Barriers AND Loss Loss or Potential Loss of ANY Two ANY Loss or ANY Potential Loss of ANY Loss or ANY Potential Loss or Potential Loss of Third Barrier Barriers EITHER Fuel Clad OR RCS of Containment Fuel Clad Barrier Loss Potential Loss
- 1. Critical Safety Function Status (p.34) 1. Critical Safety Function Status (p.34)
Core-Cooling RED Core Cooling-ORANGE OR Heat Sink-RED
- 2. Primary Coolant Activity Level (p. 34) 2. Primary Coolant Activity Level(p. 34)
Indications of RCS Coolant Activity greater than 300 aCilgm Dose Equivalent 1-131 Not Applicable (Figure 4 may be used to evaluate)
- 3. Core Exit Thermocouple Readings (p. 34) 3. Core Exit Thermocouple Readings (p. 34) 5th Hottest CETC greater than 1 200° F 5th Hottest CETC greater than 700°F
- 4. Reactor Vessel Water Level (p. 34) 4. Reactor Vessel Water Level (p. 34)
Not Applicable RVLS Plenum LEVEL less than 0%
- 5. Containment Radiation Monitoring (p. 34) 5. Containment Radiation Monitoring (p. 34)
Containment Radiation Monitor RE-27 A B greater than 80 Rlhr Not Applicable
- 6. Other Indications (p. 34) 6. Other Indications (p. 34)
Not applicable Not applicable
- 7. Emergency Director Judgment (p. 35) 7. Emergency Director Judgment (p. 35)
Judgment by the ED that the Fuel Clad Barrier is lost. Consider conditions not Judgment by the ED that the Fuel Clad Barrier is potentially lost. Consider conditions addressed and inability to determine the status of the Fuel Clad Barrier not addressed and inability to determine the status of the Fuel Clad Barrier.
RCS Barrier Loss
[ Potential Loss I. Critical Safety Function Status (p. 35) 1. Critical Safety Function Status (p. 35)
Not Applicable RCS Integrity-RED OR Heat_Sink-RED
RCS subcooling less than 16°F {less than 45° F Adverse} due to an RCS leak greater Non-isolable RCS leak (including SG tube Leakage) greater thanl20 GPM.
than Charging / RHR capacity
EEP-3.0 entered due to SG tube mpture resulting in an ECCS actuation Not Applicable
- 4. Containment Radiation Monitoring (p. 36) 4. Containment Radiation Monitoring (p. 36)
CTMT Rad Monitor RE-2 greater than 100 mRlhr Q! CTMT Radiation Monitor RE-7 Not Applicable greater than 200 mR/hr
- 5. Other Indications (p. 36) 5. Other Indications (p. 36)
Not applicable Unexplained level rise in ANY of the following:
Containment sump Reactor Coolant Drain Tank (RCDT)
Waste Holdup Tank (WHT)
- 6. Emergency Director Judgment (p. 36) 6. Emergency Director Judgment(p. 36)
Judgment by the ED that the RCS Barrier is lost. Consider conditions not addressed and Judgment by the ED that the RCS Barrier is potentially lost. Consider conditions not inability to determine the status of the RCS Barrier addressed and inability to determine the status of the RCS Barrier.
Containment Barrier Loss
[ Potential Loss
- 1. Critical Safety Function Status (p. 37) 1. Critical Safety Function Status (p. 37)
Not Applicable Containment-RED
- 2. Containment Pressure (p. 37) 2. Containment Pressure (p.. 37)
Rapid unexplained CTMT pressure lowering following initial pressure rise CTMT pressure greater than 54 psig and rising
!R Intersystem LOCA indicated by CTMT pressure or sump level response not consistent CTMT hydrogen concentration greater than 6%
with a lass of primary or secondary coolant OR CTMT CSF ORANGE AND Less than the following minimum operable equipment:
One CTMT fan cooler AND One train of CTMT spray
- 3. Core Exit Thermocouple Reading (p. 37) 3. Core Exit Thermocouple Reading (p. 37)
Not applicable CORE COOLING CSF RED Qj ORANGE for greater than 1 5mm AND RVLS LEVEL less than 0%
- 4. SG Secondary Side Release with Primary to Secondary Leakage (p. 38) 4. SG Secondary Side Release with P-to-S Leakage (p. 38)
RUPTURED S/G is also FAULTED outside of containment Not applicable OR Primary-to-Secondary leakrate greater than 10 gpm with nonisolable steam release from affected S/G to the environment
- 5. CNMT Isolation Valves Status After CNMT Isolation (p. 38) 5. CNMT Isolation Valves Status After CNMT Isolation (p. 38)
CTMT isolation valves OR dampers I closed downstream pathway to the Not Applicable environment exists after Containment Isolation
- 6. Significant Radioactive Inventory in Containment (p. 38) 6. Significant Radioactive Inventory in Containment (p. 38)
Not Applicable CTMT Rad monitor RE-27 A Q.E B greater than 3000 RIhr
- 7. Other Indications (p. 38) 7. Other Indications (p. 38)
Pathway to the environment exists based on VALID RE-lO, RE-14, RE-2l, OR RE-22 Not applicable Alarms
- 8. Emergency Director Judgment (p. 39) 8. Emergency Director Judgment (p. 39)
Judgment by the ED that the CTMT Barrier is lost. Consider conditions not addressed Judgment by the ED that the CTMT Barrier is potentially lost. Consider conditions not and inability to determine the status of the CTMT Barrier addressed and inability to determine the status of the CTMT Barrier 105
NMP-EP-1 lO-GLO1 FNP EALs ICs, Threshold Values and Basis Version 2.0 have been, or will be ineffective. The reactor vessel level chosen should be consistent with the emergency response guides applicable to the fcWty.
The conditions in this potential loss Threshold Value represent an immiflent core melt sequence which, if not corrected, could lead to vessel failure and an raised potential for containment failure. In conjunction with the Core Cooling and Heat Sink criteria in the Fuel and RCS barrier columns, this Threshold Value would result in the declaration of a General Emergency loss of two barriers and the potential loss of a third. If the function restoration procedures are ineffective, there is no success path.
- 4. SG Secondary Side Release With Primary To Secondary Leakage This loss Threshold Value recognizes that SG tube leakage can represent a bypass of the containment barrier as well as a loss of the RCS barrier. The loss Threshold Value addresses the condition in which a RUPTURED steam generator is also FAULTED. This condition represents a bypass of the RCS and containment barriers. In conjunction with RCS Barrier loss Threshold Value
- 3, this would always result in the declaration of a Site Area Emergency.
The other leakage loss Threshold Value addresses SG tube leaks that exceed 10 gpm in conjunction with a nonisolable release path to the environment from the affected steam generator. The threshold for establishing the nonisolable secondary side release is intended to be a prolonged release of radioactivity from the RUPTURED steam generator directly to the environment. This could be expected to occur when the main condenser is unavailable to accept the contaminated steam (i.e., SGTR with concurrent loss of offsite power and the RUPTURED steam generator is required for plant cooldown or a stuck open relief valve). If the main condenser is available, there may be releases via air ejectors, gland seal exhausters, and other similar controIed, and often monitored, pathways. These pathways do not meet the intent of a nonisolable release path to the environment. These minor releases are assessed using Abnormal Rad Levels I Radiological Effluent ICs.
- 5. Containment Isolation Valve Status After Containment Isolation This Threshold Value addresses incomplete containment isolation that allows direct release to the environment. It represents a loss of the containment barrier.
The use of the modifier direct in defining the release path discriminates against release paths through interfacing liquid systems. The existence of an inline charcoal filter does not make a release path indirect since the filter is not effective at removing fission noble gases. Typical filters have an efficiency of 95-99% removal of iodine. Given the magnitude of the core inventory of iodine, significant releases could still occur. In addition, since the fission product release would be driven by boiling in the reactor vessel, the high humidity in the release stream can be expected to render the filters ineffective in a short period.
There is no Potential Loss Threshold Value associated with this item.
- 6. Significant Radioactive Inventory in Containment There is no Loss Threshold Value associated with this item.
The greater than 3,000 RIhr value indicates significant fuel damage well in excess of the Threshold Values associated with both loss of Fuel Clad and loss of RCS Barriers. A major release of radioactivity requiring offsite protective actions from core damage is not possible unless a major failure of fuel cladding allows radioactive material to be released from the core into the reactor coolant.
38
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- 82. 039A2.05 082/MOD FNP BANKISRO!C/A 3.3/3.7/039A2.05!N/3/VAL 0-1 FIXED/REPLACEMENT Unit twas operating at 100% power when thefollowing occuFred:-
PCV-3371A, 1A SG ATMOSPHERIC RELIEF VALVE, failed open.
- NO turbine load adjustments have been initiated by the crew.
- The REACTOR THERMAL POWER 12-HOUR AVG exceeded 102%.
Which one of the following completes the statements below?
The maximum change in turbine power would be (1) 35MW.
A report to the NRC Operations Center (NRCOC) (2) required per EIP-8.0, Non-Emergency Notifications.
(1) (2)
A. LESS THAN is NOT B LESS THAN IS C. GREATERTHAN isNOT D. GREATER THAN IS
- 7. 039A2.05 082/MOD FNP BANKJSRO/C/A 3.3/3.7/039A2.05/N/3/VAL 0-1 FIXED/REPLACEMENT Eeed.hack -
Knowledge:
an Atmospheric Relief has a design capacity of 3.5% total steam flow @ 1025 psig.
Distractor uses Safety valve design capacity of 7.6% total steam flow @ 1085 psig; this distractor would ALSO be selected if the 5% design capacity of a STM dump is utilized.
In both cases, whether an ARV or Safety valve had failed open, the resultant Rx power would rise (unintentionally and with operator action would be short term)> 102%
Licensed Power limit (LPL). IF OPERATORs reduce power below 102%, and maintain the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> avg < 102%, SOP-0.0 section 5.2 discussion demonstrates that this short term, unintentional excursion does NOT qualify as a LPL violation. SOP-0.0 section 5.2 provides the additional guidance of NRC Regulatory Issue Summary 2007-21, Adherence To Licensed Power Limits, Revision 1, which accounts for NON-intentional short term transients which might cause an excursion > the LPL.
If operator action were not taken, however, the short term transient and unintentional aspects of this aforementioned guidance would NOT apply and EIP-8.0, NON-Emergency notification WOULD BE required per IOCFR5O.72(b)(3)(ii)(B) (STEP 13.2 of EIP-8.0), an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> report.
NMP-OS-001 establishes operational restrictions at a value of 100.0%, but only requires that immediate action be initiated to reduce power and that a CR to be generated if the 1-hour avg is> 100.0%.
Plausibility and Answer Analysis A. Incorrect. 1) See B.1
- 2) SOP-0.0 section 5.2.2 requires notification per EIP-8.0, for an unanalyzed condition that significantly degrades plant safety, as soon as possible. AS noted above, this condition is an 8-hour report.
Plausible: NMP-OS-001 section 6.1.2.5 requires a Condition Report when power is> 100%; without knowledge of SOP-0.0 guidance, EIP-8.0 notification may be missed.
SOP-0.0 section 5.2.2 bullet #2 also states, [...] initiate a Condition report to document the event and prompt LER determination. LER reports are conducted per AP-30, which per Attachement A step 2.3, requires a 60-Day REPORT-- if this were the only report required, in which case EIP-8.0 would not be applicable (only applicable for 48-hour or LESS reports).
Furthermore, this would be correct IF instead the Instantaneous, 15-mm avg, 1-hour avg, or 8-hour avg had exceeded this value in lieu of the 12-hour avg, OR if the peak power level were < 102%.
B. Correct. 1) The initial reduction, knowing the design capacity of an Atmospheric relief valve is 3% total steam flow at 1035 psig; Since 100% power
I I IS., I V tAI V 5., 15.) Sd V SSJ L(.A I J 55.. SAl I I I I 5..t WV 5.41. I Sd Sd Sd J%) Ij, S_ø II I S.fl., I Sd Sd I U 1 d Sd 1W, I Steam pressure is 750 psigL then th Impact from a failed opnARV wUl be (psig used vs psia; since inconsequential to magnitudes used)
Since: JDP Then
/ 3.5% .
- )(v750) = 2.994% (2.994% tomax design at 1025 psig3.5%)
5 102
/ 935 MW\
I (97) 906.95 MW (RANGE 911 to 907 MW)
MW: 100% 1 The actual delta is < 30 MW, Worst case, the candidate does not take into account the pressure drop from design, 3.5% X 935 MW[RANGE 900 950 MW] 31.5 to 32.7 MW Validated on Laptop Sim
- 2) Per SOP-5.2.1 bullet #2, instantaneous power excursions that are not under the direct control of a license reactor operator (e.g.,
fluctuations caused by secondary-side control valve oscillations) are not considered a violation and it is the 12-hour AVG that is required to be maintained <LPL, EIP-8.0 provides this condition under the 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> reporting requirements of IOCFR5O.72(b)(3)(ii)(B) ---STEP 13.2 of EIP-8.0 C. Incorrect. 1) an SG ARV only has a max 3.5% design steam flow capacity at 1025 psig; Plausible: this would be correct IF a Safety Valve** (>45 MW) were failed open, or if the volumetric capacity of the Safety valve were erroneously utilized for the calculation.
1 7%
750 sg) = 5.96 (RANGE 5 to 7 %)
\q1O85ps - . -
Vo5 =88825 L_\CE 822 to 888 M
- NOTE: This same calculation can be applied using the 5% at 1025 psig design capacity of a Stm dump and achieve 39 MW which ALSO is > 38 +/-
MW.
( 5% \
l.J750Ps9 4.28 (RANGE 4to 5%)
1025 I -
1(96) 897.6MW (RANGE 807 to 888.25 MW)
- 2) See A.1 D. Incorrect. 1)SeeC.1
- 2) See B.2
Plausible: This would be correct if the failed component were a Safety valve.
- 7. 039A2.05 082/MOD FNP BANKJSRO/C/A 3.3/3 .7/039A2.05/N/3/VAL 0- 1 FIXED/REPLACEMENT Notes K/A statement - 039A2.05 Main and Reheat Steam System (MRSS) Ability to (a) predict the impacts of Increasing steam demand, its relationship to increases in reactor power on the MRSS; and (b) based on predictions, use procedures to correct, control, or mitigate the consequences.
Importance Rating: 3.3 3.6 Technical
Reference:
AOP-14.0, v9.0 SOP-0.0, vi 39.0 AP-30, v39.0 EIP-8.0, v106 References provided: NONE Learning Objective: ASSESS the facility conditions associated with the Main and Reheat Steam System components, and based on that assessment, SELECT the appropriate procedure(s) for normal or abnormal situations. (OPS-62104A02) 10CFR55.43 (b) 5 Question origin: Modification from NON EMG NOT-53002B03 003 Basis for meeting K/A: a) The ARV malfunction provided in the stem causes a 3%
rise in steam demand. The examinee must predict the impact on the Main Turbine load; a function of the MRSS system pressure and flow characteristics.
b) Knowledge of EIP-8.0 requirements and SOP-0.0 clarification discussion is necessary to properly assess the notifications required for the resultant increase in REACTOR POWER SRO justification: Knowledge of administrative procedures that specify implementation, andlor coordination of plant normal, abnormal, and emergency procedures.
Specific knowledge of SOP-0.0 is required to properly assess the intent of the notification requirements.
ALSO qualifies under UNIQUE to the SRO position since the SRO is responsible for making the NON-Emergency notifications of EIP-8.0.
2011 NRC exam From the Clarification Guidance for SRO-only Questions Rev I dated 03/11/2010 flowchart for 10 CFR 55.43(b)(5):
Assessment of facility conditions and selection of appropriate procedures during
normal, abnormal, and emergency situations [10 CFR 55.43(b)(5)], involving BOTH:
1-) assessing plant conditions and then- -
- 2) selecting a procedure or section of a procedure to mitigate, recover, or with which to proceed.
Using the flowchart, this question can:
NOT be answered solely by knowing systems knowledge, i.e., how the system works, flowpath, logic, component location.
- NOT be answered solely by knowing immediate operator actions.
- NOT be answered solely by knowing entry conditions for AOPs or plant parameters that require direct entry to major EOPs.
- NOT be answered solely by knowing the purpose, overall sequence of events, or overall mitigative strategy of a procedure.
- be answered with knowledge of ONE or MORE of the following:
Assessing plant conditions (normal, abnormal, or emergency) and then selecting a procedure or section of a procedure to mitigate, recover, or with which to proceed.
Knowledge of when to implement attachments and appendices, including how to coordinate these items with procedure steps.
Knowledge of diagnostic steps and decision points in the FOPs that involve transitions to event specific sub-procedures or emergency contingency procedures.
Knowledge of administrative procedures that specify hierarchy, implementation, and/or coordination of plant normal, abnormal, and emergency procedures.
07/13/10 8:06:56 FNP-1-AQP-L4.0 SECONDARY SYSJEM LEAKAGE Version 9.0 Step Action/Expected Response Response Not Obtained NOTE:
- If the secondary leakage is upstream of the MSIVs, closing the MSIVs in step 1 may result iii a safety injection.
- Step 1 assumes attempts have been made to stabilize plant status in accordance with normal operating procedure(s) in effect.
- A rule of thumb for steam dumps is 0.5% reactor power equates to 1% steam dump demand. This reflects the fact that the steam dumps will handle greater than design flow.
- [CAj is a continuing action step.
I CA] Evaluate plant status for safe Perform the following.
operation.
- Pressurizer level GREATER THAN 15% 1.1 Verif reactor tripped.
AND 1.2 IF reactor tripped, Pressurizer pressure GREATER THAN 2000 THEN CLOSE SG main steam isolation psig and bypass valves.
AND
- Steam generator pressure GREATER THAN SG 1A lB 1C 650 psig 1A(1B,1C) SG AND MSIV TRIP
- []3369A []3369B []3369C
- Containment pressure LESS THAN 2 psig Q1N11HV []3370A [13370B []3370C 1A(1B,1C) SG AND MSIV BYPASS Q1N11HV []3368A []3368B []3368C
- IF main generator on line, THEN (check []3976A []3976B [13976C reactor power) (turbine power + any steam dump power) mismatch LESS THAN 10%. 1.3 IF SG main steam isolation and bypass valves did not close, AND THEN place associated test switch to TEST IF main generator off line, THEN check position.
f reactor power less than 15%.
ARV open results in <3% AffectedSG 1A lB 1C extra steam demand. 1A(1B,1C) SG MSIV TEST Q1N11HV [J3369A/ []3369B/ [j3369C/
70A 70B 70C Step I continued on next page Page Completed Page 2 of 24
07/13/10 8:06:56 -
ENP-L-AOP-14.0 SECONDARY SYSTEM LEAKAGE Versioi Step Action/Expected Response Response Not Obtained I I I 1.4 Go to FNP-1-EEP-0, REACTOR TRIP OR SAFETY INJECTION.
NOTE:
- Steps 2.1 through 2.10 are intended to locate and isolate the leak if possible and stabilize the plant. Applicable steps to isolate leakage sources may be performed whenever a leakage source is identified and further identification actions may be terminated when all sources have been identified.
- Based on judgment plant shutdown may be commenced by proceeding to step 8. Steps 2 through 7 should then be performed concurrently with plant shutdown.
- FNP-0-SOP-0.0 contains documentation and reporting requirements for SG safety valves which have lifted.
2 Identify SECONDARY leakage source.
2.1 Check SG atmospheric relief valves 2.1 Perform the following.
CLOSED.
2.1.1 IF SG pressure less than 1035 psig, SG 1A lB 1C THEN close affected atmospheric relief valve(s) using one of the following 1A(1B,1C) MS (presented in suggested order but any ATMOS REL VLV option may be used).
PC []3371A []3371B [j3371C a) Manually close affected SG atmospheric relief valve(s) from the MCB AffectedSG IA lB 1C 1A(1B,1C) MS ATMOS REL VLV PC [j3371A []3371B [j3371C adjusted adjusted adjusted closed closed closed Step 2 continued on next page Page Completed Page 3 of 24
07/13/10 8:06:56 ENP4-AOP-14.O- SECONDARY SYSTEM LEAKAGE Version.0 Step Action/Expected Response Response Not Obtained b) Place the affected SG atmospheric relief valve(s) in local and close from the hot shutdown panel.
AffectedSG 1A lB 1C 1A(B,C) MS ATMOS RELVLV []3371A {j3371A [j337lA Q1N1 1PV in local in local in local Controller adjusted adjusted adjusted closed closed closed c) Close the affected SG atmospheric relief valve(s) from the local control station (100 Aux Bldg outside AFW pump rooms)
AffectedSG 1A lB 1C Q1NI iBOOl A(B,C) []3371AB [J3371BB []3371CB Q1N11HS CLOSE CLOSE CLOSE d) Isolate actuator air supply and close affected SG atmospheric relief valve(s) using the manual hand jack.
(127 Aux Bldg main steam valve room)
AffectedSG 1A lB 1C Q1N11PCV []3371A {J337lB []3371C jacked jacked jacked closed closed closed Step 2 continued on next page
_Page Completed Page 4 of 24
07/13/10 8:06:56 FNP- I -AOP- l40 SECONDARY SYSTEM LF,AKAGE Version 9.0 Step Action/Expected Response Response Not Obtained Assumption is that all other e) Isolate the affected SG atmospheric efforts were ineffective and a relief valve(s) by locally unlocking delay had occurred before local and closing one of the associated operator action was isolation valves. (Master key Z) implemented. Which sets the (127 Aux Bldg main steam valve condtions of the stem. room)
AffectedSG 1A lB 1C 1A(1B,1C) MS ATMOS REL VLV ISO []004A []004C [j004E Q1N11V []004B []004D []004F 2.1.2 IF PRIMARY TO SECONDARY LEAKAGE greater than 50 gpd exists, THEN direct Counting Room to perform FNP-0-CCP-645, MAIN STEAM ABNORMAL ENVIRONMENTAL RELEASE.
2.2 Check Main Steam Safety valves - 2.2 IF associated SG pressure below main CLOSED. steam safety valve reset pressure, THEN perform the following.
SG 1A lB 1C 2.2.1 Consult Operations Manager to evaluate 1A(1B,1C) MS mechanical gagging of affected valve.
SAFETY VLV Q1NI1V [jOlOA [jOllA [1012A 2.2.2 IF PRIMARY TO SECONDARY
[]O1OB []O11B []012B LEAKAGE greater than 50 gpd exists,
[]O1OC [JO11C []012C THEN direct Counting Room to perform
[IO1OD [jOliD []012D FNP-0-CCP-645, MAN STEAM
[1O1OE [JO11E [j012E ABNORMAL ENVIRONMENTAL RELEASE.
2.2.3 IF main steam safety valve declared inoperable, THEN refer to Technical Specifications for appropriate action.
Step 2 continued on next page Page Completed Page 5 of 24
07/13/108:06:56 FNP-1AOP-14M - SECONDARY SYSThM LEAKAGE Version 9.0 Step Action/Expected Response Response Not Obtained 2.10.3 IF TDAFWP NOT required, THEN isolate TDAFWP steam supply from lB SG at hot shutdown panel.
[] Q1N12HV3235A in Local (HSDP-F)
[1 Q1N12HV3235A closed (HSDP-D) 2.10.4 Close TDAFWP STM SUPP WARMUP ISO Q1N12HV3234A (BOP).
2.10.5 IF TDAFWP STM SUPP FROM 1C SG Q1N12HV3235B can NOT be closed, THEN locally unlock and close STM LINE 1C TO TDAFWP ISO VLV Q1N12VOO5B. (Master key V) (127 ft. AUX BLDG main steam valve room) 2.10.6 IFTDAFWP STM SUPP FROM lB SG Q1N12V3235A can NOT be closed, THEN locally unlock and close STM LINE lB TO TDAFWP ISO VLV Q1N12VOO6A. (Master key Z) (127 ft. AUX BLDG main steam valve room) 3 Check secondary leak NOT isolated. 3 Perform the following.
3.1 Consult operations manager to evaluate continued plant operation with isolated components.
3.2 Evaluate actions required by applicable Technical Specifications.
after PCV-3371 isolated: assumption could be that AOP-14.O continued while field actions are being 3.3 Go to procedure and step in effect.
implemented--- no impact on question.
NO parameters direct any action more significant than that required by NMP-OS-OO1 section 6.1.2.5
_Pag.
Page 11 of24
07/13/10 8:06:56 FNP-1-AQP-14.0 SECONDARY S-YSTEM LAKAGE Version 9.0 Step Action/Expected Response Response Not Obtained ii r 4 [CA] Maintain normal plant operating conditions.
Pressurizer level stable at normal programmed value AND
- Tavg maintained within + 1.50 of expected Tavg for plant conditions.
AND
- RCS pressure maintained 2220-225 0 psig AN])
- SG level stable at normal value of 65%
5 IF PRiMARY TO SECONDARY LEAKAGE exists, THEN direct Counting Room to determine offsite dose per FNP-O-EIP-9.O, EMERGENCY ACTIONS.
6 jJ secondary leakage poses a threat to personnel, THEN notify Security to restrict access by non-essential personnel to affected areas.
_Page Completed Page 12 of24
07/13/10 8:06:56 FNP-1-AOP-14..Q SECONDARY SYSTEM LEAKAGE - Version 90 Step Action/Expected Response Response Not Obtained NOTE: The following step is a continuing action step.
7 [CA] Evaluate continued plant operations. 7 Shutdown the reactor, proceed to step 9.
- Pressurizer level stable at normal programmed value.
Tavg maintained within +/- 1.5°F of Tavg for plant conditions.
RCS pressure 2220-2250 psig.
- SG level stable at normal value of 65%.
- CST level stable.
- ff primary to secondary leakage exists, THEN, secondary release posing Q radiological threat.
- Secondary leakage posing NQ hazard to vital equipment or areas.
- Secondary leakage posing Q hazard to electrical equipment.
I. Secondary leakage posing NO hazard to personnel.
8 Check plant shutdown required, (Consult continued plant operation required, with Operations Manager conditions
- THEN return to step 7.
permitting)
Page Completed Page 13 of24
10/08/10 10:15:06 FNP-0-SOP-0.0 5.2 Power Excursions:
5.2.1 NRC Guidelines
- In no case should 102% power be exceeded.
- NRC Regulatory Issue Summary 2007-21, Adherence To Licensed Power Limits, Revision 1 indorses NEI Position Statement on Licensed Power Limits dated June 23, 2008. The following are the positions that FNP will follow:
- Licensees are reminded that there is no existing regulatory guidance condoning or authorizing operation of any nuclear power plant in excess of the maximum power level specified in the facilitys operating license. While recognizing that thermal power may rise slightly due to normal changes in plant parameters, operators are expected to take prompt corrective action to reduce thermal power whenever it is discovered to be above the licensed limit. Licensees may not intentionally operate or authorize operation above the maximum power level as specified in the license.
- The term steady state implies that temperatures, pressures, and flows are stable such that the nominal value of reactor power remains stable, subject to statistical uncertainties and normal fluctuations (e.g., feedwater oscillations).
- No actions are allowed that would intentionally raise core thermal power above the Licensed Power limit (LPL) for any period of time. Small, short-term fluctuations in power that are not under the direct control of a license reactor operator (e.g., fluctuations caused by secondary-side control valve oscillations) are not considered intentional.
- Closely monitor thermal power during steady state power operation with the goal of maintaining the two-hour thermal power average at or below the LPL. If the core thermal power average for a 2-hour period is found to exceed the LPL, take timely action to ensure that thermal power is less than or equal to LPL.
- The core thermal power average for a shift (12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />) is not to exceed the LPL.
- If the evolution is expected to cause a transient increase in reactor power that could exceed the LPL value, prudent action based on prior performance or evaluations should be taken to reduce power prior to performing the evolution.
Page 2 of 79 Version 139.0
10/08/10 10:15:06 -
FNP-0-SOP-0.0 5.2.2 Farley Requirements
- j 102% power level is exceeded, THEN implement reportability requirements in accordance with FNP-0-EIP-8.0, NON-EMERGENCY NOTIFICATIONS, for an unanalyzed condition that significantly degrades plant safety, as soon as possible.
- IF the average power level over any twelve hour period exceeds the ftill, steady-state licensed power level, THEN initiate a condition report to document the event and prompt LER determination.
5.3 Reactor Trip-- When a reactor trip occurs, the Shift Manager will take the following actions:
5.3.1 Ensure that the Shift Supervisor and operating crew place the unit in a safe condition in accordance with approved procedures.
5.3.2. Make required notifications per FNP-0-EIP-8, NON-EMERGENCY NOTIFICATIONS.
5.3.3. Direct a review of events per FNP-0-ACP-16.1 REACTOR TRIP/TRANSIENT ANALYSIS.
5.4 Safety Injection-- If Safety Injection has occurred, the Shift Manager will ensure that a Safety Injection Report is completed per FNP-0-ACP-16.1 REACTOR TRIP/TRANSIENT ANALYSIS. Forward this along with the reactor trip package, if applicable, to the Superintendent Daily Operations.
5.5 Delta Flux Outside of the Target Band AT is no longer required to be monitored from 15% to 100%. It is now monitored from 50% to 100% power. The +/- 5% target band for Al or AO is no longer a part of Technical Specifications, meaning penalty points are no longer accumulated. Instead, Al is required to be maintained inside the doghouse from 50% to 100% power. However, we will still maintain AT as close to the target as possible unless directed otherwise in specific UOPs and write an admin LCO when AT is outside the target band.
Page 3 of 79 Version 139.0
12/01/10 14:10:03 FNP-0-EIP-8.0 NON-EMERGENCY NOTIFICATIONS 1.0 Purpose This procedure delineates the 48-hour or less reporting requirements for events that occur at the plant that DO NOT result in the Declaration of an Emergency classification.
2.0 References See Table 1.
3.0 General 3.1 For Declared Emergencies, reporting requirements are described in FNP 0-EIP-9.0. A fire or personnel injury may require notifications from both procedures.
3.2 Prior to using this procedure to make a non-emergency report, determine if emergency declaration is required, using FNP-0-EIP-9.0.
3.3 Farley Nuclear Plant is required to notify the NRC Operations Center (NRCOC) via the Emergency Notification System of the non-emergency events specified in paragraphs 7.0, 10.0, and 13.0 that occurred within three years of the date of discovery.
3.4 Notification Responsibility. In the event of certain occurrences at Farley Nuclear Plant, several off-site authorities must be notified. It is the responsibility of plant officials to make the notifications to the appropriate authorities. The plant officials responsible for official notifications are:
- Shift Supervisor
- Shift Manager
- Emergency Director
- FNP Duty Manager 3.5 The FNP Duty Manager will be informed by the Shift Manager of ANY notification required by this procedure. Notification of the Corporate Duty Manager should be done by the FNP Duty Manager. IF the FNP Duty Manager is NOT able to notify the Corporate Duty Manager, THEN the Shift Manager should make the notification. The FNP Duty Manager will determine IF the EOF Manager needs to be informed of the notification immediately. IF the EOF Manager is to be notified immediately, the FNP Duty Manager will make the notification or direct the Shift Manager to do so.
Version 106
10/08/10 10:03:17 FNP-0-EIP-8.0 13.0 Eight-Hour Reports 10CFR5O.72(b)(3).
IF not reported as a Declaration of an Emergency class or as a one hour or four hour non emergency report, THEN the NRCOC and Corporate Duty Manager SHALL be notified by the Shift Manager or the FNP Duty Manager as soon as practical and in ALL cases within eight hours of the occurrence of ANY of the following (Figure 1 will be used):
. Notify the NRC resident in coniunction with this notification.
1 3.1 ANY event or condition that results in the condition of the nuclear power plant, including its principal safety barriers being seriously degraded.
1 OCFR5O.72(b)(3)(ii)(A) 13.2 ANY event or condition that results in the nuclear power plant being in an unanalyzed condition that significantly degrades plant safety.
1 OCFR5O.72(b)(3)(ii)(B) 13.3 ANY event or condition that results in valid actuation of any of the systems listed below EXCEPT when the actuation results from and is part of a pre planned sequence during testing or reactor operation.
(1 OCFR5O.72(b)(3)(iv)(A)
(1) Reactor Protection System (RPS) including reactor trip. Actuation of the RPS when the reactor is critical is reportable under section 10 as a four hour report.
(2) General containment isolation signals affecting containment isolation valves in more than one system Q multiple main steam isolation valves (MSIVs).
(3) Emergency core cooling systems (ECCS) including: high-head and low-head injection systems.
(4) Auxiliary feedwater system.
(5) Containment heat removal and depressurization systems, including containment spray AND fan cooler systems.
(6) Emergency AC electrical power systems, including emergency diesel generators (EDG5).
13.4 ANY event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to: 100FR5O.72(b)(3)(v)
(1) Shut down the reactor and maintain it in a safe shutdown condition.
(2) Remove residual heat.
Version 106
01/18/08 09:40:40 FNP-0-AP-30 For distractor plausibility:
3.0 Licensee Event Reports NMP-OS-001 and SOP-0.0 mention 3.1 Preparation of Licensee Event RePorgenerating a CR.... and PROMPT LER report.
3.1.1 If the condition has been determined to be reportable (See Attachment A and references 2.1 through 2.6 for guidance), the Performance Analysis group shall be responsible for preparing the Licensee Event Report (LER). The LER will be based on the results of the investigation required as part of the corrective action program process. Specific instructions for completing the LER form are included in NUREG- 1022.
3.1 .2 Any change or modification to a previously submitted LER requires that an updated LER be submitted. The updated LER will replace the previous report in the NRC computer file. Therefore, the update must be complete, and not contain only supplementary information to the previously submitted report.
