ML023290002
| ML023290002 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 01/09/2003 |
| From: | Ernstes M Operator Licensing and Human Performance Branch |
| To: | Sumner H Southern Nuclear Operating Co |
| References | |
| 50-321/02-301, 50-366/02-301, LR-GM-001-1102 50-321/02-301, 50-366/02-301 | |
| Download: ML023290002 (68) | |
See also: IR 05000321/2002301
Text
Post-examination Comments
(Green Paper)
E. I. HATCH NUCLEAR PLANT
EXAM 2002-301
50-321 & 50-366
OCTOBER 16 - 18, 21 - 25, &
OCTOBER 30, 2002,
Licensee Submitted Post-examination Comments
Peter H.Wells Southern Nuclear Operating Company, Inc.
Nuclear Plant Post Office Box 2010
General Manager Baxley, Georgia 31515
Edwin I.Hatch Nuclear Plant
Tel 912.537.5859
Fax 912.366.2077
SOUTHERN A
COMPANY
Energy to Serve Your World
November 5, 2002
LR-GM-001-1 102
Mr. Michael E. Ernstes
Chief Operator Licensing and Human Performance Branch
U. S. Nuclear Regulatory Commission, Region II
Atlanta Federal Center
61 Forsyth Street SW Suite 23T85
Atlanta, GA 30303
Subject: Facility Comments, Hatch License Examination
Dear Mr. Emstes:
Per ES-402 of NUREG 1021, E. I. Hatch is submitting the attached comments and
supporting references for the Operator License Examination completed on October 30,
2002. If you have any questions please contact John Lewis at 912-537-5929 or Steve
Grantham at 912-537-5916.
Nuclear Plant General Manager
Question Number: #7, SRO Exam
Justification: This question requires the candidate to 1) determine the time limit for
closing and deactivating a HPCI isolation vacuum breaker isolation valve
and 2) to determine HPCI operability. To make this determination, the
candidate must decide if HPCI meets the definition of operability, and
more specifically whether shutting the isolation valve affects the ability of
HPCI to meet its safety function.
It can be argued that loss of the ability of the vacuum breakers to function
to prevent water from being drawn into the HPCI turbine exhaust line does
not affect the ability of HPCI to inject water into the vessel and hence the
ability of HPCI to limit cladding temperature during a small break LOCA.
This argument is believed to form the basis for the accepted answer "D."
However, it can also be argued that an impact exists that will eventually
affect the safety function. An SSC is operable when it is capable of
performing its specified function(s) and when all necessary support SSCs
are also capable of performing their related support functions. Generic
Letter 91-18 references Chapter 9900, Technical Guidelines NRC
Inspection Manual, which states, "In the absence of reasonable
expectation that the SSC is operable, the SSC is to be declared inoperable
immediately." HPCI's design ensures that the reactor is sufficiently
cooled to limit cladding temperature during a small break LOCA. If HPCI
is started and subsequently stopped in this condition such that water is
drawn into the exhaust line, then during subsequent starts, the stresses on
the exhaust line would be increased above design. An indeterminate
number of repeated starts could result in damage to the exhaust line which
could affect the ability of HPCI to function. Chapter 9900 also states that
"indeterminate" is not a recognized state of operability. In fact, as noted in
the attached Hatch LER 2002-00 1, the HPCI vacuum breakers were
isolated and HPCI was declared inoperable due to the inability of the
vacuum breakers to function to prevent water from being drawn into the
exhaust line.
Since there are two lines of reasoning that may be argued, and given that
the candidates did not have access to FSAR and the bases document, the
recommendation is that both "B" and "D" be accepted as correct.
References: License Event Report (LER) 2002-001" Component Failure in a Limit
Switch Leads to Inoperability of HPCI System"
Recommendation: Accepting two correct answers, "B" and "D"
NRC Resolution:
QUESTIONS REPORT
for HATCH SRO Test
7. Unit 1 is operating at 100% RTP. The HPCI isolation valves are being stroked and
Breaker
timed per the Inservice Testing program when MO 1 E41 -F1 11 HPCI VacuumBreaker
Vacuum
Isolation Valve failed to close. The Shift Supervisordirected HPCI
Isolation Valve MO 1E41-F104 to be closed and deactivated.
MO 1E41-F104
Which ONE of the following describes the time limit for deactivating
is/are taken?
per Tech Specs and the effect on the HPCI system after the action(s)
(Provide Tech Spec section 3.6.1.3)
INOP and a 14 day
A. Actions must be taken within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. HPCI should be declared
LCO entered per TS 3.5.1.C.
INOP and a 14 day
B. Actions must be taken within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. HPCI should be declared
LCO entered per TS 3.5.1.C.
still be considered
C. Actions must be taken within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. HPCI system should
OPERABLE because it can still perform its safety function.
still be considered
DE Actions must be taken within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. HPCI system should
OPERABLE because it can still perform its safety function.
References: Tech Spec 3.6.1.3 for PCIVs
SI-LP-00501 Rev. 01, LT-00501 Fig. 1
SI-LP-00501 Rev. 01, pg 8 of 46
to isolate the line since
A. Incorrect since the actions for Tech Spec 3.6.1.3 is 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
1 valve is
there is more than 1 PCIV in the penetration flow path and only
should still be considered
INOPERABLE. Also, HPCI can still perform its function and
still be considered
B. Incorrect since HPCI can still perform its function and should
to isolate the line since
C. Incorrect since the actions for Tech Spec 3.6.1.3 is 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
1 valve is
there is more than 1 PCIV in the penetration flow path and only
D. Correct answer.
7
Friday, November 01, 2002 10:53:21 AM
Docket No. 50-366 HL-6238
U.S. Nuclear Regulatory Commission
ATTN: Document Control Desk
Washington, D.C. 20555
Edwin I. Hatch Nuclear Plant - Unit 2
Licensee Event Report
Component Failure in a Limit Switch Leads to
Inoperabilitv of HPCI System
Ladies and Gentlemen:
In accordance with the requirements of 10 CFR 50.73(a)(2)(v)(B) and 10 CFR 50.73(a)(2)(v)(D),
Southern Nuclear Operating Company is submitting the enclosed Licensee Event Report (LER)
concerning a component failure in a limit switch which lead to the inoperability of the HPCI
system.
Respectfully submitted,
H. L. Sumner, Jr.
IFL/eb
Enclosure: LER 50-366/2002-001
cc: Southern Nuclear Operating Comnanv
Mr. P. H. Wells, Nuclear Plant General Manager
SNC Document Management (R-Type A02.001)
U.S. Nuclear Regulator, Commission. Washington, D.C.
Mr. L. N. Olshan, Project Manager - Hatch
U.S. Nuclear Regulatory Commission. Region II
Mr. L. A. Reyes, Regional Administrator
Mr. J. T. Munday, Senior Resident Inspector - Hatch
Institute of Nuclear Power Operations
LEREvents@inpo.org
makucinjm@inpo.org
f.'RC FORM 366 U.S. NUCLEAR REGULATORY COMMISSION APPROVED BY OMB NO. 3150-0104 EXPIRES 7/31/2004
(7-2o01) Estimated burden per response to comply with this mandatory Information
_ collection request: 50.hrs.. Reported lessons learned are Incorporated into the
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estimate
RegulatorytoCommission,
the Records Management Branch (T-6 ES), U.S. Nuclear
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not display a currently valid OMB control number, the NRC may not conduct or
1. FACILI_____y
NAME_ sponsor, and a person is not required to respond to. the information collection.
1. FACILITY NAME 2. DOCKET NUMBER 3. PAGE
Edwin I. Hatch Nuclear Plant - Unit 2 05000-366 1 OF 5
4. TITLE
Component Failure in a Limit Switch Leads to Inoperability of HPCI System
S. EVENT DA E S. LER NUMBER 7. REPORT DATE 7P OTHER FACILITIES INVOLVED
YEAR SEOUENTIAA.REVISION MONTH IDAY YEAR NAME IFACIITY
DOCKET NUMBER(S)
INuMs NMuMER
1ACILITY
I' ii F NAME
I DOCKET05000
NUMBER(S)
03 28 200 2002 1 001 00 05 07 2002 AL: N 0DC 0ME0
9. OPERATINGf 1 11. THIS REPORT IS SUBMITTED PURSUANT TO THE REQUIREMENTS OF 10 CFR § (Check all that apply)
MODE 1 20.2201 (b) 20.2203(a)(3)(1i) 50.73(a)(2)(ii)(B) 50.73(a)(2)(ix)(A)
EVEL I
10.POWER 1100 20.2201(d)
20.2203(a)(1)
20.2203(a)(4) 50.73(a)(2)(ii) 50.73(a)(2)(x)
50.36(c)(1)(i)(A) 50.73(a)(2)(iv)(A)
20.2203(a)(2)(i) 73.71 (aI4)
50.36(c)(1 )(ii)(A) 50.73(a)(2)(v)(A) 73.71 (a)5)
20-2203(a)(2)(ii) 50.36(c)(2) X 50.73(a)(2)(v)(B) OTHER
. 20-2203(a)(2)(iii) 50.46(a)(3)(li) 50.73(a)(2)(v)(C) Specify in Abstract below
20.2203(a)(2)(Iv) 50.73(a)(2)(i)(A) Y 50.73(a)(2)(v)(D) or in NRC Form 366A
. : _ 20.2203(a)(2)(v) 50.73(a)(2)()(B) 50.73(a)(2)(vii)
20.2203(a)(2)(vi)
S R0 a (C) 50.73(a)(2)(viii)(A)
__ _ __ _ 20.2203(a)(I)(1) 50.73(a)(2)(il)(A) 50.73(a2)(viii)(B) ..
12. LICENSEE CONTACT FOR THIlS LER
NAME ELPOENME idde Aras Code)
Steven B. Tipps, Nuclear Safety and Compliance Manager, Hatch (912)367-7851
13. COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS
REPORT
.- USE SYSTEM COMPONENT MANUFACTURER REPORTABLE CAUSE SYSTEM COMPONENT MANUFACTURER
_____,____________ REPORTABLE
TO EPIX
X SB SH-V R344 Yes '4
14. SUPPLEMENTAL REPORT EXPECTED NO..EMISSED MONTH DAY YEAR
IYES
T NO S B I S O
(if yes, complete EXPECTED SUBMISSION DATE) X
IS AB M-IgOi *-llto
,Um;.
I t 140 spaces,U i.eI.,1 a~pp roxlimtllely IS si*ngle-spaced] typewriten lines)
On 03/28/2002 at 0300 EST, Unit 2 was in the Run mode at a power level of 2763 CMWT (100 percent rated thermal
power). At that time, the High Pressure Coolant Injection (HPCI) system was rendered inoperable when personnel
closed turbine exhaust line vacuum breaker isolation valve 2E41-F1 11. Personnel closed valve 2E41-F1711, a primary
containment isolation valve, per the requirements of Unit 2 Technical Specifications Condition 3.6.1.3.A following
unsatisfactory operation of turbine exhaust line vacuum breaker isolation valve 2E41-F 104 during a routine
surveillance. Bpcause valve 2E41-Fl04 is a primary containment isolation valve, its unsatisfactory operation required
that Unit 2 Technical Specifications Condition 3.6.1.3.A be entered. Entry into Condition 3.6.1.3.A required that
valve 2E41-F1 11 be closed to isolate the affected penetration, effectively isolating the turbine exhaust line vacuur)
breakers and preventing them from perforning their intended function. As a result, the HPCI system was rendered
inoperably.
This event was caused by component failure. The spring tension in the finger base sub-assembly of a limit switch
had weakened, preventing proper electrical contact and causing the open position indication to malfunction.
Because the valve's actual position was uncertain, it was declared inoperable. This required valve 2E41 -Fl 11 to be
)sed and the HPCI system to be rendered inoperable. Personnel adjusted the spring tension; completed
- .accessfully the valve test, and declared valve 2El 1-F1 04 operable. After re-opening valve 2E41 -F 111 and
completing scheduled maintenance work and the proper functional tests, the HPCI system was declared operable at
1322 EST on 03/28/2002.
RC FORM 366A (1-2001)
F NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION
(1-2001)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION
FACILITY NAME (1) DOCKET LER NUMBER (6) PAGE (3)
YEAR SEUENTIAIyER REVISIONuMR
S IA NUME
Edwin I. Hatch Nuclear Plant - Unit 2 05000-366 2002 -- 001 -- 00 2 OF 5
TEXT (Iftmore space is required,use additionalcopies of NRC Fern W66A) (17)
PLANT AND SYSTEM IDENTIFICATION
General Electric - Boiling Water Reactor
Energy Industry Identification System codes appear in the text as (EIIS Code XX).