3.1 .3 Special Reports shall be submitted to the NRC within the time period specified in the Technical Specifications. LERs submitted per 1OCRF5O.73 or IOCFR72.75 shall be submitted to the NRC within 60 days of discovery of the condition. (It is desirable, but not required to submit voluntary LERs within 60 days.) However, as stated in NUREG 1022, if the 60 day period ends on a weekend or holiday, the LER may be mailed on the first working day following the end of the 60 day period.
The LER will normally be forwarded to the Vice President-Project at least five working days prior to the due date for submittal to the NRC. LERs required per 10CFR2O.2201(b), (d), 2203(a) and 10CFR5O.46(a)(3)(ii) shall be submitted to the NRC in 30 days.
3.1 .4 Follow-up written reports on LER forms, which are required by 1 OCFR73.71 shall be written by the Performance Analysis group.
Reportability of such events will be determined and documented by Security. Also, Security shall be responsible for the investigation of the event and will provide the results of the investigation to the Performance Analysis group so that the report can be written.
3.1.5 Certain conditions involving low level radioactive waste prepared for disposal may be reported in accordance with Generic Letter 91-02. The Performance Analysis group shall be responsible for preparing this report.
3.2 Review and Approval of Licensee Event Reports 3.2.1 Upon completion, LERs including followup written reports on LER forms shall be submitted to the Plant Review Board (PRB) for review in accordance with NMP-GM-009.
3.2.2 Following review by the PRB, the LER shall be submitted to the Nuclear Plant General Manager, for approval.
3.2.3 After approval by the Nuclear Plant General Manager, the original shall be forwarded to the Vice President-Project for appropriate action.
Version 39.0
01/18/08 09:40:40 FNP-0-AP-30 ATTACHMENT A -
This attachment provides guidance as to the types of incidents that shall be reported to the NRC as Licensee Event Reports (LER). These conditions also require the preparation of a Condition Report. Unless otherwise specified in this attachment, an event shall be reportable regardless of the plant mode or power level, and regardless of the significance of the structure, system or component that initiated the event.
- 1. LERs shall be submitted for the following incidents defined in 1 OCFR2O. These will require Chemistry to perform sampling to determine if they are reportable per 1 OCFR2O:
1 .1 Any lost, stolen, or missing licensed material in an aggregate quantity equal to or greater than 1,000 times the quantity specified in appendix C to part 20 under such circumstances that it appears to the licensee that an exposure could result to persons in unrestricted areas.
+ Such incidents are also reportable under paragraph 20.2201 within 30 days.
1.2 Any event involving byproduct, source or special nuclear material that causes or threatens to cause:
a) Any dose received by an individual within a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period that exceeds 5 Rem total effective dose equivalent (TEDE), an eye dose equivalent exceeding 15 Rem or a shallow-dose equivalent to the skin or extremities exceeding 50 Rem.
b) The Release of radioactive material such that an individual could receive within a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period an intake in excess of one occupational annual limit on intake (ALl).
+ Such incidents are also reportable under paragraph 20.2202(b) and 20.2203(a)(i) within 30 days.
1 .3 Any exposure of an individual in a restricted area to radioactive material or other sources of radiation in any period of one calendar year such that a total dose in excess of 5 Rem total effective dose equivalent (TEDE), in excess of 50 Rem for the sum of the deep-dose equivalent (DDE) and the committed dose equivalent (CDE) to any individual organ or tissue other than the lens of the eye, an eye dose equivalent (LDE) in excess of 15 Rem or a shallow dose equivalent (SDE) in excess of 50 Rem to the skin or any extremity is received.
Any exposure of an individual in a restricted area who is under 18 years of age, to radioactive material or other sources of radiation in any period of one calendar year such that a dose in excess of 10 percent of the limits specified in this section is received.
Page 1 of 10 Version 39.0
01/1 8/08 09:40:40 FNP-0-AP-30 NOTE: 60 Day report for TS violation.
IF candidate were unaware of SOP-0.0 section 5.2, and only implement NMP OS-0O1, then ONE might believe that ONLY a TS thermal limit (2775 Mw B to thermal) is only the only report. IN which case, under this assumption, a 60 Day i.e.
report is required. ases.
- 2. LERs shall be submitted within 60 days for the following conditions defined in IOCFR5O:
2.1 Exceeding any Technical Specification safety limit, per 50.36(c)(1)(i)(a).
2.2 The failure of any automatic safety system to actuate when its limiting safety system setting is reached during operation, per 50.36(c)(1)(ii)(a).
2.3 The failure to meet any limiting condition for operation, per 50.36(c)(2).
- 3. LERs shall be submitted for various conditions as defined in 1 OCFR5O.73 and explained in NUREG 1022, Event Reporting Guidelines. Refer to NUREG 1022 for guidance on renortinci reauirements A link can he found on the Farlev Homeoaae in the Reference EIP-8.0 is ONLY applicable for 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or less notifications.
- f. repUILS pitpitu lIT dU(UIUdII WIUI tIIl LLIOIl UIdI WIU1 LIlld1 IIIdLtU tVtllL UI LIT loss of physical security effectiveness. Such reports may contain Safeguards Information which must be protected against disclosure. Prior to transmission of any such report, it shall be reviewed by a Determining Authority as described in paragraph 12.0 of FNP-0-AP-72. If such authority determines the report to contain Safeguards Information, it shall be transmitted in accordance with the provisions of paragraph 7 or 8 of FNP-0-AP-72, as applicable. Written reports containing Safeguards Information shall be labeled with appropriate Safeguards Information markings and handled accordingly.
LERs shall be submitted for the following events defined in I OCFR73.
4.1 Any event in which an attempt has been made or is believed to have been made to commit a theft or unlawful diversion of Special Nuclear Materials, or to commit an act of radiological sabotage against the plant.
+ Such events are reportable under paragraph 73.71(b).
Discussion: This section concerns threat related events that pose a possible threat to a facility, (i.e. theft or unlawful diversion of SNM or an act or suspected act of sabotage that has been perpetrated against the plant.) Threats are further defined as Explicit or Potential. An Explicit threat is information received by the Security Group or any other employee that an act of theft or radiological sabotage will be attempted. A potential threat is information from the same source which supports a belief that an act of theft or radiological sabotage will be attempted. In most cases threat related events have been addressed in the FNP Safeguards Security Contingency Plan. If the event in question has been addressed in the Contingency Plan and the Contingency Plan requires the event Page 3 of 10 Version 39.0
01/18/08 09:40:40 FNP-0-AP-30 ATTACHMENT A means measures as specified in Security or Safeguards Contingency Plans have been implemented. If an event is not specified in either plan, it means measures have been implemented within 10 minutes of an events occurrence that provide a level of security equivalent to that existing before the event. In most cases, loss of physical security effectiveness events have been addressed in the FNP Safeguards Security Contingency Plan. If the event in question has been addressed in the Contingency Plan and such plan requires the event to be reported, the event requires notification to the NRC. However, if after following the procedures established in the Responsibility Matrix of the Contingency Plan for the event, it is determined that the event is not reportable, a report need not be made. The methodology applied to loss of physical security events in the Contingency Plan is based on the occurrence of events that initially may or may not have security implications. Each event is first properly compensated, investigated and appropriate safeguards contingency preplanned actions are implemented. A determination is made as to whether or not the event occurrence is security related or if the cause of the loss is major.
Events that are not security related or whose cause is not major are generally not considered to be reportable. The term Security Related used herein refers to an event or incident that is perpetrated or caused by an individual with intent to perpetrate or facilitate an act of sabotage. In all such cases, the event occurrence must be reported to the NRC immediately. Significant Contingency Plan loss of effectiveness events that require NRC notification are summarized as follows:
- a. Loss of all communication systems used to summon offsite response without proper compensation, or if the loss is security related.
- b. Loss or degradation of the Intrusion Detection or Alarm System if the cause of the system outage is major or security related.
- c. Compromise or degradation of electrical/mechanical access control devices or systems if the cause of the outage is major or security related.
- d. Loss of Protected Area Barrier Lighting if the cause of the loss is major or security related.
- e. Loss or degradation of the Security System Power if the cause of the loss is major or security related.
5.0 LERs shall be written for the following events defined in 10CFR72.75. The text of 10CFR72.75 is reproduced here for reference:
§ 72.75 Reporting requirements for specific events and conditions.
(a) Emergency notifications: Each licensee shall notify the NRC Headquarters Operations Center upon the declaration of an emergency as specified in the licensees Page 5 of 10 Version 39.0
01/18/08 09:40:40 FNP-0-AP-30 ATTACHMENT A approved emergency plan addressed in § 72.32. The licensee shall notify the NRC immediately after notification of the appropriate State or local agencies, but not later than one hour after the time the licensee declares an emergency.
(b) Non-emergency notifications: Four-hour reports. Each licensee shall notify the NRC as soon as possible but not later than four hours after the discovery of any of the following events or conditions involving spent fuel, HLW, or reactor-related GTCC waste:
(1) An action taken in an emergency that departs from a condition or a technical specification contained in a license or certificate of compliance issued under this part when the action is immediately needed to protect the public health and safety, and no action consistent with license or certificate of compliance conditions or technical specifications that can provide adequate or equivalent protection is immediately apparent.
(2) Any event or situation related to the health and safety of the public or onsite personnel, or protection of the environment, for which a news release is planned or notification to other Government agencies has been or will be made. Such an event may include an onsite fatality or inadvertent release of radioactively contaminated materials.
(c) Non-emergency notifications: Eight-hour reports. Each licensee shall notify the NRC as soon as possible but not later than eight hours after the discovery of any of the following events or conditions involving spent fuel, HLW, or reactor-related GTCC waste:
(1) A defect in any spent fuel, HLW, or reactor-related GTCC waste storage structure, system, or component that is important to safety.
(2) A significant reduction in the effectiveness of any spent fuel, HLW, or reactor-related GTCC waste storage confinement system during use.
(3) Any event requiring the transport of a radioactively contaminated person to an offsite medical facility for treatment.
(d) Non-emergency notifications: 24-hour reports. Each licensee shall notify the NRC within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the discovery of any of the following events involving spent fuel, HLW, or reactor-related GTCC waste:
(1) An event in which important to safety equipment is disabled or fails to function as designed when:
(i) The equipment is required by regulation, license condition, or certificate of compliance to be available and operable to prevent releases that could exceed regulatory limits, to prevent exposures to radiation or radioactive materials that could exceed regulatory limits, or to mitigate the consequences of an accident; and (ii) No redundant equipment was available and operable to perform the required safety function.
Page 6 of 10 Version 39.0
BANK question--MODIFIED FOR REASONS stated below
- 1. NON EMG NOT-53002B03 OO3IHLTISROICIAII//I Unit Zwasat 1 OO% when the # FW Htr Extraction-Strn line isolated due tc> a DP switch malfunction. The following indications/conditions existed after the failure for 30 minutes:
- Avg NI Pwr indicated 100% on the Plant Computer.
- \T instruments 102.3% power.
- Nl-41, 42, 43, and 44 <100.0%
The Turbine load was reduced and maintained at 98%. The following indications are reported:
- 1-HourAvgRxPower 100.15%.
- 8-hour Avg Rx Power 99.9%.
Which one of the following describes the most restrictive report required by EIP-8.0, Non-Emergency Notifications, if any, for the stated conditions?
A. An One hour report is required due to exceeding the TS Thermal power limit.
B. A Four hour report is required due to exceeding 102% Rx Power.
D. No reports are required since the RX Power remained below the TS Thermal limit.
NOTE: due to SOP-0.0 section Si, answer choice C is NOT correct, but EIP-80 reports May not be required based on the conditions expressed in section 5.2 of SOP-00 in which a temporary and unintentional operation>
102% may not be an EIP-8.0 report, but May/may not be required per AP-30 (LER reporting for the> 2775 MWt event) or depending on the duration of operation> 102% without purposeful action to recover below.
---GREY area therefore: To ensure this answer choice is not an option, alter this question.
ALSO, NOTE that since Choice C could be argued NOT correct based on section 5.2.1, then Choice D is also NOT correct since AP-30 may generate an LER or other TS section 5.0 report AND TS thermal LIMIT was exceeded, however only temporarily.
Anything> 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> reports/actions are not memory level knowledge, and may require a reference.
- 83. 054G2. 1.23 O83INEW/SRO/C/A 4.314.4/054G2. I .23/N/4/VER2.O!REPLACEMENT Unit I was at 70% when the fo wingsequenc&of-events began: - -
AT 1000:
- A rapid ramp for a loss of a single SGFP per AOP-1 3.0, Condensate and Feedwater Malfunction, was performed.
- RX power was reduced to 55%.
AT 1040:
- Rx power has been ramped up to 60% power and is stable.
- The Shift Supervisor is closing out AOP-13.0 actions.
Which one of the following completes the statements below?
Sampling per STP-746, Primary Coolant System Dose Equivalent Iodine 1-131, (1) required.
Operations Manager approval (2) required to reset the LOSS OF LOAD INTERLOCK C-7A.
(1) (2)
IS is NOT B. IS C. isNOT isNOT D. is NOT
- 8. 054G2.1 .23 083/N EW/SRO/C/A 4.314.4/054G2.1 .23/N/4/VER2.0/REPLACEMENT Feedback SOP-0.0, v139, section 5.1 provides further guidance:
[..]The transient as well as the recovery change in power in the sliding one hour window must be less than 15% total. (example: a down power of 6 % followed by a recovery of 10 % in an hour exceeds the 15%
limit) (CR 2000005030)
SR3.4.16.2, states that [the] Surveillance is performed in MODE I only to ensure iodine remains within limit during [...] following fast power changes when fuel failure is more apt to occur. The Frequency, between 2 and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after a power change 15% RTP within a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> period, is established because the iodine levels peak during this time following fuel failure; samples at other times would provide inaccurate results.
AOP-13, v30, Caution prior to step 1.12 states: The LOSS OFLOAD INTERLOCK C 7A should not be reset in the event of a failure of PT-447 which actuates C-7A without consultation with the Operations manager.
In this situation, there is no failure of PT-447, so the note does not apply, but evaluation of the proper approvals and cooordination does have to be evaluated.
A. Correct 1) See above. Power has been reduced to 15% on the initial power reduction. Since power has since been raised 5 additional %, the cumulative value is 20%, this exceeds the 15% limit in any 60 mm period.
- 2) the note in AOP-13 does not apply, Operations Manager approval is not required and C-7A should be reset.
B. Incorrect 1)SeeA.1
- 2) the note in AOP-1 3 does not apply, Operations Manager approval is not required and C-7A should be reset.
C. Incorrec 1) Plausible: this would be correct if the power had not been fallen to 55%
and not been raised to accumulated >15% Change. ALSO, The step within AOP-13 reads:
7.8 Check reactor power change < 15%, Power was =15% and then was raised such that if FINAL (60%) INITIAL (70%) were considered, the value is only 10%.
- 2) see B.2.
D. Incorrect 1) see SOP-0.0 above.
- 2) incorrect, see B.2.
- 8. 054G2. 1.23 O83INEW/SRO/C/A 4.3/4.41054G2. I .23/N/4!VER2.O/REPLACEMENT Note&. - -- -
K/A statement 054 Loss of Main Feedwater (MFW)
G2.1 .23 Ability to perform specific system and integrated plant procedures during all modes Importance Rating: 4.3 4.4 Technical
Reference:
AOP-13.O, v30.O TS B3.4.16 (pg 3.4.16-6 rev 0)
TSR 3.4.16.2 (pg 3.4.16-2 rev 0)
SOP-O.O, v139 NMP-OS-007-001 v7 References provided: NONE Learning Objective: RECALL AND APPLY the information from the LCO BASES sections: BACKGROUND, APPLICABLE SAFETY ANALYSIS, ACTIONS, SURVEILLENCE REQUIREMENTS, for any Technical Specifications or TRM requirements associated with the Gross Failed Fuel Detector, and attendant equipment, to include the following:
(OPS-621 06E01): 1 OCFR55.43 (b) 2
- 3.4.16, RCS Specific Activity STATE AND EXPLAIN the operational implications for all Cautions, Notes, and Actions associated with AOP-1 3, Loss of Main Feedwater. (OPS-52520M03).
Question origin: NEW Basis for meeting K/A: Stem places the examinee in AOP-13.0 following a SGFP malfunction (effective loss of the SGFP per step 3.5 RNO) in which the RX remains at power, and must use PROCEDURES (SOP-0.0 and TS basis, along with AOP-13 to properly assess actions).
Additionally, utilization of information of Cautions of AOP-1 3 to determine if consulting the OPS Manager prior to RESETTING the C-7A interlock.
SRO justification: Facility operating limitations in the TS and their bases. [10 CFR 55.43(b)(2)]
- Application of Required Actions (Section 3) and Surveillance Requirements (SR) (Section 4) in accordance with rules of application requirements (Section 1).
- Knowledge of TS bases that is required to analyze
TS required actions and terminology and partly Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations. [10 CFR 55.43(b)(5)]
Where: knowledge of the content of the procedure (SOP-0.0 is required to further apply/evaluate the BASIS and action required by the SR). In addition, evaluation of actions required to reset interlock C-7A involves evaluation of Administrative procedures (NMP-OS-007-001) requirements to ensure proper coordination and approvals are met.
2011 NRC exam From the Clarification Guidance for SRO-only Questions Rev 1 dated 03/11/2010 flowchart for 10 CFR 55.43(b)(2):
- 1) can NOT be answered by knowing less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Tech Specs.
- 2) can NOT be answered by knowing information listed above-the-line.
- 3) can NOT be answered by knowing the TS Safety Limits or their bases.
- 4) Does involve one or more of the following for TS, TRM or ODCM:
- Application of Required Actions (Section 3) and Surveillance Requirements (Section 4) in accordance with rules of application requirements (Section 1).
- Knowledge of TS bases that is required to analyze TS required actions and terminology From the Clarification Guidance for SRO-only Questions Rev 1 dated 03/11/2010 flowchart for 10 CFR 55.43(b)(5):
- NOT be answered solely by knowing systems knowledge, i.e., how the system works, flowpath, logic, component location.
- NOT be answered solely by knowing immediate operator actions.
- NOT be answered solely by knowing entry conditions for AOPs or plant parameters that require direct entry to major EOPs.
- NOT be answered solely by knowing the purpose, overall sequence of events, or overall mitigative strategy of a procedure.
- be answered with knowledge of ONE or MORE of the following:
Assessing plant conditions (normal, abnormal, or emergency) and then selecting a procedure or section of a procedure to mitigate, recover, or with which to proceed.
Knowledge of when to implement attachments and appendices, including how to coordinate these items with procedure steps.
Knowledge of diagnostic steps and decision points in the EOPs that involve transitions to event specific sub-procedures or emergency contingency procedures.
Knowledge of administrative procedures that specify hierarchy, implementation, and/or coordination of plant normal, abnormal, and emergency procedures.(SOP-0.0 is required to further apply/evaluate the BASIS and action required by the SR AND NMP-OS-007-001 evaluation of coordination and
approvals required to reset C-7A)
Southern Nuclear Operating Company Nuclear I I
NMP-OS-007-001 4 Management Conduct of Operations COMPA Instruction I Standards andxpectations Versio-7.0 Page 47 of 49
- Before placing controls in manual, the operator determines the parameter to be controlled and the controlling band for this parameter, reviews expected system response, and establishes contingencies for potential off-normal events due to the controller being in manual whenever practicable and as time allows.
- An operator monitors the system for proper response during and after the transfer.
- While in manual, the controlled parameter should be maintained as close as practical to the expected automatic value (within the controlling band, if A candidate may think previously established).
this is required to reset the C-7A loss of load
- When a system or component has been placed in manual due to a interlock. This would not be required transient caused by an automatic control malfunction, SM permission is because there is no required prior to returning the system or component to automatic control malfunction of auto following stabilization from the transient and correction of the malfunction.
control.
- When manual operation is no longer required, operators return the system to automatic or standby mode.
6.29.2.2 Safety Systems Operators do not override the initiation of a safety system function unless specifically directed to do so by procedure or other controlling document.
6.30 Work Management 6.30.1 Standard Operations drives the work planning priorities in an operationally focused organization.
Work activities are thoroughly planned and scheduled to maintain defense-in-depth, manage risks, and enable effective coordination among various work groups.
Operations personnel are actively engaged in the work planning and scheduling process. Operators remain cognizant of maintenance, modification, and testing activities. Operators demonstrate a desire to minimize the number of deficiencies that result in Operator Workarounds and Burdens.
6.30.2 Expectations 6.30.2.1 Planning Operators display intolerance for equipment deficiencies by taking a leadership role in the work management process. Operators document deficiencies in a prompt manner, make sound and timely operability calls, and prioritize work requests using their in-depth plant knowledge.
07/13/10 8:06:50 FNP- 1 -AOP- 13.0 CONDENSATE AND FEEDWATER MALF4CTION - Vrioi 3O0 -
Step Action/Expected Response Response Not Obtained F I I 1.8 Closely monitor steam generator narrow 1.8 IF SG narrow range levels NQT maintained range levels. greater than 28%,
WHEN a SG narrow range level recovers THEN trip the reactor and go to
[1 FNP-1-EEP-0, REACTOR TRIP OR to approximately 55%,
THEN verify its main feedwater SAFETY INJECTION.
regulating valve controllers in MANUAL.
[] Match feed flow with steam flow.
[1 Return feedwater regulating valves to AUTO.
1.9 Monitor feedwater flow and steam flow.
1.10 Verify that feedwater and steam flow trend to approximately equal values for the target, turbine load.
1.11 Maintain SG narrow range level approximately 65%.
CAUTION: The LOSS OF LOAD INTERLOCK C 7A should not be reset in the event of a failure of PT-447 which actuates C-7A without consultation with the Operations manager.
1.12 Check LOSS OF LOAD INTERLOCK 1.12 IF C-7A is to be reset, C-7A on the BYP & PERMISSIVES THEN perform the following panel NQI illuminated.
1.12.1 Verify that all steam dump valves indicate closed.
1.12.2 Verify 0 demand on STM HDR PRESS controller PK 464 and STM DUMP DEMAND T1408 1.12.3 Place STM DUMP INTLK TRAIN A and TRAIN B to OFF RESET 1.12.4 Place STM DUMP MODE SEL TRAINS A-B to RESET and then release to spring return to TAVG.
Step 1 continued on next page Page Completed Page 5 of 23
07/13/10 8:06:50 -
FNP-UAQP4IO CQNDENSATE AND FEEDWATER MAUUNCTION VeriQn30O Step Action/Expected Response Response Not Obtained I* II 7.7.3 Place STM DUMP INTLK TRAIN A and TRAIN B to OFF RESET 7.7.4 Place STM DUMP MODE SEL TRAINS A-B to RESET and then release to spring return to TAVG.
7.7.5 Place STM DUMP INTLK TRAIN A and B to ON.
7.8 Check reactor power change < 15% 7.8 Notif Shift Radiochemist to sample the RCS per FNP-0-STP-746.
7.9 Check parameters within limits for 7.9 IF the Team is NQI confident that a continued at power operation. parameter is being restored, THEN trip the reactor and go to
- Pressurizer level greater than 15% FNP-1-EEP-0, REACTOR TRIP OR SAFETY INJECTION.
- Pressurizer pressure greater than 2100 psig
- SG narrow range levels 35%-75%
- TAVG541°F-580°F
- Control rod bank position Lo-Lo Annunciator FE2 Clear
- Delta I within limits specified in the COLR 7.10 Check condensate and feedwater function 7.10 Return to step 1.
stabilized.
7.11 Adjust reactor power and turbine load as necessary to maintain REACTOR THERMAL POWER 1 HOUR AVG (Computer point QC4621HR8)< 2775 MWt.
Step 7 continued on next page Page Completed Page 22 of 23
RCS Specific Activity 3.4.16 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and C.1 Be in MODE 3 with 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Tavg < 500°F.
Time of Condition A not met.
OR DOSE EQUIVALENT 1-131 in the unacceptable region of Figure 3.4.16-1.
SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.16.1 Verify reactor coolant gross specific activity 7 days 100/p iCi/gm.
SR 3.4.16.2 NOTE Only required to be performed in MODE 1.
Verify reactor coolant DOSE EQUIVALENT 1-131 14 days specific activity 0.5 iCi/gm.
AND Between 2 and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after a THERMAL POWER change of 15% RTP within a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> period Farley Units 1 and 2 3.4.16-2 Amendment No. 147 (Unit 1)
Amendment No. 138 (Unit 2)
RCS Specific Activity B 3.4.16 BASES SURVEILLANCE SR 3.4.16.2 REQUIREMENTS (continued) This Surveillance is performed in MODE 1 only to ensure iodine remains within limit during normal operation and following fast power changes when fuel failure is more apt to occur. The 14 day Frequency is adequate to trend changes in the iodine activity level, considering gross activity is monitored every 7 days. The Frequency, between 2 and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after a power change 15% RTP within a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> period, is established because the iodine levels peak during this time following fuel failure; samples at other times would provide inaccurate results.
SR 3.4.16.3 A radiochemical analysis for E determination is required every 184 days (6 months) with the plant operating in MODE 1 equilibrium conditions. The E determination directly relates to the LCO and is required to verify plant operation within the specified gross activity LCO limit. The analysis for E is a measurement of the average energies per disintegration for isotopes with half lives longer than 15 minutes, excluding iodines. The Frequency of 184 days recognizes E does not change rapidly.
This SR has been modified by a Note that indicates sampling is required to be performed within 31 days after a minimum of 2 effective full power days and 20 days of MODE 1 operation have elapsed since the reactor was last subcritical for at least 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. This ensures that the radioactive materials are at equilibrium so the analysis for E is representative and not skewed by a crud burst or other similar abnormal event.
REFERENCES 1. 10 CFR 100.11, 1973.
- 2. FSAR, Section 15.4.3.
Farley Units 1 and 2 B 3.4.16-6 Revision 0
09/23/10 16:00:25 FNP-0-SOP-0.0 FARLEY NUCLEAR PLANT SHARED SYSTEM OPERATING PROCEDURE SOP-0 GENERAL INSTRUCTIONS TO OPERATIONS PERSONNEL 1.0 Purpose To provide guidance for general housekeeping, routine operations, and management xpectations.
2.0 Routine Tours and Inspections, Logs, Equipment Hours Log, and Reactor Operator Log Reference FNP-0-SOP-0.l 1, WATCH STATION TOURS AND OPERATOR LOGS.
3.0 Housekeeping / Material Condition Instructions for housekeeping and plant material conditions are located in FNP-SOP-0. 11.
4.0 Shift Turnovers Shift Turnovers should be conducted in accordance with FNP-0-SOP-0.14, SHIFT TURNOVER AND RELIEF.
5.0 Power Changes 5.1 Greater than 15% in a One Hour Period Chemistry must be promptly notified to pull an RCS sample and perform STP-746 between 2 and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> following a power change of 15% within any one hour time period (this is a sliding window). This sample is necessary to meet a Technical Specification Surveillance Requirement. During any power change, the total reactor power change in all hourly periods must be monitored.
A power transient is not the sole factor for determining if the STP is required.
The transient as well as the recovery change in power in the sliding one hour window must be less than 15% total. (example: a down power of 6 % followed by a recovery of 10 % in an hour exceeds the 15% limit) (CR 2000005030)
Page 1 of 79 Version 139.0
- 84. 055EA2.02 084/NEWISRO/CIA 4.4/4.6/EPEO55EA2.02/N/3IVAL 0-1 FIXED/MINOR ED A Station Blackout has occurred on Unit 2 Tha follon9 conctitions exist
- ECP-O.O, Loss of All AC Power, is in progress.
- The crew has commenced feeding and depressurizing the SGs after a significant delay due to a TDAFW pump malfunction.
- RCS pressure is 1675 psig and very slowly 1.
- ALL CETCs are 735°F and t.
- Hot Leg temperatures are 612°F and t.
- Cold Leg temperatures are 585°F and .
- SG pressures are 885 psig and L.
Which one of the following completes the statements below?
Natural circulation (1) established.
The crew is required to implement FRP-C.2, Response to Inadequate Core Cooling, (2)
(1) (2)
A. IS immediately upon exit from ECP-O.O B. IS after restarting equipment in ECP-O.2, Loss of ALL AC Power Recovery With SI Required.
C. is NOT immediately upon exit from ECP-O.O D is NOT after restarting equipment in ECP-O.2, Loss of ALL AC Power Recovery With SI Required.
- 9. 055EA2.02 084/NEW/SRO/C/A 4.4/4.6/EPEO55EA2.02/N/3/VAL 0-1 FIXED/MINOR ED Feedhiek - -
Natural Circulation cooling is identified by the following Plant conditions:
- Large AT [indications of 27°F & 1 is given]
- RCS hot & cold leg not voided [not saturated]
- Indications used to verify ADEQUATE natural circulation CETC5 stable or falling [rising 1 is given]
Pressure stable or falling [very slowly t is given]
Subcooled Margin Monitor> 16°F {45°F} [-127 is given]
RCS Hot leg temps stable or falling [rising t is given]
RCS Cold leg temps at saturated conditions for SG press.
[585°F is much > 532°F]
ECP-O.O, v22.O, step I CAUTION & FNP-1-ECP-O.2, v18, Step I Caution CAUTION: CSFST should be monitored for information only. No FRP should be implemented until completion of Step 13.
STEP 14 reads, GO to EEP-1, therefore is the end of ECP-O.2.
SOP-O.8 section 4.2 Applicability states:
The user should begin monitoring the CSFSTs when directed by EEP-O or upon transition from EEP-O. The CSFSTs are not monitored initially because the ERPs are already directing the initial action required to protect the barriers. If the user enters ECP-O.O, the CSFSTs should be monitored for information only. The Function Restoration Procedures assume that at least one train of safeguards busses is available, If all AC power has been lost, ECP-O.O will provide the appropriate actions to protect the barriers.
A. Incorrect. 1) The RCS is significantly voided, reflux boiling is underway. The CETCs at the edge of the core are stable due to the REFLUX cooling.
Plausible: Large AT exists if this were the only data used to evaluate then natural circ would be established. Candidate is required to know the NC criteria to come up with the correc tanswer and the values are operationally valid.
- 2) The FRPs are not applicable as stated above.
Plausible: AC power is restored PRIOR to exiting ECP-O.O. One might also incorrectly recall the guidance of SOP-O.8 where recall of the assumption that at least one train of safeguards busses is available is why the FRP is NOT implemented, one might believe it is NOW applicable since power is restored. Also, one might incorrectly recall SOP-O.8 guidance to imply that CSFSTs [shall be implemented] upon transition from ECP-O.O (in lieu of EEP-O.O).
B. Incorrect. 1)seeA.1.
- 2) see D.2 C. incorrect 1)SeeD.1
- 2) See A.2
D. Correct: 1) NaturaL cirou1ation isNGT established,- REFWX coe[ing is:
- 2) Per ECP-O.0, Step 1 Caution and ECP-0.2 Step 1 Caution and Step 14 NOTE, FRPs are not implemented during a loss of all AC; and only implemented after all safety equipment has been restarted per ECP-O.2.
OPERATIONAL validity discussion:
See FSAR chapter 15.3 and 15.4.
Plant conditions (operational validity): NO AC results in a likely failure of RCP seals which will be equivalent to a cross-over leg SBLOCA.
Since there is no SI flow the BLOWDOWN phase is extended. IF SG pressure had not been reduced to initiate Core Cooling then Core temperatures will rise. This temperature rise combined with a loss of Coolant accident would permit Core temperatures to rise and a voiding of the RX vessel. This voiding would fill the SG U-tubes, disconnecting the SG with the RCS, prevents natural circulation and REFLUX boiling provides core cooling: as the RCS condenses in the SG tubes and falls back into both the HOT leg and Cold leg. The cold leg temperature will be at or near saturation of the SG as it flows back into the core, but the HOT leg temperature would indicate either a superheated or saturated temp.
RCS pressure = 1675 psig therefore RCS THOT temp (saturated) = 610°F.
CETCs = if RCS voiding has occurred such that RE FLUX boiling has begun, then CETCs would be rising, except for those near the THot Nozzles which would be cooled by the water returning from th SG pressure = IF the cooldown was delayed (no AC= NO Air = local manual operation of SG ARVs required) then SG pressure would be maintained just below automatic operation until Air supply was exhausted, at which time would be held below Safety setpoint by intermittent safety valve operation (1075 psig) 900 psig therefore SG temp = 534°F and RCS Cold leg temp would be higher and lowering since the SG ARVs are open and as a function of the LOOP Seal of the RCS loop.
- 9. 055EA2.02 O84INEW/SRO!C/A 4.4/4.6/EPEO55EA2.02/N/3/VAL 0-1 FIXED/MINOR ED K/A statement 055EA2.02 Loss of Offsite and Onsite Power (Station Blackout)
Ability to determine or interpret the following as they apply to a Station Blackout: RCS core cooling through natural circulation cooling to SIG cooling Importance Rating: 4.4 4.6 Technical
Reference:
FNP-1-CSF-0.0, v17.O FNP-1-ECP-0.0, v22.0 FSAR Ch 15.3 & 15.4 (SBLOCA and LBLOCA)
References provided: none Learning Objective: ASSESS the facility conditions associated with the (1) ECP-O.O, Loss of All AC Power; (2) ECP-O.1, Loss of All AC Power Recovery, Without SI Required; (3) ECP-O.2, Loss of All AC Power Recovery, With SI Required, and based on that assessment: (OPS-62532A01)
- SELECT the appropriate procedures during normal, abnormal and emergency situations. 10CFR55.43 (b) 5
- DETERMINE if transition to another section of the procedure or to another procedure is required
- DETERMINE if the critical safety functions are satisfied Question origin: NEW Basis for meeting K/A: INTERPRET plant conditions for evidence (or lack thereof) of Natural Circulation cooling.