DESCRIPTION OF EVENT
On 03/28/2002 at 0300 EST, Unit 2 was in the Run mode at a power level of 2763 CMWT (100 percent
rated thermal power). At that time, the High Pressure Coolant Injection (HPCI, EIIS Code BJ) system was
rendered inoperable when Operations personnel closed turbine exhaust line vacuum breaker isolation valve
2E41 -F111. Personnel closed valve 2E41 -F11l, a primary containment isolation valve, per the
requirements of Unit 2 Technical Specifications Condition 3.6.1.3.A following unsatisfactory operation of
turbine exhaust line vacuum breaker isolation valve 2E41-F104 during the performance of a routine
surveillance. The open (red) indication light illuminated as expected when Operations personnel began to
open valve 2E41-F104 during the performance of surveillance procedure 34SV-E41-001-2S, "HPCI Valve
Operability." However, the open indication light extinguished unexpectedly while the valve was opening
and remained extinguished after completion of the expected opening stroke time and other indications
showed the valve was open. Operations personnel conservatively declared valve 2E41-F104 inoperable
due to their uncertainty regarding its actual position.
Because valve 2E41-F104 is a primary containment isolation valve, the unsatisfactory operation of its open
position indication light required that Unit 2 Technical Specifications Condition 3.6.1.3.A be entered for an
inoperable isolation valve. Entry into Condition 3.6.1.3.A required that valve 2E41-FI111, a primary
containment isolation valve located in the same line, be closed and deactivated in order to isolate the
affected penetration flow path. Operations personnel closed and deactivated valve 2E41-F1 111 under
Clearance 2-02-122. However, closure of valve 2E41-Fl 11 effectively isolated the HPCI turbine exhaust
line vacuum breakers, preventing them from performing their intended function of stopping suppression
pool water from being drawn into the HPCI turbine exhaust line. As a result, the HPCI system was
rendered inoperable. Operations personnel therefore entered Unit 2 Technical Specification Condition
3.5.1.C and initiated Required Action Sheet 2-02-064 as directed by the Technical Specifications and plant
proceddres.
CAUSE OF EVENT
This event was caused by component failure. The spring tension in the finger base sub-assembly for limit
switch #8 had weakened, preventing proper electrical contact in one of the limit switches that indicate the
position of valve 2E41-F104. This caused the open position indication (red light in the Main Control
Room) to malfunction during performance of a periodic valve stroke test. Because they were uncertain of
he valve's actual position, Operations personnel conservatively declared it inoperable. This required valve
2E41-F1 11 to be closed and the HPCI system to be rendered inoperable for the reasons described
previously.
NRC Form 366A (1-2001)
NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION
(1-2001)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION
FACILITY NAME (1) DOCKET LER NUMBER (6) PAGE (3)
YEAR SEQUENTIAL I REVISION
Edwin I. Hatch Nuclear Plant - Unit 2 05000-366 002 001 -- 00rS 3 OF 5
TEXT (if more space is required,use additionalcopies of NRC Form 366A) (17)
REPORTABILITY ANALYSIS AND SAFETY ASSESSMENT
This event is reportable per 10 CFR 50.73 (a)(2)(v) because an event occurred in which the HPCI system, a
single train safety system, was rendered inoperable.
The HPCI system consists of a steam turbine-driven pump and the necessary piping and valves to transfer
water from the suppression pool or the condensate storage tank (EIIS Code KA) to the reactor vessel. The
system is designed to inject water to the reactor vessel over a range of reactor pressures from 160 psig
through full rated pressure. The HPCI system starts and injects automatically whenever low reactor water
level or high drywell pressure indicates the possibility of an abnormal loss of coolant inventory. The HPCI
system, in particular, is designed to replace lost reactor coolant inventory in cases where a small line break
occurs which does not result in full depressurization of the reactor vessel.
The backup for the HPCI system is the Automatic Depressurization System (ADS) together with two low
pressure injection systems: the Low Pressure Coolant Injection (LPCI, EIIS Code BO) system and the Core
Spray (EIIS Code BM) system. The Core Spray system is composed of two independent, redundant, 100
percent capacity subsystems. Each subsystem consists of a motor driven pump, its own dedicated spray
sparger located above the core, and piping and valves to transfer water from the suppression pool to the
sparger. Upon receipt of an initiation signal, the Core Spray pumps in both subsystems start. Once ADS
has reduced reactor pressure sufficiently, Core Spray system flow begins.
LPCI is an operating mode of the Residual Heat Removal (EIIS Code BO) system. There are two
independent, redundant, 100 percent capacity LPCI subsystems, each consisting of two motor driven pumps
and piping and valves to transfer water from the suppression pool to the reactor vessel. Upon receipt of an
initiation signal, all four LPCI pumps automatically start. Once ADS has reduced reactor pressure
sufficiently, the LPCI flow to the reactor vessel begins. The divisionally separated initiation logic systems
for LPCI and Core Spray incorporate "crossover" circuitry allowing each division to trigger an initiation of
the other division. With this design, any one operable division of logic can produce a full actuation in both
divisions of all the pumps and valves necessary for injection to the reactor vessel.
In this event, the HPCI system was rendered inoperable when personnel closed valve 2E41-F1 11,
effectively isolating the HPCI turbine exhaust line vacuum breakers and preventing them from performing
their intended function. During the time the HPCI system was inoperable, however, the Reactor Core
Isolation Cooling (RCIC, EIIS Code BN) system was available to inject high pressure water into the reactor
vessel. Although not an emergency core cooling system, the RCIC system is designed, maintained, and
tested to the same standards and requirements as the HPCI system and therefore should reliably inject water
into the reactor vessel when required. If a break exceeded the capacity of the RCIC system (400 gallons per
minute), the ADS was available to depressurize the reactor vessel to the point that either the Core Spray or
LPCI systems could have been used to provide water to the reactor core. The capacity of one loop of the
Core Spray system is equal to that of the HPCI system (4250 gallons per minute each); the capacity of one
loop of the LPCI system is approximately three times that of the HPCI system. Therefore, any one of the
NRC Form 366A (1-2001)
NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSIEON
(1-2001)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION
FACILITY NAME (1) DOCKET LER NUMBER (6) PAGE
YEAR SEQUENTIALI REVISION
YR YEAR INUMBER
Edwin I. Hatch Nuclear Plant - Unit 2 05000-366 2002 -- 001 -- 00 4 OF .
TEXT (Ifmore space is required, use additionalcopies of NRC Fonn 366A) (17)
four loops of the low pressure injection systems would have provided sufficient injection capacity for a
small break loss-of-coolant accident.
Based on this analysis, it is concluded that this event had no adverse impact on nuclear safety. This
analysis is applicable to all power levels and operating modes in which a loss-of-coolant accident is
postulated to occur.
CORRECTIVE ACTIONS
Maintenance personnel adjusted the limit switch finger base sub-assembly spring tension per Maintenance
Work Order 2-02-00513. Operations personnel stroked the valve to ensure proper operation of the
position indication lights. They then completed successfully the periodic valve stroke test and declared
valve 2E1 l-F104 operable at 0905 EST on 03/28/2002. After valve 2E41-FlII was re-opened and
previously scheduled, but unrelated, maintenance work and the proper functional tests were completed,
Operations personnel declared the HPCI system operable at 1322 EST on 03/28/2002.
ADDITIONAL INFORMATION
Other Systems Affected: No systems other than those already mentioned in this report were affected by this
event.
Failed Components Information:
Master Parts List Number: 2E41-F104 EIS System Code: BJ
Manufacturer: Limitorque Corp. Reportable to EPIX: Yes
Model Number: 10158 Root Cause Code: X
Type: Switch, Position EIIS Component Code: 33
Manufacturer Code: L200
Commitment Information: This report does not create any permanent licensing commitments.
Previous Similar Events: Previous similar events in the last two years in which a single-train safety system
was rendered inoperable were reported in the following Licensee Event Reports:
50-321/2001-001, dated 05/03/2001,
50-321/2000-007, dated 09/27/2000, and
50-321/2000-005, dated 09/15/2000.
in the first event, the HPCI system was rendered inoperable when a battery charger fuse failure caused
voltage fluctuations on a power supply bus, resulting in brief losses of power to the HPCI system flow
controller. In the second event, the HPCI system was rendered inoperable when its flow control input
I
NRC Foen 366A (1-2001)
NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION
(1-2001)
LICENSEE EVENT REPORT (LER) .
TEXT CONTINUATION
FACILITY NAME (1) DOCKET LER NUMBER (6) PAGE (3)
YEAR SEQUENTIAL REVISION
1
I YEAR NUMBER
Edwin I. Hatch Nuclear Plant - Unit 2 05000-366 2002 -- 001 -- 00 5 OF 5
TEXT (If more space is required,use additionalcopies of NRC Form 36A) (17)
signal resistor failed causing erratic operation of the controller. In the third event, the HPCI system was
rendered inoperable when its turbine stop valve stuck in the open position. Corrective actions for these
previous events could not have prevented this event because the previous failures involved different and
unrelated components and failure modes.
NRC Form 366A (1-2001)
Question Number: #15, SRO Exam
- 21, RO Exam
Justification: The question requires an interpretation of the APRM response with regard
to LPRM inputs and indicated power level.
The alarm APRM UPSC TRIP/INOP SYS B has been replaced with
APRMIOPRM TRIP (34AR-603-210-2).
APRM operability requirements require at least 17 operable LPRM inputs
and at least 3 operable LPRMs per axial level. For the conditions given,
only a Rod Block would exist. (34SV-C51-003-2, "LPRM Operational
Status" page 4 of 20)
Therefore, the APRMIOPRM TRIP would not exist.
The question does not have a correct answer.
References: 34AR-603-210-2, "APRMIOPRM TRIP"
34SV-C51-003-2, "LPRM Operational Status" page 4 of 20
GEK-103927, Volume I, pages 2-7, 2-22
GEK-103927, Volume II, pages 2-7, 2-11, 2-12
Recommendation: Delete this question
NRC Resolution:
QUESTIONS REPORT
for HATCH SRO Test
15.
Unit 2 is starting up with the Reactor Mode Switch in the START/HOT STBY position.
The following is the present status of each APRM with regard to LPRM inputs and
indicated power level.
A B C D
Level D LPRM Inputs 6 5 6 7
Level C LPRM Inputs 5 3 8 8
B LPRM Inputs 6 6 5 2
Level
Inputs 5 3 6 6
Level A LPRM
Indicated Power Level 12% 14% 12% 11%
Which ONE of the following describes the plant response to these conditions and the
cause for the response?
A. Half Scram due to High power on APRM "B".
B. Full Scram due to High power on APRM's "A", "B" and "C".
C. APRM UPSC TRIP/INOP SYS B Alarm due to APRM "B" having too few LPRM
Inputs.
Dr APRM UPSC TRIP/INOP SYS B Alarm due to APRM "D" having too few LPRM
Inputs.
References: SI-LP-01203-00 Rev. SI-00 pg 8-9 of 51
EO 012.003.d.01
A. Incorrect since Full Scram would occur if power reached 13% with Mode Switch in
START/HOT STBY.
B. Incorrect since power level is too low for scram condition. (13% with Mode Switch in
START/HOT STBY)
C. Incorrect since APRM B has the minimum LPRM Inputs required (17).
D. Correct answer.
Friday, November 01, 2002 10:54:04 AM 15
1.0 IDENTIFICATION: ALARM PANEL 603-2 ... ...............
APRM/OPRM
TRIP
-DEVICE: .,,SETPOFNT:
APRM/OPRM Instrument . 1) Neutron Flux High Trip (117% in RUN, 13% not in run)
2051 -K6 5A(B)(C)(D) 2) STP High Trip (0.58W + 55% - 0.58 AW) clamped at 113.5%
via the 2 Out Of 4 3) Inop Trip (instrument mode switch not in operate,
Voter Module critical self test fault detected, loss of power)
K4) OPRM Trip (See Setpoint Index, COLA, or ODAs) - OPRM Trip is enabled
2051 -K61 7A(B)(C)(D) reactor power is above 25% AND recirculation flow is below 60%.
4ý1 only when
3.0 CLASSIFICATION:
2.0 CONDITION: 4.0 LOCATION:
have an upscale trip, OPRM
One or more of the APRM/OPRM Monitors
trip, or are inoperative. 2H1 1-P603 Panel 603-2
5.0 OPERATOR ACTIONS:
NOTES
R613, will be lost.