A consequence to the lack (loss) of Natural Circulation, the Core Cooling CSF is Challenged, thus requiring implementation of FRP-C.2, the candidate must DETERMINE when the corrective ACTIONS must be implemented.
SRO justification: (10 CFR 55.43.b.5) Assessing plant conditions (normal, abnormal, or emergency) and then selecting a procedure or section of a procedure to mitigate, recover, or with which to proceed.
Knowledge of administrative procedures that specify hierarchy, implementation, andlor coordination of plant normal, abnormal, and emergency procedures 2011 NRC exam From the Clarification Guidance for SRO-only Questions Rev I dated 03/11/2010 flowchart for 10 CFR 55.43(b)(5):
Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations [10 CFR 55.43(b)(5)], involving BOTH:
- 1) assessing plant conditions and then
- 2) selecting a procedure-or section & a procedure to mitigate, recover, orwfth which to proceed.
Using the flowchart, this question can:
- NOT be answered solely by knowing systems knowledge, i.e., how the system works, flowpath, logic, component location.
- NOT be answered solely by knowing immediate operator actions.
- NOT be answered solely by knowing entry conditions for AOP5 or plant parameters that require direct entry to major EOPs.
- NOT be answered solely by knowing the purpose, overall sequence of events, or overall mitigative strategy of a procedure.
- be answered with knowledge of ONE or MORE of the following:
Assessing plant conditions (normal, abnormal, or emergency) and then selecting a procedure or section of a procedure to mitigate, recover, or with which to proceed.
Knowledge of when to implement attachments and appendices, including how to coordinate these items with procedure steps.
Knowledge of diagnostic steps and decision points in the EOPs that involve transitions to event specific sub-procedures or emergency contingency procedures.
Knowledge of administrative procedures that specify hierarchy, implementation, and/or coordination of plant normal, abnormal, and emergency procedures.
FNP1ECP-O.O LOSS OF ALL AC POWER Revision 22 Step Action/Expected Response Response NOT Obtained III I I CAUTION: Critical safety function status trees should be monitored for information only. No function restoration or other procedure should be implemented during a loss of all AC power.
NOTE:
- This procedure is applicable in modes 1 thru 4 only.
FNP-1-AOP-5.O, LOSS OF A OR B TRAIN ELECTRICAL POWER, is applicable for all other plant modes.
- Steps 1 and 2 are IMMEDIATE ACTION steps.
- The Plant Emergency Alarm cannot be activated until AC power is restored.
Check reactor tripped.
1.1 Check reactor trip and reactor 1.1 Perform the following.
trip bypass breakers - OPEN.
1.1.1 Manually trip reactor.
[1 Reactor trip breaker A
[1 Reactor trip breaker B 1.1.2 i any reactor trip breaker
[1 Reactor trip bypass breaker A open or any reactor
[] Reactor trip bypass breaker B trip bypass breaker open, THEN locally open affected breaker. (121 ft. AUX BLDG rod control room) 1.2 Check nuclear power - FALLING.
PR1 (2 .3 .4)
PERCENT FULL POWER
[] NI 41B
[] NI 42B
[] NI 43B
[] NI 44B IR1 (2)
CURRENT
[1 NI 353
[1 NI 36B Page Completed Page 2 of 40
FNP-1-ECP-O.O LOSS OF ALL AC POWER Revision 22 Step Action/Expected Response Response NOT Obtained III I I NOTE: If RCP seal cooling was previously isolated, further cooling of the RCP seals will be established by natural circulation cooldown as directed in subsequent procedures.
29 Evaluate plant conditions.
29.1 Check SI not required. 29.1 Go to FNP-1-ECP-O.2, LOSS OF ALL AC POWER RECOVERY WITH SI
- Check SUB COOLED MARGIN REQUIRED.
MONITOR indication - GREATER than 16°F{45°F} SUBCOOLED IN CETC MODE.
- Check pressurizer level -
GREATER THAN l3%{43%}.
29.2 Go to FNP-l-ECP-O.l, LOSS OF ALL AC POWER RECOVERY WITHOUT SI REQUIRED.
-END-Page 39 of 40
FNP-l-ECP-O.2 LOSS OF ALL AC POWER RECOVERY WITH SI REQUIRED Revision 18 Step Action/Expected Response Response NOT Obtained III I I CAUTION: Critical safety function status trees should be monitored for information only. No Function Restoration Procedure should be implemented until completion of step 13.
1 Reset SI signals.
1.1 Verify SI - RESET. 1.1 any train will NOT reset using the MCB SI RESET F] MLB-l 1-1 not lit (A TRN) pushbuttons,
[1 MLB-l 11-1 not lit (B TRN) THEN place the affected train S821 RESET switch to RESET.
(SSPS TEST CAB.)
1.2 Reset B1F sequencer. (139 ft.
AUX BLDG A train SWGR room) 1.3 Reset BiG sequencer. (121 ft.
AUX BLDG B train SWGR room) 2 [CA] Check RWST level - GREATER 2 Establish cold leg THAN 12.5 ft. recirculation alignment by performing the following.
RWST LVL 2.1 Verify recirculation valve disconnects closed using
[1 LI 40]5A ATTACHMENT 2.
[1 LI 4075B 2.2 Verify ECCS aligned for recirculatiori using ATTACHMENT 3.
2.3 Go to Step 4.
Page Completed Page 2 of 15
FNP1ECP-0.2 LOSS OF ALL AC POWER RECOVERY WITH SI REQUIRED Revision 18 Step Action/Expected Response Response NOT Obtained I I 13 Verify Containment Spray Not Required:
13.1 Check containment pressure - 13.1 Perform the following.
HAS REMAINED LESS THAN 27 psig. 13.1.1 Verify containment spray pump suction valves open.
CTMT PRESS
[] PR 950 RWST TO 1A(1B) CS PUMP
[1 Q1E13MOV8817A
[1 Q1E13MOV8817B 13.1.2 Verify one containment spray pump running.
13.1.3 Verify PHASE B CTMT ISO alignment.
13.1.3.1 Check All MLB-3 lights lit.
13.1.3.2 j any MLB-3 light 1Q lit, THEN verify at least one valve closed at each PHASE B CTMT penetration using ATTACHMENT 5, PHASE B CONTAINMENT ISOLATION.
13.1.4 Verify running containment spray pump flow - GREATER THAN 0 gpm.
CS FLOW
[1 Fl 958A
[1 El 958B NOTE: Function Restoration Procedures should now be implemented.
14 Go to FNP-1-EEP-1, LOSS OF REACTOR OR SECONDARY COOLANT.
- END -
Page 14 of 15
- 85. 05 8AG2.2.25 085!NEW/SRO/C/A 3 .2/4.2/APEO5 8AG2.2.251N/3IVER2.0/MINOR ED Unit .1 has-experienced a trip following a LOSS of 4he IA Aux Building 12&V DC bus. -
The plant has been stabilized and the crew has completed ESP-O.1, Reactor Trip Response.
AT 1000 the following was reported:
- LA-09, 125V DC BUS 1A SUPPLY BKR, has tripped open.
- 1A Battery Chargers DC output breaker is tripped open.
- The 1A 125V DC Battery Charger has been damaged.
- The 1A Battery terminals are damaged.
AT 1010 the following was reported by the Electricians:
- The fault is isolated to the battery terminals.
- The 1A 125V Battery has NOT been repaired.
Which one of the following completes the statements below?
Before DC power is restored, the SG Atmospheric Relief Valves (I)
OPERABLE per TS 3.7.4, Atmospheric Relief Valves (ARVs).
Placing the 1C Battery Charger in service on the IA 125V DC Bus AND restoring bus voltage (2) restore OPERABILITY of the 1A Aux Building 125V DC bus per TS 3.8.4, DC SourcesOperating.
(1) (2)
A. ARE WILL ARE will NOT C. are NOT WILL D. are NOT will NOT
- 10. 05 8AG2.2.25 085/NEW/SRO/C/A 3 .2/4.2/APEO58AG2.2.251N/3/VER2.OJMINOR ED
- Fedhek. -
A loss of the 1 25V Aux Building DC bus will result in (among other responses) a loss of air to the Feed reg and bypass valves due to solenoid arrangement and will require a Loss of Feed trip per AOP-1 3 at any power level > 5%. NOTE: the MSIVs can not be remotely tripped closed due to the loss of DC power. SG pressures will be controlled automatically on the SG Safety valves until Manual operation of the ARVs is taken.
All of the ARVs are powered from 1A 125V DC Aux building DC and will fail closed upon loss of DC power (regardless of air supply).
TS B3.7.4 states that an ARV is considered OPERABLE (even if isolated) when it is capable of providing controlled relief of the main steam flow and capable of fully opening and closing on demand, either remotely or locally via manual control. (TS B3 .7.4-3)
TS B3.8.4 states that an OPERABLE DC electrical power subsystem requires all required batteries and respective chargers to be operating and connected to the associated DC bus(es).
A. Incorrect 1) See B.1
- 2) Restoration of power is not ALL that is required for TS 3.8.4. The Battery must also be restored.
Plausible: TS 38.9, also applicable during this malfunction contains a statement that is often confused with the DC distribution system. TS B3.8.9 states that an OPERABLE AC electrical power distribution subsystems require the associated buses, load centers, motor control centers, and distribution panels to be energized to their proper voltages. If this definition of operability is mistakenly applied to TS 3.8.4 and the DC buses, this answer would be selected.
B. Correct 1) The ARV5 only need to be capable of being operated, with any method. See above.
- 2) Restoration of voltage will recover the functionality but not the OPERABILITY of the 125V DC bus.
C. Incorrect 1) Plausible: A loss of power to all the ARVs would inhibit MCB operation, and the electrical HS operation at the 100 ft Lower Equipment Room.
One might believe that manual automatic or remote operation is required to maintain operability of the ARVs.
- 2) see A.1 D. Incorrect 1)seeC.1
- 2) See B.2
- 10. 058AG2.2.25 O85INEW/SRO/C/A 3 .2/4.2/APEO58AG2.2.251N/3/VER2.O/MINOR ED Notes - -
K/A statement 058A-- Loss of DC POWER 02.2.25 Knowledge of the bases in Technical Specifiations for LCOs and safety limits.
Importance Rating: 3.2 4.2 Technical
Reference:
TS (Rev 50)
B3.8.4, pg B3.8.4-4 B3.7.4, pg B3.7.4-3 B3.8.9, pg B3.8.9-2 References provided: NONE Learning Objective: RECALL AND APPLY the information from the LCO BASES sections:[. ..] associated with the DC Distribution System components [...], to include the following: (OPS-62103C01)
- 3.8.4, DC Sources Operating-
- 3.8.9, Distribution Systems Operating
[...]
AND RECALL AND APPLY the information from the LCO BASES sections: [...] associated with the Main and Reheat Steam System [...], to include the following:
(OPS-621 04A01):
[...]
3.7.4, Atmospheric Relief Valves (ARV5)
[. ..]
Question origin: NEW Basis for meeting K/A: Basis knowledge for Both 3.7.4 and 3.8.4 are required. The conditions provided that require that assessment are the direct result of a single train loss of DC.
SRO justification: 10 CFR 55.43(b)(2) Knowledge of TS bases that is required to analyze TS required actions and terminology.
The BASIS information is required to analyze the term OPERABLE for the given systems.
2011 NRC exam From the Clarification Guidance for SRO-only Questions Rev I dated 03111/2010 flowchart for 10 CFR 55.43(b)(2)
- 1) can NOT be answered by knowing less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Tech Specs.
- 2) can NOT be answered by knowing information listed above-the-line.
- 3) can NOT be answered by knowing the TS Safety Limits or their bases.
- Application of Required Actions (Section 3) and Surveillance Requirements (Section 4) in accordance with rules of application requirements (Section 1).
- Knowledge of TS bases that is required to analyze TS required actions and terminology
ARVs B3.7;4 BASES LCO Failure to meet the LCO can result in the inability to cool the unit to (continued) RHR entry conditions following an event in which the condenser is unavailable for use with the Steam Dump System.
An ARV is considered OPERABLE (even if isolated) when it is capable of providing controlled relief of the main steam flow and capable of fully opening and closing on demand, either remotely or locally via manual control.
APPLICABILITY In MODES 1, 2, and 3, the ARVs are required to be OPERABLE.
In MODE 4, the pressure and temperature limitations are such that the probability of an SGTR event requiring ARV operation is low. In addition, the RHR system is available to provide the decay heat removal function in MODE 4. Therefore, the ARVs are not required to be OPERABLE in MODE 4 to satisfy the safety analysis assumptions of the DBA. However, the capability to remove decay heat from a SG required to be OPERABLE in MODE 4 by LCO 3.4.6, RCS Loops MODE 4 is implicit in the requirement for an OPERABLE SG and may require the associated ARV be capable of removing that heat if the normal decay heat removal system (steam dump) is not available.
In MODE 5 or 6, an SGTR is not a credible event.
ACTIONS With one required ARV line inoperable, action must be taken to restore OPERABLE status within 7 days. The 7 day Completion Time allows for the redundant capability afforded by the remaining OPERABLE ARV lines, a nonsafety grade backup in the Steam Dump System, and MSSVs.
B.1 With two or more ARV lines inoperable, action must be taken to restore all but one ARV line to OPERABLE status. Since the manual isolation valves can be closed to isolate an ARV, some repairs may (continued)
Farley Units I and 2 B 3.7.4-3 Revision 33
DC Sources Operating
- B3.&.4 BASES APPLICABLE The OPERABILITY of the DC sources is consistent with the initial SAFETY ANALYSES assumptions of the accident analyses and is based upon meeting the (continued) design basis of the unit. This includes maintaining the DC sources OPERABLE during accident conditions in the event of:
- b. A worst case single failure.
The DC sources satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO Both the Auxiliary Building 125 VDC source subsystems (Train A and B) and two SWIS 125 VDC source subsystems (one in each train) including a battery charger for each Auxiliary Building and SWIS battery and the corresponding control equipment and interconnecting cabling supplying power to the associated bus within the train are required to be OPERABLE to ensure the availability of the required power to shut down the reactor and maintain it in a safe condition after an anticipated operational occurrence (AOO) or a postulated DBA. Loss of any train DC electrical power subsystem does not prevent the minimum safety function from being performed (Ref. 4).
An OPERABLE DC electrical power subsystem requires all required batteries and respective chargers to be operating and connected to the associated DC bus(es).
APPLICABILITY The DC electrical power sources are required to be OPERABLE in MODES 1, 2, 3, and 4 to ensure safe unit operation and to ensure that:
- a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AOOs or abnormal transients; and
- b. Adequate core cooling is provided, and containment integrity and other vital functions are maintained in the event of a postulated DBA.
The DC electrical power requirements for MODES 5 and 6 are addressed in the Bases for LCO 3.8.5, DC Sources Shutdown.
Farley Units 1 and 2 B 3.8.4-4 Revision 0
Distribution Systems Operating BASES APPLICABLE DC, and AC vital bus electrical power distribution systems are SAFETY ANALYSES designed to provide sufficient capacity, capability, redundancy, and (continued) reliability to ensure the availability of necessary power to ESF systems so that the fuel, Reactor Coolant System, and containment design limits are not exceeded. These limits are discussed in more detail in the Bases for Section 3.2, Power Distribution Limits; Section 3.4, Reactor Coolant System (RCS); and Section 3.6, Containment Systems.
The OPERABILITY of the AC, DC, and AC vital bus electrical power distribution systems is consistent with the initial assumptions of the accident analyses and is based upon meeting the design basis of the unit. This includes maintaining power distribution systems OPERABLE during accident conditions in the event of:
- a. An assumed loss of all offsite power or all onsite AC electrical power; and
- b. A worst case single failure.
The distribution systems satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO The required power distribution subsystems listed in Table B 3.8.9-1 ensure the availability of AC, DC, and AC vital bus electrical power for the systems required to shut down the reactor and maintain it in a safe condition after an anticipated operational occurrence (AOO) or a postulated DBA. The AC, DC, and AC vital bus electrical power distribution subsystems are required to be OPERABLE.
Maintaining the Train A and Train B AC, DC, and AC vital bus electrical power distribution subsystems OPERABLE ensures that the redundancy incorporated into the design of ESF is not defeated. Therefore, a single failure within any system or within the electrical power distribution subsystems will not prevent safe shutdown of the reactor.
Plausible distractor . . .
OPERABLE AC electncal power distribution subsystems require the associated buses, load centers, motor control centers, and distribution panels to be energized to their proper voltages. OPERABLE DC electrical power distribution subsystems require the associated buses to be energized to their proper voltage from either the associated (continued)
Farley Units 1 and 2 B 3.8.9-2 Revision 0
Distribution Systems Operating
- B3.8.9-BASES LCO battery or charger. OPERABLE vital bus electrical power distribution (continued) subsystems require the associated buses to be energized to their proper voltage from the associated inverter via inverted DC voltage or Class 1 E constant voltage transformer.
In addition, tie breakers between redundant safety related AC, DC, and AC vital bus power distribution subsystems, if they exist, must be open.
This prevents any electrical malfunction in any power distribution subsystem from propagating to the redundant subsystem, that could cause the failure of a redundant subsystem and a loss of essential safety function(s). If any tie breakers are closed, the affected redundant electrical power distribution subsystems are considered inoperable. This applies to the onsite, safety related redundant electrical power distribution subsystems. It does not, however, preclude redundant Class 1 E 4.16 kV buses from being powered from the same offsite circuit.
APPLICABILITY The electrical power distribution subsystems are required to be OPERABLE in MODES 1, 2, 3, and 4 to ensure that:
- a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AOOs or abnormal transients; and
- b. Adequate core cooling is provided, and containment OPERABILITY and other vital functions are maintained in the event of a postulated DBA.
Electrical power distribution subsystem requirements for MODES 5 and 6 are covered in the Bases for LCO 3.8.10, Distribution Systems Shutdown.
ACTIONS Ai With one or more required AC buses, load centers, motor control centers, or distribution panels, except AC vital buses, inoperable, and a loss of safety function has not yet occurred, the remaining AC electrical power distribution subsystems are capable of supporting the (continued)
Farley Units 1 and 2 B 3.8.9-3 Revision 0
- 86. 061 AA2.04 086/NEW/SRO/MEM 3.5/4.2/06 IAA2.04/N/3IVER2.0/REPLACEMENT Whith one of the following completes the statements be[ow?
The alarm function(s) of R-5, SFP RM, (1) required for OPERABILITY per TR 13.3.4, Radiation Monitoring Instrumentation.
R-5 (2) automatically trip the Fuel Handling Area Supply and Exhaust Fans on a HIGH radiation condition.
(1) (2)
A. is NOT will NOT B. is NOT WILL IS will NOT D. IS WILL
- 11. 061 AA2.04 086/NEW/SRO/MEM 3.5/4.2/06 1AA2.04/N/3/VER2.0/REPLACE MENT Feedbaek NOTE: IMPENDING CHANGE TO TRM: OPERABILiTY will be REPLA CED by FUNCTIONALITY.... Check for change after PROCEDURE FREEZ E.
TRM Bases B13.3.4 states:
The OPERABILITY of the radiation monitoring channels ensures that:
- 1) the radiation levels are continually measured in the areas served by the individual channels and
- 2) the alarm is initiated when the radiation level trip setpoint is exce eded.
STP-1 .0 checks R-5 indications and switch positions on the drawer in the MCR only.
The purpose of this Daily surveillance is to validate the #1 function is satisfied.
STP-227.IA, Fuel Storage Pool Area Monitor N1D21RE0005 Calibration and Channel Operational Test, tests the Alarm function.
See Table A of SOP-45.O, v42.O for all RMs auto functions. R-5 has NONE.
A. Incorrect 1) PerTR B13.3.4 and SR 13.3.4.4 (STP-227.1A) Acceptance Criteri a,
the Alarm feature is a REQUIRED PART of the R-5 operability. The purpose of R-5 is to ensure evacuation and notification of personnel for a
potential Fuel accident in the SEP room.
- 2) See C.2 Plausible: This answer choice is plausible if one were to believe that the R-5 indication function is all that is required. STP-1 .0 is completed daily by the operator but the alarm function is not regularly checked. With proper recall of Systems knowledge ONLY but Without knowledge to TR Bases this answer choice would be selected.
B. Incorrect 1)SeeA.1
- 2) See Table A of SOP-45.0, v42.0. R-5 is an Area Radiation Monitor that performs NO automatic Functions beyond an LOCAL and REMO TE Alarm.
Plausible: R-5 provides indication for a Fuel handling accident in the SFP room at which time the Fuel handling ventilation will isolate, but due to R-25A and OR R-25B Process Effluent Radiation Monitors.
C. Correct 1) TR BI 3.3.4 function #2 identifies the need for the Alarm function for operability of R-5.
- 2) R-5s only function as an ARM is to monitor and warn personnel of an radiological accident.
D. Incorrect 1) See C.1
- 2) See A.2
- Plausible: This answer choica would be selected if on wore war Of The Alarm feature requirement of the TR, but confuse the automatic function of R-25A & R-25B (PERM) with the R-5 (ARM) function.
- 11. 061AA2.04 086/NEW/SROIMEM 3.5/4.2/06 1AA2.041N/3/VER2.0/REPLACEMEN T
- Notes -
K/A statement Area Radiation Monitoring (ARM) System Alarms 061AA2.04 Ability to determine and interpret whether an alarm channel is functioning properly as they apply to the Area Radiation Monitoring (ARM) System Importance Rating: 3.5 4.2 Technical
Reference:
SOP-45, v42.0 TR 13.3.4, v8.O TR B13.3.4, v3.0 STP-1.0, v104.O References provided: NONE Learning Objective: RECALL AND APPLY the information from the LCO BASES sections: [....J for TRM requirements associated with Radiation Monitoring System components and attendant equipment alignment, to include the following (OPS-62106D01): 10CFR55.43 (b) 2 13.3.4, Radiation Monitoring Instrumentation Question origin: NEW Basis for meeting K/A: the question challenges the examinees ability to determine if R-5 (ARM for SFP area) is OPERABLE without the ALARM capability; The question also challenges the examinees ability to recognize proper response to the R-5 alarm condition vs an equivalent (PERM) rad monitor that operates during the same postulated accident for which the monitors are required.
SRO justification: 10 CFR 55.43(b)(2)
Requires knowledge of TRM bases document to determine OPERABILTY of the SEP Area ARM.
2011 NRC exam 10 CFR 55.43(b)(2)
Facility operating limitations in the TS and their bases. [10 CFR 55.43(b)(2)]
From the Clarification Guidance for SRO-only Questions Rev I dated 03/11/
2010 flowchart:
- 1) can NOT be answered by knowing less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Tech Specs.
- 2) can NOT be answered by knowing information listed above-the-line.
- 3) can NOT be answered by knowing the TS Safety Limits or their bases.
- 4) Does involve oneor more of the following for TS, TRMorODCM
- Application of Required Actions (Section 3) and Surveillance Requirements (Section 4) in accordance with rules of application requirements (Section 1).
- Knowledge of TS bases that is required to analyze TS required actions and terminology
Radiation Monitoring Instrumentation TRI3.3.4 - -
13.3 Instrumentation TR 13.3.4 Radiation Monitoring Instrumentation TR 13.3.4 The radiation monitoring instrumentation channels listed in Table 13.3.4-1 shall be OPERABLE with their alarm/trip setpoints within the specified limits.
APPLICABILITY: As shown in Table 13.3.4-1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more radiation A.1 Adjust the setpoint(s) to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> monitoring channel(s) with within the limit.
alarm/trip setpoint exceeding limit. OR A.2 Declare the channel(s) 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> inoperable.
B. The fuel storage pool area B.1 NOTE (R-5) radiation monitoring The first performance of TRS channel inoperable. 13.3.4.1 is not required to be completed until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after R-5 is declared inoperable.
Initiate action to perform Immediately TRS 13.3.4.1 and continue at required frequency until the fuel storage pool area (R-5) radiation monitoring channel is returned to OPERABLE status.
Farley Units I and 2 13.3.4-1 Version 8.0 Technical Requirements
Radiation Monitoring Instrumentation TR 13.3.4 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. The plant vent stack C.1 Initiate the preplanned 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> effluent (R-29B) radiation alternate method of monitoring channel monitoring the appropriate inoperable, parameter(s).
OR AND One or more main steam C.2 Restore the inoperable 7 days relief and atmospheric channel(s) to OPERABLE steam dump discharge status.
(R-60 A, B or C) radiation monitoring channel(s) inoperable.
OR The auxiliary feed pump turbine exhaust (R-60D) radiation monitoring channel inoperable.
OR One or more turbine building ventilation exhaust (R-15 B or C) radiation monitoring channel(s) inoperable.
D. Required Action and Di Prepare and submit a report 14 days associated Completion to the Commission outlining Time of Condition C not the action taken, the cause met. of the inoperability and the plans and schedule for restoring the system to OPERABLE status.
Farley Units I and 2 13.3.4 2 -
Version 8.0 Technical Requirements
Radiation Monitoring Instrumentation TRt3.34 TECHNICAL REQUIREMENT SURVEILLANCES SURVEILLANCE FREQUENCY TRSI3.3.4.1 NOTE Only required to be performed when the fuel storage pool area radiation monitoring channel (R-5) is inoperable.
Perform area surveys of the monitored area with portable 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> monitoring instrumentation.
TRS 13.3.4.2 NOTE Refer to Table 13.3.4-1 to determine which SRs apply for each radiation monitor channel.
Perform a CHANNEL CHECK. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> TRS 13.3.4.3 NOTE Refer to Table 1 3.3.4-1 to determine which SRs apply for each radiation monitor channel.
Perform a COT. 92 days TRS 13.3.4.4 NOTE Refer to Table 13.3.4-1 to determine which SRs apply for each radiation monitor channel.
Perform a CHANNEL CALIBRATION. 18 months Farley Units I and 2 13.3.4 3 Version 8.0 Technical Requirements
Radiation Monitoring Instrumentation TR13.3.4 Table 13.3.4-1 Radiation Monitoring Instrumentation Radiation Monitoring Applicable Alarm/Trip Required Technical Instrument Channel Modes or Setpoint Channels Requirement Other Surveillance specified Conditions
- 1. Area Monitors
- a. Fuel Storage Pool With fuel in 15 mr/hr 1 TRS (Note1 13341 )
Area (R-5) the storage TRS 13.3.4.2 pool TRS 13.3.4.3 TRS 13.3.4.4
- 2. Process Monitors (Noble Gas Effluent Monitors)
- b. Main Steam 1,2, 3 N/A 3 TRS 13.3.4.2 Relief and TRS 13.3.4.4 Atmospheric Steam Dump Discharge (R-60A, B, C)
- d. Turbine Building 1, and N/A 2 TRS 13.3.4.2 Ventilation With vacuum TRS 13.3.4.4 Exhaust in the (includes condenser condenser air ejector exhaust)
(R-15 B and C)
Note 1: Only required to be performed when the fuel storage pool area radiation monitoring channel (R-5) is inoperable.
Farley Units I and 2 13.3.4 -4 Version 8.0 Technical Requirements
Imentation B 13.3 B 13.3 INSTRUMENTA11ON BASES TR 13.3.1 Movable Incore Detectors The OPERABILITY of the movable incore detectors with the specified minimum complement of equipment ensures that the measurements obtained from use of this system accura tely represent the spatial neutron flux distribution of the reactor core. The OPERABILITY of this system is demonstrated by irradiating each detector used and determining the accept ability of its voltage curve.
For the purpose of measuring FQ(Z) and Fxy a full incore flux map is used.
Quarter-core flux maps, as defined in WCAP-8648, June 1976, may be used in recalibration of the excore neutron flux detection system. Full incore flux maps or symmetric incore thimbles may be used for monitoring the QUADRANT POWER TILT RATIO when one Power Range Chann el is inoperable.
TR 13.3.2 High Energy Line Break Isolation Sensors The high energy line break isolation sensors are designed to mitigate the conseq uences of the discharge of steam and/or water to the affected room and other lines and system s contained therein. In addition, the sensors will initiate signals that will alert the operator to bring the plant to a shutdown condition.
TR 13.3.3 Turbine Overspeed Protection This Technical Requirement is provided to ensure that the turbine overspeed protect ion instrumentation and the turbine speed control valves are OPERABLE and will protect the turbine from excessive overspeed. Protection from turbine excessive overspeed is require d since excessive overspeed of the turbine could generate potentially damaging missile which s could impact and damage safety related components, equipment or structures.
TR 13.3.4 Radiation Monitoring Instrumentation The OPERABILITY of the radiation monitoring channels ensures that:
- 1) the radiation levels are continually measured in the areas served by the individual channels and
- 2) the alarm is initiated when the radiation level trip setpoint is exceeded.
Farley Units I and 2 B 13.3-1 Version 3.0 Technical Requirements Bases
4.1.3 Perform the following to verify drawers aligned for monitors listed in Table A:
4.1.3.1 Verify operation selector in OPERATE. E 4.1.3.2 Verify range selector in WIDE.
4.1.3.3 Verify drawer indicating lights as follows:
- a. Power Light - ON
- b. Channel Test Light - OFF
- c. High Alarm Light - OFF D
- d. Low Alarm Light - OFF D TABLE A MONITOR NAME TYPE AUTO FUNCTION R-1A CONTROL RM AREA Area No R-2 CTMT 155 ft Area No R-3 RADIOCHEMISTRY LAB Area No R-4 1C CHG PUMP RM Area No R-5 SFP RM Area No R-6 SAMPLE RM AREA Area No R-7 SEAL TABLE Area No R-8 DRUMMING STATION Area No R-13 WASTE GAS COMPR SUCT Gas No R-14 PLANT VENT Gas YES R-15 SJAE EXH Gas No R-17A CCW Liquid YES R-17B CCW Liquid YES R-18 LIQ WASTE DISCH Liquid YES R-19 SGBD SAMPLE Liquid YES R-20A SW FROM CTMT CLRS Liquid No R-20B SW FROM CTMT CLRS Liquid No R-22 VENT STACK GAS Gas No R-23A SGBD HX OUTLET Liquid YES R-23B SGBD TO DILUTION Liquid YES
UNIT 1 Farley Nuclear PIai, A FNP-1-STP-1.0 Ver IC 12/2/2010 12:51 :05 OPERATIONS DAILY AND SHIFT SURVEILLANCE Page Number REQUIREMENTS 32of98 Appendix 1 Modes 1, 2, 3, 4 Page 26 of 47 TITLE NIGHT DAY ACCEPTANCE CRITERIA TECH SPEC
- 41. Fuel Storage Pool Area Monitor (RJhr) With fuel in storage pool or bldg.;
R-5 Channel Check, Verify power on and TRS 13.3.4,2 L operation selector in OPERATE.
IF R-5 is inoperable, THEN have area TRS 13.3.4,1 surveys performed in the SFP once per day.
- 42. RCS Leakage Detection Particulate Activity (cpm) Mode 1,2, 3,4; SR 3.4.15.1 R-1 1 Channel Check and Monitor.
NORM/SUPV keylock in NORM, CH1 OPER Light(GREEN) Lit***
Abnormally low readings on R-1 1 with normal readings on R-12 may indicate a valve line-up problem. Request I&C to perform FNP-1-STP-227.2 to ensure R-1 1 is operable. {OR 97-345)
- 43. RCS Leakage Detection Gaseous Activity (cpm) Mode 1,2,3,4; SR 3.4.15.1 Channel Check and Monitor. Verify R 12 NORM/SUPV keylock in NORM, CH2 OPER Light(GREEN) Lit Abnormally low readings on R-12 with normal readings on R-11 may indicate a valve line-up problem. Request I&C to perform FNP-1-STP-227.2 to ensure R-12 is operable. {OR 97-345)
- 44. Plant Vent Gaseous Activity (cpm) At All Times; 5.5.4.a Channel Check. Verify power on and R 14 operation selector in OPERATE.
- 45. Condenser Air Ejector Activity (cpm) At All Times; 5.5.4.a Channel Check. Verify power on and R 15 operation selector in OPERATE.
- 87. 069AG2.2.7 O87JNEW/SRO/MEM 2.9/3 .6/069AG2.2.71N!3/VER2.O!REPLACEMENT Unit I -is in MODE S.
An Infrequently Performed Test, as defined by NMP-AD-006, Infrequently Performed Tests and Evolutions (IPTE), is scheduled to be performed requiring various MOVs to be torqued closed.
At 0500 MOV-3182, CCW FROM RCP OIL CLRS, was operated as follows:
- The supply breaker for MOV-3182 was opened.
- MOV-3182 was locally closed using the handwheel.
At 1900 the following occurred:
- MOV-3182 was locally opened.
- The supply breaker for MOV-31 82 was closed.
- ON the MCB handswitch for MOV-3182, ONLY the RED light is LIT.
- NO maintenance activities have been conducted on MOV-3182.
Which one of the following completes the statements below?
The Operations Superintendent (1) provide the Senior Line Manager oversight required for the test per NMP-AD-006.
MOV-3182 is (2) OPERABLE per SOP-O.O, General Instruction To Operations Personnel.
(1) (2)
A. may NOT is NOT B. may NOT IS C MAY is NOT D. MAY IS
- 12. 069AG2.2.7 087/NEW/SRO/MEM 2.9/3 .6/069AG2.2.7/N/3/VER2.O/REPLACEMENT Feedback -.