IF power is lost to APRM "D", Recirc flow indications 2B31-R617 &
II power is lost to APRM "A", Recirc flow input to recorder 2B31-R614, will be lost.
oscillations OR by an OPRM trip,
5.1 IF the OPRM System is inop, AND the alarm is caused by periodic APRM
enter 34AB-C51-001-2S.
APRM Numac's on 2H11-P608 that one OR more
5.2 Confirm on the APRM ODAs on 2H11-P603 AND/OR the Each of the 2 Out Of 4 Logic Modules in
of the APRM/OPRM channels indicates a trip or inop condition. instrument. Also, an OPRM trip
2H11-P608 should indicate a trip input from the affected APRM/OPRM
condition will display the screen message "Instability Detected".
APRM tripped or inop condition OFR an OPRM
5.3 IF more than one APRM/OPRM instrument indicates an AN.D enter 34AB-C71-001-2S, Scram
tripped condition, confirm that a full reactor scram has occurred
Procedure.
confirm the following at 2H1 1-P603:
5.4 IF the annunciator is due to an STP upscale trip OR inop trip,
- the white Rod Out light is EXTINGUISHED
- annunciator 603-238 ROD OUT BLOCK is ALARMED
region of operation defined on the power versus core
5.5 Confirm that the power and flow are within the analyzed
flow map per 34GO-OPS-005-2S.
and STA and initiate corrective action within
5.5.1 If operating outside of the region, notify the Shift Supervisor
15 minutes.
action to exit per the STA's direction.
5.5.2 I.E operating in the Region of Potential Instabilities, take
is failed, notify the Shift Supervisor and STA AND IF
5.6 IF the APRM/OPRM instrument does not have a trip O.R APRM/OPRM.
sufficient APRM/OPRM instruments are operable, BYPASS the
6.0 CAUSES:
power)
6.1 APRM Upscale Trip (fixed neutron flux or flow biased thermal
i6.2 OPRM Trip (any of three algorithms)
6.3 APRM Inop
8.0 TECH. SPEC./LCO:
7.0 REFERENCES:
Monitoring 8.1 TS 3.3.1.1-1 Item 2 Reactor Protection
7.1 H-51995 thru H-52015, Power Range Neutron System Instrumentation Average Power
System 2C51B Elementary Diagram
Range Monitor
7.2 S-61334, PRNM System Requirement Specification 8.2 TRM 3.3.2 Item 3 Control Rod Block
7.2 H-27605 thru H-27619, Reactor Protection System 2C71
Instrumentation APRM
Elementary Diagram
7.3 H-27499 thru H-27515, Reactor Manual Control Sys 2C11A
Elementary Diagram 3ý4AR-603-21 0-2S
F_ 21 DC-DCX
VER. 3.3
MGR-0048 Rev. 4
001-OS
SOUTHERN NUCLEAR PAGE
PLANT E. . HATCH 4 OF 20
DOCUMENT TITLE: DOCUMENT NUMBER: REVISIONNERSION
LPRM OPERATIONAL STATUS 34SV-C51-003-2S NO:
4 ED 1
4.3.6 LPRMs may be bypassed while the APRM instrument is in a operable status. This is
performed from the "BYPASS SELECTIONS" display which is accessible by password
control in the OPER-SET mode. LPRM status can also be displayed on the APRM ODAs
on 2H11-P603.
5.0 PRECAUTIONS/LIMITATIONS{ TC "5.0
PRECAUTIONS/LIMITATIONS"\FH\L1 }
5.1 PRECAUTIONS
Observe the safety rules outlined in the Southern Nuclear Safety and Health Manual.
5.2 LIMITATIONS
5.2.1 APRM operability requirements require at least 17 operable LPRM inputs AND at leastj3
operable LPRMs per axial rlevel. IF LPI-Moperability falls below these requirements, a,,
rod block will be generated from the associated APRM.a
5.2.2 OPRM operability requirements are at least 14 operable cells with at least one operable
LPRM per cell, AND at least 17 total operable LPRMs. (See Attachment 2 for OPRM cell
assignments).
6.0 PREREQUISITES{ TC "6.0 PREREQUISITES"\FH\L1 }
N/A - Not applicable to this procedure
MGR-0001 Rev 3
GEK-103927, VOLUME I
the two
channel's ability to perform its safety function. Operation of one of
redundant low voltage power supplies with its voltages below minimum is an example
of a non-critical fault because only one of the power supplies is needed for the
instrument to be fully operational.
by the
2-25 Trips and Alarms. Several safety trips and alarm signals are generated
APRM System. In the APRM instrument, the Average Neutron Flux value is compared
to one of two fixed high trip setpoint values and to a fixed downscale trip setpoint
Switch is in
value. The active high trip setpoint is a high value if the Reactor Mode
in any other
the "RUN" position and it is lowered if the Reactor Mode Switch is
The STP
position. The STP value is compared to the two flow-biased setpoints.
Switch is
upscale alarm setpoint is replaced with a fixed value when the Reactor Mode
also compared
any position other than than the "RUN" position. The STP value is
enabling
against a user adjustable LPSP and user adjustable LPAP for use in sending
an alert to
signals to the RWM. Faults detected by self-test either cause an alarm as
signal, or a
the operator, or a control rod withdrawal block, or a safety trip
combination of these actions depending on the nature of the fa .An 414ip is-
edWeithr te
ene total qquantity, of operative (non-bypassed) LPRM detector
values is less than the associated user-adjustable setpoint or the quantity of operative
k,,LPRM detector values from a partcular, level is less than three. i
a variety
2-26 OUTPUTS. Data generated within the APRM System are output by
cable
of means. Safety trip status data are multiplexed and transmitted by fiber-optic
Flux and
from the APRM instrument to all 2/4 Logic Modules. The Average Neutron
System by fiber
STP values are transmitted from the APRM instrument to the RBM
lamps, plant
optic cable along with trip and alarm status. Signals for remote indicator
are generated
annunciators, signals, to the RWM, and control rod withdrawal blocks
of the associated
by the APRM instrument and transmitted to the non-safety section
logically
2/4 Logic Module. The non-safety section of the 2/4 Logic Module
signal prior to
combines these signals with the APRM channel manual bypass
each 2/4 Logic
transmitting these signals to external equipment. The safety section of
the channel
Module receives the safety trip status from every APRM instrument and
each 2/4 Logic
bypass status from the other 2/4 Logic Modules. With this data,
in a trip state.
Module logically determines whether its safety outputs should be
2-7
GEK-103927, VOLUME I
for each of the
2-76 Front Panel Indicators. There are status indicators
also have status indicators.
APRM/OPRM channel trip input signals. The outputs
the trip signals, trip memory
Although the 2/4 Logic Module does not latch
indication of a past or present
indicators on both the input and output trips provide
only affects the front panel
trip and clear by manual reset, but this trip memory
indicators.
2-77 SUMMARY OF PRNMS TRIPS AND ALARMS
"LRS'y SAFETY TRIPS
PRNMS SYSTEM
LPRM Upscale (None)
LPRM System
LPRM Downscale
..
APRM System
......
ST? Upscale Alarm
....................
Neutron Flux-High
. ..........
STP Upscale Trip ] STP Upscale Trip
Downscale Inop Trip
Neutron Flux Upscl
Tripopr
.LPRM Low Coun;
APRM Inop Alarm
. ....
..........................
..........
OPRM System OPRM Trip OPEM Trip
Pre-Trip Alarm
OPRM Trip Enabled
OPRM Inop Alarm
Flow Upscale (APRM) (None)
Recirculation Flow Monitor
System Flow Compare (RBM)
.
......... ... .... ... ~
.
...... ......
... ........... ...
Inop Trip (None)
RBM System
Upscale
Downscale
Rod Inhibit
Inop Alarm
......... .. .............................................................. .... .. .. ...
...... 7ý - -
(None) APRM High/nop
2/4 Logic System OPRM Trip
2-22
GEK-103927, VOLUME II
setpoints. The APRM allows enabling single recirculation loop operation offsets when
in either the OPERATE or INOP-CAL modes of instrument operation under
password control.
2-25 APRM TRIPS AND ALARMS. The APRM provides the following trip and
alarm functions:
A. Neutron Flux - High Trip
B. Simulated Thermal Power - High Trip
C. Simulated Thermal Power - Upscale Alarm
D. Neutron Flux Downscale Alarm
E. APRM Inoperative Trip
F. STS Alarm
C. LPRMLow Count (Rod Block) j
H. Low Power Set Point (LPSP)
I. Low Power Alarm Point (LPAP)
J. Flow Upscale Alarm
K. LPRM Upscale Alarm
L. LPRM Downscale Alarm
M. OPRM Trip (Core Instability Detected)
N. OPRM Pre-Trip Alarm
0. OPRM Trip Enabled Alarm
P. OPRM INOP Alarm
2-26 The APRM provides different upscale trip and alarm setpoints that depend
the
upon the reactor mode as illustrated in Table 2-1. The trip and alarm status of
APRM channels is remotely indicated at the instrument's front panel display and the
operator's display. These signals are also transmitted to the RBM instruments. The
of
upscale and downscale APRM trips and alarms are non-latching with an accuracy
0.1% and a hysteresis of 1.0% flux.
2-7
GEK-103927, VOLUME II
B. The quantity of operating LPRM detectors at any given reactor level in
the Average Neutron Flux level is less than three.
I9n C. The quantity of operating LPRM detectors in the Average Neutron Flux
level is less than the required minimum (user adjustable).
2-40 Low Power Set-Point (LPSP) and Low Power Alarm Point (LPAP). Each
APRM instrument provides two separate signals that are intended for use in enabling
separate functions of the Rod Worth Minimizer (RWM) system. The LPSP and LPAP
signals are in the enforcement condition when the STP level falls below a user-defined
setpoint and is reset when the signal rises above the reset point.
where: STP = Simulated Thermal Power Level
LPSP_Setpt = Low Power Setpoint
LPAPSetpt = Low PowerAlanm Setpoint
2-41 APRM Control Rod Withdrawal Block. Each APRM instrument provides a
rod block signal to the RMCS under any of the following conditions:;
A. Simulated Thermal Power Upscale Alarm.
B. Neutron Flux Downscale Alarm.
C. APRM Inoperative Trip.
D. The quantity of operating LPRM detectors at any given reactor level iWt
the Average Neutron Flux level is less than three.
E. The quantity of operating LPRM detectors in the Average Neutron Flux
level is less than the required minimum (user adjustable).
F. Recirculation Flow Upscale Level/Off- Normal Alarm.
2-42 Reactor Protection System Trip. The RPS trip is set when any of the
following trips are set and is reset when all of the following trips are reset:
2-12
GEK-103927, VOLUME II
RunSetpoint = (Slope * [Flow - AFlow]) + Offset (2-8)
where: Slope = Slope of the Power/Flow level line (user adjustable)
Flow = Total recirculation flow the APRM instrument is using
A*low = Delta flow setpointrfor single recirculation loop operation (user adjustable)
Offset = The flux offset (or setpoint) at zero flow (user adjustable)
2-36 Neutron Flux Downscale Alarm. The APRM provides a downscale alarm
signal intended for use as a rod block when the average neutron flux level falls below
a user-defined setpoint and is reset when the signal rises above the reset point.
Dnscale Alarm = (APRMFlux * DnscaleSetpt AND NOT APRM.jnoperative) (2-9)
where: APRMFlux = Average Neutron Flux Level
Dnscale_Setpt = Downscale Setpoint
APRM_Inoperative = APRM Inoperative Trip
"2-37 APRM Inoperative Trip. The APRM channel provides an inoperative trip
signal to the Reactor Protection System (RPS) when the following conditions occur:
A. A critical self-test fault is detected.
B. The instrument's keylock switch is in the "INOP" position.
C. The firmware/software watchdog timer has timed out.
D. Loss of input power.
2-38 It is possible to momentarily inhibit the inoperative trip output when the
instrument keylock mode switch is in the inoperative/calibrate position for testing
purposes (i.e., trip check is being performed on the recirculation flow, simulated
thermal power, or APRM flux signals).
2-39 APRM Trouble Alarm. Each APRM instrument provides a trouble alarm
when the following conditions occur.
/ A. Any self-test fault is detected.
2-11
Question Number: #57, SRO Exam
- 66, RO Exam
Justification: The question has the candidates determine why 3lRS-OPS-001-1 S, has
steps to scram the Reactor by deenergizing RPS or actuating the Scram
Discharge Volume level switches.
K/A 295016 AK 3.01 states: "Knowledge of the reasons for the following
responses as they apply to control room abandonment: Reactor scram."
This question does not test the knowledge of the reasons for a Reactor
scram. It tests the reason for two steps in a procedure to provide a Reactor
scram. This question exceeds the intent and bounds of the K/A.
References: K/A Catalog
Recommendation: Delete this question.
NRC Resolution:
QUESTIONS REPORT
for HATCH SRO Test
57.
There is an electrical fire in the Control Room and black smoke has made the Control
Room inaccessable. If possible, prior to leaving the Control Room the Reactor
Operator inserts a manual Scram per 31RS-OPS-O01-1S, Shutdown from Outside
Control Room.
Which ONE of the following describes why the procedure also has steps to Scram the
reactor by de-energizing RPS or actuating the Scram Discharge Volume level
switches?
A. The Technical Specifications require that Reactor Scram capability from outside the
Control Room be maintained.
B.' The FSAR requires the ability for prompt hot shutdown of the reactor from locations
outside the Control Room.
C. The Technical Requirements Manual requires the capability to Scram the reactor
from outside the Control Room.
D. The capability for prompt hot shutdown of the reactor from outside the Control
Room is not required but is a safe operating practice.
References: HNP-2-FSAR-3 pg 3.1-16 and 17.
HNP-2-FSAR-7 pg 7.5-5 thru 7.5-10.
Procedure 31 RS-OPS-001-1S Rev. 3
A. Incorrect since Technical Specifications do not describe how to shutdown the plant
from outside the control room.
B. Correct answer.
C. Incorrect since the Technical Requirements Manual does not describe how to
shutdown the plant from outside the control room.
D. Incorrect since it is a requirement to be able to perform a prompt hot shutdown from
outside the control room.
Monday, November 04, 2002 11:13:08 AM 57
Question Number: #66, SRO Exam
- 74, RO Exam
Justification: The question has the candidate use specific number of input signals from
various Group isolations to SPDS and determine the resulting SPDS
indication.
The referenced objective of the lesson plan, 056.002.c.03 of
LT-LP-05601-05, "Safety Parameter Display System," requires the
candidate to identify the significance of the colors green, orange, red,
yellow, and white as they pertain to SPDS. The objective does not require
an explanation or evaluation of the number of input signals.
K/A 295026 EK 2.04 states: "Knowledge of the interrelationship between
suppression pool high water temperature and the following: SPDS."
This question exceeds the referenced objective and the bounds of the K/A
for SRO/RO knowledge by testing the number of valid inputs for SPDS
indication.
K/A Catalog
References:
LT-LP-05601-05, "Safety Parameter Display System," page 2 of 20
Recommendation: Delete this question.
NRC Resolution:
QUESTIONS REPORT
for HATCH SRO Test
66.
Unit 1 is in Mode 1 with the quarterly HPCI Pump Operability Surveillance in progress.
The Suppression Pool average temperature is 102 0 F. The following signals are being
sent to SPDS:
Group 1 signals: 4 out of 5 are operable and reading 102 0 F.
Group 2 signals: 5 out of 5 are operable and reading 103 0 F.
Group 3 signals: 4 out of 5 are operable and reading 102 0 F.
Which ONE of the following conditions describes the SPDS indication?
A. Green box with the average temp indicated since average temp is <1050 F.
B. Yellow box with the average temp indicated since all groups have a signal.
C. Yellow box with no temp indicated since all signals are not operable.
DV Red box with the average temp indicated since average temp is >1 00OF.
Reference: LT-LP-05601 Rev. 03 Safety Parameter Display System
EO 056.002.c.03
A. Incorrect because the average temp must be <1 00OF to be green.
B. Incorrect because there are 2 or more imputs to each group and temp is > 100OF so
the box should be red.
C. Incorrect because there are 2 or more imputs to each group and temp is > 1OOOF so
the box should be red.
D. Correct answer since average temp > 100OF and there are 2 or more inputs to each
group.
Monday, November 04, 2002 11:13:35 AM 66
Page 2 of 20
LT-LP-05601-05
SAFETY PARAMETER DISPLAY SYSTEM
OBJECTIVES
TERMINAL OBJECTIVES
056.001.A OPERATE the Safety Parameter Display System per 34SO-X75-002-2/1 "Operation of
SPDS Equipment" and the Emergency Response Data System (ERDS) Users Manual.
056.002.C MONITOR the Safety Parameter Display System per 34SO-X75-002-2/1 "Operation of
SPDS Equipment" and the ERDS Users Manual.
400.068.A Given SPDS, EVALUATE and REPORT significant trends and/or data to crew personnel.
ENABLING OBJECTIVES
1. Given a list of Plant locations, SELECT the locations where SPDS consoles are found.
(056.001.a.01)
2. Given a list of power supplies, SELECT the normal power supply for the SPDS system.
(056.001.a.05)
3. Given a list of categories, SELECT the 7 categories available on SPDS. (056.001.a.03)
4. Given a display or drawing of an SPDS "Screen", EVALUATE and REPORT significant trends
and/or data to crew personnel. (SRP/STA) (400.068.a.02)
5. Given a list of statements, IDENTIFY the statement which best describes the significance of the colors
green, orange, red, yellow, and white as they pertain to the following: (056.002.c.03)1
a. Parameter field and status indicator box for;
1. SRV
2. ADS
3. LLSLý
4. Analog Parameterst
b. Containment Isolation Status (PCIS)
c. Valve Position
d. SRM Detection Status
6. Given SPDS indications, ANALYZE the indications and DETERMINE if an instrument has failed.
(056.002.c.01)
Question Number: #72, SRO Exam
- 78, RO Exam
Justification: The question has the candidate determine the reason for emergency
depressurization with two areas exceeding maximum safe operating
temperature. The choices include threats to SC integrity, substantial
degradation of primary system and fuel failure, threat to SC integrity or
equipment, degradation of primary system and emergency
depressurization to place the plant in a safe condition.
K/A 295032 EK 3.03 states: "Knowledge of the reasons for the following
responses as they apply to high secondary containment area temperature:
Isolating affected systems."
This question does not require knowledge of the reasons for isolating the
affected systems. This question is not within the bounds of the K/A.
While the knowledge required for the reasons for emergency
depressurization is reasonable to examine, the choices also contain another
correct answer.
"C" is correct as given by LR-LP-20325.
The EOP flow chart path of this question assumes a Primary System is
discharging. For a Primary System to be discharging there must be
substantial degradation of the primary system. If these conditions are met,
emergeAcy depressurization is required to place the RPV in the lowest
possible energy state, which is its safest condition. Emergency depress,
exceeding cooldown rate, implies as quickly as possible. "D" is correct as
well.
References: LR-LP-20325, pages 16 & 20 of 38
K/A Catalog
BWROG EPGs/SAGs, Appendix B, page B-8-12
Recommendation: Accept two correct answers, "C" and "D".
NRC Resolution:
QUESTIONS REPORT
for HATCH SRO Test
72.
The SC-SECONDARY CONTAINMENT CONTROL EOP requires Emergency
Depressurization if 2 or more areas exceed the Maximum Safe Operating Temperature
and a primary system is discharging reactor coolant into secondary containment.
Which ONE of the following statements explain the reason for this action?
A. The rise in secondary containment parameters indicate a wide-spread problem
which may pose an indirect but immediate threat to secondary containment integrity
or continued safe operation of the plant.
B. The rise in secondary containment parameters indicate substantial degredation of
the primary system and may lead to fuel failure if the leaks are not isolated.
C. The rise in secondary containment parameters indicate a wide-spread problem
which may pose a direct and immediate threat to secondary containment integrity
or equipment located in secondary containment.
D. The rise in secondary containment parameters indicate substantial degredation of
the primary system and emergency depressurization places the plant in the safest
condition as quickly as possible.
References: LR-LP-20325 Rev. 05, pg 19 and 20 of 40
EO 201.077.a.14, 201.078.a.15, 201.079.a.19
A. Incorrect since condition pose a DIRECT threat to containment, not an INDIRECT
threat.
B. Incorrect since this condition does not indicate substantial primary system
degredation.
C. Correct answer.
D. Incorrect since this condition does not indicate substantial primary system
degredation.
Friday, November 01,2002 10:56:05 AM 72
Page 20 of38
LR-LP-20325-05
OUTLINE OF INSTRUCTION
Define Max Safe Operating The Max Safe Operating Water Level is defined as the highest water
Water Level. level at which safe shutdown equipment will not fail NOR will personnel
access required for safe shutdown be precluded.
Discuss bases for Max Safe The Max Safe Operating Water Level is based on the point at
Operating Water Level. which safety related or vital equipment just starts to become
covered with water. This is determined by actual field
measurements.
MNO water level is inside the NOTE: The Max Normal Operating Water Level is based on
sump the water level inside the instrumentor drain sumps and is
identified by annunciators.
MSO water level is water on NOTE: The Max Safe Operating Level is actual water level
the floor in inches above the roomfloor and is measured by a
installed ruler in the room.
Point out that this step applies The criteria of "more than one area" specified in this step identifies the
to SC/T, SC/L and SC/R. rise in secondary containment parameters as a wide-spread problem,
which may pose a direct and immediate threat tol
Discuss the reasons for "* Secondary containment integrity, or
Emergency Depressurization when
more than one area is exceeding "* Equipment located in the secondary containment, or'
the Max Safe Operating Value.
"* Continued safe operation of the plant,
Point out the division of Areas This reasoning applies to all three secondary parameters: Temperature,
on Tables 4, 5 & 6. Area Water level, and Radiation level
Point out that exceeding a Max One parameter (e.g., temperature) above its maximum safe operating
Safe Operating Parameter value in one area and a different parameter (e.g., radiation or water
Value in one area and different level) above its maximum safe operating value in the same area or
Max Safe Operating parameter different area is not a condition which requires emergency
in another area does not satisfy depressurization.
the WAIT UNTIL statement.
The same reasoning applies to A combination of parameters (temperature, water, or radiation level)
two parameters exceeding the exceeding maximum safe operating values in one area does not
limit in the same area. necessarily indicate:
- that control of a given parameter cannot be maintained, or
__Page
16 of 38
TLIER-P-20325-OS
OUTLINE OF INSTRUCTION
Stress that this step allows The word RESTORE appears in these steps which allows the operator
water level to be RESTORED to use the sump pumps, if not previously operating, to lower water
before any isolations are levels below the Max Normal Operating Value without having to isolate
required. systems.
PERFORM CONCURRENTLY
WAIT UNTIL
,Primary system
is discharging reactor coolant
and cannot be isolated
(Table 7)
Point out that this step applies to At this point, alternate paths provide instructions to shut down the
SC/T, SC/L and SC/R. reactor per normal operating procedures OR scram the reactor and enter
the RC[A] flowchart and prepare to rapidly depressurize the reactor.
The path that is taken is based on the source of:
Discuss performing the paths "* Heat, (primary system discharging into the area or a fire in
concurrently. the area) OR
"* Water level (primary system discharging into the area or
from fire suppression systems) OR
"* Radiation addition to the secondary containment.
Need to perform both until One path (the left hand side) assumes that a primary system is still;
source of problem identified as discharging reactor coolant into secondary containment, and if
a Reactor Coolant leak or not. conditions are met, requires a scram and emergency depressurization to'
place the RPV in the lowest possible energy state.
The second path directs an orderly reactor shutdown to be performed
when the abnormal secondary containment condition is a result of a non
reactor coolant discharge.
EPG/SAG Step
SC/T-4 If a primary system is discharginginto secondary containment:
SC/T-4.1 Before any area temperature reaches its maximum safe
operating temperature,enter [proceduredeveloped from
the RPV Control Emergency ProcedureGuideline] at
[Step RC-1] and execute it concurrently with this
procedure.
Discussion
\Primary'systehis comprise the pipes, valves, and other equipment which connect
directly to the RPV such that a reduction in RPV pressure will effect a decrease in th4
flow of steam or water being discharged through an unisolated break in the systen.
If a primary system is discharging into the secondary containment when this step of the
procedure is reached, one of three conditions must exist.
" A primary system break cannot be isolated because system operation is required to;
assure adequate core cooling or shutdown the reactog.
"* No isolation valves exist upstream of a primary system break, or if isolation
valves do exist, they cannot be closed because of some mechanical/
electrical/pneumatic failur4.
"* The source of the discharge cannot be determined.
Since the RPV is the only significant source of heat, other than a fire, that might cause
area temperatures to increase to their maximum safe operating values, the action in
Step SC/T-4.1 should terminate increasing secondary containment temperatures.