NMP-AD-006, section 4.2 provides a list of who may function as a SENIOR LINE MANAGER- that list is as follows:
- Site Vice President
- Plant Manager
- Engineering Director
- Site Support Manager
- Department head / line manager preferred
- Operations Superintendent
- Maintenance Assistant Manager TS 3.6.3 is applicable MODES I through 4, and not applicable in MODE 6, but the components status of operable/inoperable is tracked such that prior to entering Mode 4. THE SRO must recognize the condition of the Containment Isolation Valve and track it properly to comply with containment INTEGRITY requirements.
SOP-0.0, vi 39.0 provides the following guidance with regard to these conditions:
15.5.3 Prior to manually seating or back seating an MOV that performs a safety function; the Shift Supervisor should evaluate the effect on valve operability with respect to Technical Specifications, Inservice Test Plan, or other applicable requirements. (SOER 83-9):
15.5.4 IF an MOV that performs a safety function, is to be placed in a position other than the one required to fulfill its safety function, THEN the MOV should be considered inoperable after manual operation. (SOER 83-9):
15.5.5 IF an MOV that performs a safety function is to be placed in the position required to fulfill its safety function, THEN the MOV is still considered operable after manual operation. (SOER 83-9):
15.5.6 After manual operation of any MOV that performs a safety function, an LCO (either Voluntary or Administrative) should be initiated. The LCO should require the MOV to be stroked electrically (one full cycle) to demonstrate electrical operability prior to return to service. IF electrical operability of the motor operator cannot be verified, THEN initiate a Condition Report. (SOER 83-9):
ANSWER I DISTRACTOR ANALYSIS A. Incorrect. 1) See above; The Operations Superintendent is the lowest level of supervision within the Operation chain of command that may function as this role. The Operations Superintendent may or may not be senior to the Shift Manager.
Plausible: OPS Superintendent is equivalent to Shift Manager.
NMP-AD-006 specifically excludes ON SHIFT compliment from this allowance however and the SM, which is not part of the current shift compliment (NOT THE ON-SHIFT SM) can. This distinction is commonly confused.
2> See C.1 B. Incorrect. 1)SeeA.1
- 2) See above; Because the valve is OPEN and there is a potential that the MOV may not be capable of overcoming the Closing torque and be incapable of closing the valve before the thermal overload protection trips the breaker or the valve being bound, the OPERABILITY of this valve can not be proven.
Plausible: This answer choice is correct IF the ON SHIFT Shift Manager was providing the oversight role; AND IF the valve were left in the CLOSED position; although it would still have a tracking LCO on its electric operability for when it was not in its required position.
C. Correct. 1) Defined by NMP-AD-006 section 4.2.
- 2) See above; MOV-3182s safety Function is to CLOSE upon a Phase B containment Isolation signal, therefore it is NOT IN its required SAFETY FUNCTION position. Per the SOP-O.O guidance noted above, this Valve is NOT OPERABLE AND is required to have a tracking LCO for electric operability. (ADMIN LCO is required for electronic OPERABILITY as well as TS OPERABILITY since MODE 6).
D. Incorrect. 1)seeC.1
- 2) See B.2 Plausible: one might select this answer choice if one were to properly recall NMP-AD-006, but not the guidance within SOP-O.O.
- 12. 069AG2.2.7 O87INEW/SRO/MEM 2.9/3 .6/069AG2.2.7/N/3/VER2.OIREPLACEMENT Notes --
K/A statement 069A Loss of Containment Integrity G2.2.7 Knowledge of the process for conducting special or infrequent tests.
Importance Rating: 2.9 3.6 Technical
Reference:
SOP-0 .0, vi 39 NMP-AD-006, v9.0 References provided: none Learning Objective: Using plant procedures as a guide, evaluate a maintenance item for release and determine if it can be released and what actions are required. (OPS52303N01)
RECALL AND APPLY the information of the generic LCO requirements (LCO 3.0.1 thru 3.0.7; SR 4.0.1 thru 4.0.4) including the BASES of the generic section, for any Technical Specifications or TRM requirements (OPS-62302A02): 10CFR55.43 (b) 2 Question origin: NEW Basis for meeting K/A: Question tests the requirements of NMP-AD-006 for conducting an IPTE, applicable during testing of Containment isolation valves.
Generically challenges MOV (component) Operability determination using SOP-0.0 guidance.
SRO justification: 10 CFR 55.43(b)(2):
Application of generic LCO requirements (LCO 3.0.1 thru 3.0.7 and SR 4.0.1 thru 4.0.4) 2011 NRC exam From the Clarification Guidance for SRO-only Questions Rev 1 dated 03/11/2010 flowchart for 10 CFR 55.43(b)(2)
- 1) can NOT be answered by knowing less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Tech Specs.
- 2) can NOT be answered by knowing information listed above-the-line.
- 3) can NOT be answered by knowing the TS Safety Limits or their bases.
- 4) Does involve one or more of the following for TS, TRM or ODCM:
- Application of Required Actions (Section 3) and Surveillance Requirements (Section 4) in accordance with rules of application requirements (Section 1).
- Knowledge of TS bases that is required to analyze TS required actions and terminology - - -
- Special, infrequently performed surveillance testing that involves complicated sequencing or placing the plant in unusual configurations (for example, emergency core cooling system check valve leakage tests, ILRT, etc.).
- Special test procedures conducted in conjunction with existing procedures which could place the plant outside normal operating limits and could require additional controls to reduce the potential for significantly degrading the plants margin of safety such as low power physics testing.
- Evolutions involving significant radiological or occupational hazards such as confined space entry using an SCBA, radiography or diving in spent fuel pools.
Recurring Corporate Action Item 2009200174 is assigned to the Operations Peer Team to annually review and, if needed, update this IPTE definition and Table 1, Required IPTE Activities. (H 1992300064) 4.2 Senior Line Manager The functions of the Senior Line Manager will be performed by one of the following:
- Site Vice President
- Plant Manager
- Engineering Director
- Site Support Manager
- Department head I line manager preferred
- Operations Superintendent
- Maintenance Assistant Manager (V2001 342510) (V2003344462) 5.0 Responsibilities 5.1 The Site VP or Plant Manager The Plant Manager (Site Support Manager and Engineering Director are backups) is responsible for interpreting the definition of Infrequently Performed Test or Evolution and determining when activities meet the threshold for IPTE that are not specifically listed on Table 1. Suggested changes to the IPTE definition or activities requiring an IPTE briefing should be forwarded to the Operations Peer Team for incorporation into this NMP. As a minimum, the IPTEs specified in Table 1 Required IPTE Activities shall constitute mandatory requirements. When new or unusual evolutions or tests are performed, one of the above individuals shall determine if the activity shall be treated as an IPTE.
(V1991323078) (H 1992300059) 5.2 Senior Line Manager The Senior Line Manager has responsibility for the oversight of the test or evolution. The Senior Line Manager will brief operating and test personnel on management expectations prior to the start of the testlevolution and provide management oversight. This briefing shall cover all items required by Attachment 1 (IPTE Briefing Checklist). These briefings should be performed in an area that is as free from distractions as allowed by the situation. Senior Line Management oversight of the activity is required; the degree of oversight shall be at the discretion of the Senior Line Manager conducting the briefing and shall be commensurate with the risk involved with the activity. Management oversight may take the form of
12/01/10 14:40:42 FNP-0-SOP-0.0 15.5 Restrictions On Manual Operation of MOVs CAUTION: IF MOV is powered up and capable of remote operation, THEN de energize the power supply before manually operating MOV.
15.5.1 If a MOV must be operated manually, and the valve can be opened electrically, the manual operator should be engaged with the valve in the open position.
15.5.2 SMB-00 MOV operators can potentially open on high D/P when declutched for manual operation. IF any of the following MOVs are required to be maintained closed after being declutched, THEN tie wrap or otherwise secure the MOVs handwheel in place.
- Q1(2)E21M0V8105
- Q1(2)E21M0V8106
- Q1(2)E21M0V8107
- Q1(2)E21MOV81O8
- Qi (2)E2 1 MOV8 1 09A!B/C
- Q1(2)E21M0V8803A/B
- Q1(2)E21M0V8884
- Q1(2)E21M0V8885
- Q1(2)E21M0V8886
- Qi (2)E2 1 MOV8000A/B 15.5.3 Prior to manually seating or back seating an MOV that performs a safety function; the Shift Supervisor should evaluate the effect on valve operability with respect to Technical Specifications, Inservice Test Plan, or other applicable requirements. (SUER 83-9):
15.5.4 IF an MOV that performs a safety function, is to be placed in a position other than the one required to fulfill its safety function, THEN the MOV should be considered inoperable after manual operation. (SUER 83-9):
15.5.5 fl an MOV that performs a safety function is to be placed in the position required to fulfill its safety function, THEN the MOV is still considered operable after manual operation. (SUER 83-9):
Page 24 of 79 Version 139.0
12/01/10 14:40:42 FNP-0-SOP-0.O 15.5.6 After manual operation of any MOV that performs a safety function, an LCO (either Voluntary or Administrative) should be initiated. The LCO should require the MOV to be stroked electrically (one full cycle) to demonstrate electrical operability prior to return to service. 11E electrical operability of the motor operator cannot be verified, THEN initiate a Condition Report. (SOER 83-9):
15.5.7 NOT at any time pull up on the declutch lever. This would damage the clutch internals.
15.5.8 DO NOT use the manual operator to force the valve any further against its seat than the motor operator will drive it. The motor may not be able to drive the valve off the seat without damaging the operator. IF the motor operator fails to close the valve against the seat, THEN the manual operator may be used to close the valve and a Condition Report shall be submitted to evaluate the MOV operator.
15.5.9 Q NOT hold the de-clutch lever in the depressed position while the motor is running. Inadvertent re-engagement of the motor operator could damage the clutch internals.
15.5.10 DO NOT use any type of additional mechanical advantage (such as a cheater bar) when operating an MOV manually. Such use will damage the valve operator.
15.5.11 Excessive force should not be applied to declutch lever as deformation of the de-clutch shaft will result.
Page 25 of 79 Version 139.0
- 88. 071 G2.2.38 088/NEW/SRO/C/A 3.6/4.5/071 G2.2.38/ODCM/4/VER 3.0/MINOR ED Gonsid& the following conditionswhioh occurred on dayshift:
The crew performed STP-60.2, Gaseous Radwaste Treatment And Ventilation Exhaust Treatment Operability Verification.
A Voluntary LCO was initiated due to HV-3096A & B, CCW from Evap Pkgs &
H2 Recomb, being taken off the jack and opened during the performance of STP-60.2.
- STP-60.2 was completed UNSAT due to the Waste Gas compressors failing to run for 15 minutes.
- HV-3096A & B were returned to the Jacked Closed position and the Voluntary LCO was cleared.
Which one of the following completes the statements below?
In addition to a Control Room LCO Log entry, an LCOITR Status Sheet (1) required to document the short duration Voluntary LCO on CCW.
A Waste Gas release (2) permitted while the Waste Gas Compressors are INOPERABLE, per the ODCM.
(1) (2)
A. IS is NOT B. IS IS C. is NOT is NOT D is NOT IS
- 13. 071 G2.2.38 O88INEW/SRO/C/A 3.6/4.5/071 G2.2.38/ODCMJ4/VER 3.0/MINOR ED Eeedhack -
Part I SOP-51 .0, v50.0 section 4.20, referenced by STP-60.2, is equipped with a CAUTION &
NOTE that read:
Prior to performance of the following steps, evaluate LCO requirements per FNP-0-SOP-0.13 App C [B Administrative error in SOP-0.13, v24.0] due to HV-3096B1A not being jacked closed.
Q1P17HV3O96BIA CCW TO/FROM EVAP PKGS & H2 RECOMB are normally jacked closed. CR 2010103438 HV3096A & B have a design flaw that requires them to be maintained Jacked closed to maintain the operability of CCW while in modes 1-4. These valves must be opened to permit this testing ( permitted by SR 3.0.5). Therefore a Voluntary LCO entry is made and must be documented.
However, the Completion of an LCOITR Status Sheet is NOT required for [...] short term entry into an LCOITR which will be cleared prior to archiving the Control Room Log for the day. (SOP-0.13, v24.0 section 3.0.2)
Part 2 3.1.5 GASEOUS RADWASTE TREATMENT SYSTEM Control In accordance with Technical Specification 5.5.4.f, the GASEOUS RADWASTE TREATMENT SYSTEM and the VENTILATION EXHAUST TREATMENT SYSTEM shall be OPERABLE. [...]
3.1.5.2 Actions With gaseous waste being discharged without treatment and in excess of the limits in Section 3.1.5, prepare and submit to the Nuclear Regulatory Commission within 30 days, pursuant to 10 CFR 50.4, a Special Report which includes the following information:
- a. Identification of the inoperable equipment or subsystem and the reason for inoperability,
- b. Action(s) taken to restore the inoperable equipment to OPERABLE status, and
- c. Summary description of action(s) taken to prevent a recurrence.
The satisfactory completion of STP-60.2 is NOT necessary to satisfy the operability of the WASTE GAS RELEASE System Control. Further, there are no restrictions on the WG release as a result of the inoperable WG compressors.
A. Incorrect 1) Because the LCO entry is short, an LCO/TR Status Sheet is NOT required, instead a Control Room Log entry is made to contain the necessary information of section 3.0.2 of SOP-Ol .3.
Plausible: This would be a correct response if the duration of inoperability were longer or expected to cross over a turnover.
- 2) There is NO restriction on the release.
SOP-51 .0, v50.0 appendix 2 prerequisite 2.7 requires the WG system to be Shutdown, therefore there is- no impact on the release of theWG system..
Plausible: if one were to believe that the WG Compressors are required to be OPERATIONAL for a Release to be conducted.
B. Incorrect 1) See A.1 for analysis and plausibility
- 2) See D.2 C. Incorrect 1) See D.1
- 2) See A.2 for analysis and plausibility D. Incorrect 1) Because this LCO Condition entry is short lived, a Control Room Log entry is all that is required per SOP-0.13 section 3.0.2.
- 2) This is correct per SOP-0. 13 section 2.3.
- 13. 07102.2.38 O88INEW/SRO/C/A 3.6/4.5/071G2.2.38/ODCMJ4/VER 3.0/MINOR ED Nutes -
K/A statement 071Waste Gas Disposal System (WGDS)
G2.2.38 Knowledge of conditions and limitations in the facility license Importance Rating: 3.6 4.5 Technical
Reference:
SOP-0. 1 3,V24 ODCM v24 ,
SOP-51.O, v50.0 STP-60.2, v8.0 References provided: none Learning Objective: STATE AND DESCRIBE the process for recording and tracking the failure to meet the Limiting Condition for Operation and Technical Requirements (OPS-52302A07)
ASSESS the facility conditions associated with the Waste Gas System components, and based on that assessment, SELECT the appropriate procedure(s) for normal or abnormal situations. (OPS-62106B02).
Question origin: NEW Basis for meeting K/A: Complying with TS and plant procedures are a provision of the facility license. This question challenges a surveillance performed regularly and the required documentation requirements for LCO which are not met as well as ODCM requirements related to the WG Disposal system.
Knowledge of the WG disposal system operation procedure and evaluation of the ODCM Limitations/Actions/Basis is necessary to evaluate the ability to perform a release.
SRO justification: 10 CFR 55.43(b)(1):The required actions for not meeting administrative controls listed in Technical Specification (TS) Section 5 or 6 2011 NRC exam Conditions and limitations in the facility license. [10 CFR 55.43(b)(1)J Some examples of SRO exam items for this topic include:
- Reporting requirements when the maximum licensed thermal power output is exceeded.
- Administration of fire protection program requirements such as compensatory actions associated with inoperable sprinkler systems, fire doors, etc.
- The required actions for not meeting administrative controls listed in Technical Specification (TS) Section 5 or 6, depending on the facility (e.g.,
shift staffing requirements).
- National Pollutant Discharge Elimination System (NPDES) requirements, if
applicable.
Processes for TB and-FSAR changes.
12/01/10 14:34:53 FNP-0-SOP-0.13 3.0.2 Initiation of short term LCO/TR ACTION statement Completion of an LCO!TR Status Sheet is NOT required for the performance of surveillances or short term entry into an LCO/TR which will be cleared prior to archiving the Control Room Log for the day. In this case, the following steps should be performed to document the item in Control Room Log:
- a. Enter the ENTRY and EXIT times of the LCO/TR.
- b. Enter a brief description of the activity that caused the LCO/TR to not be met. The description should begin with an identification number of any applicable WO number, surveillance procedure, or other document that is causing the entry. The description should also include a brief word summary of the activity (ex. PZR Press.
channel COT-PT 455).
- c. Enter a list of the Technical Specification or Technical Requirement entered.
- d. Enter a statement of the results the LOSF Evaluation determination performed.
Example: 0234 Authorized FNP-X-STP-X, Unit 1 RHR Pump A 1ST. Entered TS 3.5.2 Condition A. No LOSF exists due to this inoperability.
- e. Change the Entry Type from Standard to LCO. This will cause the log entry to appear in red.
- f. Verifr that SS-Shift Supervisor is selected as the Sub Log.
- g. For planned work, the releasing SRO will be responsible and required to write the LCO entered for the specified work when the work order is released. The applicable units SS will peer check the written LCO. The SS is expected to annotate that the LCO has been peer checked in AutoLog. [Al 2008202372]
- h. For mandatory LCO entries, inform the Operations Manager or one of the Operations staff superintendents Version 24.0
10/08/10 10:22:51 FNP-1-SOP-51.0 4.20 Waste Gas System Leak Check and Startup With The Recombiners Bypassed CAUTION: The cooling water discharge valve of the seal water heat exchanger for the compressor not in use must remain closed when the compressor is not in use.
TCAUTION: Prior to performance of the following steps, evaluate LCO requirements
[ per 1?NP-0SOP0.13 App C due to IIV-3096B1A not being jacked closed.
NOTE: Q1P17HV3O96B/A CCW TO/FROM EVAP PKGS & H2 RECOMB are normally jacked closed. CR 2010103438 4.20.1 Perform the following to establish cooling water to the waste gas compressor.
4.20.1.1 IF required, THEN remove Q1P17HV3O96B/A CCW TO/FROM EVAP PKGS & H2 RECOMB from the jack per FNP-1-SOP-23.0.
4.20.1.2 Attempt to open Q1PI 7HV3096B/A CCW TO/FROM EVAP PKGS & H2 RECOMB. If first attempt is successful, proceed to step 4.20.2. Otherwise, continue in the procedure.
NOTE: Operating experience has shown that QIP17HV3O96B may not open when demanded due to high delta P across the valve seat. CCW TO 1A(B) RHR HX Q1P17MOV3185A(B) may have to be opened to minimize the delta P across Q1P17HV3O96B. CR 2010103438 4.20.1.3 IF required, THEN open CCW TO 1A(B) RHR HX Q1P17MOV3185A(B) in the on service train.
4.20.1.4 Verify open Q1P17HV3O96B/A CCW TO/FROM EVAP PKGS & H2 RECOMB.
4.20.1.5 IF CCW TO 1A(B) RHR HX Q1P17MOV3185A(B)was opened to minimize delta P, THEN close CCW TO 1A(B)RHRHX Q1P17MOV3185A(B).
4.20.2 Adjust water flow through waste gas compressor A(B) seal water heat exchanger to 50 gpm on FI-3085 by adjusting the cooling water discharge valve NiP 17V045A(B).
4.20.3 Record the non-shutdown waste gas decay tank pressures on Appendix D.
Version 50.0
- 89. 074EG2.4.20 O89INEW/SRO!C/A 3 .814.3/EPEO74EG2 .4.20/N!4!VER2.O/REPLACEMENT I has tnpped following-a small break LOCA
- All High Head Safety Injection pumps have failed or are unavailable.
- PCV-444B, PRZR PORV, is leaking by its seat.
- FRP-C.1, Response to Inadequate Core Cooling, is in progress.
- All RCPs are secured and power is NOT available.
- The crew is evaluating an RCS depressurization.
Which one of the following completes the statements below per FRP-C.1?
MOV-8000B, PRZR PORV ISO, (1) be opened to reduce RCS pressure with PCV-444B.
After opening available vent paths, IF the CETCS are >1200°F and rising, the crewshall (2)
(1) (2)
A WILL transition to SAC RG-1, Severe Accident Control Room Guideline Initial Response B. WILL return to the earlier step of FRP-C.1 to re-assess if RCPs can be started C. will NOT transition to SACRG-1, Severe Accident Control Room Guideline Initial Response D. will NOT return to the earlier step of FRP-C.1 to re-assess if RCPs can be started
- 14. 074EG2.4.20 089/NEW/SRO/C/A 3.8/4.3!EPEO74EG2.4.20/N/4IVER2.OIREPLACEMENT Feedbgc.k NOTE at STEP 13.3 of FRP-C.1 (also contained in various other ERPs such as EEP-1 .0) states:
[...] A failed open PORV must not be unisolated. A leaking PORV which is isolated with power available to the isolation valve should remain isolated until needed to reduce RCS pressure or mitigate an RCS overpressure condition. Any leaking PORV should be re-isolated when not in use STEP 23 RNO provides the only transition to SACRG-1:
IF the fifth hottest core exit TIC is greater than 1200°F AND rising, AND RCPs running in all available cooling loops, THEN go to FNP-1-SACRG-1 [...J STEP 23 is encountered only after all three major mitigative strategies are implemented. Those strategies are:
1- RESTORE HHSI or LHSI then recover inventory. (steps 1-9) 2- if strategy us unsuccessful, then Rapidly depressurize the SG to Depress the RCS to inject SI Accumulators. (steps 10-21) 3- if strategy I & 2 is unsuccesful then Start all available RCPs and VENT the RCS inside Containment--- RCPs for delay time (forced mixed cooling) and VENT to achieve LHSI flow, steps 21-29)
A. Correct 1) See step 13.3 NOTE.
- 2) See step 23 RNO.
B. Incorrect 1)SeeA.1
- 2) See step 23 RNO.
Plausible: This is the correct action if temperatures were lowering (step 23.1 RNO actions). This return to step 21 occurs also at step 26 & 27 which would be encountered if <1200°F or even if >1200°F but stable.
C. Incorrect 1) See step 13.3 NOTE
- 2) see A.1 Plausible: THE NOTE directs that a FAILED OPEN valve SHALL NOT be unisolated. This could be easily confused with the LEAKING Valve.
D. Incorrect 1)seeC.1
- 2) see B.2
- 14. 074EG2.4.20 O89JNEW/SRO/C/A 3 .8/4.3IEPEO74EG2 .4.201N/4/VER2.OIREPLACEMENT Nite - - -
K/A statement - 074E Inadequate Core Cooling G2.4.20 Knowledge of the operational implications of EOP warnings, cautions, and notes.
Importance Rating: 3.8 4.3 Technical
Reference:
FRP-C. 1, viTO FRB-C.1, vl.0 References provided: NONE Learning Objective: ASSESS the facility conditions associated with the (1) FRP-C.1, Response to Inadequate Core Cooling;
[...] and based on that assessment: (OPS-62533C01)
- SELECT the appropriate procedures during normal, abnormal and emergency situations.
- DETERMINE if transition to another section of the procedure or to another procedure is required
- DETERMINE if the critical safety functions are satisfied Question origin: NEW Basis for meeting K/A: REQUIRES knowledge of operational implication of STEP 13.3 NOTE contained within FRP-C.1 and FRP-C.2; which identifies the allowance to utilize a PRZR PORV for Depressurization if it was isolated solely for seat leakage.
But NOT for a stuck open valve. (RO KNOW LEDGE)
Also, requires knowledge of Whether or NOT a depressurization should proceed without SI flow. (SRO decision point--- contained within NOTE at step 21.2)
REQUIRES TRANSITION Criteria with regard to FRP-C.1 that would be implemented if HHSI were not ever recovered.
(SRO knowledge level).
SRO justification: 10 CFR 55.43(b)(5)
Knowledge of diagnostic steps and decision points in the EOPs that involve transitions to event specific sub-procedures or emergency contingency procedures.
2011 NRC exam Using the flowchart, this question can:
- NOT be answered solely by knowing systems knowledge, i.e., how the system works, flowpath, logic, component location.
- NOT be answered solely by knowing immediate operator actions.
- NOT be answered solely by knowing entry conditions for AOPs or plant parameters
that require direct entry to major EOPs.
NOT b answered solely by knowing the purpose, OVrll sequence of events, or overall mitigative strategy of a procedure.
Knowledge of the mitigative strategy (depressurization) is part of that information required for Part 1, but knowledge of the information contained within the NOTE and whether or not to proceed with the strategy is being challenged.
CAN be answered with knowledge of ONE or MORE of the following:
Assessing plant conditions (normal, abnormal, or emergency) and then selecting a procedure or section of a procedure to mitigate, recover, or with which to proceed.
Knowledge of when to implement attachments and appendices, including how to coordinate these items with procedure steps. (When to implement the strategy, RCS depressurization)
Knowledge of diagnostic steps and decision points in the EOPs that involve transitions to event specific sub-procedures or emergency contingency procedures.
Knowledge of administrative procedures that specify hierarchy, implementation, and/or coordination of plant normal, abnormal, and emergency procedures.
FNP-1-FRPC.l RESPONSE TO INADEQUATE CORE COOLING Revision 17 Step Action/Expected Response Response NOT Obtained III I I NOTE: The purpose of the following step is to establish an availab le PORV flowpath for mitigation of overpressure conditions, without relying on the PRZR code safety valves. A failed open PORV must not be unisolated. A leaking PORV which is isolated with power availab le to the isolation valve should remain isolated until needed to reduce RCS pressure or mitigate an RCS overpressure condition. Any leaking PORV should be reisolated when not in use.
13.3 Check at least one PRZR PORV 13.3 Open any PRZR PORV ISO not ISO - OPEN. required to isolate an open or leaking PORV.
13.4 Verify reactor vessel head vent valves - CLOSED.
RX VESSEL HEAD VENT OUTER ISO
[1 Q1B13SV2213A
[] Q1B13SV2213B RX VESSEL HEAD VENT INNER ISO
[1 Q1B13SV2214A
[] Q1B13SV2214B 1
P age Completed Page 14 of 33
FNP-1-FRP-C.1 RESPONSE TO INADEQUATE CORE COOLING Revision 17 Step Action/Expected Response Response NOT Obtained III I I 22.1.4 IF pressure in intact SGs can NOT be reduced, THEN dump steam from a faulted or ruptured SG.
23 Check core exit TICs - LESS 23 Perform the following.
THAN 1200°F.
23.1 IF core exit temperatures are lowering, THEN return to Step 21.
OBSERVE NOTE PRIOR TO STEP 21.
23.2 IF the fifth hottest core exit T/C is greater than 1200°F rising, AND RCPs running in all available cooling loops, THEN go to FNP-1-SACRG-1.
SEVERE ACCIDENT CONTROL ROOM GUIDELINE INITIAL RESPONSE.
24 Check if SI accumulators should be isolated.
24.1 Check LHSI - AT LEAST 24.1 Proceed to step 26.
INTERMITTENT FLOW.
1A(1B)
[] Fl 605A
[] Fl 6O5B 24.2 Reset SI. 24.2 i any train will reset using the MCB SI RESET
[1 MLB-1 1-1 not lit (A TRN) pushbuttons, 1 MLB-1 11-1 not lit (B TRN) THEN place the affected train S821 RESET switch to RESET.
(SSPS TEST CAB.)
Step 24 continued on next page.
Page Completed Page 28 of 33
MAJOR ACTION CATEGORIES IN FR-C.l o Establish Safety Injection Flow To the RCS o Rapidly Depressurize SGs to Depressurize RCS o Start RCPs and Open All RCS Vent Paths to Containment FR-C.1 Background 7 HP-Rev. 2, 4/30/2005 HFRC1BG .doc
- 90. 077AA2. 10 090/NEW/SRO/C/A 3.6/3 .8/APEO77AA2. 1 0/N/3/VER2.0/MINOR ED Unit 1 isat 1OO% -
Several substations are separated from the grid resulting in the followings plant conditions:
- Unit 1 Generator Voltage is 20.45 kV.
- The following alarms have actuated:
WE2, IF 4KV BUS OV-OR-UV OR LOSS OF DC.
VE2, I G 4KV BUS OV-OR-UV OR LOSS OF DC.
- Grid frequency has fallen to 59.6 hertz and is stable.
- 41 60V Bus voltages are 3840 Volts.
- This condition has existed for the past hour.
Which one of the following completes the statements below?
The Generator temperatures will (1)
AOP-5.2, Degraded Grid, will require the crew to (2)
(1) (2)
A. RISE immediately enter AOP-17.0, Rapid Load Reduction B. LOWER immediately enter AOP-1 7.0, Rapid Load Reduction RISE place the unit in mode 3 in the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> using UOP-3.I, POWER OPERATION D. LOWER place the unit in mode 3 in the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> using UOP-3.I, POWER OPERATION
- 15. 077AA2. 10 090/NEW/SRO/C/A 3.6/3 .8/APEO77AA2. 10/N/3/VER2.0/MINOR ED Feedback -
The FNP HV switchyard is connected to the Grid at a location where there is limited generation, and a loss of various substations could result in either a loss of load OR a loss of supporting GENERATION (Supply).
Generator (and Bus) VOLTAGE and frequency display that an OVERLOAD condition has occurred (more load than generation capacity), this would result in HIGHER currents on the Main Generator windings, and VR thus resulting in Greater R losses (MORE HEAT generation). If the condition were to persist, the insulation 2
l within the Main Generator begins to break down resulting in a reduction in its RESISTANCE and eventual failure.
NAI & NB1, v17, provides the following direction:
NOTE: Per FNP-1-SOP-28.1, Turbine Generator Operation, the accumulated time operating between 58.5 Hz and 59.5 Hz should not exceed 60 minutes.
IF the frequency remains above 57 Hz and approaches the time band limits (see above note), THEN operator action is required to prevent turbine damage by removing the turbine from the grid.
HOWEVER, unlimited operation is allowed between 59.5 Hz and 60.5 Hz.
Both WE2 and VE2 will direct AOP-5.2 entry, and both are ENTRY CONDITIONS for AOP-5.2. (RO knowledge).
AOP-5.2, v14.0, step 3 will evaluate bus voltage.
IF >4200 V, (Alarm HI-volt stpt is 4220V) then the RNO actions of step 3.1 will direct starting reactive loads and log voltages every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, and do NO other actions until directed by ACC/PCC.
IF <3850V then logging voltage every 30 mins is required per step 3.2 RNO actions.
and aligning equipment for the most reliable conditions. IF the conditions persist for> 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, then step 11 will require a planned shutdown to be conducted within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
NAI & NB1. v17, provides the following NOTE:
Per FNP-1-SOP-28.1, Turbine Generator Operation, the accumulated time operating between 58.5 Hz and 59.5 Hz should not exceed 60 minutes.
IF the frequency remains above 57 Hz and approaches the time band limits (see above note), THEN operator action is required to prevent turbine damage by removing the turbine from the grid.
A. Incorrect 1) Temperatures will rise due to the high current conditions. See above.
- 2) Reducing Reactor power per AOP-1 7, would exasperate the Grid voltage condition; Reducing Turbine load would result in reducing Grid voltage further and potentially causing a Degraded Grid LOSP condition.
The potential damage to the Generator is NOT instantaneous and delaying or slowing the progression of the degraded grid would permit more time for ACC/PCC to correct the condition, before increasing the risk to the plant and/or the public by dropping a significant power supply
thus potentially causing an LOSP condition for FNP and a Blackout condition for thegrid. (SeeTS B3.3.5discussion).
Plausible: The low frequency condition may lead one to believe that the conditions are dire and that immediate action is required to protect the main generator. An immediate load reduction might be warranted for a HIGH voltage condition (although only by the direction of PCCIACC; not directed by AOP-5.2 for a high voltage condition). Also, if examinee properly assesses the temp impact, then one might believe a rapid load reduction is required to protect the Main Turbine from damage.
NOTE: immediately is part of answer choice A & B since AOP-17 could be required AFTER UOP-3.1 is initiated if a delay is encountered to comply with TS 3.3.5)
B. Incorrect 1) Temperatures would go up.
Plausible: This would be the correct temperature response and ACTION if 4160V bus voltages were >4220 Volts; caused by a loss of LOAD vs Generation. Under lower current flows from the generator and from the voltage regulator would reduce 1R losses.
2
- 2) See A.2 Plausible: The low voltage conditions on the 4160V bus would result in an increased current draw on each of the loads within the plant therefore, sustained operation with degraded voltage, one might believe that the downpower is necessary to protect the plant components if they had incorrectly assessed the temperature impact on the Main Generator.
C. Correct 1) See above discussion
- 2) See above procedure quotes/summary.
D.lncorrect 1) See B.1
- 2) See C.2 Plausible: This would be selected if one were to improperly asses the temperature impact, and properly recall the transition requirement within the procedure.
- 90. 077AA2. 10 O9OINEW/SRO/C/A 3.6/3 .8/APE077AA2. 1 0/N/3/VER2.0/MINOR ED KJA statement 077AA2.1O Generator Voltage and Electric Grid DisturbancesAbility to determine and interpret Generator overheating and the required actions as they apply to Generator Voltage and Electric Grid Disturbances.
Importance Rating: 3.6 3.8 Technical
Reference:
FNP-0-SOP-36.8, vi 5.0 ARP-2.1, v32.0 ARP-2.2, v30.0 ARP-1.13, v17.0 AOP-5.2, v14.0 References provided: NONE Learning Objective: EVALUATE plant conditions and DETERMINE if transition to another section of [...] AOP-5.2, Degraded Grid or to another procedure is required. (OPS-62521N02)
Question origin: NEW Basis for meeting K/A: Generator Voltage is degraded below operational limits of SOP-36.8, the candidate must interpret these indications and determine that the Main Generator is overloaded vs underloaded and a generator overheat condition will occur (SYSTEM/Fundamental knowledge=RO).