If temperatures in any one of the areas listed in Table SC-1 of the Secondary Containment
Control guideline approach their maximum safe operating value, adequate core cooling,
containment integrity, safety of personnel, or continued operability of equipment required
to perform EPG actions can no longer be assured. The RPV Control Guideline must be
entered to make certain the reactor is scrammed. Scramming the reactor reduces to decay
heat levels the energy that the RPV may be discharging to the secondary containment. An
explicit direction to scram the reactor is not provided in this step.
B-8-12 Rev I
Question Number: #98, SRO Exam
- 99, RO Exam
Justification: This question requires the candidate to identify how the Shift Supervisor
maintains constant communication with the Fire Brigade from the Main
Control Room.
The fire radio was recently replaced with a UHF radio system which uses
a Fire Brigade talk group to maintain communications with the Fire
Brigade. This question was developed and validated based on referenced
training material which not yet been updated. Consequently there are no
correct answers.
References: DCR 01-004, "Base Station Radio"
Recommendation: Delete this question.
NRC Resolution:
QUESTIONS REPORT
for HATCH SRO Test
98.
A Fire has been reported by the Unit 1 EHC skid and the Fire Brigade has been
dispatched.
Which ONE of the following describes how the Shift Supervisor maintains constant
communications with the Fire Brigade from the Main Control Room?
A. A hand held radio dedicated to UHF Channel 1.
B!0 VHF base station dedicated to VHF Channel 2.
C. UHF base station dedicated to VHF Channel 1.
D. A hand held radio dedicated to VHF Channel 2.
References: LT-LP-10004 Rev. 03 pg 15 of 19.
LO LT-10004.008
A. Incorrect since hand held radios are not used in the Control Room.
B. Correct answer.
C. Incorrect answer since the base channel is VHF and uses Channel 2.
D. Incorrect since hand held radios are not used in the Control Room.
Monday, November 04, 2002 11:14:18 AM
99
SOUTHrERNA EDWIN I. HATCH NUCLEAR PLANT
COMPANY
10 CFR 50.59 Screen/Evaluation
. -*.. . .o vn*scev Page 1 of 5
DCR 01-004
Responsible
Organization:
Base Station Radio Unit(s) j Tmin"Numb: 01-00402 2
E SCS 0 BPC 03 Site 03 Other:
Ref. P1A 5**AV
I0
Annual Operating Report Summary - Category C
(Maximum of 10 lines)
This change replaces the existing 150 MHz Radio System to allow better coverage of the plant. This change
does not modify the function of this system.
(Maximum of 5 lines)
The 150 MHz Radio System is not safety related. It does not challenge any safety-related system or
component. This change does not reduce the margin of safety as defined in the basis for any
Technical Specification.
Description of proposed change, test, or experiment:
Background:
The existing 150 MHz Radio System is aging, and experiencing high maintenance costs.
Coverage in some areas of the plant is poor. Testing has shown that a 450 MHz radio system will
provide better coverage.
Description:
A new 450 MHz radio system will. beinstalled in the plant. It consists of five separate radio
systems mounted in a stand-alone rack. Each of the radios operates on a different frequency
within the 450 MHz band. All five radios can be used simultaneously. The radio assigned to the
frequency used by Plant Security will be powered from Unit 1 Vital AC Panel, 1R25-S063. On a
temporary basis, the existing 150 MHz security radio will be left in place until the new radio has
been proven to perform satisfactorily.
This change involves the placement of radio transmitter/receivers in the Reactor Building.
Additionally this new equipment contains microprocessors and is by definition a digital upgrade.
The change has therefore been evaluated against the requirements of EPRI Guidelines and GL
95-02 as identified in the DIR. This change is part of a change which involves switching of
normal radio frequencies from the 150MHz band to the 450 MHz band. This will change the
normal background characteristics for EMI at plant Hatch. Use of administrative controls to
control portable radios and application of the EPRI guidance for fixed equipment ensures that the
overall design will meet applicable regulatory requirements and therefore be acceptable for use
at Plant Hatch. A follow-up survey will be conducted to establish baseline emission data for the
new radio system and to further confirm compliance with EPRI TR 102323.
10 CFR 5059.DOT REV. 3 08/08/00
- SOUTHRNA
-eRNAL
EDWIN I. HATCH NUCLEAR PLANT
Engineering& GenerationServices 10 CFR 50.59 Screen/Evaluation
II Pagee2/oft5
I
DCR 01-004 Base Station Radio Tilesmiaa Nowno
Unit(s) 1&2 01-004.002
Responsible Organitiu.:
SGS
C 0 BPC 03 Site 0 Other:
The power supplies and transmitters are potential EMI emitters Ref. P1 5.10
panel, 1R25-S063 and Lighting panel IT51-SOI 1; therefore, and are connected to the Vital AC
an EMI filter will be provided for the
power feeds from lR25-S063 and iT51-SOI1, per EPRI
TR-102323 EMI limiting practices
option 2. The electrical load for the new radio equipment has
been analyzed and found to be less
than the existing load, therefore installation of the new
equipment will not adversely impact
panels 1R25-S063 and 1T51-SOIl.
Civil related modifications include the installation of two
nonsafety-related racks located in the
radio room at Elevation 255'-10" of the Unit 1 Reactor Building.
The
multi-frequency electronics and radio equipment. Nonsafety-relatedracks will house the hybrid
located at levels 130'-0", 185'-0", and 130'-0", 203'-0" Antenna mounts will be
of the Unit 1 and Unit 2 Reactor
Buildings respectively, and one on the refueling floor. Anchorage
structure are described in Chapter 12 of the Unit 1 FSAR, requirements for a Category I
and Chapter 3 of the Unit 2 FSAR.
Anchorage design of the components conforms to Seismic
Category II/I design requirements as to
preclude any failure during a seismic event. Raceway modifications
are designed to Seismic
Category requirements.
References:
I. FSAR HNP-2 Section 9.5.2.3.3
2. Unit I FSAR, Rev. 18C, dated 7/00- Chapter 12 "Structures
and Shielding"
3. Unit 2 FSAR, Rev. 18C, dated 7/00- Chapter 3, "Design
of Structures, Components, and Systems"
4. NEI 96-07, Rev. 0
5. EPRI TR-102323, Rev. 1
6. EJ-0390
7. EJ-0391
8. The Hatch Fire Hazards Analysis - Appendix D
Section IV.B.5.c and IV.B.5.d
A. I0CFR50.59 APPLICABILIT'
The activity to which this evaluation applies represents:
1. E Yes C1 No A change to the plant as described in the
FSAR, Technical Specification (TS)
Bases, or Technical Requirements Manual (TRM) or will this
change require
a revision to some portion of the FSAR, TS Bases or TRM?
Basis for answer: This DCR includes the mounting of racks and antenna mounts
the plant radio system, which are nonsafety-related components for
Seismic Category I area of the Unit 1 Reactor Building. Seismic housed within in a
Category I raceways
are also modified. The seismic design requirements for safety-related
structures, and components (SSC's), are described in Chapter systems,
12 of the Unit 1 FSAR
and Chapter 3 of the Unit 2 FSAR. These FSAR requirements
are also applied to non-
10 CFR 5059.DOT REV. 3 08/08/00
SOUTHERNA
COMPANY EDWIN I. HATCH NUCLEAR PLANT
Engineerine & Generation .Vervien 10 CFR 50.59 Screen/Evaluation
Jý M . - Page3of5
DCR 01-004 Base Station Radio
Responsible Qrsztooi :0 Unit(s) 1&2 01-004-002
-0 -0
E SCS 0 BPC 01 Site 01 Other:
safety-related SSC's to the extent necessary to insure that they do not prevent safety Ref. P1 5.10
related SSC's from performing their safety functions. Therefore, as described in
NEI
96-07, Rev. 0, this modification represents a potential un-reviewed safety question
with
respect to seismic design. The 10 CFR 50.59 is applicable to this DCR, and a safety
evaluation is required (see Section B). Additionally, the Hatch Fire Hazards Analysis
Appendix D Section IV.B.5.c and IV.B.5.d state that radio repeaters are not used
at
Hatch. The equipment being installed in the Reactor Building functions both as
a
trunking system and repeater. When not in service the radios will function radio
to
radio as they do presently. Thus the FHA will be revised to reflect this.
The plant radio system is not described in any detail in the FSAR, other than
the brief mention that there is a two-way radio communication system.
Replacing the radios, or changing frequencies does not require any change to
the FSAR, or any included figure, the Technical Specification, or the
Technical Requirements Manual. The installation of the new radios could
raise some EMI/RFI questions, and the installation constitutes a digital
upgrade.
2. 0 Yes 0 No A change to procedures as described in the FSAR, TS Bases, or TRM?
Basis for answer: The plant radio system is not described in any procedure as described in the
FSAR, and the replacement of any radio equipment does not change any
procedure as described in the FSAR.
3. 0 Yes 0 No A test or experiment not described in the FSAR?
Basis for answer: This is not a test or experiment. It is a permanent replacement of one radio
system with another.
4. 0 Yes 0 No A change to the Technical Specifications and/or Environmental Protection
Plan incorporated in the operating license?
Basis for answer: The plant radio system is not described in the Technical Specifications, nor
does it have any impact on the Environmental Protection Plan.
If the answer to any question in section A is "YES", complete section B.
10 CFR 5059.DOT REV. 3 08/08/00
r HRF NA.
O COMPANY EDWIN I. HATCH NUCLEAR PLANT
ý ý-3-,y ý$
10 CFR 50.59 Screen/Evaluation
Engineering & Generation Services
Page 4 of 5
Prepared by: Sam Diggs / Sam Diggs .Date 2/14/01K
Print Signature
Reviewed by: George Chambers / George Chambers
Signature
Date 2/14/01
Nuc. Sup. Review: C. B. Heard / C. B. Heard Date 2/14/01
Print Signature
Approved by: K. D. Turner, Jr. / K. D. Turner, Jr. Date 2/14/01
Print Signature
B. SAFETY EVALUATION
1. 0 Yes O No May the proposed activity increase the probability
of an occurrence of an
accident previously evaluated in the FSAR?
Basis for answer: The radio equipment itself is not a system important
to safety. Equipment
important to safety needs to be protected from electrical emissions
that could
interfere with its function. The power supply to the radios will
utilize filters
to protect other equipment from emissions. A walkdown was performed
to
verify that the distributed antenna system run through parts of
the Reactor
Building was not run near sensitive equipment. Plant procedures
govern the
use of hand-held radios and define the permitted and restricted
areas. The
change in the radio system will therefore not increase the probability
of an
occurrence of an accident previously evaluated in the FSAR.
2. 0 Yes E0 No May the proposed activity increase the consequences of an accident
previously evaluated in the FSAR?
Basis for answer: The installation of the non safety-related equipment is designed for design
basis seismic loads so-as to prevent interaction with safety-related
equipment. The raceway modifications are designed to category
requirements. The equipment being installed in the Reactor BuildingI
functions both as a trunking system and repeater. The repeater function
essential to communications and if it fails the radios will still function is not
radio
to radio as they do presently. Therefore, these modifications will
not
increase the consequences of an accident previously evaluated in the FSAR.
1O CFR 5059.DOT REV. 3 08/08/00
SOUTHERNAmMDtaAW
r EDWIN I. HATCH NUCLEAR PLANT
MP-A;$r /
10 CFR 50.59 Screen/Evaluation
.ngcnegring a Generauonaerv cVC Page 5 of 5
IJob: r nmitutl
snl: NumbesI
DCR 01-004 I Bse Station Radio Unit(s) 1&2 01-004-02I
Responsible
Organintion:
0t SCS 0 BPC 0 Site 03 Other:
Ref. P1 5.10
3. O Yes 0 No May the proposed activity increase the probability of occurrence of a
malfunction of safety-related/important to safety equipment previously
evaluated in the FSAR?
Basis for answer: The EMI/RFI evaluation for this system verified that RFI generated will
remain in the acceptable region as identified in EPRI TR 102323 and power
line filters are utilized to ensure conducted emissions are not transmitted to
the incoming power source. As described earlier, the new plant radio system
will meet seismic design requirements along with material, and construction
standards of the original design as to preclude any malfunction of safety
related equipment.
4. O Yes El No May the proposed activity increase the consequences of a malfunction of
safety-related/important to safety equipment previously evaluated in the
FSAR?
Basis for answer: All equipment associated with this modification is non-safety related, and
seismically anchored in accordance with Seismic Category Il/I design
requirements to prevent overturning. The proposed activity would not
increase the consequences of a malfunction of safety-related/important to
safety equipment previously evaluated in the FSAR.