The candidate must also identify the procedure transition directed byAOP-5.i that requires normal shutdown using UOP-3.1 vs performing a Rapid Downpower using AOP-17O. (SRO procedure selection).
SRO justification: 10 CFR 55.43(b)(5)
Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations [10 CFR 55.43(b)(5)], involving BOTH:
- 1) assessing plant conditions and then
- 2) selecting a procedure or section of a procedure to mitigate, recover, or with which to proceed.
One area of SRO level knowledge is knowledge of content of the procedure vs. the procedures overall mitgative strategy or purpose.
AOP-5.1 has two different strategies; based on the conditions of the degraded grid (HI or LOW). To answer this correctly the candidate must have knowledge of:
the fundamental temperature response to an overload on
the Generator.
the transitions required NOTE: the reason for the transition is added only for the intent to maintain plausibility by matching PT 1 and PT 2 response options.
2011 NRC exam From the Clarification Guidance for SRO-only Questions Rev 1 dated 03/11/2010 flowchart for 10 CFR 55.43(b)(5):
Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations [10 CFR 55.43(b)(5)], involving BOTH:
- 1) assessing plant conditions and then
- 2) selecting a procedure or section of a procedure to mitigate, recover, or with which to proceed.
Using the flowchart, this question can:
Using the flowchart, this question can:
- NOT be answered solely by knowing systems knowledge, i.e., how the system works, flowpath, logic, component location. (PT I IS syslfund knowledge, but PT 2 requires procedural knowledge)
- NOT be answered solely by knowing immediate operator actions.
- NOT be answered solely by knowing entry conditions for AOPs or plant parameters that require direct entry to major EOPs.
- NOT be answered solely by knowing the purpose, overall sequence of events, or overall mitigative strategy of a procedure. (PT 2 provides the strategy that is to be implemented. IT is knowledge of HOW the strategy is accomplished via procedure selection that is needed instead.)
- CAN be answered with knowledge of ONE or MORE of the following:
Assessing plant conditions (normal, abnormal, or emergency) and then selecting a procedure or section of a procedure to mitigate, recover, or with which to proceed.
Knowledge of when to implement attachments and appendices, including how to coordinate these items with procedure steps. (Requires knowledge of the TIME requirements for the implementation of the transitions (using transition as equivalent to attachment and appendices of same procedure since AOP-5.2 will be conducted in parrallel to UOP-3.1).
Knowledge of diagnostic steps and decision points in the EOPs that involve transitions to event specific sub-procedures or emergency contingency procedures. (Where event specific in this case is the Shutdown guidance)
Knowledge of administrative procedures that specify hierarchy, implementation, and/or coordination of plant normal, abnormal, and emergency procedures. (The plant shutdown time requirements vs immediately are incorporated within the decision point.)
07/13/10 8:11:14 FNP-1-AOP52 DEGRADED GRJD. Version 14.0 B Symptoms or Entry Conditions This procedure is entered when a potential or actual degraded condition is indicated by any of the following:
- a. Notification from the Power Control Center that SES security tools will be unavailable for the greater than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> during normal system and weather conditions or greater than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> during abnormal conditions.
- b. Notification from the Power Control Center that the offsite grid is one contingency away from being degraded.
- c. Notification from the Power Control Center that the offsite grid has become degraded.
- d. EPB annunciator(s), 4KV Bus OV-OR-UV or Loss of DC, in alarm:
07/13/10 8:11:14 FNP-I-AOP-51 DEGRADED GRID Version 14.
Step Action/Expected Response Response Not Obtained II 1 Check Power Control Center (PCC IF PCC notification NOT issued, THEN proceed to Step 2.
1.1 Check notification type - 1.1 Proceed to Step 1.2 to evaluate additional SYSTEM SECURITY TOOLS WILL BE notification types.
UNAVAILABLE in effect for longer than allowable duration.
- 8 Hours under normal system and weather conditions OR
- 1 Hour under abnormal conditions 1.1.1 Obtain information from PCC and complete DATA SHEET 1, LOSS OF SYSTEM SECURITY TOOLS.
1.2 Check notification type OFFSITE GRID
- 1.2 Proceed to Step 1.3 to evaluate additional IS ONE CONTiNGENCY AWAY FROM notification types.
BEING DEGRADED in effect.
1.2.1 Obtain information from PCC and complete DATA SHEET 2, ONE CONTINGENCY AWAY FROM BEING DEGRADED 1.3 Check notification type OFFSITE GRID
- 1.3 Proceed to step 2.
IS DEGRADED in effect.
1.3.1 Obtain information from PCC and complete DATA SHEET 3, DEGRADED GRID.
Page Completed Page 3 of 7
07/13/10 8:11:14 -
FNP-L-AOP-S2 DEGRADED GRID Vrsion 14.0 Step Action/Expected Response Response Not Obtained 2 LCAI Ensure abnormal condition(s) logged in Reactor Operators Log.
- Any abnormal grid condition(s)
- Any abnormal 4160V Buses iF and IG voltage
- Any PCC notification type 4CAJ Check Status of 4160 V Buses iF (And 3.1 Check 4160 V Buses 1 F and 1 G voltages - 3.1 Perform the following:
LESS THAN 4200V.
3.1.1 Consider starting additional bus loads, such as RW Pumps, to assist in voltage control.
3.1.2 Contact Alabama Control Center for voltage control strategies.
3.1.3 Record iF and 1G 4160 V bus voltages every four hours on TABLE 1, iF and 1G 4160 V BUS VOLTAGE LOG.
3.1.4 IF a PCC notification has been issued, THEN proceed to step 4.
3.1.5 WHEN both 4160 V Busses iF and 1G voltage are less than 4200 V, THEN go to procedure and step in effect.
3.1.6 Returntostep2.
Step 3 continued on next page Page Completed Page 4 of 7
07/13/108:11:14 FNP-L-AOP-52 DEGRADED GRID - Vorsion 14O-Step Action/Expected Response Response Not Obtained II I 3.2 Check voltages NOT DEGRADED
- 3.2 Perform the following:
- 4160 V Buses iF and 1G voltages - 3.2.1 Record lF and 1G 4160 V bus voltage GREATER THAN 3850 V indication every half hour on TABLE 1, IF and IG 4160 V BUS VOLTAGE
DC annunciators CLEAR
- WE2forbuslF 3.2.2 RefertoTS3.3.5.
AND
- VE2 for bus 1G CAUTION: Diesel generators are in the most reliable condition when secured and aligned for auto start.
The intent of step 4 is to secure any diesel generators which are running and not required.
4 Verify All Emergency Diesel Generators -
ALIGNED FOR AUTO START using:
- FNP-0-SOP-38.0, DIESEL GENERATORS 5 [CA] Restore out of service major plant components placing priority on the following:
- Turbine Driven Auxiliary Feedwater Pump
- Motor Driven Auxiliary Feedwater Pumps
- Charging Pumps
- Service Water Pumps
- Component Cooling Water Pumps
- SSPS Page Completed Page 5 of 7
07/13/10 8:11:14 FNR-L-AOP-51 - DEGRADED GRID Version 14.0 Step Action/Expected Response Response Not Obtained 6 Suspend all work activities in the Low Voltage and High Voltage Switchyards.
7 Evaluate Effects On Non-Safety Related Plant Busses And Equipment
- Non-safety related 4160 V Busses
- Reactor Coolant Pumps
- Condenser Circulating Water Pumps
- Condensate Pumps 8 Consult Operations Manager To Evaluate Continued Plant Operation 9 Contact Alabama Control Center For Voltage Control Strategies NOTE: Step 10 is a continuing ation step.
10 LCA] Check Status of 4160 V Buses 1FAnd1G:
10.1 4160 V Buses iF and 1G voltages LESS- 10.1 Return to step 2.
THAN 4200 V 10.2 4160 V Buses iF and 1G voltages LESS- 10.2 Perform the following:
THAN 3850 V 10.2.1 IF no PCC notification exists, THEN go to procedure and step in effect.
10.2.2 Return to step 2.
Page Completed Page 6 of 7
07/13/10 8:11:14 FMP-1-AOP51 DEGRADED GRID Vern 14, Step Action/Expected Response Response Not Obtained 11 Evaluate need for plant shutdown (refer to TS 3.3.5, Action F.1):
11.1 Check reactor MODE 1 Q, 2 11.1 Proceed to Step 12.
11.2 Check duration of degraded voltage - 11.2 Return to Step 2.
GREATER THAN ONE HOUR 11.3 Initiate actions to place Reactor in MODE 3 within the next 6 Hours using:
- FNP-1-UOP-3.1, POWER OPERATION
- FNP-1-UOP-2.1, SHUTDOWN OF UNIT FROM MIMMUM LOAD TO HOT STANDBY 12 Evaluate need for plant cooldown (refer to TS 3.3.5, Action F.2):
12.1 Check Reactor MODE 3 OR 4
- 12.1 Return to Step 2.
12.1.1 Check duration of degraded voltage -
GREATER THAN 7 HOURS.
12.1.2 Initiate actions to place Reactor in MODE 5 within the next 30 Hours using:
- FNP-1-UOP-2.2, SHUTDOWN OF UNIT FROM HOT STANDBY TO COLD SHUTDOWN 13 Return To Step 2.
°-END
_Page Completed Page 7 of 7
10/08/10 10:01:18 FNP-0-ARP-2.1 LOCATION VE2 SETPOINT: From UV Relays 27-1, or 27-2; Variable below 2450V E2 From digital voltmeter: QSH1 1EPBVMR1G 1G, 4KV BUS LO 3850 V (10 sec. delay) OV-OR-UV OR HI 4220 V (10 sec. delay) LOSS OF DC ORIGIN: 1. Under Voltage Relays (27-1 and/or 27-2)
- 2. Aux. Relay (74)
- 3. Digital Voltmeter Relay Contact (LO-27V)
- 4. Digital Voltmeter Relay Contact (HI-59V)
PROBABLE CAUSE
- 1. Under voltage condition or degraded grid on 1G bus.
- 3. Voltmeter selector switch in Off position.
AUTOMATIC ACTION NOTE:
- I[ the alarm is due to a loss of DC, THEN underfrequency protection is lost.
- On bus undervoltage of < 2870 V, digital indication will be lost because indicators are powered from PTs.
IF undervoltage on 1 G bus, THEN B 1 G sequencer load shedding circuit will be energized and 1 B Diesel Generator starts.
OPERATOR ACTION
- 1. IF a reactor trip occurs, THEN refer to FNP-1-EEP-0, REACTOR TRIP OR SAFETY INJECTION.
- 2. Determine cause of the alarm.
- 3. IF undervoltage was cause, THEN refer to FNP-1-AOP-5, LOSS OF ELECTRICAL TRAIN A OR B.
- 4. IF loss of D.C. to protection relays was cause, THEN notify appropriate plant personnel to locate and correct the cause.
- 5. degraded grid voltage is indicated (grid voltage being either high or low), THEN refer to FNP-1-AOP-5.2, DEGRADED GRID.
Page 1 of 2 Version 32.0
10/08/10 10:01:18 FNP-0-ARP-2.1 LOCATION VE2 OPERATOR ACTION (CONT.)
- 6. Return electrical and component lineups to normal as soon as possible.
- 7. IF the alarm is determined to be inoperable, THEN refer to LCO 3.3.5 Condition D.
- 8. IF the alarm is due to an actual undervoltage condition, THEN refer to LCO 3.3.5 Condition E.
References:
D-177163; D-177212; PCN S91-1 -7598; REA 95-1022 Page 2 of 2 Version 32.0
10/08/10 10:01:20 FNP-0-ARP-2.2
- LOCATION WE2 SETPOINT: From UV Relays 27-1 or 27-2; Variable below 2450V E2 I From digital voltmeter: QSH1 1EPBVMR1F iF, 4KV BUS LO 3850 V (10 sec. delay) OV-OR-TJV OR HI 4220 V (10 sec. delay) LOSS OF DC ORIGIN: 1. Under Voltage Relays (27-1 and/or 27-2)
- 2. Aux. Relay (74)
- 3. Digital Voltmeter Relay Contact (LO-27V)
- 4. Digital Voltmeter Relay Contact (HI-59V)
PROBABLE CAUSE
- 1. Under voltage condition or degraded grid on bus iF.
- 3. Over voltage condition.
- 4. Voltmeter selector switch in Off position.
AUTOMATIC ACTION NOTE:
- IF the alarm is due to a loss of DC, THEN underfrequency protection is lost.
I
- On bus undervoltage of< 2870 V, digital indication will be lost because indicators are powered from PTs.
- 1. under voltage on bus iF, THEN B1F sequencer load shedding circuit will be energized and i-2A and 1C Diesel Generators starts.
OPERATOR ACTION
- 1. IF a Reactor Trip occurs, THEN refer to FNP-i -EEP-0, REACTOR TRIP OR SAFETY INJECTION.
- 2. Determine cause of alarm.
- 3. IF under voltage was cause, THEN refer to FNP-1-AOP-5.0, LOSS OF A OR B TRAIN ELECTRICAL POWER.
- 4. IF loss of DC to protection relays was cause, THEN notify appropriate plant personnel to locate and correct the cause.
- 5. degraded grid voltage is indicated (grid voltage being either high or low), THEN refer to FNP-1-AOP-5.2, DEGRADED GRID.
- 6. Return electrical and component lineups to normal as soon as possible.
LOCATION WE2 Page 1 of 2 Version 30.0
10/08/10 10:01:20 FNP-0-ARP-2.2 OPERATOR ACTION contd
- 7. IF the alarm is determined to be inoperable, THEN refer to LCO 3.3.5 Condition D.
- 8. IF the alarm is due to an actual undervoltage condition, THEN refer to LCO 3.3.5 Condition E.
References:
D-177157; D-177218, Sh. 2; PCN S91-l -7598; REA 95-1022 Page 2 of 2 Version 30.0
4.7.3 To secure the 1A AHU (GE), perform the following:
- Set the system switch to OFF. D
- Set the fan switch to AUTO. D 4.7.4 To secure the TRANE AHU, perform the following:
- Press the left button until the system indicates OFF. (blinking is what is selected)
- Press the right button (Done).
4.8 Voltage Management Strategy Guidance NOTE This section provides the guidance, and communicates a common understanding concerning the voltage schedules, shunt reactor operations, capacitor bank operations, and the transmission system capabilities concerning voltage management. Maintaining the proper voltage schedule is important to ensure stability for the Farley units under certain fault conditions.
4.8.1 General Guidelines 4.8.1.1 The reference voltage indications approved by the Alabama Control Center (ACC) to maintain the 230kV and 500kV Voltage Schedules are listed below. They are monitored in the switch house using a web camera.
- 230kV-No. 2 230kV Voltmeter
- 500kV-Unit 2 Voltmeter 4.8.1.2 The 230Kv and 500kV Voltage Schedules should be observed at all times by the plant operators when the units are tied to the grid unless otherwise directed by the ACC System Operator. At Farley we will attempt to maintain +1- 1 .0 kV.
4.8.1.3 The allowable, undirected deviation from the voltage schedule should not exceed:
- +1- 2.0 kV for the 230kV busses
- +1- 3.0 kV for the 500kV busses
4.8.1.4 If Farley cannot maintain the Voltage Schedule within the allowable, undirected deviation in item 4.8.1.3 above, then a relief from the voltage schedule will be requested from the ACC System Operator.
- If a relief is granted, then the ACC System Operator will provide the FNP Plant Operator a maximum deviation value from the Voltage Schedule. The relief granted will be logged in Auto Log. The Auto Log entry will include the name of the ACC System Operator granting the relief, and the maximum deviation limit provided.
- If a relief is not granted, then the Generator Operator will make an Auto Log entry, and write a condition report (CR).
This is required by the NERC standards.
4.8.1.5 When either unit is off line, then request a blanket relief for the duration of the outage to exempt Farley from maintaining the 500kV schedule. The 500kV voltage will float as it did for many years before we started maintaining both schedules. The 230kV voltage schedule will be maintained to ensure we meet the Power Quality Guide, and FSAR voltages for the ESF components. Ensure an Auto Log entry is made similar to the following: During the Unit 1/2 refueling/forced outage, voltage will not be able to be raised I lowered to meet the APC 500kV voltage schedule. Relief granted by ACC (System Operator name).
4.8.1.6 Unit capability curves should be adhered to when attempting to maintain bus voltage schedule.
4.8.1.7 Station service voltage limits should be observed when attempting to maintain bus voltage.
4.8.1.8 The Voltage is subject to change at the request of the ACC System Operator. ACC System Operator requests shall be met in a timely manner. Any emergency request shall be met as soon as possible.
4.8.1.9 The System Operator would like to minimize switching the shunt reactor in/out of service as much as possible. With one Unit off for refueling, placing the shunt in service, and leaving it in service, appears to be successful in allowing Farley to maintain the Voltage Schedule within the NERC allowable, undirected deviation. This also keeps the shunt reactor switching to a minimum.
4.8.1.10 The ACC System Operator does not want to deviate too far from the scheduled voltage because a single contingency could put Farley in a situation for high I low on-site voltages, and possible damage to equipment.
TSHARED
[Q/&2Q1fl I Farley Nuclear Plant A Procedure Number Ver FNP-0-SOP-36.8 PagNumbe 15.0 I
I I
j 10:12:29 -
HIGH VOLTAGE SWITCHYARDACTIVrnES 30 of 36 I 4.8.1.11 The ACC System Operator is allowed some discretion for short durations from the allowable, undirected deviation from the Voltage Schedule.
4.8.2 Guidelines to Raise and Lower System Voltage. The Farley Operators shall adjust the main generator reactive load voltage to meet the system requirements as directed by the System Operator, while observing the following guidelines.
4.8.2.1 The reactive load adjustments cannot exceed 22kV +1- 5%
(20.9-23.1 kV).
4.8.2.2 The Farley administrative limit is -300 MVARs to prevent the auto adjuster from going to its mechanical stop.
4.8.2.3 The 230kV Shunt Reactor is placed in service when the 230kV bus voltage needs to be lowered, and the 230kV Capacitor Bank is placed in service when the 230kV bus voltage needs to be raised. Because the two devices perform opposite functions, they never should be in service at the same time, and an interlock scheme is provided on switches 955 and 957 to prevent this from happening.
4.8.2.4 The Capacitor Bank will automatically switch on when bus voltage drops to 234kV (5 second time delay), and automatically switch off when bus voltage exceeds 240kV (20 second time delay).
4.8.2.5 The ACC will switch the shunt reactor in service when system load is < 16,000 MW, and it is expected to remain at that load for
>4 hours.
4.8.2.6 When the system load goes above 16,000 MW, and is increasing, then the ACC will switch the shunt reactor out of service.
4.8.2.7 Placing the Capacitor Bank in service raises the bus voltage 2kV.
4.8.2.8 Placing the Shunt Reactor in service lowers the bus voltage 3kV.
10/08/10 10:20:03 FNP-1-ARP-l.13 LOCATION NA1 SETPOINT: 59.5 HZ Al I UF ORIGIN: Underfrequency Relay SFF2O4B 1 A BELOW 59.5 HZ PROBABLE CAUSE
- 1. Unplanned circuit breaker operation or failure in high voltage switchyard.
- 2. System voltage fluctuation.
- 3. Transformer failure.
- 4. Transmission System disturbance OR abnormal operation resulting in the load demand exceeding the generating capability.
NOTE:
- Per FNP-1-SOP-28.1, Turbine Generator Operation, unlimited operation is allowed between 59.5 Hz and 60.5 Hz. The accumulated time operating between 58.5 Hz and 59.5 Hz should not exceed 60 minutes and the accumulated time operating between 56 Hz and 58.5 Hz should not exceed 10 minutes. The unit should not be operated at less than 56 Hz OR greater than 60.5 Hz. For operation at exactly 59.5 Hz OR 58.5 Hz, the more restrictive time limit of 60 minutes and 10 minutes, respectively, should be applied.
- The 2 out of 3 RCP IJF protection scheme will cause a reactor trip and consequently a turbine trip at 57 Hz.
- A System underfrequency load shedding program is in place to prevent the system turbine generators from exceeding the allowable time limits at underfrequency conditions. Should a severe overload/underfrequency condition occur on the Southern grid, some or all of the other major units on the system may automatically trip due to operation of their turbine UF relays. For this condition, the frequency at FNP will very likely drop below 57 Hz and the FNP units will trip due to operation of the RCP UF relays. Should the frequency remain above 57 Hz AND approach the time band limits, THEN operator action is required to prevent turbine damage.
AUTOMATIC ACTION With the generator on line and the speed loop in service, the DEH frequency compensation circuitry will automatically adjust governor valve position if turbine speed differs from 1800 rpm more than 8 rpm (i.e., < 1792 rpm or
> 1808 rpm). This is equivalent to a generator frequency of< 59.73 hz or
> 60.27 hz.
Page 1 of 2 Version 17.0
10/08/10 10:20:03 FNP-1-ARP-4.13 LOCATION NA1 OPERATOR ACTION
- 1. Note and record the frequency AND monitor the time duration of the underfrequency condition for each underfrequency band less than Q, equal to 59.5 Hz as described in the previous note.
- 2. Contact the Alabama Control Center to request information and grid frequency control assistance. Refer to FNP- 1 -UOP-3.1, Appendix 7 Q.
FNP-1-UOP-1 .2, Appendix 8 if a complete loss of communications between Farley Nuclear Plant, and the Power Coordination Center (PCC) and the Alabama Control Center (ACC) for the Southern Control Area has occurred. (Al 2009207415)
- 3. Verify that an actual UF condition exists by noting turbine speed and generator frequency. IF both units are on line, THEN both should receive the same indications of an UF condition.
- 4. IF the frequency remains above 57 Hz AND approaches the time band limits, THEN operator action is required to prevent turbine damage by removing the turbine from the grid.
- 5. Determine the cause of the underfrequency condition and attempt to restore operation at 60 Hz.
References:
A-177100, Sh. 596; D-172845; D-172722, Sh. 1 & 2; D-173408; D-172732; D-172842; D-172784, Sb. 4; U-185049; DCP 00-0-9560, REA 97-1359 Page 2 of 2 Version 17.0
10/08/10 10:20:03 FNP- 1 -ARP- 1.13
- LOCATION NBI SETPOTNT: 59.5 HZ Bli UF ORIGiN: Underfrequency Relay Annun. Timer UFT1 BELOW 59.5 HZ FOR 50 MINUTES PROBABLE CAUSE
- 1. Unplanned circuit breaker operation or failure in the high voltage switchyard.
- 2. System frequency fluctuation.
- 3. Transformer failure.
- 4. Transmission System disturbance OR abnormal operation resulting in the load demand exceeding the generating capacity.
NOTE: Per FNP-1-SOP-28.1, Turbine Generator Operation, the accumulated time operating between 58.5 Hz and 59.5 Hz should not exceed 60 minutes. I AUTOMATIC ACTION With the generator on line and the speed loop in service, the DEH frequency compensation circuitry will automatically adjust governor valve position if turbine speed differs from 1800 rpm more than 8 rpm (i.e., < 1792 rpm or
> 1808 rpm). This is equivalent to a generator frequency of< 59.73 Hz or
> 60.27 Hz.
OPERATOR ACTION
- 1. Verify that an actual UF condition exists by noting turbine speed and generator frequency. IF both units are on line, THEN both should receive the same indications of an UF condition.
- 2. Contact the Alabama Control Center to request information and grid Due to the frequency control assistance. Refer to FNP- 1 -UOP-3.1, Appendix 7 Q, ambiguious nature FNP- 1 -UOP- 1.2, Appendix 8 if a complete loss of communications of REMOVE the between Farley Nuclear Plant, and the Power Coordination Center (PCC) and the Alabama Control Center (ACC) for the Southern Control Area has turbine from the occurred. (Al 2009207415) grid (which could permit AOP-17, E-0 3. IF the frequency remains above 57 Hz and approaches the time band or UOP-3.1) limits (see above note), THEN operator action is required to prevent frequency is held turbine damage by removing the turbine from the grid.
above setpoint. 4. Determine the cause of the underfrequency condition and attempt to restore operation at 60 Hz.
-177100, Sh. 601; D-172845; D-172722, Sh. 1 & 2; D-173408; D-172732;
-172842; D-172784, Sh. 4; U-185049; DCP 00-0-9560, REA 97-1359 Page 1 of 1 Version 17.0
LOP DG Start Instrumentation 3.3 INSTRUMENTATION 3.3.5 Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation LCO 3.3.5 The LOP instrumentation for each Function in Table 3.3.5-1 shall be OPERABLE.
APPLICABILITY: According to Table 3.3.5-1.
ACTIONS Separate Condition entry is allowed for each Function.
CONDITION REQUIRED ACTION COMPLETION TIME A. NOTE A.1 NOTE Only applicable to The inoperable channel Functions 1 and 2. may be bypassed for up 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for surveillance
. testing of other channels.
One or more functions with one channel per train inoperable.
Place channel in trip. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> B. NOTE B.1 Restore all but one 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Only applicable to channel per train to Functions 1 and 2. OPERABLE status.
One or more Functions with two or more channels per train inoperable.
C. Required Action and C.1 Enter applicable Immediately associated Completion Condition(s) and Required Time of Condition A or Action(s) for the B not met. associated DG made inoperable by LOP DG start instrumentation.
Farley Units 1 and 2 3.3.5-1 Amendment No. 146 (Unit 1)
Amendment No. 137 (Unit 2)
- _$ I I....I JSA* I .4I%.* _?I_I _flI I II% *%I..IISJ rnbiguous, TS basis and application cannot be used to address this KA. ----fix go to AOP-5.2 transitions.
QuLD_rgue (successfully?) that the TS 3.84 ConditionCis onjy appl1c?Pl, since the alarm featr i Dt me?.--- BASIS suggests that this is the correct response; and AOP-5.2 step 11 follows that guide.
L .j POST exam follow-up document to address this ambiguity in TS and ask licensing if Condition E ording should include OR voltage <3850V D. NOTE D.1 Verify voltage on Once per 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Only applicable to associated bus is 3850 Function 3. volts.
One Alarm Function channel inoperable on one or more trains.
E. Required Action and E.1 Restore bus voltage to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> associated Completion 3850 volts.
Time of Condition D not met.
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 of Condition E AND not met.
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 /> SURVEILLANCE_REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.5.1 NOTES
- 1. TADOT shall exclude actuation of the final trip actuation relay for LOP Functions 1 and 2.
- 2. Setpoint verification not required.
Perform TADOT. 31 days Farley Units 1 and 2 3.3.5-2 Amendment No. 146 (Unit 1)
Amendment No. 137 (Unit 2)
LOP DG Start Instrumentation B 3.3 INSTRUMENTATION B 3.3.5 Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation BASES BACKGROUND Successful operation of the required safety functions of the Engineered Safety Features (ESF) systems is dependent upon the availability of adequate power sources for energizing the various components such as pump motors, motor operated valves, and the associated control components. Offsite power is the preferred source of power for the 4.16 kV emergency buses which power the required ESF components. The LOP protection instrumentation monitors voltage on the F and G 4.16 kV buses. Each electrical train has independent LOP instrumentation and relay actuation logic for detecting degraded grid or loss of voltage conditions, and initiating an LOP emergency diesel generator (EDG) start signal. There are three LOP protection instrumentation actuation levels.
The first level of protection consists of a single independent channel providing a degraded grid voltage alarm. This alarm is set at 3850V. This setpoint is based on detection of a degrading voltage condition where the bus voltage is below the minimum expected based on studies of the expected operation of the offsite power system. The alarm has a time delay to reduce the possibility of nuisance alarms for expected voltage transients.
The second level is set at 3675V. This level generates an LOP signal for sustained degraded grid voltage conditions. The inverse time setting prevents an unnecessary LOP by ensuring the existence of a sustained voltage inadequacy before actuation.
The third level is set at 3255V. This level generates an LOP signal for near instantaneous loss of voltage conditions. The inverse time setting provides quick detection of a significant voltage inadequacy while preventing an unnecessary LOP for momentary power system disturbances.
The second and third levels provide LOP actuation signals. Each level consists of three undervoltage relays (i.e., channels) with inverse time characteristics arranged in a two-out-of-three logic.
Actuation of either protection level will automatically disconnect the 4.16 kV emergency buses from the offsite power source. The loss of voltage sensors start the EDGs, and following the bus load shed, the Emergency Sequencer automatically reloads the bus.
(continued)
Farley Units 1 and 2 B 3.3.5-1 Revision 42
LOP DG Start instrumentation 8.3.15 BASES BACKGROUND The LOP instrumentation is also discussed in FSAR, Section 8.3 (continued) (Ref.1).
Alarm/Trir Setpoints and Allowable Values The actual nominal Alarm/Trip Setpoint entered into the device is normally still more conservative than that required by the Allowable Value. If the measured setpoint does not exceed the Allowable Value, the relay is considered OPERABLE.
Setpoints adjusted in accordance with the Allowable Value ensure that the consequences of accidents will be acceptable, providing the unit is operated from within the LCOs at the onset of the accident and that the equipment functions as designed.
Allowable Values and/or Alarm/Trip Setpoints are specified for each Function in the LCO. Nominal Alarm or Trip Setpoints are also specified in the unit specific setpoint calculations. The nominal setpoints are selected to ensure that the setpoint measured by the surveillance procedure does not exceed the Allowable Value if the device is performing as required. If the measured setpoint does not exceed the Allowable Value, the device is considered OPERABLE.
Operation with an Alarm or Trip Setpoint less conservative than the nominal value, but within the Allowable Value, is acceptable provided that operation and testing is consistent with the assumptions of the unit specific setpoint calculation.
Each Allowable Value and/or Alarm/Trip Setpoint specified is more conservative than the analytical limit specified in the voltage analyses to account for instrument uncertainties appropriate to the trip function.
These uncertainties are defined in the unit specific setpoint calculation (Ref. 3).
APPLICABLE The LOP DG start instrumentation is required for the ESF Systems to SAFETY ANALYSES function in any accident with a loss of offsite power. Its design basis is that of the ESF Actuation System (ESFAS).
Safety analyses credit the loading of the DG based on concurrent loss of offsite power and a loss of coolant accident (LOCA). The (continued)
Farley Units 1 and 2 B 3.3.5-2 Revision 42
- ft13.5 BASES APPLICABLE actual DG start has historically been associated with the ESFAS SAFETY ANALYSES actuation. The DG loading is included in the delay time associated (continued) with each safety system component requiring DG supplied power following a loss of offsite power.
Monitoring by the offsite power system grid operators and the first level LOP instrumentation (alarm) provide the primary protection for a degraded grid event. The degraded grid voltage alarm provides notification to control room operators that an abnormally low voltage condition exists on a 4.16 kV emergency bus. For slow acting transient conditions, the alarm setpoint allows for the initiation of manual actions by the offsite power system operator to restore normal bus voltage and protect required ESF LOCA loads from the low voltage condition without initiating an unnecessary automatic disconnect from the preferred offsite power source.
An administrative limit is established at a voltage level between the degraded grid voltage alarm allowable value (3835V) and the automatic degraded grid voltage actuation upper allowable value (3749V). Calculations verify that no ESF components require a 4.16kV bus voltage higher than the administrative limit to perform their safety functions. In the voltage range between the administrative limit and the degraded grid voltage actuation trip setpoint, a few ESF components may not have automatic protection from inadequate voltage. The manual actions provide the primary means of protecting these few ESF components from a sustained, slightly low voltage condition and all components from unnecessary automatic disconnection from the preferred offsite power source.
The required channels of LOP DG start instrumentation, in conjunction with the ESF systems powered from the DGs, provide unit protection in the event of any of the analyzed accidents discussed in FSAR, Section 15 (Ref. 2), in which a loss of offsite power is assumed.
The delay times assumed in the safety analysis for the ESF equipment bound the 12 second DG start delay and include the appropriate sequencing delay, if applicable. The response times for ESFAS actuated equipment in LCO 3.3.2, Engineered Safety Feature Actuation System (ESFAS) Instrumentation, include the appropriate DG loading and sequencing delay.
The LOP DG start instrumentation channels satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).
Farley Units 1 and 2 B 3.3.5-3 Revision 42
LOP DG Start Instrumentation B3.15 BASES LCO The LCO for LOP DG start instrumentation requires that three channels per train of both the loss of voltage and degraded grid voltage actuation Functions shall be OPERABLE in MODES 1, 2, 3, and 4 when the LOP DG start instrumentation supports safety systems associated with the ESFAS. In MODES 5 and 6, the three channels must be OPERABLE whenever the associated DG is required to be OPERABLE to ensure that the automatic start of the DG is available when needed. Loss of the LOP DG Start Instrumentation Function could result in the delay of safety systems initiation when required. This could lead to unacceptable consequences during accidents. During the loss of offsite power the DG powers the motor driven auxiliary feedwater pumps. Failure of these pumps to start would leave only one turbine driven pump, as well as an increased potential for a loss of decay heat removal through the secondary system.
In addition, the LCO requires one channel of the degraded grid alarm function per train of 4.16 kV emergency buses to be OPERABLE in MODES 1, 2, 3, and 4. The required alarm channels include the Digital Voltmeter Relay Contacts (LO-27V) on buses F and G and the associated alarm annunciators WE2, VE2 (Unit 1) and YE2, ZE2 (Unit 2). The alarm channels provide assurance that manual actions are taken to restore bus voltage and protect the required ESF LOCA loads from a degraded grid voltage condition.