5. D Yes 0 No May the proposed activity create the possibility of an accident of a different
type than any previously evaluated in the FSAR?
Basis for answer: The proposed activity to the plant radio system maintains intended
communications. And the administrative controls in place to preclude
EMI/RFI interference also remain the same. The results of the technical
evaluation indicate that the modifications meet the same design
requirements, material, and construction standards of the original system.
The proposed activity, therefore, will not create the possibility of an accident
of a different type than any previously evaluated in the FSAR
6. 0 Yes ONo May the proposed activity create the possibility of a malfunction of safety
related/important to safety equipment of a different type than any previously
evaluated in the FSAR?
Basis for answer: The EMI/RFI evaluation for this system verified that RFI generated will
remain in the acceptable region as identified in EPRI TR 102323 and power
line filters are utilized to ensure conducted emissions are not transmitted to
the incoming power source. The proposed activity to the plant radio system
maintains the intended function of the radio components. The results of the
technical evaluation indicate that the modifications meet the design, material,
IOCFR5059.DOT REV.3 08/08/00
SOMUERNA EDWIN I. HATCH NUCLEAR PLANT
COMPANY
10 CER 50.59 Screen/Evaluation
Engineering& GenerationServices
JJob;
Page 6 of 5
Tide:
DCR 01-004 Base Station Radio
0 SCSfanntm 0 BPC 03 Site 0 Other:
Ref PI 5.10
and construction standards of the original design. The replacement of the
components will not create the possibility of a malfunction of safety
related/important to safety equipment of a different type than any previously
evaluated in the FSAR.
7. 0 Yes IONo Does the proposed activity reduce the margin of safety as defined in the basis
for any Technical Specification?
Basis for answer: The limitations described in the Technical Specifications will not be affected
since the modification does not alter the intended function, reliability, or
availability of any safety-related system. No acceptance limits, setpoint, or
design failure points as defined in the basis for any Technical Specification
will be affected. Therefore, there is no reduction in any margin of safety.
If the answer to any of the questions in section B (excluding Question
7a) is "YES", a license
amendment must be obtained from the NRC before the document/activity
may be implemented.
10 CFR 5059.DOT REV. 3 08/08/00
SOUINERNA EDWIN I. HATCH NUCLEAR PLANT
COMPANY
- & GeneraionDesign Input Record
Engineering & Generation Services Pae 1 nf7
IsT2SnnUI I
Job:
DCR 01-004
Job Revision:
Title: SRi
Base Station Radio
Pre-tnns DIR Rev.:
IUnit~s) 1&2 Number nn I
0 Ref. PI 5.0 a
Summary of Project Scope:
Replace existing plant operations and security base station radio systems and cabling with systems purchased
under PO 6047264. In addition to the existing Vital AC power feed to the equipment, a second formerly
abandoned power circuit from Lighting Panel IT51-S011 will be extended into the Radio room to provide
power to the 450MHz non security equipment and the 150 MHz security equipment. Since this radio system
replacement is a digital upgrade, line filters will be installed in the AC power feeds to prevent EMI with
other equipment connected to the 120 VAC system. The power for the existing Radio room lighting will be
moved from the Vital AC feed to the 1T5 1-SO 11 feed and a switch will be added to the circuit.
Civil related modifications include the installation of two nonsafety-related racks, and the relocation of one
nonsafety-related security radio rack, located in the radio room at Elevation 255'-10" of the Unit 1 Reactor
Building. The racks will house the hybrid multi-frequency electronics and radio equipment Nonsafety-related
Antenna mounts will be located at levels 130'-0", 185'-0", and 130'-0", 203'-0" of the Unit 1 and Unit 2
Reactor Buildings respectively, and one on the refueling floor. A short conduit run will be installed from
just outside the radio room and end inside the radio room. Anchorage requirements for a Category I structure
are described in Chapter 12 of the Unit 1 FSAR, and Chapter 3 of the Unit 2 FSAR. Anchorage design of the
components, to prevent overturning, conforms to Seismic Category 11/1 design procedures as to preclude any
failure during a seismic event.
There is no mechanical involvement in this DCP.
Is the system/structure referenced in or identified by any of the following (if YES, list revision/issue):
FSAR/FHA: 0 Yes 0 No Hatch Unit 2 FSAR, revision 18C, Section 9.5.2.3.3
Tech Specs: 0 Yes 0 No
SED: 0 Yes 0 No
Design Inputs: List all applicable codes, standards, references, plant-specific documents, assumptions
made, and other inputs used in developing the design.
1. EPRI TR- 02323-RI, Guidelines for Electromagnetic Interference Testing in Power Plants
2. E. I. Hatch Nuclear Plant Units 1 and 2 Seismic Floor Response Spectra of Record, Rev.1, 7-31-87.
3. Hatch Seismic Margin Earthquake In-Structure Response Spectra. (Letter from David McKinney to
Gary McGaha dated 4/28/95, "Hatch SME In-Structure Response Spectra")
4. Unt 1 FSAR, Rev. 18C, dated 7/00- Chapter 12 "Structures and Shielding"
5. Unit 2 FSAR, Rev. 18C, dated 7/00- Chapter 3, "Design of Structures, Components, and Systems"
6. NRC Regulatory Guide 1.100, "Seismic Qualification of Electric Equipment for Nuclear Power Plants,"
Rev. 2 dated 06/1988
7. NRC Regulatory Guide 1.29, "Seismic Design Classification," Rev. 1
8. AISC Cold Formed Steel Design Manual, 1968 Edition.
9. AWS D. 1.1-90 Structural Welding Code
10. Specification for Aluminum Structures, 1986 Edition.
ii. Engineering Data for Aluminum Structures, 1986 Edition.
DESIGN INPUT RECORD.DOT REV. 2 08/08/00
SOUTHERN A EDWIN I. HATCH NUCLEAR PLANT
COMPANY
Engineering& GenerationServices Design Input Record
Job
Page 2 of 2
Tide:
DCR 01-004 Base Station Radio
Job Revision: Pt-trans DIR Rev.:
0
I IUnit(s)
Uni s I1&2 01-004-002
0 Ref. PI 5.02
Prepared by:
Michael A. Morgan / Michael A. Morgan
CIVIL Print Date 2/14/01
Signature
Richard M. Edge / Richard M. Edge
ELECTRICAL Print
Date 2/14/01
Signature
Sam Digges / Sam Digges Signature Date 2/14/01
I&C Print
J. W. Dailey / K. D. Turner, Jr. for
MECHANICAL Print Signature
Date 2/14/01
OTHER Print
Date
/ Signature
OTHER Print
Date
Signature
/
OTHER Print
Date
Signature
DESIGN INPUT RECORD.DOT REV. 2 08/08/00
SOUTHERNA
COMPANY
EDWIN I. HATCH NUCLEAR PLANT
Special Design Considerations
Engineering& GenerationServices Page 1 of 1
lob: Title:Transmtal Nwnbcr
D 01-004 Base Station Radio Units) I and 2 01-004-001
Ref. PI 5.03
1. The existing security transmitter rack and associated equipment will be retained and relocated as indicated
in DCP Worksheets E003 and E004. This rack will be powered from the new receptacles fed from Lighting
Panel 1T51-SO11. This equipment may be removed or abandoned in place after the trial period for the 450
MHz radio system. No FCR will be issued if the rack is removed, an ABN will be issued to document
removal of the rack
2. The Radiax distributed antenna system will be rerouted in the vicinity of transmitter 1T48-N004 to increase
the distance from the cable to the transmitter, so that the transmitter will not be impacted by the potential
increase in power to the antenna.
3. Site Procedure AG-IRS-01-0400N provides administrative controls for use of portable radios at Plant Hatch.
Use of this procedure is acceptable for control of the 450MHz units as long as it is clarified with respect to
power level, e.g. at .25 watts these radios should still be kept at a 3 foot distance from sensitive equipment.
So that while it is not necessary to maintain ten feet it is still necessary to maintain three.
4. The plant currently uses EPRI TR 102323 for control of EMI/RFI and this report must be verified to be
valid at the changed frequency via a site survey as a condition of this DCR.
SPECIAL DESIGN CONSIDERATIONS.DOT REV. 1 08/08/00
Question Number: #53, SRO Exam
- 54, SRO Exam
Justification: Robert W. Johnson, after completing NRC SRO TEST 2002, filled out his
answer sheet. When transposing the answers for #53 and #54, he
answered "E". He intended to answer "D" for both questions.
"E" is not a possible answer, since each question only has four possible
answers.
References: Original Exam for Robert W. Johnson, Page 29, Questions #53 and #54
Recommendation: Correct his answer sheet so answers for #53 and #54 are "D'.
NRC Resolution:
NRC SRO TEST 2002
53. -
...
Unit I is operating at 75% RTP with Safety Relief Valve (SRV) "G" leaking to the
Suppression Pool. All attempts to reseat the valve have failed. One RHR loop is
operating in the Suppression Pool Cooling mode with Suppression Pool temperature at
11 OF and increasing very slowly.
Which ONE of the following actions would the crew be expected to take?
A. Maximize torus cooling by placing the other RHR loop in operation and continue
operating.
B. Depressurize the RPV to less than 200 psig within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
C. Reduce THERMAL POWER until all OPERABLE IRM channels < 25/40 divisions of
full scale on Range 7 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
- j Place the reactor Mode Switch in the shutdown position immediately.
54.
Unit 2 is operating at 100% RTP. The quarterly HPCI Flow Rate Test was just
suspended with the following plant conditions:
Torus Cooling Both loops in operation
Torus Temperature 105 0 F and increasing
Torus Level 149" and decreasing
Which ONE of the following describes the reason for suspending adding heat to the
Suppression Pool per Tech Spec section 3.6.2.1?
A. Ensures primary containment design limits are not exceeded in the event of a
LOCA.
B. Preserves heat absorption capabilities of the suppression pool.
C. Ensure PCPL is not reached in the event of an emergency depressurization.
@) Ensure HCTL is not reached in the event of a LOCA.
Tuesday, October 29, 2002 1:28:02 PM 29
Question Number: Admin A-2
LR-JP-25048-00, "Review of Scram Discharge Volume Isolation Valve
Timing and Closure Test"
Justification: The JPM required that the SRO candidates review surveillance procedure;
34SV-Cl 1-002-2, "Scram Discharge Volume Isolation Valve Timing and
Closure Test." The candidate was required to identify that three valves
were outside of acceptable closure times. The candidate was then required
to identify the appropriate Tech Spec actions.
Three of the valves had unacceptable closure times. Two exceeded both
the procedural and Tech Spec limitations. One exceeded only the
procedural limits.
Some of the candidates stated that the valve that exceeded procedural
limits only was procedurally UNSAT, and did not require the Tech Spec
action. The other candidates took the more conservative approach and
declared all valves inoperative per Tech Specs and entered the appropriate
action statement.
Tested components which do NOT meet the criteria specified in the
surveillance procedure are considered inoperable. However, because the
surveillance procedure is also used to satisfy the requirements of ASME
code, some of the criteria may be more restrictive than Technical
Specifications. When the component tested fails to meet the procedure
criterion but meets the Technical Specification criterion it may be shown
that the component meets Technical Specification operability. In this
case, 2C1 1-F011 had a stroke time of 56 sec which did not meet the
procedure acceptance criterion, but was within the Technical Specification
criterion of _60 sec and could therefore possibly be justified as operable.
References: LR-JP-25048-00, "Review of Scram Discharge Volume Isolation Valve
Timing & Closure Test"
34SV-C1 1-002-2S, "Scram Discharge Volume Isolation Valve Timing &
Closure Test"
Tech Spec 3.1.8, "Scram Discharge Volume (SDV) Vent and Drain
Valves"
Recommendation: In view of these factors and the possible interpretation by the
candidate that the task required them to make their determination
based on the Technical Specification, both responses should be
considered acceptable as long as the candidate demonstrated a sound
basis for the decision.
NRC Resolution:
SDV Vent and Drain Valves
3.1.8
3.1 REACTIVITY CONTROL SYSTEMS
3.1.8 Scram Discharge Volume (SDV) Vent and Drain.ValvesA
LCO 3.1.8 Each SDV vent and drain valve shall be OPERABLE.
I
APPLICABILITY: MODES 1 and 2.
ACTIONS
NOTE-
.. . -.. -- .
Separate Condition entry is allowed for each SDV vent and drain line.