APPLICABILITY The LOP DG Start Instrumentation Functions are required in MODES 1, 2, 3, and 4 because ESF Functions are designed to provide protection in these MODES. Actuation in MODE 5 or 6 is required whenever the required DG must be OPERABLE so that it can perform its function on an LOP or degraded power to the vital bus.
The degraded grid alarm function is required OPERABLE in MODES 1, 2, 3, and 4 to support the voltage requirements of the ESF loads required OPERABLE to mitigate a design basis LOCA. In MODES 5 and 6, the degraded grid alarm function is not required OPERABLE as no design basis LOCA is assumed to occur in these MODES and most of the ESF loads required to mitigate a design basis LOCA are not required OPERABLE.
Farley Units I and 2 B 3.3.5-4 Revision 42
LOP DG Start Instrumentation BASES ACTIONS In the event a channels Alarm or Trip Setpoint is found nonconservative with respect to the Allowable Value, or the channel is found inoperable, then the function that channel provides must be declared inoperable and the LCO Condition entered for the particular protection function affected.
Because the required channels are specified on a per train basis, the Condition may be entered separately for each train as appropriate.
A Note has been added in the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed in the LCO. The Completion Time(s) of the inoperable channel(s) of a Function will be tracked separately for each Function starting from the time the Condition was entered for that Function.
A.1 Condition A applies to the LOP DG start Functions (Functions 1 and
- 2) with one loss of voltage or degraded grid voltage channel per train inoperable.
If one channel is inoperable, Required Action A.1 requires that channel to be placed in trip within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. With a channel in trip, the remaining LOP DG start instrumentation channels will provide a oneout-of-two logic to initiate a trip of the incoming offsite power.
A Note is added to Condition A indicating that it is only applicable to Functions I and 2.
A Note is added to allow bypassing an inoperable channel for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for surveillance testing of other channels. This allowance is made where bypassing the channel does not cause an actuation and where at least two other channels are monitoring that parameter.
The specified Completion Time and time allowed for bypassing one channel are reasonable considering the Function remains fully OPERABLE on each train and the low probability of an event occurring during these intervals.
B.1 Condition B applies to LOP Functions 1 and 2 when two or more loss of voltage or degraded voltage channels on a single train are inoperable.
(continued)
Farley Units 1 and 2 B 3.3.5-5 Revision 42
LOP DG Start Instrumentation B3.35 BASES ACTIONS B.1 (continued)
A Note is added to Condition B indicating that it is only applicable to Functions I and 2.
Required Action B.1 requires restoring all but one channel on a train to OPERABLE status. With a single inoperable channel remaining on a train, Condition A is applicable. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time should allow ample time to repair most failures and takes into account the low probability of an event requiring an LOP start occurring during this interval.
C.1 Condition C applies to each of the LOP DG start Functions when the Required Action and associated Completion Time for Condition A or B are not met.
In these circumstances the Conditions specified in LCO 3.8.1, AC Sources Operating, or LCO 3.8.2, AC Sources Shutdown, for the DG made inoperable by failure of the LOP DG start instrumentation are required to be entered immediately. The actions of those LCOs provide for adequate compensatory actions to assure unit safety.
D.I Condition D applies when the required degraded grid voltage alarm function is inoperable on one or both trains of emergency buses. The affected bus voltage associated with each inoperable alarm function must be verified 3850 volts every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. Frequent bus voltage verifications in lieu of an OPERABLE alarm effectively accomplish the same function as the alarm and allow operation to continue without the required alarm(s). A Note is added to Condition D indicating that it is only applicable to Function 3.
E.1 Condition E is applicable when the Required Action and associated Completion Time of Condition D is not met. If the voltage being verified per Required Action D.1 is <3850 volts, action must be taken to restore the voltage to 3850 volts within one hour. The Completion Time of one hour is reasonable to ensure prompt action is taken to restore adequate voltage to the affected emergency bus(es).
(continued)
Farley Units 1 and 2 B 3.3.5-6 Revision 0
LOP DG Start Instrumentation B 3.3.5 BASES ACTIONS F.1 and F.2 (continued)
Condition F becomes applicable when the Required Action and associated Completion Time of Condition E is not met. If the emergency bus voltage cannot be restored to 3850 volts within the Completion Time of Condition E, action must be taken to place the unit in a MODE where the LCO requirement for the Alarm function is not applicable. To achieve this status, the unit must be brought to MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and 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 3.3.5.1 REQUIREMENTS SR 3.3.5.1 is the performance of a TADOT. This test is performed every 31 days. The test checks trip devices that provide actuation signals directly, bypassing the analog process control equipment.
The TADOT surveillance is modified by two Notes. The first Note excludes the actuation of the final trip actuation relay for LOP Functions I and 2 from this TADOT. The actuation of this relay would cause the DG start and separation of the emergency buses from the grid. The actual DG start and connection to the emergency bus is verified by other surveillance testing (SR 3.3.5.3) accomplished during shutdown conditions. The second Note provides an exception to the verification of the LOP function setpoints during performance of this monthly TADOT. The TADOT includes verification of the undervoltage device operation upon removal of the input voltage and does not require the setpoint be verified or adjusted. The LOP function setpoints are verified during the 18 month CHANNEL CALIBRATION. In addition, the TADOT includes verification of the operation of the two-out-of-three logic associated with LOP Functions 1 and 2. The Frequency is based on the known reliability of the relays and controls and the multichannel redundancy available, and has been shown to be acceptable through operating experience.
SR 3.3.5.2 SR 3.3.5.2 is the performance of a CHANNEL CALIBRATION.
The setpoints, as well as the response to a loss of voltage and a degraded grid voltage test, shall include a single point verification that I (continued)
Farley Units I and 2 B 3.3.5-7 Revision 42
- 91. 078A2.0 1 09 1/MOD/SRO/C/A 2.4/2.9/078A2.0 1//3/VER 3.0/REPLACEMENT tJnit.1 is at 100%. Thefoflowing ccndWons exist
- The 1 B Air Dryer is isolated.
- The 1A Air Dryer after filters clog.
- LCV-459, LTDN LINE ISO, RED and GREEN lights are both LIT.
- All Feed Reg Valves are showing intermediate with 100% demand on the controllers.
The Crew implemented EEP-0.O, Reactor Trip or Safety Injection, with the following results:
- Reactor Trip Breakers could not be opened and remain closed.
- BOTH MG set supply breakers were opened.
- ESP-0.1, Reactor Trip Response, has been entered.
Which one of the following completes the statements below?
V902, AIR DRYER AUTO BYP, will open at (1)
The Critical Safety Function Restoration procedure whose entry conditions will be met FIRST if NO further actions are taken in accordance with CSF-0.0, Critical Safety Function Status Trees, is (2)
(1) (2)
A. 55 psig FRP-H.5, Response to Steam Generator Low Level B. 55 psig FRP-I.1, Reponse to High Pressurizer Level C. 70 psig FRP-H.5, Response to Steam Generator Low Level D 70 psig FRP-l.1, Reponse to High Pressurizer Level
- 16. 078A2.0 1 091/MOD/SRO/C/A 2.4/2.9/078A2.0 1//3IVER 3.0/REPLACEMENT Feedback - - --- -
Auto setpoints:
SERVICE AIR ISOLATES AT 80 PSIG FALLING INST AIR DRYERS ARE BYPASSED AT 70 PSIG FALLING INST AIR TO SERVICE BLDG ISOLATES AT 55 PSIG FALLING INST AIR TO TURBINE BLDG ISOLATES AT 45 PSIG FALLING SEQUENCE OF EVENTS for a Loss of air event:
- 1) As IA header pressure drops to 80 psig, the expected KD3, SA PRESS LO, will NOT alarm, this pressure switch is located upstream of the Air Dryers. And under this condition, the UPSTREAM Air pressure is normal. As such, the automatic SA isolation will not occur, V901, will remain OPEN due to the same issue regarding PS location, and failure mechanism.
HOWEVER, KDI will alarm. KDI warns the operator that as air pressure drops to <85 psig, Letdown isolation valves will drift close and the orifice isolation valves will close on interlock.
EVENT #1: LETDOWN ISOLATES
- 2) IA pressure will continue to lower to 75 psig, KD3, IA PRESS LO, will alarm. This again alerts the operator that Letdown would isolate.
- 3) AT 70 psig, V902 will OPEN and bypass the dryers this function will restore IA system to normal operating pressure.
The RX is tripped in accordance with AOP-6.0 step 1 when Critical valve control becomes erratic.
Following the Trip, as long as IA is available, then the STM dumps will operate to maintain Tavg at 547°F(if P-4 is met) or at 551°F (DUE TO C-7A). IF IA is not available, then Temp will rise to 554F and be maintained by the SG Safety valves. WHEN/IF Air pressure is restored, the components would operate as expected with no operator action.
Because the Rx Trip Breakers remain closed, P-4 will not result in FRV closure when RCS Tavg falls to 554°F; The steam Generators will continue to be fed.
OTHER impacts on FW: when IA pressure falls, the FRVs have a potential of Closing due to spring pressure overcoming the available air pressure, this would isolate Feedwater to the SGs from the still running SGFPs, and COULD result in SGWL falling. When Air pressure is restored, the FRVs would function as long as a P-14 signal were not present (in such a case both SGFPs would trip and start AFW), thereby restoring Feedwater prior to a LOW level condition; This loss and recovery of IA pressure however, would offer a potential for P-14 on the recovery of air, which would in turn Cause an AFW actuation, which would then align AFW at full flow. Thereby again preventing a LOW SG water inventory problem.
FCV-122 and HCV-186, without AIR fail open, and with AIR restored would deliver flow to the RCS at NO LESS than 35 (20 gpm charging and 16 gpm seal inj) gpm in automatic. This in conjunction with the isolation of LETDOWN which is expected to occur, would result in PZR level continuously rising. (92-24)% PRZR LVL x 50 GaII% + 35 GPM = 97 mins
[nformaflon pro 4ded:
1 - -
LETDOWN isolating MUST be provided to confirm that LETDOWN has in fact isolated.
FRV status is provided to justify Why a RX trip was initiated (STEP 1 of AOP-6)
A. Incorrect 1) This is the setpoint for SA to be isolated to the Service Building.
- 2) This procedure would be entered if All SG NR levels were to fall to <
31%.This condition is unlikely to occur since the SGFPs would remain running until either P-14 (HIGH water level due to slow response of FRV5) or LOW Stm line pressure SI/MSLIS causes them to trip at which time AFW would auto actuate to provide full AFW flow to all SG, further preventing a low water level condition. The FRV operation would be restored as IA pressure is restored.
Plausible: The FRVs are shown to be impacted by the reducing Air pressure, One might believe thta the FRVS would not restore to NORMAL operation, and remain shut, in which the SG levels would fall, until the Auto-start of the AFW pumps occur at 28% NR level which is below the entry conditions for this procedure.
B. Incorrect 1) See A.1
- 2) See D.2 Plausible: This choice is plausible if the examinee were able to identify the correct procedure but not the correct setpoint.
C. Incorrect 1) See D.1
- 2) See A.2 Plausible: This answer choice would be selected if the consequence were not properly understood but knowledge of the setpoint is correct.
D. Correct 1) This is the correct setpoint for V902 to auto open, and bypass the IA dryer.
This action would restore air flow to the down stream IA header and recover pressure to normal.
- 2) A loss of Air causes Letdown to isolate, and FCV-1 22 to fail OPEN, resulting in a rise in PZR level. When PZR level exceeds 92%, and RVLIS> 100% upper plenum, FRP-l.1 entry conditions would be met. This is the FIRST of the listed FRPs that would be encountered for the conditions provided. Even after Air is restored, letdown remains isolated and CHG flow would continue to flow at a minimum of 20 GPM. Albeit slow, the PZR level would rise to 92% before SG NR level were to fall.
- 16. 078A2.0 1 09 1/MOD/SRO/C/A 2.4/2.91078A2.0 I//3/VER 3.0/REPLACEMENT Notes K/A statement 078A2.O1 Instrument Air System (lAS)
Ability to (a) predict the impacts of Air dryer and filter malfunctions on the lAS; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those malfunctions or operations:
Importance Rating: 2.4 2.9 Technical
Reference:
AOP-6.0, v37.0 References provided: NONE Learning Objective: ASSESS the facility conditions associated with the Compressed Air System components, and based on that assessment, SELECT the appropriate procedure(s) for normal situations. (OPS-62108A01) 10CFR55.43 (b) 5 Question origin: MODIFIED BANK (WATTS BARR Aug 2010; 065G.2.4.21)
Basis for meeting K/A: a) Air dryer malfunction is stated in the stem, and a prediction of the dryers bypass valve automatic operation is tested. --RO LEVEL system setpoint knowledge b) Procedure selection and predicting impacts: The examinee must anticipate the Charging System and Feed system response following the restoration of IA following the automatic operation of V902 by evaluating the FRP entry conditions that would first be entered.
SRO justification: 10 CFR 55.43(b)(5)
Assessing plant conditions (normal, abnormal, or emergency) and then selecting a procedure or section of a procedure to mitigate, recover, or with which to proceed.
2011 NRC exam From the Clarification Guidance for SRO-only Questions Rev 1 dated 03/11/2010 flowchart for 10 CFR 55.43(b)(5):
Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations [10 CFR 55.43(b)(5)], involving BOTH:
- 1) assessing plant conditions and then
- 2) selecting a procedure or section of a procedure to mitigate, recover, or with which to proceed.
Using the flowchart, this question can:
- NOT be answered solely by knowing systems knowledge, i.e., how the system works, flowpath, logic, component location.
PART I can be answered SOLELY with Systems knowledge
PART 2 REQUIRES System knowledge but ALSO requires knowledge of YELLOW PATH FRB ntry conditions;
- NOT be answered solely by knowing immediate operator actions.
- NOT be answered solely by knowing entry conditions for AOPs or plant parameters that require direct entry to major EOPs.
Part 2 requires knowledge of YELLOW path FRPS (NOT RED or ORANGE)
- NOT be answered solely by knowing the purpose, overall sequence of events, or overall mitigative strategy of a procedure.
- CAN be answered with knowledge of ONE or MORE of the following:
Assessing plant conditions (normal, abnormal, or emergency) and then selecting a procedure or section of a procedure to mitigate, recover, or with which to proceed.
Knowledge of when to implement attachments and appendices, including how to coordinate these items with procedure steps.
Knowledge of diagnostic steps and decision points in the EOPs that involve transitions to event specific sub-procedures or emergency contingency procedures.
Knowledge of administrative procedures that specify hierarchy, implementation, and/or coordination of plant normal, abnormal, and emergency procedures.
12/01/10 14:12:10 FNP-1-ARP-1.10 LOCATION KD2 SETPOINT: 75+/-2 PSIG D2 I IA PRESS ORIGIN: Pressure Switch NiP 19PS5 10-N LO PROBABLE CAUSE
- 1. Air Compressor tripped.
- 2. Improper valve lineup.
- 3. Instrument Air Line rupture.
- 4. Air Dryer malfunction.
AUTOMATIC ACTION NOTE: IF instrument air pressure falls below 85 psig, THEN LCV-459 and 460 may partially close causing orifice isolation valves 8149A, B, and C to isolate letdown.
- 1. If air header pressure decreases to 80 psig, Service Air will isolate (V-901)
- a. If Service Air pressure drops to 75 psig and was aligned to containment, Service Air would isolate, (HV-2935B and HV-2935C) close.
- 2. 1A, lB and 1C air compressors will start as demanded by the sequence controller.
- 3. Pressure downstream of inst air dryers, bypasses dryers (V902) at 70 psig.
- 4. Pressure downstream of inst air dryers, isolates inst air to service bldg (V904) at 55 psig.
- 5. Pressure downstream of inst air dryers, isolates inst air to turbine bldg (V903) at 45 psig.
OPERATOR ACTION
- 1. Check indications and determine actual instrument air pressure.
- 2. Start an additional air compressor, if available, to maintain system pressure.
- 3. IF a loss of instrument air has occurred, THEN perform the actions required by FNP-1-AOP-6.0, LOSS OF INSTRUMENT AIR.
- 4. an Air System rupture is indicated, THEN notify Plant Personnel to locate and isolate the ruptured piping.
- 5. IF an improper valve lineup exists, THEN investigate and correct the valve lineup.
- 6. IF malfunction of air compressor sequencer indicated, THEN operate the air compressors in accordance with FNP-1-SOP-31.0, COMPRESSED AIR SYSTEM. Station appropriate personnel at the air compressors to monitor air header pressure.
References:
A-177100, Sh. 462; A-170750, Sh. 32; C-l72745; D-l70131, Sh. 2 Page 1 of 1 Version 69.0
12/01/10 14:10:41 -
FNP-1-AOP-6.0 LOSS OF INSTRUMENT AIR Version 38.0 -
A. Purpose This procedure provides actions for response to a loss of instrument air pressure..
This procedure is applicable at all times.
B. Symptoms or Entry Conditions 1 This procedure is entered by either of the following:
[] A loss of instrument air is determined to exist by the indication on instrument air pressure indicator PI-4004B.
[] Loss of control or erratic operation of air operated valves is experienced by the operating crew.
2 This procedure may be entered from the following Annunciator Response Procedures.
[] KD1 IA TO PENE RM PRESS LO (FNP-1-ARP-1.10)
[j KD2IAPRESSLO
[j KD3SAPRESSLO C. Automatic Actions NOTE: TABLE 1 provides a list of AOVs, their failed position and whether or not a manual operator is available.
1 SERVICE AIR ISOLATES AT 80 PSIG FALLING 2 INST AIR DRYERS ARE BYPASSED AT 70 PSIG FALLING 3 INST AIR TO SERVICE BLDG ISOLATES AT 55 PSIG FALLING 4 INST AIR TO TURBINE BLDG ISOLATES AT 45 PSIG FALLING Page 1 ofl3
12/01/10 14:10:41 FNP-1-AOP-6.0 - - LOSS OF iNSTRUMENT AIR Version 380 Step Action/Expected Response Response Not Obtained NOTE: ff the reactor is tripped due to a loss of instrument air, THEN the actions of this procedure should be implemented in conjunction with FNP-1-ESP-0.1, REACTOR TRIP RESPONSE.
1 WHEN the reactor is critical AND control of critical AOVs becomes erratic, THEN trip the reactor and go to FNP-1-EEP-O, REACTOR TRIP OR SAFETY INJECTION.
CAUTION: the generator Hydrogen dryer control panel purge flow is lost, do not operate any controls on the control power panel.
2 Start any available AIR COMPRESSOR. 2 jf an air compressor cannot be started from the control room, THEN perform the following while continuing in this procedure:
2.1 IF instrument air to the Turbine building is lost, THEN de-energize the generator Hydrogen dryer.
2.1.1 At 1U 120/208V Distribution Cabinet N1R19L568 open breaker #8 located near the lB SGFP oil conditioner.
2.2 Dispatch personnel to locally start any available air compressor per FNP- I -SOP-3 1.0, COMPRESSED AIR SYSTEM.
2.3 IF 2C air compressor is available, THEN align 2C air compressor to Unit 1 using FNP-1-SOP-31.0, COMPRESSED AIR SYSTEM.
Page Completed Page 2 of 13
- 92. 103G2.1.36 O92INEW/SRO/MEM 3.O/4.1/0103G2.1.36//4/VAL 0-1 FIXED/MINOR ED Uni.t2 is in MODE 6, UQP-4.1 7 ControlLing Procedure For RefueUnçs in progress.and the following conditions exist:
- Time since shutdown is 120 hours0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br />.
- Time to Core Boiling is 5.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
- Refueling cavity is 153 6.
- The crew is unlatching the control rod drive shafts.
- The containment Equipment Hatch is closed.
Maintenance requests to open the Equipment Hatch and reports the following:
- A Maintenance Closure Response Team (MCRT) has been briefed and is available with all necessary equipment to close the Equipment Hatch.
- The estimated time to clear the Hatch and secure it with four (4) bolts is 100 minutes.
Which one of the following completes the statement below?
The Equipment Hatch (1) permitted to be opened because (2) per UOP-4.0, General Outage Operations Guidance.
(1) (2)
A. is NOT insufficient time has elapsed to allow the decay of short lived fission products within the RCS B. is NOT the time for the MCRT to sufficiently close the Equipment Hatch is too long C IS Refueling Integrity IS required but can be satisfied with the MCRTs response D. IS Refueling Integrity is NOT required while unlatching the control rod drive shafts
- 17. 103G2. 1.36 092INEW/SROIMEM 3.0/4. 1/0103G2. 1 .36//4/VAL 0-1 FIXED/MINOR ED Feedback -
LCO 3.9.3 The containment penetrations shall be in the following status during CORE ALTERATIONS (the movement of any fuel, sources, or reactivity control components, within the reactor vessel with the vessel head removed and fuel in the vessel):
- a. The equipment hatch is capable of being closed and held in place by four bolts;
- b. One door in each air lock is capable of being closed; and [...]
TS 3.9.3 would be satisfied if opened per UOP-4.0, v42.0 APPENDIX 1, General Outage Operations Guidance, section 2.10 qualifies with a time restriction which defines the capability to close of the TS:
Equipment Hatch & Airlocks Capable of Being Closed on Short Notice Ii2 equipment hatch meets this definition when the Maintenance Closure Response Team (MCRT) is established. The personnel and aux airlocks meet this definition when a routine check of the hoses and cables going through the airlocks reveals that at least one door in each airlock can be closed in less than the current time to boil. (Al 2008207932)
STP-18.4, v33.0, section 2.3.1 further provides time constraints on the capability to close the equipment hatch. This requirement states that if the equipment hatch is capable of being closed by a MCRT and establish closure within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of notification, then refueling integrity is satisfied.
A. Incorrect 1) see UOP-4.0 section 4.12.
- 2) this is the basis for TRM 13.9.1 which requires >100 hours decay time to allow for the decay of short lived fission products. This time is satisfied.
Further, this would not prevent opening the Equipment Hatch, instead it would prevent Core Alts.
Plausible: if one were to mis-apply TRM 13.9.1 bases; orto confuse the time assumed in the Fuel Pool heat load bases which is 140 hours0.00162 days <br />0.0389 hours <br />2.314815e-4 weeks <br />5.327e-5 months <br /> prior to core offload.
REF: FSAR Section 9.1.3, FSAR 9.1.3.1 page 9.1-5 bases for heat load of the pool The evaluation demonstrated suspending movement into the spent-fuel pool at 130°F ensures pool design temperature limits will not be reached. This evaluation assumed a core offload rate of 8 assemblies per hour starting at 140 h after reactor shutdown. The pool operational temperature limit of 130°F provides for personnel safety and limits room air temperature for habitability.
B.lncorrect 1) See STP-18.4 quoted above.
- 2) Since the time to re-install the hatch, is 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, the MCRTs response is sufficient to permit opening the door.
Plausible: Only 4 bolts being installed and taking one hour and 40 mins to accomplish this may seem excessively long or incomplete closure; Without knowledge of the requirements defined within the Surveillance
test (acceptance criteria) then this answer choice would be chosen.
- Additioria1iy if time to eore boil were longer than the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 4D min, thn this answer would be correct per UOP-4.1 step 4.12.
C. Correct 1) The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 40 mins is sufficiently quick to meet the requirements of STP-18.4 and the minimum of 4 bolts is all that is required to establish Containment Closure upon the notification of the need.
- 2) This statement is correct, unlatching of the CRDM shafts does meet the definition of a CORE ALTERATION. Therefore refueling integrity is required. This is further exemplified by UOP-4.1, requires STP-18.4 to be conducted at step 517.4, prior to the control rod drive shafts being unlatched.
D. Incorrect 1) See C.1
- 2) this statement is NOT correct. There is a potential that the Control Rod is moved during the unlatching process therefore, CORE ALTERATION must be considered in progress when performing this activity, and thus, TS 3.9.3 is applicable.
Plausible: Since the Control Rod drive shafts are being disconnected, not necessarily moved then one might assume that this does not meet the definition of a CORE ALTERATION.
- 17. 103G2.1.36 092/NEW/SRO/MEM 3.O/4.1/0103G2.l.36//4/VALO-l FIXED
/MINOR ED Notes -
K/A statement:l 03G2.l .36Containment SystemKno wledge of procedures and limitations involved in core alterations.
Importance Rating: 3.0 4.1 Technical
Reference:
UOP-4.0, v43.0 STP-18.4, v33.0 TS 3.9.3 TB 3.9.3, v44.0 UOP-4.1, v56.1 STP-13.0 ver 3.0 FSAR Section 9.1.3 References provided: None.
Learning Objective: Given a set of conditions during performance of UOP-4.0, General Outage Operations Guidance, EVALUATE plant conditions and DETERMINE the appropriate actions that need to be taken. (OPS-62511A01).
Question origin: NEW Basis for meeting K/A: Knowledge of Generic Refueling procedure is required to properly assess Containment closure (REFUELING INTEGRITY) requirements to permit disassembly of the Rx Vessel to occur.
SRO justification: 10 CFR 55.43(b)(6)
Procedures and limitations involved in initial core loading, alterations in core configuration, control rod programming, and determination of various internal and external effects on core reactivity.
2011 NRC exam 10 CFR 55.43(b)(6)
Procedures and limitations involved in initial core loading, alterati ons in core configuration, control rod programming, and determination of various internal and external effects on core reactivity. [10 CFR 55.43(b)(6)]
Some examples of SRO exam items for this topic include:
- Evaluating core conditions and emergency classifications base d on core conditions.
- Administrative requirements associated with low power physic s testing processes.
- Administrative requirements associated with refueling activities, such as approvals required to amend core loading sheets or administrativ e controls of potential dilution paths and/or activities.
- Administrative controls associated with the installation of neutro n sources.
Knowledge of TS bases for reactivity controls.
Procedure Number Ver S HARED - Farley Nuclear Plant FNR-0-UOP-4.0 42.0 10/8/2010 10:13:41 Page Number GENERAL OUTAGE OPERATIONS GUIDANCE 7 of 93 4.11 Time to Core Boiling 4.11.1 Tables A and B provide estimates of the time to core boiling following a loss of RHR capability for two cases:
- Time to Saturation as a function of time after shutdown for a full core immediately after shutdown for a refueling.
- Time to Saturation as a function of time after shutdown for a core in which one third of the spent fuel has been replaced with new fuel.
These tables can be used to estimate the amount of time available for operator action to restore RHR before additional protective measures must be taken.
NOTE It is not generally desired to interpolate between data points on Tables A or B; the intent of this procedure is to estimate time to core boiling using the closest conservative values.
Interpolation is allowed, with Shift Supervision permission, if required by specific plant conditions.
4.11.1.1 Both cases are evaluated for conditions when RCS level is at mid loop (1 229), at three feet below the reactor flange (1267), RCS at full conditions and when the reactor cavity is full. For RCS levels other than those given in the Tables, time to boiling may be estimated using the data in the Tables as a guide.
4.11.1.2 Both cases are also evaluated for three assumed initial temperatures:
100°F, 120°F, and 140°F. Use the closest conservative (higher) RCS initial temperature or interpolate the data for the current RCS temperature.
4.11.1.3 Use the closest conservative (lower) time after shutdown or interpolate the data for the current time after shutdown.
4.12 When RCS time to boil is less than the time required to close the Equipment Hatch and the RCS is breached then the Equipment Hatch shall be closed.
(Al 2008207873) 4.13 Any changes to this procedure require a review by the On-Line and Outage Scheduling department to ensure there are no conflicts or inconsistencies.
(CR 2004102447)
SHARED. Farley Nuclear Plant A Procedure Number Ver F1P-Q-UQP-4.O -42.0 Page Number 10/8/2010 10:13:41 GENERAL OUTAGE OPERATIONS GUIDANCE 18 of 93 2.10 Equipment Hatch & Airlocks Capable of Being Closed on Short Notice The equipment hatch meets this definition when the Maintenance Closure Response Team (MCRT) is established. The personnel and aux airlocks meet this definition when a routine check of the hoses and cables going through the airlocks reveals that at least one door in each airlock can be closed in less than the current time to boil.
(Al 2008207932) 2.11 HHSI Pump / Flow Path Available A charging pump is capable of injecting water into the RCS from the RWST which contains > 50,000 gallons of water. Only minor valve manipulations are required.
2.12 LHSI Pump / Flow Path Available A RHR pump is capable of injecting water into the RCS from the RWST which contains > 50,000 gallons of water. Only minor valve manipulations are required.
2.13 Operability of boration flowpaths are governed by TRM specifications 13.1.2, 13.1.4, and 13.1.6.
2.13.1 When boration flowpaths are required to be operable based on the TRM, then the available boration flow paths are determined using the guidance of Table 4 of FNP-1-STP-2.1 or FNP-2-STP-2.1, Boron Injection Flow Path Verification and Boric Acid Transfer Pump Operability Test, MODES 5 & 6 and by verifying FNP-1-STP-3.2 or FNP-2-STP-3.2, Borated Water Source Operability Test Mode 5, 6 is current.
NOTE The charging pump must be available in mode 5, but only the fiowpath is required to be available in mode 6.
Additionally, Normal charging can be considered an available boration flow path under the following conditions:
2.13.1.1 Q1E21MOV81O7 and Q1E21MOV81O8 are open, OR Q2E21MOV81O7 and Q2E21MOV81O8 are open.
2.13.1.2 With one of the following charging pump requirements met.
- IA or 2A Charging Pump available
- lB Charging Pump Available with Qi E21 MOV81 32A and B open, or 2B Charging Pump Available with Q2E21MOV8132A and B open
- 1C Charging pump available with Q1E21MOV8132A and B open and Q1E2IMOV8133A and B open, OR 2C Charging pump available with Q2E21 MOV81 32A and B open and Q2E21M0V8133A and B open.
Containment Penetrations
- 3.9.3 3.9 REFUELING OPERATIONS 3.9.3 Containment Penetrations LCO 3.9.3 The containment penetrations shall be in the following status:
- a. The equipment hatch is capable of being closed and held in place by four bolts;
- b. One door in each air lock is capable of being closed; and
- c. Each penetration providing direct access from the containment atmosphere to the outside atmosphere either:
- 1. closed by a manual or automatic isolation valve, blind flange, or equivalent, or
- 2. capable of being closed by an OPERABLE Containment Purge and Exhaust Isolation System.
APPLICABILITY: During CORE ALTERATIONS, During movement of irradiated fuel assemblies within containment.
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more containment A.1 Suspend CORE Immediately penetrations not in ALTERATI ONS.
required status.
AND A.2 Suspend movement of Immediately irradiated fuel assemblies within containment.
Farley Units 1 and 2 3.9.3-1 Amendment No. 178 (Unit 1)
Amendment No. 171 (Unit 2)
Containment Penetrations 83.aa B 3.9 REFUELING OPERATIONS B 3.9.3 Containment Penetrations BASES BACKGROUND During CORE ALTERATIONS or movement of irradiated fuel assemblies within containment, a release of fission product radioactivity within containment will be limited to maintain dose consequences within regulatory limits when the LCO requirements are met. In MODES 1, 2, 3, and 4, this is accomplished by maintaining containment OPERABLE as described in LCO 3.6.1, Containment.
In MODE 6, the potential for containment pressurization as a result of an accident is not likely; therefore, requirements to isolate the containment from the outside atmosphere can be less stringent. The LCD requirements are referred to as refueling integrity rather than containment OPERABILITY. Refueling integrity means that all potential escape paths are closed or capable of being closed. Since there is no potential for containment pressurization, the 10 CFR 50, Appendix J leakage criteria and tests are not required.
The containment serves to contain fission product radioactivity that may be released from the reactor core following an accident, such that offsite radiation exposures are maintained well within the requirements of 10 CFR 100. Additionally, the containment provides radiation shielding from the fission products that may be present in the containment atmosphere following accident conditions.
The containment equipment hatch, which is part of the containment pressure boundary, provides a means for moving large equipment and components into and out of containment. If closed, the equipment hatch must be held in place by at least four bolts. Good engineering practice dictates that the bolts required by this LCO be approximately equally spaced. Alternatively, the equipment hatch can be open provided it can be installed with a minimum of four bolts holding it in place.
The containment air locks, which are also part of the containment pressure boundary, provide a means for personnel access during MODES 1, 2, 3, and 4 unit operation in accordance with LCD 3.6.2, Containment Air Locks. Each air lock has a door at both ends. The doors are normally interlocked to prevent simultaneous opening when containment OPERABILITY is required. During periods of unit shutdown (continued)
Farley Units 1 and 2 B 3.9.3-1 Revision 44
Containment Penetrations B 3.9.3 BASES BACKGROUND when refueling integrity is not required, the door interlock mechanism (continued) may be disabled, allowing both doors of an air lock to remain open for extended periods when frequent containment entry is necessary.
During CORE ALTERATIONS or movement of irradiated fuel assemblies within containment, refueling integrity is required; therefore, the door interlock mechanism may remain disabled, but one air lock door must always remain capable of being closed.
The requirements for refueling integrity ensure that a release of fission product radioactivity within containment will be limited to maintain dose consequences within regulatory limits.
The Containment Purge and Exhaust System includes two subsystems. The normal subsystem includes a 48-inch purge penetration and a 48-inch exhaust penetration. The second subsystem, a minipurge system, includes an 8-inch purge and an 8 inch exhaust line that utilize the 48-inch penetrations. During MODES 1, 2, 3, and 4, the two 48-inch purge valves in each of the normal purge and exhaust penetrations are secured in the closed position. The two 8-inch minipurge valves in each of the two minipurge lines may be opened in these MODES in accordance with LCO 3.6.3, Containment Isolation Valves, but are closed automatically by the Engineered Safety Features Actuation System (ESFAS) instrumentation specified in LCO 3.3.6, Containment Purge and Exhaust Isolation Instrumentation. Neither of the subsystems is subject to a Specification in MODE 5.
In MODE 6, large air exchanges are necessary to conduct refueling operations. The normal 48-inch purge system is used for this purpose, and all four valves are closed by the ESFAS instrumentation specified in LCO 3.3.6, Containment Purge and Exhaust Isolation Instrumentation.
The minipurge system is not normally used in MODE 6. However, if the minipurge valves are opened they are capable of being closed automatically by the instrumentation specified in LCO 3.3.6, Containment Purge and Exhaust Isolation Instrumentation.
The other containment penetrations that provide direct access from containment atmosphere to outside atmosphere must be isolated on at least one side. Isolation may be achieved by a closed automatic (continued)
Farley Units 1 and 2 B 3.9.3-2 Revision 44
Containment Penetrations
- B3.aZ BASES BACKGROUND isolation valve, a manual isolation valve, blind flange, or equivalent.
(continued) Equivalent isolation methods allowed under the provisions of 10 CFR 50.59 may include use of a material that can provide a temporary, atmospheric pressure, ventilation barrier for the other containment penetrations during CORE ALTERATIONS or movement of irradiated fuel assemblies within containment (Ref. 1).
APPLICABLE During CORE ALTERATIONS or movement of irradiated fuel SAFETY ANALYSES assemblies within containment, the most severe radiological consequences result from a fuel handling accident. The fuel handling accident is a postulated event that involves damage to irradiated fuel (Ref. 2). The fuel handling accident analyzed includes dropping a single irradiated fuel assembly. The requirements of LCO 3.9.6, Refueling Cavity Water Level, and the minimum decay time of 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> prior to CORE ALTERATIONS ensure that the release of fission product radioactivity, subsequent to a fuel handling accident, results in doses that are well within the guideline values specified in 10 CFR 100. Standard Review Plan, Section 15.7.4, Rev. I (Ref. 3),
defines well within 10 CFR 100 to be 25% or less of the 10 CFR 100 values. The acceptance limits for offsite radiation exposure will be 25% of 10 CFR 100 values.
Containment penetrations satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO This LCO limits the consequences of a fuel handling accident in containment by limiting the potential escape paths for fission product radioactivity released within containment. The LCO requires any penetration providing direct access from the containment atmosphere to the outside atmosphere to be closed except for the OPERABLE containment purge and exhaust penetrations, the equipment hatch and the personnel air locks. For the OPERABLE containment purge and exhaust penetrations, this LCO ensures that these penetrations are isolable by the Containment Purge and Exhaust Isolation System.
For the equipment hatch and personnel air locks, closure capability is provided by a designated trained closure crew and the necessary equipment. The OPERABILITY requirements for LCO 3.3.6, Containment Purge and Exhaust Isolation Instrumentation, ensure that the automatic purge and exhaust valve closure times specified in the FSAR can be achieved and, therefore, meet the assumptions used in the safety achieved and, therefore, meet the assumptions used in the safety analysis to ensure that releases through the valves (continued)
Farley Units 1 and 2 B 3.9.3-3 Revision 44
Containment Penetrations B 3.9.3 BASES LCO are terminated, such that radiological doses are within the acceptance (continued) limit.
The equipment hatch and personnel air locks are considered isolable when the following criteria are satisfied:
- 1. the necessary equipment required to close the hatch and personnel air locks is available,
- 2. at least 23 feet of water is maintained over the top of the reactor vessel flange in accordance with Specification 3.9.6,
- 3. a designated trained closure crew is available.
The equipment hatch and personnel air locks door openings must be capable of being cleared of any obstruction so that closure can be achieved as soon as possible.
The containment personnel air lock and emergency personnel air lock doors may be open during movement of irradiated fuel in the containment and during CORE ALTERATIONS provided that one door in each air lock is capable of being closed in the event of a fuel handling accident. Should a fuel handling accident occur inside containment, one door in each personnel air lock will be closed following an evacuation of containment.
The closure of the equipment hatch and the personnel air locks will be completed promptly following a fuel handling accident within containment.
APPLICABILITY The containment penetration requirements are applicable during CORE ALTERATIONS or movement of irradiated fuel assemblies within containment because this is when there is a potential for a fuel handling accident. In MODES 1, 2, 3, and 4, containment penetration requirements are addressed by LCO 3.6.1. In MODES 5 and 6, when CORE ALTERATIONS or movement of irradiated fuel assemblies within containment are not being conducted, the potential for a fuel handling accident does not exist. Therefore, under these conditions no requirements are placed on containment penetration status.
Farley Units 1 and 2 B 3.9.3-4 Revision 44
2/14/2011 11:07 FNP-1-STP-18.4 Appendix E PERSONNEL AND EMERGENCY AIR LOCK VENT VALVE CLOSURE FOR CONTAINMENT CLOSURE INTEGRITY VERIFICATION At the completion of each applicable step, the Shift Support Supervisor, Shift Supervisor or other designated personnel shall initial and record the date and time in the space provided by the associated step.
INITIALS DATE/TIME 2.0 Acceptance Criteria 2.1 Asterisked (*) steps are those associated with Acceptance Criteria.
2.2 Acceptance Criteria for Mid-Loop Integrity 2.2.1 Containment closure can be established within two hours of the initiating event. (CMT 0007668) 2.3 Acceptance Criteria for Refueling Integrity 2.3.1 The equipment door/hatch is closed or is capable of being closed with the following requirements.
- FNP-0-STP-610 is completed.
- A Maintenance Closure Response Team (MCRT) is available and briefed to effect closure within two hours of notification. This assumes only 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of dose exposure will be incurred by the MCRT.
- Closure includes being closed and held in place by a minimum of 4 bolts lAW FNP-0-MP-38.0.
2.3.2 A minimum of one door in the personnel air lock and one door in the auxiliary air lock are capable of being closed.(A12008206863) 2.3.3 Containment purge and exhaust valves and mini purge valves are capable of being closed by containment purge isolation signal and valve stroke times are less than or equal to the maximum allowable stroke times penetrations serviced by these valves are isolated by at least one closed valve.
2.3.4 Containment integrity is satisfactory for all mechanical and electrical penetrations, except for the equipment door/hatch, the personnel air lock and the auxiliary air lock which can be open under admin control specified in 2.3.1 and 2.3.2.
Version 33.0
- 93. G2. 1.35 093/BANK/SRO/C/A 2.2/3 .9/G2. 1 .35/N/3//JAN 13 Unit 2 is in MODE 6for a refueling outage.
Which one of the following is a responsibility of the Fuel Handling Supervisor in accordance with EN P-O-FHP-0.0, Refueling Operations?
The Fuel Handling Supervisor is required to A. monitor lifting operations of any load in excess of 3000 lbs over the Spent Fuel Storage Racks containing fuel Bk authorize unlatching a fuel assembly from the Manipulator Crane in the Reactor Vessel C. document and update status maps during fue handling operations D. remain in constant communications with the refueling team inside containment performing Core Alterations while he is monitoring fuel movement in the Spent Fuel Pool
- 18. G2. 1.35 O93IBANKJSRO/C!A 2.2/3 .9/G2. 1 .35/N13//JAN 13 Feedback FHP-0.0, v12.0 section 4.3, Fuel Handling Supervisor responsibilities and FHP-0.0, v12.0 Appendix 1 step 1.8 TRM 13.9.4 FHP-2-FHP-1 .0, v21 A. Incorrect. This is incorrect since TR 13.9.4 prohibits Loads > 3000 pounds from travel over fuel assemblies in the storage pool.
Plausible: Fuel handling activities (movement of tools, wier gates, or other assemblies) could require the FHS to authorize lifts over the SFPs.
B. Correct. PRIOR to unlatching a fuel assembly in the Rx vessel, the SRO in charge of refueling must give permission. Per FNP-0-FHP-0.0 Appendix 1 Step 1.8.
C. Incorrect. Engineering Support does this per FNP-2-FHP-1 .0 Step 3.11.
Plausible: FHP-0.0 step 4.3.14 assigns the responsibility to the FHS to periodically review status board and procedure signoffs to verify proper documentation of fuel movements.
D. Incorrect. This is incorrect since during CORE ALTERATIONS the FHS is REQUIRED to be in Containment during core alts per FHP-0.0, step 3.3, and FHP-21 .OA & B Steps 1.4.
Although constant communications are required per step 3.21 & 3.22 of FNP-2-FHP-1 .0, and the FHS is usually maintains communications the FHS is not contained within the list of minimum refueling stations that must be established 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> before refueling operations. This requirement satisfies TRM 13.9.2 which is to ensure that refueling station personnel can be promptly informed of significant changes in the facility status or core reactivity conditions during CORE ALTERATIONS. (TR B13.9-1).
Plausible since, FHP-0.0 step 4.3.13 states, Normally station himself inside containment, and 4.3.9 requires the FHS stays informed of the systems that affect the fuel handling and ensures that all evolutions in progress are compatible with the refueling program. Further with the appendix 1 step 1.8 bullet which states, Fuel Handling Supervisor is in control of all aspects of fuel movement, one might consider that the Fuel handling supervisor is permitted to ROAM between Containment and the SFP during core offload/reload activities.
- 18. G2.1.35 O93IBANKJSRO/C/A 2.2/3.9/G2J.351N!3//JAN 13 Notes K/A statement G2.1 .35 Knowledge of the fuel-handling responsibilities of SROs.
Importance Rating: 2.2 3.9 Technical
Reference:
FHP-0.0, v12.0 FHP-7.0, v21 .0 References provided: None Learning Objective: RECALL AND DISCUSS the Precautions and Limitations (P&L), Notes and Cautions (applicable to the System Operator) found in the following procedures (OPS-40305B1 1):
- FHP-1 .0 Refueling Operations
- FHP-7.0 Limitations And Precautions For Handling Fuel Assemblies Question origin: FNP Bank (REFUEL/STOR-62108D02 001 )--CHANGES to A & D distractors and PROCEDURE change might qualify as MODIFIED.
2005 NRC exam-- under G2.2.29 Basis for meeting K/A: The conditions of the stem directly relate the responsibilities of the Fuel Handling SRO.
SRO justification: 10 CFR 55.43(b)(7) Fuel handling facilities and procedures.
To include:
- Refuel floor SRO responsibilities.
2011 NRC exam There is NO flow chart available for 10 CFR 55.43(b)(6) within Clarification Guidance for SRO-only Questions Rev 1 (03/11/2010).
The item specifically listed as an example for this topic.
Fuel handling facilities and procedures. [10 CFR 55.43(b)(7)]
Some examples of SRO exam items for this topic include:
- Refuel floor SRO responsibilities.
- Assessment of fuel handling equipment surveillance requirement acceptance criteria.
- Prerequisites for vessel disassembly and re-assembly.
- Decay heat assessment.
- Assessment of surveillance requirements for the refueling mode.
- Reporting requirements.
- Emergency classifications.
Does NOT include items that the RO is responsible at FNP; such as fuel handling equipment and refueling related control room instrumentation operability requirements,
abnormal operating procedure immediate actions, etc.
10/27/09 13:02:56 - FNP-0-FHP-0.0 FARLEY NUCLEAR PLANT UNITS 1 & 2 FUEL HANDLING PROCEDURE FNP-0-FHP-0.0 REFUELING ORGANIZATION 1.0 Purpose This procedure provides an outline of the organization, personnel and their responsibilities to accomplish refueling operations.
2.0 Initial Conditions 2.1 All personnel involved with the actual performance of the fueling operation have read the refueling procedures and a copy of the refueling procedures are available in the general work area for reference if needed.
2.2 The version of this procedure has been verified to be the current version and correct unit for the task (OR 1-98-498).
2.3 Definitions 2.3.1 FUEL HANDLING COORDINATOR A person with Farley specific fuel handling experience and knowledge assigned to provide oversight and direction for non-outage fuel movement and fuel handling equipment surveillance.
2.3.2 FUEL HANDLING SUPERVISOR An active licensed Senior Reactor Operator or SRO Limited to Fuel Handling licensed individual assigned the duty of supervision of fuel handling activities and direct supervision of core alterations. He should directly report to the on-duty Shift Supervisor.
2.3.3 FUEL STATUS BOARD Display board set up to indicate the current location of fuel assemblies and components in the various fuel storage locations at FNP during refueling outages. A computer-generated display that provides a pictorial representation, such as TracWorks, is considered equivalent to a fuel status board.
Version 12.0
10/27/09 13:02:56 FNP-0-FHP-0.0 2.3.4 FUEL HANDLING DATA SHEETS The document which sets forth the step-by-step sequence of fuel movement operations which will be followed for the refueling of the reactor core during a refueling outage.
2.3.5 CORE ALTERATIONS Movement of any fuel, sources, or other reactivity control components within the reactor vessel with the vessel head removed and fuel in the vessel. Suspension of CORE ALTERATIONS shall not preclude completion of movement of a component to a safe position.
2.4 Copies of fuel handling data sheets shall be available at all stations involved in fuel and/or insert shuffles. This includes the Control Room, CTMT Upender and SFP Upender stations. The master fuel handling data sheets will be maintained by the Reactor Engineer in the Control Room.
3.0 Limitations and Precautions 3.1 The Fuel Handling Coordinator, Shift Manager, Fuel Handling Supervisor, Reactor Engineer, Unit Shift Supervisor, Health Physics Technician, Reactor Operator or System Operators shall have the authority and responsibility to suspend refueling operations if, in his judgment, any conditions exist which threaten personnel safety or safe handling of fuel.
3.2 Suspension of core alterations shall not preclude any individual assigned to the refueling crew from completion of movement of a component to a safe conservative position.
3.3 All core alterations shall be observed and directly supervised by either a licensed SRO or SRO Limited to Fuel Handling who is in the Containment Building of the affected unit and has no other concurrent responsibility during this operation.
3.4 No more than one fuel assembly shall be out of the storage racks, fuel cleaning canisters, new fuel elevator, fuel transfer system upender, or fuel assembly leak test canister at any given time in the SFP. A minimum distance of 12 inches, edge-to-edge, shall be maintained between the assembly being manipulated and any assembly not located in a storage rack. No more than two fuel assemblies shall be out of the Reactor Vessel at any given time in the Containment and then the minimum edge-to-edge distance between those two assemblies must be at least 12 inches.
Version 12.0
10/27/09 13:02:56 -
FNP-0-FHP-0.0 4.2.14 Coordinate security badging and rad worker training for contract refueling personnel (i.e. Westinghouse).
4.2.15 Manage Operations portable equipment associated with refueling such as Tn-Nuclear filter.
4.2.16 Budget for refueling contractor services and approve invoices for payment.
4.2.17 Ensure that the Shift Manager and the appropriate Shift Supervisor is briefed during each shift in which refueling activities are in progress.
4.2.18 Ensure activities described in Appendix 1 are implemented.
4.2.19 Act as Service Administrator for Westinghouse refueling service.
4.3 Fuel Handling Supervisor 4.3.1 The Fuel Handling Supervisor shall have a current Senior Reactor Operators (SRO) license or a SRO license limited to fuel handling.
4.3.2 The Fuel Handling Supervisor should be trained in proper fuel handling technique at FNP.
4.3.3 Must be familiar with this procedure as well as all other FNP fuel handling procedures.
4.3.4 Ensures that approved procedures are adhered to by all refueling crew personnel.
4.3.5 Ensures that all required check-off and prerequisites are completed prior to commencing a specific fuel handling evolution.
4.3.6 Ensures that appropriate entries and sign-offs are made on the Fuel Transfer Sheets.
4.3.7 Ensures Fuel Handling Data Sheet compliance in containment.
4.3.8 Contacts the Reactor Engineer for approval of any deviations from the approved Fuel Transfer Sheets.
4.3.9 Keeps himself informed of the systems that affect fuel handling and ensures that all evolutions in progress are compatible with the refueling program.
Version 12.0
10/27/09 13:02:56 -
FNP-0-FHP-0.0 4.3.10 May perform as second person who verifies correct manipulation of fuel assembly and inserts.
4.3.11 The Fuel Handling Supervisor ensures that the Reactor Engineer is notified of all assemblies that are difficult to seat and of the observations made from the binocular visual inspection.
4.3.12 Document and resolve any anomalous condition that may arise.
4.3.13 Normally station himself inside containment.
4.3.14 Periodically review status board and procedure signoffs to verify continuing proper documentation of fuel movements. This should be done at least once per shift when the SRO is out of containment.
4.3.15 Ensure a copy of the refueling procedures is available on a shift to shift basis.
4.3.16 Ensure Controlled Refueling Area Boundary (CRAB) cleanliness is maintained throughout the refueling evolution.
4.4 SHIFT SUPERVISOR 4.4.1 As part of his normal duties, the Unit Shift Supervisor will be responsible for maintaining the required status of all support systems needed for the refueling operation, such as the Residual Heat Removal Systems, etc.
4.4.2 Monitors the plant and refueling operation for plant safety and compliance with Technical Specifications.
4.4.3 Ensures that direct communications are maintained between the refueling area in Containment, the Spent Fuel Pool, and the Control Room when core alterations are in progress.
4.4.4 Document and resolve any anomalous plant conditions that may arise.
4.4.5 Initiates cavity water level surveillance whenever the reactor cavity is flooded.
Version 12.0
10/27/09 13:02:56 FNP-0-FHP-0.0 APPENDIX 1 1.5 Transfer New Fuel to SFP
- Schedule and coordinate receipt, inspection, and transfer of new fuel.
- Ensure ROs, SROs, and SOs, and appropriate Reactor Engineering personnel are scheduled to support new fuel receipt inspection and transfer.
- Establish CRAB area for new fuel racks used for fuel inspection and storage.
1.6 SFP Transfer Canal Drain Down (FNP-1/2-SOP-54.0, SPENT FUEL POOL COOLING AND PURIFICATION SYSTEM)
- Prepare/ensure necessary equipment available for pump down of SFP transfer canal.
- Two submersible pumps may be required to overcome weir gate leakage; thus two complete pumping systems should be available.
- Ensure sufficient RHTJRWST capacity exists for water removed from canal.
- If cask storage area weir gate is to be in place during pump down, ensure all refueling tools are in transfer canal area prior to pump down of canal. Otherwise, tools confined in cask storage area cannot be checked until after SFP canal floodup.
1.7 Fuel Handling Tool Checkout
- Support refueling team as necessary for tool checks.
- Provide maintenance support as necessary to resolve equipment problems.
1.8 Issue Fuel Handling Supervisor letter delineating responsibilities and concerns during fuel handling evolutions. Brief all Fuel Handling Supervisors on responsibilities.
- Fuel Handling Supervisor must give permission to unlatch from fuel assemblies installed in the core.
- Fuel Handling Supervisor is in control of all aspects of fuel movement.
- Fuel Handling Supervisor must ensure:
(1) articles in cavity area are properly secured.
(2) Refueling personnel signoff the refueling procedure shiftly, as required.
Page 3 of 7 Version 12.0
- 1. REFUEL/STOR-62 1 08D02 OO1/HLT/SRO/C/A 2.2/3.9/G2. 1.35//U Unit 2 is in a refueling outagç and in MODE 6.
Which one of the following is reQuired to be done by the SRO in charge of refueling in accordance with FNP-2-FHP-1 .0 Refue flrfi7 .
potentially a correct answer--- Refueling activities A.
B Give permission prior to unlatching a fuel assembly in the Reactor Vessel.
C. Document current status of fuel handling operations by keeping status maps up to date.
a correct answer, since rr . to ore LY the listed stations in FHP-1 .0 are required. FHS is not listed.
A. Incorrect. Approval must be coordinated with HP per step 3.2 of FNP-2-FHP-1., not the SRO.
B. Correct. To give permission prior to unlatching a fuel assembly in the Reactor Vessel.
Per FNP-2-FHP-1 .0 Step 3.7.
C. Incorrect. Engineering Support does this per FNP-2-FHP-1 .0 Step 3.11.
D. Incorrect. The SRO in charge of refueling must be in Containment (SEP is not allowed) prior to unload or reload per FNP-2-FHP-1 .OA & B Steps 1.4.
2005 NRC exam-- under G2.2.29 G2.1 .35 Knowledge of the fuel-handling responsibilities of SROs.
- 2. Evaluate abnormal plant or equipment conditions associated with the Euel Storage, Handling and Refueling System and determine the integrated plant actions needed to mitigate the consequence of the abnormality (OPS52I 08D02).
- 94. G2.2.12 094/MOD FNP BANKJSRO/MEM 3.7/4.1/G2.2.121N/3/VAL 0-1 FIXED/MINOR ED Unit 2 is in Mode 1 when the following, is discovered: -
At 1300 a routine 24-hour surveillance, applicable while in MODES 1 & 2, was last performed at 0600 on the previous day (31 hours3.587963e-4 days <br />0.00861 hours <br />5.125661e-5 weeks <br />1.17955e-5 months <br /> ago).
Which one of the following describes the minimum TS required response to the discovery?
The LCO for which the surveillance is required A. is NOT met, and the applicable action statements must be implemented immediately B. is NOT met, and the applicable action statements must be implemented within one (1) hour C. IS met, and the completion may be delayed up to 0600 tomorrow, at which time, if not completed, the LCO must be declared NOT met D IS met, and the completion may be delayed up to 1300 tomorrow, at which time, if not completed, the LCO must be declared NOT met
- 19. G2.2.12 094/MOD FNP BANKJSRO/MEM 3.7/4.1/G2.2.12/N/3/VAL 0-1 FIXED/IvIINOR ED___
Feedback SR 3.01 states that an surveNlance shall be met during the MODES [...] in that applicability for the individual LCOs [...]. Failure to perform a Surveillance within the specified Frequency shall be failure to meet the LCO except as provided in SR 3.0.3.
SR 3.0.3 states:
If it is discovered that a Surveillance was not performed within its specified Frequency, then compliance with the requirement to declare the LCO not met may be delayed, from the time of discovery, up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or up to the limit of the specified Frequency, whichever is greater. [...]
If the Surveillance is not performed within the delay period, the LCO must immediately be declared not met, and the applicable Condition(s) must be entered.
When the Surveillance is performed within the delay period and the Surveillance is not met, the LCO must immediately be declared not met, and the applicable Condition(s) must be entered.
A. Incorrect This is contrary to the guidance of SR 3.0.3, the exception to SR 3.0.1.
Plausible: This would be true if SR 3.0.1 did not allow the exception and if at any time the SR is not satisfactorily completed, then the LCO is immediately declared NOT met. Further if the surveillance is not completed within the permitted delay time, then the LCO is immediately declared NOT met.
B. Incorrect SeeA.1 Plausible: If one believes the LCO must be declared NOT met, and confuse/mis-understand the permitted 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> delay before shutting down of TS 3.0.3 and apply it to SR 3.0.3.
C. Incorrect The delay period is applied from the time of discovery. In this case 1300 today was the time of discovery, therefore 1300 the following day is the maximum delay time.
Plausible: This is a common misconception of SR 3.0.3 regarding when to apply the extension. Often it is mis-applied from the time of its original required completion time. 0600 + 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> = 0600 the following day.
D. Correct See the SR quotes above.
- 19. G2.2.12 094/MOD FNP BANKJSRO/MEM 3.7/4.1/G2.2.12/N/3!VAL 0-1 FIXED/MINOR ED Notes K/A statement G2.2.12 Knowledge of surveillance procedures.
Importance Rating: 3.7 4.1 Technical
Reference:
SR 3.0.1 & 3.0.3 pg 3.0-4 of TS (Rev 50)
References provided: NONE Learning Objective: RECALL AND APPLY the information of the generic LCD requirements (LCD 3.0.1 thru 3.0.7; SR 4.0.1 thru 4.0.4) including the BASES of the generic section for any Technical Specifications or TRM requirements (OPS-62302A02): Examples of exam items that are unique to the SRO position include:
with rules of application requirements (Section 1)
Application of generic LCO requirements (LCD 3.0.1 thru 3.0.7; SR 4.0.1 thru 4.0.4)
Question origin: Modified FNP Bank INTRO TS-52302A03 028; NRC history: Byron 2000; FNP 2001 Basis for meeting K/A: This is a Generic KA therefore effort has been made to make this a generic application of the TS requirements.
Requires knowledge of SR 3.0.1, and SR 3.0.3.
SRO justification: 1 OCFR55.43 (b) 2: Application of generic LCO requirements (LCD 3.0.1 thru 3.0.7; SR 4.0.1 thru 4.0.4) 2011 NRC exam Facility operating limitations in the TS and their bases. [10 CFR 55.43(b)(2)]
From the Clarification Guidance for SRO-only Questions Rev I dated 03/11/2010 flowchart:
- 1) can NOT be answered by knowing less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Tech Specs.
- 2) can NOT be answered by knowing information listed above-the-line.
- 3) can NOT be answered by knowing the TS Safety Limits or their bases.
- 4) Does involve one or more of the following for TS, TRM or DDCM:
- Application of Required Actions (Section 3) and Surveillance Requirements (Section 4) in accordance with rules of application requirements (Section 1).
- Application of generic LCO requirements (LCD 3.0.1 thru 3.0.7 and SR 4.0.1 thr4.0.4)
- Knowledge of TS bases that is required to analyze TS required actions and terminology
SR Applicability ao 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY SR 3.0.1 SRs shall be met during the MODES or other specified conditions in the Applicability for individual LCOs, unless otherwise stated in the SR.
Failure to meet a Surveillance, whether such failure is experienced during the performance of the Surveillance or between performances of the Surveillance, shall be failure to meet the LCO. Failure to perform a Surveillance within the specified Frequency shall be failure to meet the LCO except as provided in SR 3.0.3. Surveillances do not have to be performed on inoperable equipment or variables outside specified limits.
SR 3.0.2 The specified Frequency for each SR is met if the Surveillance is performed within 1.25 times the interval specified in the Frequency, as measured from the previous performance or as measured from the time a specified condition of the Frequency is met.
For Frequencies specified as once, the above interval extension does not apply.
If a Completion Time requires periodic performance on a once per. .
basis, the above Frequency extension applies to each performance after the initial performance.
Exceptions to this Specification are stated in the individual Specifications.
SR 3.0.3 If it is discovered that a Surveillance was not performed within its specified Frequency, then compliance with the requirement to declare the LCD not met may be delayed, from the time of 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 the limit of the specified Frequency, whichever is greater. This delay period is permitted to allow performance of the Surveillance. A risk evaluation shall be performed for any Surveillance delayed greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and the risk impact shall be managed.
If the Surveillance is not performed within the delay period, the LCD must immediately be declared not met, and the applicable Condition(s) must be entered.
When the Surveillance is performed within the delay period and the Surveillance is not met, the LCO must immediately be declared not met, and the applicable Condition(s) must be entered.
SR 3.0.4 Entry into a MODE or other specified condition in the Applicability of an LCD shall only be made when the LCOs Surveillances have been met within their specified Frequency, except as provided by SR 3.0.3. When an LCO is not met due to Surveillances not having been met, entry into a MODE or other specified condition in the Applicability shall only be made in accordance with LCO 3.0.4.
(continued)
Farley Units 1 and 2 3.0-4 Amendment No. 173 (Unit 1)
Amendment No. 166 (Unit 2)
- 95. G2.2. 18 095/NEW/SRO/C/A 2.6/3 .9/G2.2. 1 8//2/VAL 0-1 FIXED/REPLACEMENT Unit 1 is preparing to enter Mid-Loop prior to core offload and the following conditions exist:
- Maintenance on the 1 C Condensate pump is in progress.
- Southeast Division is performing maintenance in the 500 kV Switchyard.
Which one of the following completes the statements below per NMP-OS-010, Protected Train/Division and Protected Equipment Program?
Work on the 1 C Condensate pump (1) required to be re-approved in the form of a GREEN SHEET.
Work in the 500kV switchyard (2) required to be re-approved in the form of a GREEN SHEET.
(1) (2)
IS IS B. IS is NOT C. is NOT IS D. is NOT is NOT
- 20. G2.2. 18 O95INEW/SRO/C/A 2.61.912.2.1 8//2/VAL 0-1 FIXED/REPLACEMENT Feedback -
NMP-OS-010, V4.0 step 6.3 provides the following guidance:
Additional Considerations for PWR Mid-Loop Operations During mid-loop operations at PWRs, it is particularly important that work in progress has no impact on Reactor Coolant System water level controls or decay heat removal systems.
6.3.3 states
All work in the field must be re-approved prior to approaching the mid-loop operating condition. Prior approval shall be by a work group supervisor and an SRO on a Green Sheet similar to that shown in Attachment
- 6. Green Sheets shall accompany the work package and be on display in the field wherever a work activity is in progress.
Attachment 5 provides this additional information:
Do NOT perform ANY activity or manipulation on ANY systems that have the potential to affect:
- Reactor Coolant System Inventory
- Vital Power Supplies
- Diesel Generators
- Off Site Power Sources
- Containment Closure Do NOT perform ANY activity or manipulation on ANY systems without proper authorization Approved mid-loop Green Sheets are required for ALL in plant work activities during mid-loop. This includes both units and the switchyard NOTE: the work in the switchyard is not specified, Work activities could occur within the switchyard that would not have the potential to affect any offsite power source. This generic statement is intentional; eliminate the argument that the work in the switchyard CAN NOT occur at all.
(REF ACP-4.0)
A. Correct: see above B. Incorrect: 1)seeA
- 2) ALL work, including work in the switchyard shall be Re-approved prior to entering MID-LOOP operation on either unit.
Plausible: The work on the Unit 2 High Voltage Switchyard would seem Innocuous to a UNIT I Mid-Loop operation. Since there would be no Direct impact on the 230KV switchyard.
C. Incorrect: 1) Plausible: Since UNIT 1 Condensate system does NOT affect any of the systems listed on attachment 5. one could believe that this requirement is unnecessary.
2)SeeA.2 D. Incorrect 1)SeeC.1
- 2) See B2 Plausible: Without knowledge of the requirements of NMP-OS-O1 0 and the amplification/clarification contained within Attachement 5, one could perceive that there is NO direct impact on those systems listed and there would be no need to implement a Green Sheet.
- 20. G2.2. 18 095/NEW/SRO/C/A 2.6/3 .9/G2.2 .1 8//2/VAL 0-1 FIXED/REPLACEMENT Notes K/A statement G2.2.18 Knowledge of the process for managing maintenance activities during shutdown operations.
Importance Rating: 2.6 3.9 Technical
Reference:
NMP-OS-010, v4.0 References to be provided: NONE Learning Objective: Using plant procedures as a guide, evaluate a maintenance item for release and determine if it can be released and what actions are required.
(OPS52303N01)
Given a set of conditions during performance of UOP-4.3, Mid-Loop Operations and RCS Fill and Vent, EVALUATE plant conditions and DETERMINE the appropriate actions that need to be taken (OPS-40503D03).
Question origin: NEW Comments: KA match: Knowledge of work control/release during MID-LOOP operation = shutdown operations.
SRO justification: Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations. [10 CFR 55.43(b)(5)]
Knowledge of when to implement attachments and appendices, including how to coordinate these items with procedure steps Addiitonally, The task of approving or permitting work to proceed (approving work orders) is assigned to the SRO for the positions of (SS, SM, SSS-Plant, or Work Control Center SRO)
Southern Nuclear Operating Company SOLJTHERNa Nuclear ManagmQnt I Protected Train/Division and Protected NMP-OS-010 COM E[pmenI Program in 4.0 Procedure Page 8 of 15 Protected Equipment Tape is used to establish a barrier around protected equipment if placards are NOT feasible. Consider this method to protect larger pieces of equipment, such as the Instrument Air Compr essor, Condensate Pumps, etc.
Cones or stanchions with Protected Equipment signs affixed are acceptable for equipment areas such as MCCs that are not behind a closable door.
6.2.10 Operation of Protected Equipment If maintenance or testing must be performed on protected equipm ent, then that equipment is no longer protected.
6.2.10.1 Remove the protected equipment postings while the maintenance is in progress.
6.2i0.2 Implement contingency measures as necessary to ensure plant reliability and safety are maintained.
62.10.3 Normal starting of protected equipment is allowed under the follow ing conditions:
Shift Manager gives permission after evaluating the risk Shift Supervisor participates in the Pre-Job Briefing A peer check or concurrent verification is performed for the operati on Direct supervisory oversight is present for the operation 6.2.11 Removing Protected Equipment and Protected Equipment Area Signs 6.2.11 .1 When equipment no longer needs to be protected, then the applica ble Protected Equipment and Protected Equipment Area signs shall be remov ed. Removal is recorded in the applicable log.
6.3 Additional Considerations for PWR Mid-Loop Operations During mid-loop operations at PWRs, it is particularly important that work in progress has no impact on Reactor Coolant System water level controls or decay heat removal systems.
6.3.1 Approximately 2 days before entry into mid-loop operating conditi ons, the Operations Manager will send a letter to all on site employees similar to Attach ment 4.
6.3.2 All beginning of shift briefings for periods when the plant will be at mid-loop will include the information presented in Attachment 5, Pre Shift Briefing Mid-L oop Dos and Donts.
63.3 All work in the field must be re-approved prior to approaching the mid-loop operating condition. Prior approval shall be by a work group supervisor and an SRO on a Green Sheet similar to that shown in Attachment 6. Green Sheets shall accompany the work package and be on display in the field wherever a work activity is in progress.
6.3.4 A manager or Operations Supervisor shall walk down plant areas twice shiftly while at mid-loop to ensure no work is in progress without an approved Green Sheet.
I i
SOUTHERN Nuclear Management Procedure Southern Nuclear Operating Company Protected Train/Division and Protected Equ[pmt PrOgra NMP-OS-O1O VersIofl Page 9 of 15 f
6.3.5 Other supervision, management, operators, security personnel and observers who enter plant areas shall ensure a Green Sheet on display wherever workers are present.