CONDITION REQUIRED ACTION COMPLETION TIME
A. One or more SDV vent or A.1 Restore valve to 7 days
drain lines with one valve OPERABLE status.
B. One or more SDV vent or B.1 ----- NOTE-
drain lines with both valves An Isolated line may be
inoperable. unisolated under
administrative control to
allow draining and
venting of the SDV.
Isolate the associated 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />
line.
C. Required Action and C.1 Be in MODE 3. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
associated Completion
Time not met
HATCH UNIT 2 3.1-22 Amendment No. 135
SDV Vent and Drain Valves
SURVEILLANCE REQUIREMENTS
SURVEILLANCE FREQUENCY
SR 3.1.8.1 --------....-.....------- NOTE------
Not required to be met on vent and drain valves - V.
closed during performance of SR 3.1.8.2.
Verify each SDV vent and drain valve is open. 31 days
SR 3.1.8.2 Cycle each SDV vent and drain valve to the fully 92 days
closed and fully open position.
SR 3.1.8.3 Verify each SDV vent and drain valve:r 24 months
a. Closes in < 60 seconds after receipt of anw
actual or simulated scram signal; and
b. Opens when the actual or simulated scram
signal is reset.'
HATCH UNIT 2 3.1-23 .. Amendment No ,t 174
Southern Nuclear
E. I. Hatch Nuclear Plant
Operations Training
TITLE
REVIEW OF SCRAM DISCHARGE VOLUME ISOLATION VALVE TIMING &
CLOSURE TEST
AUTHOR MEDIA NUMBER TIME
R. L. SMITH LR-JP-25048-00 20 Minutes
RECOMMENDED BY 'APPROVED BY DATE
T. F. PHILLIPS R. S. GRANTHAM 10/07/02
SOUTHERN
w w w i
w4
COMPANY
Energy to Serve Your World'
SOUTHERN NUCLEAR OPERATING COMPANY
PLANT E. I. HATCH Page 1 of 1
FORM TITLE: TRAINING MATERIAL REVISION SHEET
Program/Course Code: OPERATIONS TRAINING Media Number: LR-JP-25048
.. itials Initials
0 10/07/02 Initial development. RLS RSG
LR-JP-25048-00
Page 2 of 6
UNIT 1 0 UNIT 2 (X)
TASK TITLE: REVIEW OF SCRAM DISCHARGE VOLUME
ISOLATION VALVE TIMING & CLOSURE TEST
JPM NUMBER: LR-JP-25048-0O
TASK STANDARD: The task shall be complete when the operator reviews the
completed surveillance procedure, 34S V-Cl 1-002-2, and
determines if the test is satisfactory or unsatisfactory.
TASK NUMBER: XXX.XXX
OBJECTIVE NUMBER: XXX.XXX.X
PLANT HATCH JTA IMPORTANCE RATING:
RO X.XX
SRO X.XX
K/A CATALOG NUMBER: G2.1.33
K/A CATALOG JTA IMPORTANCE RATING:
RO 3.4
SRO 4.0
OPERATOR APPLICABILITY: Reactor Operator (RO)
GENERAL REFERENCES: Unit 2.
34SV-Cl 1-002-2 Rev 4.2
REQUIRED MATERIALS: Unit 2, -
Completed surveillance package: 34SV-C 11-002-2
APPROXIMATE COMPLETION TIME: 20 Minutes
SIMULATOR SETUP: N/A
1)
UNIT 2
READ TO THE OPERATOR
INITIAL CONDITIONS:
1. Unit 2 is at 100% RTP.
2. Maintenance has been performed on the SDV vent and drain valves.
3. 34SV-Cl 1-002-2S, "Scram Discharge Volume Isolation Valve Timing &
Closure Test," has just been completed due to the maintenance.
INITIATING CUES:
Review the procedure data and determine the acceptability of the test, and
determine if any required Tech Spec action(s) are necessary.
LR-JP-25048-00
Page 4 of 6
STEP PERFORMANCE STEP 2< STANDARD SAT/UNSAT,
- .(COMMENTS)
START
TIME:
PROMPT: AT this time, GIVE the operator the completed copy of 34SV-C 11-002-2S,
"Scram Discharge Volume Isolation Valve Timing & Closure Test"
1. The operator reviews the procedure. The operator REVIEWS
Discharge Volume Isolation
Valve Timing & Closure Test."
2. The operator evaluates closing stroke Per step 7.2.5, 7.2.7 and 7.2.8 of
time data for: 34SV-Cl 1-002-2S, the operator
2C1l-FO10A SDV Vent Vlv EVALUATES the closing stroke
time data for:
2C11-F035A SDV Vent Vlv
2C1l-F010A SDV Vent Vlv
2C1 1-F010B SDV Vent Vlv
2C11-F035A SDV Vent VIv
2CI 1-F035B SDV Vent Vlv
2C1 1-F010B SDV Vent Vlv
2C1 1-F0l1 SDV Drain Vlv
2C11-F035B SDV Vent Vlv
2C1 l-F037 SDV Drain Vlv
2C1 1-F01I SDV Drain Vlv
2C11 -F037 SDV Drain Vlv
Per step 7.2.7 and 7.2.8 of
34SV-C1 1-002-2S, the operator
DETERMINES the closing stroke
time data for:
2C11-F035A SDV Vent Vlv
2C1 1-F7011 SDV Drain Vlv
2CI 1-F037 SDV Drain Vlv
Have exceeded their closing time
limit per steps 7.2.7 and 7.2.8, ,
and they are
UNSATISFACTORY.
RESPONSE CUE: N/A
PROMPT: IF the operator recommends that section 7.3 needs to be performed to adjust
the timing of the UNSAT valves, INFORM the operator due to plant
conditions that section 7.3 CANNOT be performed at this time.
(** Indicates critical step)
LR-JP-25048-00
Page 5 of 6
STEP.; PERFORMANCE STEP STANDARD . SATIUNSAT
(COMMENTS)
4. The operator evaluates the closing Per steps 7.2.20 and 7.2.22 of
time difference data for: 34SV-Cl 1-002-2S, the operator
2CI I-F010A SDV Vent Vlv EVALUATES the closing time
difference data for:
2C1 l-F035A SDV Vent Vlv
2C1 1-F010A SDV Vent VIv
2C11-F010B SDV Vent Vlv
2C11-F035A SDV Vent Vlv
2CI 1-F035B SDV Vent Vlv 2C11-FOIOB SDV Vent Vlv
2CI1I-F0l1 SDV Drain Vlv
2C1 1-F035B SDV
Vent Vlv
2C1 1-F037 SDV Drain Vlv
2C1 1-FO011 SDV Drain Vlv
2C1 1-F037 SDV Drain Vlv
and DETERMINES it to be
SATISFACTORY.
5. The operator evaluates the opening Per steps 7.2.23 and 7.2.25 of
time difference data for: 34SV-Cl 1-002-2S, the operator
2C1 1-F010A SDV Vent Vlv EVALUATES the opening time
difference data for:
2C 1 -F035A SDV Vent Vlv
2CI 1-FO10A SDV Vent Vlv
2CI 1-F010B SDV Vent Vlv
2C1 1-F035A SDV Vent Vlv
2CI 1-F035B SDV Vent VIv
2CI1-FO1OB SDV Vent Vlv
2C11 -FOII SDV Drain VIv
2C11-F0351 SDV Vent Vlv
2C1Il1-F037 SDV Drain Vlv
2C1 l-FO 1I SDV Drain Vlv
2C1 l-F037 SDV Drain Vlv
and DETERMINES it to be
SATISFACTORY.
i.
condition A and B, the operator
DETERMINES, that 3.1.8A
applies to 2C11-F035A, 2C1 1
FOi1, & 2C11-F037 valves, and'
3.1.8.B applies to 2C 11-FO11 and'
2C11 -F037 valves.
3.1.8.A Restore valve to
OPERABLE status within 7daysr.
3.1.8.B Isolate the the associated
line within 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />s:
I
RESPONSE CUE: N/A
(** Indicates critical step)
LR-JP-25048-00
Page 6 of 6
STEP PERFORMANCE STEP - TANDARD SAT/UtNSAT
NOTE: The operator may note that the Drain line valves (2C11-F011 and 2C11
F037) may be opened under administrative control to allow draining of the
SDV.
END
TIME:
NOTE: The terminating cue shall be given to the operator when:
- With no reasonable progress, the operator exceeds double
the allotted time.
- Operator states the task is complete.
TERMINATING CUE: We will stop here.
(** Indicates critical step)
DOCUMENT TYPE: PAGE
SOUTHERN NUCLEAR
PLANT E. I. HATCH . SURVEILLANCE PROCEDURE- 1 OF 16
DOCUMENT TITLE: DOCUMENT NUMBER: REVISIONNERSION
SCRAM DISCHARGE VOLUME ISOLATION VALVE / 34SV-C11-002-2S,' NO:
TIMING & CLOSURE TEST, 4.2
EXPIRATION APPROVALS: C.R. Dedrickson DATE 10-07-99 ECTIVE
DATE: DEPARTMENT MGR DATE:
N/A NPGM/POAGM/PSAGM N/A DATE N/A 09/27/01
1.0 OBJECTIVE
This procedure provides instructions for verifying that the scram discharge volume vent and
drain valves close in the proper amount of time when given a simulated scram signal and that
they open when that signal is removed. This prpcedure satisfies the requirements of Unit 2 TS i
SR 3.1.8..31 TS 5.5.6, and ASME OM Code Subsection ISTC.
TABLE OF CONTENTS
Section Page
2.0 APPLICABILITY .......................................................................................................... 1
3.0 RE FE REN C ES .................................................................................................................... 2
4.0 REQUIREMENTS ....................................................................................................... 2
5.0 PRECAUTIONS/LIMITATIONS ...................................................................................... 3
6.0 PR ER EQ UISITES ............................................................................................................... 3
7.0 P R O C ED UR E ..................................................................................................................... 4
7.1 PR ETEST ................................................................................................................ 4
7.2 TIMING AND CLOSURE TEST ................................................................................ 5
7.3 ADJUSTM ENT ....................................................................................................... 10
7.4 RESTO RATIO N .................................................................................................... 13
7.5 TEST RESULTS .................................................................................................... 14
7.6 TEST R EV IEW ............................................................................................................ 16
2.0 APPLICABILITY
2,1 This procedure applies to the Unit 2 Scram Discharge Volume Vent and Drain VIvs,
2C11 -F01 OA & B, 2C1 1-F035A & B, 2C11 -F01I and 2C11 -F037; their associated Solenoid
Operated Pilot Valves, 2C11 -F009 and 2C11 -F040; and their actuating relays, 2C71 -K21 A-D.
This procedure is required to be performed at least once per 18 months.
2.2 This procedure is performed after maintenance on the SDV Valves that could affect valve
2.3 IF performing this procedure for setup and timing only and no maintenance was performed on
the SDV Valves, the stem verification will be marked N/R.
MGR-0002 Rev 8
SOUTHERN NUCLEAR PAGE
PLANT E. I. HATCH 1 20F16
DOCUMENT TITLE: DOCUMENT NUMBER: REVISIONNERSION
SCRAM DISCHARGE VOLUME ISOLATION VALVE 34SV-C1 1-002-2S NO:
TIMING & CLOSURE TEST 4.2
3.0 REFERENCES
3.1 90AC-OAM-001 -OS, Test and Surveillance Control
3.2 Unit 2 TS 5.5.6 and TS SR 3.1.8.3
3.3 H-26006 and H-26007, Control Rod Drive Hydraulic System P&IDs
3.4 H-27605 thru H-27619 and H-27850, Reactor Protection System Elementary Diagrams
3.5 Edwin I. Hatch Nuclear Plant Unit 2 - Valve Inservice Testing Plan
3.6 42EN-INS-001-OS, Inservice Testing Program
3.7 31 GO-INS-001 -0S, IS] Pump and Valve Operability Tests
4.0 REQUIREMENTS
4.1 PERSONNEL REQUIREMENTS
The number and qualification level of personnel performing this procedure will be determined
by the Shift Supervisor.
4.2 MATERIAL AND EQUIPMENT
4.2.1 2 HFA Gagging devices (optional)
4.2.2 Six calibrated stopwatches - one for each valve
4.3 SPECIAL REQUIREMENTS
4.3.1 Independent verification, as described in 10AC-MGR-019-OS, Procedure Use and
Adherence, will be required for portions of this procedure.
4.3.2 The VERIFIED part of any step requiring independent verification may be performed out
of sequence any time after completion of the first signoff.
4.3.3 The RESTORATION section of this procedure must be performed anytime the procedure
is begun, regardless of whether the results are acceptable OR unacceptable.