6.3.6 Work without a Green Sheet will be stopped until the work is evaluated and appropriate approvals are obtained. A Condition Report shall be generated for any instance of work during mid-loop without a Green Sheet.
7.0 Records None, completed Protected Equipment Logs should be routed to the Operations Superintendent-Daily for review and then they may be discarded.
8.0 Commitments None
Southern Nuclear Operating Company Nuclear NMP-OS-010 5OUTHERN S Management Protected Train/Division and Protected Version 4.0 Procedure EqwpmentProram Page 14 of 15 Attachment 5 Pre Shift Briefing Mid-Loop Dos and Donts MID-LOOP OPERATION DOS Inform the Control Room of ANY primary system leaks or system draining Perform ONLY those activities approved to work during mid-loop operations designated by the Green Sheets. This includes all work on both units and the switchyard.
If required, support RHR and inventory recovery actions as directed by Operations.
If in doubt, ASK questions. Call the Operations Outage Manager at {Phone number)
MID-LOOP OPERATION DONTS Don NOT manipulate ANY valve or component unless authorized by Operations Do NOT perform ANY activity or manipulation on ANY systems that have the potential to affect:
- Reactor Coolant System Inventory
- Vital Power Supplies
- Diesel Generators
- Off Site Power Sources
- Containment Closure Do NOT perform ANY activity or manipulation on ANY systems without proper authorization Approved mid-loop Green Sheets are required for ALL in plant work activities during mid-loop This includes both units and the switchyard
Southern Nuclear Operating Company SOUTHERNAI&
COMPANY Nuclear Management Procedure I
i -
Protected Train/Division and Protected
- Equipment program I Green Sheet Authorization for Work Activity During Mid-Loop Operations NMP-OS-O1 0 Version 4.0 Page l5of 15 1 GREEN SHEET Mid-Loop Operations MWO#
Description of Work______________________________
Supervisor______________________ I____
Date SRO_____________________ I___
Date EXAMPLE
- 96. G2.3.12 096/MOD FNP BANK!SRO/C/A 3.213.71G2.3.12/N/3IIJAN 13 Unit 2 has been in Mcde.6 for 3 weekand the. foIIowingcond.itions exist:
- Fuel movement is in progress.
- The following Alarms actuate:
FH2, SFP LVL Hl-LO EC5, RCS LVL HI-LO PG3, CTMT SUMP LVL HI-HI OR TRBL.
- SFP and Refueling Cavity Levels are 152 and dropping.
- Leakage around the Reactor Cavity Seal has been reported from Containment.
- Carriage at Pit lamp is ON in the SEP room.
- A used Fuel assembly is in the SEP side upender in the lowered position.
Which one of the following completes the statements below per AOP-30.O, Refueling Accident?
The fuel assembly (1) be left in its current position before the fuel transfer tube gate valve is closed.
The method that will be used to fill the reactor cavity will be from (2)
(1) (2)
A. MAY the boration flowpath lAW AOP-12.O, Residual Heat Removal System Malfunction B MAY the RWST lAW SOP-7.O, Residual Heat Removal System C. may NOT the boration flowpath lAW AOP-12.O, Residual Heat Removal System Malfunction D. may NOT the RWST lAW SOP-7.O, Residual Heat Removal System
- 21. G2.3.12 096/MOD FNP BANKJSRO/C/A 3.2/3.7/G2.3.12/N/3//JAN 13 Feedback -
AOP-30 step 1 requires that the fuel assembly is placed in a safe location which includes of the following:
[] Place fuel assembly in upender with manipulator crane gripper disengaged and raised to the GRIPPER UP DISENGAGED position.
[1 Place fuel assembly in the spent fuel rack.
20.3 Align remaining RHR pump to fill refueling cavity from RWST using FNP-1-SOP-7.O, RESIDUAL HEAT REMOVAL SYSTEM.
A. Incorrect 1) The fuel may be left in its current location since this location is a Safe Location per AOP-30 step 1 and there are no impediments (Cart cable) to closing the Gate valve.
- 2) see C.2 Plausible since entry conditions for AOP-1 2 are met with EC5 in alarm, and AOP-12 does direct filling/raising level.
B. Correct 1) The fuel may be left in its current location since this location is a Safe Location per AOP-30 step 1 and there are no impediments (Cart cable) to closing the Gate valve.
- 2) Step 20.3 will direct filling the Refueling Cavity from the RWST using SOP-TO.
C. Incorrect 1) Location is acceptable. see B.1
- 2) Fill source and procedure are not correct. AOP-30 is implemented (entry condition) rapidly falling refueling cavity level is observed. If cavity level is rapidly falling then the fill rate from the boration flowpath source is likely insufficient to recover inventory.
Plausible, since IF the fuel transfer cart was in the Refueling Cavity, which would prevent the closure of the gate valve, and would require it to be moved. ALSO, one might consider that the fuel assembly must be up-righted to be considered in a Safe Location. Various interlocks associated with the CART, the gate valve position and the UPENDER position could be confused to believe that movement of the fuel assembly is required.
- 2) See plausibility for A.2 D. Incorrect 1)SeeC.1
- 2) See B.2
- 21. G2.312 096/MOD FNP BANKJSRO/C/A 3.213.71G2.3.12/N13/IJAN 13 Notes K/A statement G2.3.12 Knowledge of radiological safety principles pertaining to licensed operator duties, such as containment entry requirements, fuel handling responsibilities, access to locked high-radiation areas, aligning filters, etc.
Importance Rating: 3.2 3.7 Technical
Reference:
FNP-1-AOP-30.0 Version 14, ARP-3.3 PG3, ARP-1 .6 FH4 & FH5, AOP-12 Revision 18.0 References provided: None Learning Objective: Given a set of conditions during performance of UOP-4.1, Controlling Procedure for Refueling, EVALUATE plant conditions and DETERMINE the appropriate actions that need to be taken. (OPS-6251 1 BOl)
EVALUATE plant conditions and DETERMINE if transition to another section of AOP-30.0, Refueling Accident, or to another procedure is required. (OPS-62521 H02)
Question origin: MODIFIED FNP Bank (AOP-30.0-62521 H02 001) NO LONGER a match to 2008 NRC exam question.
Basis for meeting K/A: During fuel handling, the Refueling Supervisor (SRO in charge of fuel handling) has the sole responsibility for evaluating placement of fuel during a fuel handling accident.
This evaluation is necessary to place the fuel in the event dependent location that will most likely preclude a high dose rate for the protection of personnel specifically mitigating potentially high dose rate conditions during a fuel handling accident OR leak which reduces the shielding above the high dose irradiated fuel SRO justification: 10 CFR 55.43(b)(5)
From the Clarification Guidance for SRO-only Questions Rev I dated 03/11/2010 flowchart for 10 CFR 55.43(b)(5):
Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations [10 CFR 55.43(b)(5)J, involving BOTH:
- 1) assessing plant conditions and then
- 2) selecting a procedure or section of a procedure to mitigate, recover, or with which to proceed One area of SRO level knowledge is knowledge of content of the procedure vs. the procedures overall mitgative
strategy or purpose.
Fuel handling facilities and procedures.
Some examples of SRO exam items for this topic include:
Refuel floor SRO responsibilities.
The Fuel Handling Supervisor (FHS) is responsible for placing the Fuel in a safe location upon any fuel handling accident. The FHS must then be familiar with the acceptable locations that are safe locations.
2011 NRC exam There is NO flow chart available for 10 CFR 55.43(b)(7) within Clarification Guidance for SRO-only Questions Rev 1(03/11/2010).
The item specifically listed as an example for this topic.
From the Clarification Guidance for SRO-only Questions Rev 1 dated 03/11/2010 flowchart for 10 CFR 55.43(b)(5):
Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations [10 CFR 55.43(b)(5)J, involving BOTH:
- 1) assessing plant conditions and then
- 2) selecting a procedure or section of a procedure to mitigate, recover, or with which to proceed.
Using the flowchart, this question can:
- NOT be answered solely by knowing systems knowledge, i.e., how the system works, flowpath, logic, component location. (although knowledge of the FHS interlocks and the location of the cart with relation to the gate valve closure can be answered based on Systems knowledge, the added level of knowledge required is that of safe fuel storage locations.)
- NOT be answered solely by knowing immediate operator actions.
- NOT be answered solely by knowing entry conditions for AOPs or plant parameters that require direct entry to major EOPs.
- NOT be answered solely by knowing the purpose, overall sequence of events, or overall mitigative strategy of a procedure. (This question specifically asks HOW the cavity will be filled. Filling the cavity is part of the mitigative strategy, but the SRO must have knowledge of the specific content of the procedure and the required sub-procedure necessary to implement to accomplish that goal).
- be answered with knowledge of ONE or MORE of the following:
Assessing plant conditions (normal, abnormal, or emergency) and then selecting a procedure or section of a procedure to mitigate, recover, or with which to proceed.
Knowledge of when to implement attachments and appendices, including how to coordinate these items with procedure steps.
Knowledge of diagnostic steps and decision points in the EOPs that involve transitions to event specific sub-procedures or emergency contingency procedures. (SOP-7.0 vs AOP-12.0 are the equivalent event specific sub-procedures implemented from AOP-30.0).
Knowledge of administrative procedures that specify hierarchy, implementation, and/or coordination of plant normal, abnormal, and emergency procedures.
07/13/10 8:08:41 FNP-1-AOP-30.O REFUELiNG ACCIDENT Version 17.0 Step Action/Expected Response Response Not Obtained ii r NOTE:
- A high alarm from R-25A or B will automatically isolate fuel building HVAC and start penetration room filtration.
- The Refueling Supervisor, or Cask Supervisor for dry storage activities, shall have sole responsibility for evaluating placement of fuel in step 1.
- The Refueling Supervisor, or Cask Supervisor for dry storage activities, shall have sole responsibility for evacuation of the refueling or dry storage crew.
Secure all Fuel Handling operations:
1.1 fuel movement in progress and conditions permit, THEN place fuel assembly in a safe location by one of the following:
[1 Return fuel assembly to assigned location in the core.
[] Place fuel assembly in upender with manipulator crane gripper disengaged and raised to the GRIPPER UP DISENGAGED position.
[1 Place fuel assembly in the spent fuel rack.
[J Place fuel assembly in the multi purpose canister (MPC) fuel basket.
{] Lower the MPC into the cask storage area or cask wash area, as appropriate.
1.2 Verify CTMT and spent fuel room upenders LOWERED.
1.3 Verify CONVEYER CONTROL switch in ON at CONTAINMENT BUILDING panel.
1.4 Verify CARRIAGE AT PIT lamp is ON.
(155 ft. AUX BLDG spent fuel room control panel) 1.5 Close fuel transfer tube gate valve.
(155 ft, AUX BLDG spent fuel room)
Step 1 continued on next page
_Page Completed Page 2 of 8
07/13/108:08:41 FNP-1-AOP-30.0 REFUELING ACCIDENT -
Ytsiou 17.0 Step Action/Expected Response Response Not Obtained 15 Evaluate placing spent fuel pool purification system in service using FNP-1-SOP.-54.O, SPENT FUEL PIT COOLING AND PURIFICATION SYSTEM.
16 Evaluate placing containment preaccess filtration system in service per FNP-1-SOP-12.2, CONTAINMENT PURGE AND PRE-ACESS FILTRATION SYSTEM.
17 Consult Operations Manager to evaluate further plant response.
18 Go to procedure and step in effect.
NOTE: Efforts to determine source of inventory loss should be performed in parallel with makeup efforts below. Possible sources of inventory loss include damaged nozzle dams, reactor cavity seal or spent fuel pooi liner, or RHR system malfunctions. Refer to FNP-1-AOP-12.0, RESIDUAL HEAT REMOVAL SYSTEM MALFUNCTION for RHR malfunctions.
19 Place CTMT SUMP PUMPs Q1G21PO19A and Q1G21PO19B in PULL-TO-LOCK.
20.1 Verify only one RHR PUMP STARTED -
IN COOLDOWN ALIGNMENT.
20.2 [CA] Monitor running RHR pump for evidence of cavitation.
20.3 Align remaining RHR pump to fill 20.3 Align one charging pump or the refueling refueling cavity from RWST using water purification pump to fill the refueling FNP-1-SOP-7.0, RESIDUAL HEAT cavity.
REMOVAL SYSTEM.
Page Completed Page 7 of 8
2/14/2011 11:07 FNP-1-AOP-12.O RESIDUAL HEAT REMOVAL SYSTEM MALFUNCTION Revision 24 B. Symptoms or Entry Conditions This procedure is entered when a malfunction of the RI-IR system is indicated by any of the following:
1.1 Trip of any operating RHR pump 1.2 Excessive RI-IR system leakage 1.3 Evidence of running RHR pump cavitation 1.4 Closure of loop suction valve 1.5 High RCS or core exit T/C temperature 1.6 Procedure could be entered from various annunciator response procedures.
CF3 1A OR lB RHR PUMP OVERLOAD TRIP CF4 1A RHR HX OUTLET FLOW LO CF5 lB RHR HX OUTLET FLOW LO CG3 1A OR lB RHR HX CCW DISCH FLOW RI EA5 1A OR lB RHR PUMP CAVITATION EB5 MID-LOOP CORE EXIT TEMP HI EC5 RCS LVL HI-LO Page 2 of 24
2/14/2011 11:07 FNP-1-AOP-12 .0 RESIDUAL HEAT REMOVAL SYSTEM MALFUNCTION Revision 24 Step Action/Expected Response Response NOT Obtained lIE I I CAUTION: Containment closure is required to be completed within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of the initiating event unless an operable RHR pump is placed in service cooling the RCS the RCS temperature is below 180°F.
CAUTION: Filling the pressurizer to 100% will cause a loss of nozzle dams due to the head of water.
NOTE: RCS to RHR loop suction valves will be deenergized if RCS TAVG is less than 180°F.
1 Check RHR loop suction valves - 1 Stop any RHR PUMP with closed OPEN. loop suction valve(s) 1.1 IE required, RHR PUMP 1A lB THEN adjust charging flow to maintain RCS level.
lC(1A) RCS LOOP TO lA(1B) RHR PUMP Q1E11MOV [1 8701A [] 8702A
[] 8701B [1 8702B 1C(1A) RCS LOOP TO 1A(1B) RHR PUMP [1 FU-T5 [] FU-G2 LOOP SUCTION POWER [1 FV-V2 [] FV-V3 SUPPLY BREAKERS CLOSED (IF REQUIRED) 2 IF the cause of the RBR malfunction is known AND does not affect the standby RUR train, TEEN place the standby RHR train in service per FNP-l-SOP-7.O. RESIDUAL HEAT REMOVAL SYSTEM.
Page 3 of 24
- 1. AOP-30.0-6252 1 H02 00 1/HLT/SRO/C/A 3 .213.71G2.3.12/fIl been in Mode 6 for 3 weeks, and the following conditions exist:
- Fuel movement is in progress.
- SEP and Refueling Cavity Levels are 152 and dropping.
- FH2, SEP LVL HI-LO, is in alarm.
- EC5, RCS LVL HI-LO, is in alarm.
- Leakage around the Reactor Cavity Seal has been reported from Containment.
- Carriage at Pit lamp is ON in SEP room.
- A used Fuel assembly is in the SFP side upender in the lowered position.
Which ONE of the following describes the correct responses to these conditions per AOP-30.O, Refueling Accident?
A. Close fuel transfer tube gate valve and leave the fuel assembly in its current location.
- Line up to fill the RCS from the boration flowpath lAW AOP-12.O, Residual Heat Removal System Malfunction.
By Close fuel transfer tube gate valve and leave the fuel assembly in its current location.
- Line up to fill the reactor cavity from the RWST lAW SOP-7, Residual Heat Removal System.
C.
- Place fuel assembly in the SEP racks, then close the gate valve.
- Line up to fill the RCS from the boration flowpath lAW AOP-12.O, Residual Heat Removal System Malfunction.
D. . Place fuel assembly in the SFP racks, then close the gate valve.
- Line up to fill the refueling cavity from the RWST lAW SOP-7, Residual Heat Removal System.
A. Incorrect First part is correct per AOP-30, which is the controlling procedijre for these conditions. Second part incorrect, but plausible since entry conditions for AOP-1 2 are met with EC5 in alarm, and AOPrI 2 does direct filling from the boration path. AOP-30 does not direct the operator to AOP-12 to fill the RCS. AOP-30 directs using SOP-7 to fill from the RWST.
B. Correct AOP-30 directs the assembly to be placed in the upender and lowered and moved to the SEP room so the gate valve can be closed. The assembly is then left in this location while the problem is resolved and to make sure the SEP level is not decreasing. Then at a later time the assembly would be moved to the SFP racks.
C. Incorrect First part incorrect, but plausible, since the SEP racks are a safe location for the fuel during a leak which lowers level. The fuel is in a safe place and should not be moved prior to closing the gate valve. Second part incorrect, but plausible since entry conditions for AOP-1 2 are met with EC5 in alarm, and AOP-30 directs AOP-12 isolation of a leak for an RHR malfunction.
D. Incorrect First part incorrect (see C). Second part correct (see B).
K/A statement - G2.3.12 Knowledge of radiological safety principles pertaining to licensed QRerator duties, such as containment entry requirements, fuel handling responsibilities, access to locked high-radiation areas, aligning filters, etc.
Importance Rating: 3.2 3.7 Technical
Reference:
FNP-1-AOP-30.0 Version 14, ARP-3.3 PG3, ARP-1.6 FH4 & FH5, AOP-12 Revision 18.0 References to be provided: None Learning Objective: Determine the appropriate action for given conditions during performance of UOP-4.1, [CONTROLLING PROCEDURE FOR REFUELING] (0PS40503B03).
Question origin: 2008 HLT 32 NRC Exam Comments: K/A Match: During fuel handling, the Refueling Supervisor (SRO in charge of fuel handling) has the sole responsibility for evaluating placement of fuel during a fuel handling accident. This evaluation is necessary to place the fuel in the event dependent location that will most likely preclude a high dose rate for the protection of personnel specifically mitigating potentially high dose rate conditions during a fuel handling accident OR leak which reduces the shielding above the high dose irradiated fuel SRO justification: 10 CFR 55.43 (b) (5 & 6)
This question requires recalling what strategy or action is written into a plant procedure, including when the strategy or action is required. It also requires the SRO to know his unique responsibilities for radiological safety principles pertaining to his duties during fuel handling,
- 97. G2.3.6 097/MOD FNP BANKJSRO/MEM 2.0/3.81G2.3.6/N/2/IJAN 13 Unit 1 is operating at 100% power, and the following conditions exist
- A release of the #2 Waste Monitor Tank (WMT) is planned.
- R-18, Liquid Radwaste Effluent Monitor, is INOPERABLE.
- Chemistry has taken two (2) samples of the #2 WMT and reports the activity is
<1 .4 xl O- pCi/mL and is within the normal limits for a release.
- Two Shift Radio-Chemists have verified the manual input for the computer generated release rate calculation.
Which one of the following completes the statement below?
A WMT release (1) permitted (2) per the ODCM.
(1) (2)
A. is NOT UNTIL R-18 is returned to service B. is NOT UNTIL the activity is lowered less than <lxi iJCi/mL IS BUT two qualified plant personnel are required to verify the discharge lineup D. IS BUT an SRO is required to verify the discharge lineup and the entire release rate calculation
- 22. G23.6 097/MOD FNP BANKJSRO/MEM 2.0/3.8/G2.3.6/N/2//JAN 13 Feedback ODCM v24.0 A. Incorrect A release could be held until RE-18 is operable, and this may be chosen as the conservative action, but it is not required per the ODCM. The ODCM directs the ACTION shown in Table 2-1, which permit a release if all conditions can be completed.
Plausible: if a release was on-going when R-i 8 became inoperable then the release must be immediately stopped. (SOP-50.0, v66.0, P&L 3.3)
B. Incorrect The release limit of lxi iJCi/mL is that for SGBD per action 29, not applicable to the R-18 release path, therefore a release is permitted at this activity. The activity is NOT too high for release assuming all the requirements of the ODCM are met.
Plausible: Two consecutive samples must be taken, and must be within release limits (the release limit provided exceeds the limit which is applicable only to SGBD Release path).
C. Correct This answer choice describes the actions required by ACTION 28 of the of Table 2-1 of the ODCM which states the effluent releases may continue provided that prior to initiating the release:
- a. Two separate samples must be analyzed,
- b. two independent qualified members of facility staff verify the discharge line valving and verify:
- 1) the manual portion of the computer input for the release rate calculations OR
- 2) the entire release rate calculations if performed manually.
A liquid release permit is required to be reviewed by the SSS per SOP-50.1 appendices i&2 to verify the above requirements are satisfied.
D. Incorrect AN SRO is NOT required to verify either the valve lineup or the calculation. The ODCM requires that the release rate calculations are verified by TWO qualified facility personnel, and the discharge flowpath also verified by TWO qualified facility personnel; NEITHER requires an SRO and both are normally not performed by an SRO. The System operators normally complete the valve lineup and verification while the Chemists normally complete the calculations and verifications. Further, the entire release rate calculation is not REQUIRED unless the calculation is done manually, but again is not REQUIRED to be performed by an SRO.
Although an SRO is not restricted from these verifications and would not be incorrect if SROs functioned as one or both of the TWO verifications; however the answer only states that a single (an) SRO performs the verification, the REQUIREMENT is that TWO personnel perform the verification.
lausile: Two quallfled faculty staff must verifthe release path, an SRO could satisfy one or both of those personnel requirements, though normally conducted by SO. An SRO is required to review the release permit per step 2.5.3 of SOP-50.1 Appendix 1, it is plausible that one might believe that since the chemists ony verified the manual input to the calculations that the entire calculation must still be verified, or that they do not meet the requirements of the ODCM.
- 22. G2.3.6 097/MOD FNP BANKJSRO/MEM 2.0/3.8/G2.3.6/N/2//J AN 13 Notes K/A statement G2.3.6 Radiation ControlAbil ity to approve release permits.
Importance Rating: 2.0 3.8 Technical
Reference:
ODCM, Version 24 References provided: None Learning Objective: OPS-62106A01RECALL AND APPLY the informati on from the LCO BASES sections: BACKGROUND, APPLICABLE SAFETY ANALYSIS, ACTIONS, SURVEILLENCE REQUIREMENTS, for any Tech nical Specifications or TRM requirements associated with Liquid and Solid Waste System components and attendant equipment alignment, to include the following
- 5.5.1, Offsite Dose Calculation Manual (ODCM)
Question origin: MODIFIED FROM FNP Bank (LIQ SD WAST-62106A01 003 which was used on 2008 NRC exam)
Basis for meeting K/A: The SRO must approve a release if ODCM actio ns are met prior to the release, although for a normal release the Chemistry Department provides the FINAL approval of the permit, the affected units SS (SRO) must first prov ide approval. This question provides a scenario in whic h the release cannot be allowed until ODCM actions are accomplished as determined by the SRO, and the applicant must recall what completed actions allow approvin g the release.
SRO justification: 10CFR55.43 (b) (2)
Requires application (and knowledge) of REQUIR ED ACTIONS required by the ODCM.
10 CFR 55.43 (b) (5 & 6)
This question requires recalling what strategy or actio n is written into a plant procedure, including when the strategy or action is required.
2011 NRC exam 10 CFR 55.43(b)(2)
Facility operating limitations in the TS and their base
- s. [10 CFR 55.43(b)(2)]
From the Clarification Guidance for SRO-only Questions Rev I dated 03/11/
2010 flowchart:
- 1) can NOT be answered by knowing less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Tech Specs.
- 2) can NOT be answered by knowing information listed above-the-line.
- 3) can NOT be answered by knowing the TS Safety Limits or their bases.
- 4) Does involve one or more of the following for TS, TRM or ODCM:
- Application of Required Actions (Section 3) and Surveillance Requirements (Section 4) in accordance with rules of application requirements (Section 1).
- Knowledge of TS bases that is required to analyze TS required actions and terminology
FNP-ODCM CHAPTER 2 LIQUID EFFLUENTS 2.1 LIMITS OF OPERATION The following Liquid Effluent Controls implement requirements establi shed by Technical Specifications Section 5.0. Terms printed in all capital letters are defined in Chapter 10.
2.1.1 Liquid Effluent Monitoring Instrumentation Control In accordance with Technical Specification 5.5.4.a, the radioactive liquid effluent monitoring instrumentation channels shown in Table 2-1 shall be OPERABLE with their alarm/trip setpoints set to ensure that the limits specified in Section 2.1.2 are not exceeded.
The alarm/trip setpoints of these channels shall be determined in accordance with Section 2.3.
2.1.1.1 Applicability This limit applies at all times.
2.1.1.2 Actions With a radioactive liquid effluent monitoring instrumentation channe l alarm/trip setpoint less conservative than required by the above control, immediately suspen d the release of radioactive liquid effluents monitored by the affected channel, declare the channe l inoperable, or change the setpoint to a conservative value.
With less than the minimum number of radioactive liquid effluent monito ring instrumentation channels OPERABLE, take the ACTION shown in Table 2-1. Restore the inoperable instrumentation to OPERABLE status within 30 days and, if unsuccessful, explain in the next Radioactive Effluent Release Report pursuant to Section 7.2 why this inoperability was not corrected in a timely manner.
This control does not affect shutdown requirements or MODE change s.
2.1.1.3 Surveillance Requirements Each radioactive liquid effluent monitoring instrumentation channel shall be demonstrated OPERABLE by performance of the CHANNEL CHECK, SOURCE CHEC K, CHANNEL CALIBRATION, and CHANNEL OPERATIONAL TEST (COT) operati ons at the frequencies shown in Table 2-2.
2-1 Version 24 01/10
FNP-ODCM 2.1.1.4 Basis The radioactive liquid effluent instrumentation is provided to monitor and control, as applicable, the releases of radioactive materials in liquid effluents during actual or potent ial releases of liquid effluents. The Alarm/Trip Setpoints for these instruments shall be calcula ted and adjusted in accordance with the methodology and parameters in Section 2.3 to ensure that the alarm/trip will occur prior to exceeding the limits of Section 2.1.2. The OPERABILITY and use of this instrumentation is consistent with the requirements of General Design Criteri a 60, 63, and 64 of Appendix A to 10 CFR Part 50.
2-2 Version 24 01/10
FNP-ODCM
- Table 2-1 Rdioactivé L[quid Effluent Monitoring Instrumentation OPERABILITY Requirementsa Instrument Minimum Channels OPERABLE ACTION
- 1. Gross Radioactivity Monitors Providing Automatic Termination of Release
- a. Liquid Radwaste Effluent Line (RE-18) 1 28
- b. Steam Generator Blowdown Effluent Line (RE-23B) 1 29
- 2. Flowrate Measurement Devices
- a. Liquid Radwaste Effluent Line
- 1) Waste Monitor Tank No. 1 1 30
- 2) Waste Monitor Tank No. 2 1 30
- b. Discharge Canal Dilution Line (Service Water) 1 30
- c. Steam Generator Blowdown Effluent Line 1 30
- a. All requirements in this table apply to each unit.
2-3 Version 24 01/10
FNP-ODCM Table 24 (Oontd) Nbtatin for Table 2-1 - ACTION Statements ACTION 28 With the number of channels OPE RABLE less than required by the Minimum Channels OPERABLE requirement, effluent relea ses may continue provided that prior to initiating a release:
- a. At least two independent samples are analyzed in acco rdance with Section 2.1.2.3, and
- b. At least two technically qualified members of the Facility Staff independently verify the discharge line valving and (1) Verify the manual portion of the computer input for the release rate calculations performed on the computer, or (2) Verify the entire release rate calculations if such calculations are performed manually.
Otherwise, suspend release of radioactive effluents via this pathway.
ACTION 29 With the number of channels OPERAB LE less than required by the Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue, provided grab samples are analyzed for gross radio activity (beta or gamma) at a MINIMUM DETECTABLE CONCENTRATION no high er than 1 x lOpCi/mL.
7
- a. At least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> when the specific activity of the secondary coolant is greater than 0.01 tCi/gram DOSE EQUIVALENT 1-131.
- b. At least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when the specific activ ity of the secondary coolant is less than or equal to 0.01 tCi/gram DOSE EQUIVALEN T 1-131.
ACTION 30 With the number of channels OPERAB LE less than required by the Minimum Channels OPERABLE requirement, effluent relea ses via this pathway may continue, provided that 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 /> during actual releases.
Pump curves may be used to estimate flow.
2-4 Version 24 01/10
05/17/10 15:17:22 FNP-1-SOP-50.0 3.0 Precautions and Limitations 3.1 Due to the presence of radioactive or potenti ally radioactive materials within the confines of the liquid waste processing sys tem, constant vigilance must be exercised over system piping, valves, tank s, and other components whether in operation or shutdown. Pre-operational che cks and normal routine operations and surveillance should include visual checks for system deterioration, component leakage, and correct system line-up which if not detected and corrected could subsequently result in the release of radioac tive liquid to the immediate area, the environment, or other parts of this system 3.2 Radiation monitor R- 18 must be operab le and in service during liquid waste discharge to the river except as permitted by technical specifications.
3.3 IF R-18 becomes inoperable while dischar ging liquid waste to the river, THEN the discharge must be stopped imm ediately.
3.4 The Shift Supervisor or Shift Support Sup ervisor shall be notified any time R- 18 is taken out of service or becomes inoper able.
3.5 A Radioactive Liquid Release Permit mu st be completed and approved prior to discharging radioactive liquid to the rive r.
3.6 Verify that tanks aligned to receive liquid waste discharge have sufficient capacity to receive the liquid.
3.7 Tank levels shall be monitored periodical ly during processing, discharge or transfer of liquid waste. For processing or transfers, the levels of the source tank and the destination tank should be determi ned. The approximate flow rate should be considered and used to determine an app roximate completion time. Tank levels shall be checked prior to the estimat ed completion of the processing or transfer such that sufficient margin exists to prevent tank overflow. At no time should the High Level Alarm be relied upo n for securing the processing or transfer of a tank. To preclude overflow, waste tanks should not be filled to greater than 95%.
3.8 A deficiency report should be written to rep lace liquid waste system filters when the IXP increases to greater than 20 psid.
3.9 Caution should be exercised when pumpin g liquids to ascertain that affected pumps do not lose suction.
3.10 Once a WMT has been placed on recircu lation for sampling purposes, prior to discharging to the environment, the tank shall remain in an isolated condition to prevent the introduction of any liquids whi ch could alter the concentrations of the tanks contained volume.
Version 66.0
- 1. LIQ SD WAST-62106A01 OO3JHLT/SRO/MEM 2.0/3 .8/G2.3 .6/I/I Unit 1 is operating at 100%power,.a nd the following conditions exist BANKquesTW
- A release of the Waste Monitor Tank is planned.
- R-18, Liquid Radwaste Effluent Monito r is inoperable.
Which ONE of the following correctly stat es the required ODCM ACTIONS that the SRO who approves the release must ensure are completed?
A. R-18 must be returned to service; a rele ase cannot be conducted with R-18 inoperable.
B. Release rate calculations and sample results that show activity of the release liquid is <lxi microcuries per milliliter must be verifie d.
C Two separate samples must be analyze d, two independent qualified members of facility staff must verify disc harge valve lineup and release rate calculations.
D. The tank must be recirculated for two volumes and a Senior Reactor Operator must verify release rate calc ulations and discharge valve lineup.
A. Incorrect. Plausible, since applicant may confuse what the conditions consist and if all conditions are not met then of no release can be made. A release could be held until RE-18 is operable, and this may be chosen as the conservative action, but it is not require d per the ODCM.
B. Incorrect. Plausible, since per the OD CM action 29 a release to the environmen with an inoperable Steam Generator t Blowdown (SGBD) effluent monitor (RE-23B) may be made provided the rele ase limit of lxi 7 microcuries per milliliter is not exceeded.
C. Correct. Two separate samples must be analyzed, two independent qualified members of facility staff verify discharge valve lineup and verify release rate calculations per ODCM.
D. Incorrect. Plausible since the tank must be recirculated for two volumes for releases (SOP-50.iApp. 1, step 2.3.13) normal
, an SRO does review the calculations for each normal release (SO P-50.iApp. 1, step 2.5.3), and the verifiy release rate calcs and dischar ge valve lineup is correct, except two staff members must perform these.
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K/A statement G2.3.6 Radiation ControlAbility to approve release permits.
tmportane Rating: 2.0 3.8 BANK question Technical
Reference:
ODCM, Version 24 References to be provided: None Learning Objective: OPS-62106A01RECALL AND APPLY the information from the LCO BASES sections: BACKGROUND, APPLICABLE SAFETY ANALYSIS, ACTIONS, SURVEILLENCE REQUIREMENTS, for any Technical Specifications or TRM requirements associated with Liquid and Solid Waste System components and attendant equipment alignment, to include the following 5.5.1, Offsite Dose Calculation Manual (ODCM)
Question origin: FNP Bank (LIQ SD WAST-62106A01 003) 2008 HLT 32 NRC Exam Comments: k/a match: The SRO must approve a release if ODCM actions are required to be met prior to the release, even though for a normal release the Chemistry Department approves the release after an SRO review of the permit.
This question provides a scenario in which the release cannot be allowed until ODCM actions are accomplished as determined by the SRO, and the applicant must recall what completed actions allow approving the release.
SRO justification: 10CFR55.43 (b) 2 Requires application (and knowledge) of REQUIRED ACTIONS required by the ODCM.
10 CFR 55.43 (b) (5 & 6)
This question requires recalling what strategy or action is written into a plant procedure, including when the strategy or action is required.
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