4.3.4 If in mode 1 or 2, this test will be immediately EXITED and the RESTORATION section
will be performed if annunciator 603-238, ROD OUT BLOCK alarms due to high SDV
level. This action is taken to allow the SDV to be drained prior to receipt of a SCRAM.
G16.30
MGR-0001 Rev 3
SOUTHERN NUCLEAR PAGE
PLANT E. I. HATCH-- 3 OF 16
DOCUMENT TITLE: DOCUMENT NUMBER: REVISIONNERSION
SCRAM DISCHARGE VOLUME ISOLATION VALVE 34SV-C11-002-2S NO:
TIMING & CLOSURE TEST 4.2
5.0 PRECAUTIONS/LIMITATIONS
5.1 PRECAUTIONS
5.1.1 Observe safety rules outlined in the Southern Nuclear Safety and Health Manual.
5.1.2 Observe proper radiation protection practices to maintain personnel exposure ALARA
and to limit the spread of contamination. Remain alert for changes which might require
additional radiation protection.
5.1.3 IF the CRD System is operating during this test, leaking scram valves will cause
the scram valves discharge volume to begin filling during this test. IF the level
reaches 57 gal., a reactor scram will result.
5.1.4 The following annunciators may alarm during this test:
603-119, SCRAM DISCH VOL NOT DRAINED
603-238, ROD OUT BLOCK
603-239, RMCS / RWM ROD BLOCK OR SYSTEM TROUBLE
5.2 LIMITATIONS
N/A - Not applicable to this procedure
6.0 PREREQUISITES
6.1 The scram valve pilot air header is pressurized to between 70 PSIG and 75 PSIG.
6.2 The RPS is in operation and the scram relays are reset.
6.3 The Scram Discharge Volume Vent and Drain Vlvs, 2C1 1-F01 GA & B, 2C1 1-F035A & B,
2C1 1-F01 1 and 2C1 1-F037 are OPEN.
6.4 This test may be performed with the reactor in ANY mode of operation. It is preferable that the
reactor is in Modes 3, 4 or 5 with all operable control rods fully inserted, AND all other control
rods tagged under clearance such that they will NOT scram in the event of a scram signal
occurring.
6.5 Communications have been established between the RPS Panels, 2H1-1 -P609, 2H1 1-P611,
and Panel 2H11-P603.
6.6 A Radiation Work Permit may be required for entry to areas for valve stem position
verification.
G16.30
MGR-0001 Rev 3
PAGE
SOUTHERN NUCLEAR
PLANT E. I. HATCH.. .. 40F16.
DOCUMENT TITLE: DOCUMENT NUMBER: REVISIONNERSION
SCRAM DISCHARGE VOLUME ISOLATION VALVE 34SV-C11-002-2S NO:
TIMING & CLOSURE TEST 4.2
7.0 PROCEDURE
7.1 PRETEST
7.1.1 Confirm that all prerequisites have been met. -A-
7.1.2 Obtain Shift Supervisor's permission to perform this surveillance.
7.1.3 Record stopwatch numbers:
w- .9
-03 #4&
G16.30
MGR-0001 Rev 3
SOUTHERN NUCLEAR PAGE
PLANT E. 016
OF5
5HATCH
DOCUMENT TITLE: DOCUMENT NUMBER: REVISIONNERSION
SCRAM DISCHARGE VOLUME ISOLATION VALVE 34SV-Cl 1-002-2S NO:
TIMING & CLOSURE TEST 4.2
7.2 TIMING AND CLOSURE TEST
CONTINUOUS
7.2.1 At Panel 2H11 -P609, GAG or FINGER CLOSED relay 2C71 -K21A.
NOTES
-The valve closing time is measured from the closing of relay 2C71-K21C until the red light
extinguishes. The stopwatches are to be started WHEN the relay is closed and stopped WHEN the
red light extinguishes.
-Ensure that the following relay remains closed until after all closing times have been recorded.
-The following step simulates a full scram and will cause all scram discharge volume vent and drain
valves to close.
7.2.2 At Panel 2H11-P609, GAG or FINGER CLOSED relay 2C71-K21C.
7.2.3 At Panel 2H1-1 -P603, simultaneously START the stopwatches.
7.2.4 WHEN the individual scram discharge volume vent or drain valves
stop closing, STOP the stopwatches. ..
7.2.5 Record the closing times of the scram discharge volume vent and drain valves:
Scram Discharge Volume Vent VIv, 2C1 1-F01 OA 53 Sec. 4)L
Scramr Dischargeýc~
ciamDischr'ge Volum Ie'Vent Vlv, 2011 -F,1035A .. L..e
Scram Discharge Volume Vent Vlv, 2C11 -F01O3B q Sec. 4 fiY.
Scram Discharge Volume Vent Vlv, 2C11 -F035B 13 Sec.
Scam 1bischarge'Volume Drain Vl, 2611-F01oi .. j .Sec4
Scam: Discharge Volume Drain VIv, 2011 -F037 LSec.
G16.30
MGR-0001 Rev 3
SOUTHERN NUCLEAR PAGE
PLANT E. I. HATCH 6 OF 16
DOCUMENT TITLE: DOCUMENT NUMBER: REVISIONNERSION
SCRAM DISCHARGE VOLUME ISOLATION VALVE 34SV-C11-002-2S NO:
TIMING & CLOSURE TEST 4.2
7.2.6 Confirm that the SDV vent and drain valves are actually closed by observing valve stem
position.
Scram Discharge Volume Vent VIv, 2C0 1-F01OA, CLOSED
Scm D
Scram Discharge Volume Vent VIv, 2C0 1-F035A, CLOSED
Scram Discharge Volume Vent Vlv, 2C11 -F035B, CLOSED
Scram Discharge Volume Drint Vlv, 2011-F3l, CLOSED
Scram Discharge Volume Drain VIv, 2C0 1 -F0371, CLOSED
Scram Discharge Volume Drain VIv, 2C1 1-F037, CLOSED
7.2.7. Confjirm that valves 2C 1-F01OA, 2C1 1"-F01OB and 2C11 -F011i
close in less than or equal to 55 seconds. i
7.2.8 Confirm that valves 2C1 1-F035A, 2C1 1-F035B and 2C1 1-F037
close in less than or equal to 60 seconds.!
NOTE
The valve opening time delay is measured from the release of relay 2C71 -K21 C until the red light
illuminates. The stopwatches are to be started WHEN the relay is released and stopped WHEN the red
light illuminates.
7.2.9 At Panel 2H11 1-P609, RELEASE relay 2C71-K21C.
7.2.10 At Panel 2H1-1 -P603, simultaneously START the stopwatches.
7.2.11 At Panel 2H1-1 -P609, RELEASE relay 2C71 -K21 A.
7.2.12 WHEN the individual scram discharge volume vent or drain valves
begin to open, STOP the stopwatches.
G16.30
MGR-0001 Rev 3
SOUTHERN NUCLEAR PAGE
PLANT E. 1.HATCI -. 7 OF 16
DOCUMENT TITLE: DOCUMENT NUMBER: REVISIONNERSION
SCRAM DISCHARGE VOLUME ISOLATION VALVE 34SV-C11-002-2S NO:
TIMING & CLOSURE TEST 4.2
7.2.13 Record the valve opening time delay for each of the scram discharge volume vent and
drain valves.
Scram Discharge Volume Vent Vlv, 2C1 1-F010A Za Sec.
Scram Discharge Volume Vent VIv, 2C1 1-F035A 1j _Sec.
Scram Discharge Volume Vent VIv, 2C11 -F01OB 22 Sec. -4:
Scram Discharge Volume Vent VIv, 2C1 1-F035B I r Sec.
Scram Discharge Volume Drain Vlv, 2C01-F011 22. Sec.
Scram Discharge Volume Drain VIv, 2C0 1-F037 .J".Sec.
7.2.14 Confirm that the SDV vent and drain valves are actually OPEN by observing valve stem
position.
Scram Discharge Volume Vent VIv, 2C0 1-F101OA OPEN
Scram Discharge Volume Vent Vlv, 2C 1-FO35A OPEN
Scram Discharge Volume Vent VIv, 2C11-F01OB OPEN
Scram Discharge Volume Vent VIv, 2C 1-F0358 OPEN
Scram Discharge Volume Drain VIv, 2C0 1-F011 OPEN
Scram Discharge w
Volume Drain VIv, 2C11 -F037 OPEN
7.2.15 At Panel 2H1-1 -P611, GAG or FINGER CLOSED relay 2C71 -K21 B. -4-he'l
7.2.16 At Panel 2H1-1 -P611, GAG or FINGER CLOSED relay 2C71 -K21 D.
7d44
7.2.16.1 Confirm that all scram discharge volume vent and drain valves CLOSE:
Scram Discharge Volume Vent VIv, 2C1 1-F101OA
Scram Discharge Volume Vent VIv, 2C 1-FO35A
Scram Discharge Volume Vent VIv, 2C1 1-F01OB
Scram Discharge Volume Vent Vlv, 2C11 -F035B
Scram Discharge Volume Drain VIv, 2C1 1-F011
Scram Discharge Volume Drain VIv, 2C0 1-F037
G16.30
MGR-0001 Rev 3
SOUTHERN NUCLEAR PAGE
PLANT E. I. HATCH-.-- 8 OF 16
DOCUMENT TITLE: DOCUMENT NUMBER: REVISION/VERSION
SCRAM DISCHARGE VOLUME ISOLATION VALVE 34SV-C11-002-2S NO:
TIMING & CLOSURE TEST 4.2
7.2.17 At Panel 2H1-1 -P611, RELEASE relay 2C71-K21 D.
7.2.18 At Panel 2H1-1 -P611, RELEASE relay 2C71 -K21 B.
7.2.19 Confirm that all scram discharge volume vent and drain valves OPEN:
Scram Discharge Volume Vent VIv, 2C1 1-F01OA OPENS 4iA
Scram Discharge Volume Vent VIv, 2C 1-F035A OPENS
Scram Discharge Volume Vent Vlv, 2C0 1-F01OB OPENS
Scram Discharge Volume Vent VIv, 2C11 -F035B OPENS
Scram Discharge Volume Drain VIv, 2C0 1-F01I OPENS
Scram Discharge Volume Drain VIv, 2C11-F037 OPENS
7.2.20 Using times from step 7.2.5, calculate the difference in closing time between the valves
listed below:
2C11-F035A closing time 41 Sec.
MINUS
2C11-F010A closing time S3 Sec. = g Sec. _1_
2C11 -F035B closing time Sec.
MINUS
2C11 -F010B closing time d/g' Sec.= ( Sec. .4
2C11 -F037 closing time 6/ < Sec.
MINUS
2C11 -F01 1 closing tim e , o sec.£= ___'Sec. 4t1
7.2.21 Verify all calculations in the previous step are correct.
AR.
G16.30
MGR-0001 Rev 3
SOUTHERN NUCLEAR PAGE
PLANT E. I. HATCH ...... 9 OF 16
DOCUMENT TITLE: DOCUMENT NUMBER: REVISIONNERSION
SCRAM DISCHARGE VOLUME ISOLATION VALVE 34SV-C11-002-2S NO:
TIMING & CLOSURE TEST 4.2
7.2.22 Confirm that the difference in closing time between valves 2C11 -F035A
and 2C11 -F010A, 2C11 -F035B and 2C11 -F010B, and 2C11 -F037 and
2C11 -F011 is greater than or equal to 5 Seconds.
7.2.23 Using times from step 7.2.13, calculate the difference in valve opening time delay
between the valves listed below:
2C11 -F01 OA opening delay time 2U0 Sec.
MINUS
2C11 -F035A opening delay time IV_ Sec.= 16 Sec.
7ý-k-
2C11 -F010B opening delay time 2-.- Sec.
MINUS
2C011 -FO35B opening delay time /"5Sec. = "Sec.
2C0 1-F01 1 opening delay time ZZ- Sec.
MINUS
2C11 -F037 opening delay time /7* Sec. = 15' Sec.
. r.-
7.2.24 Verify all calculations in the previous step are correct.
7.2.25 Confirm that the difference in valve opening time delay between valves
2C11 -FO10A and 2C11 -F035A, 2C11 -F010B and 2C11 -F035B, and
2C11 -F01 1 and 2C11 -F037 is greater than or equal to 5 Seconds.
7.2.26 IF all of the valve times recorded in this Section meet the acceptance
criteria, proceed to the Restoration Section of this procedure;
otherwise, continue with the Adjustment Section.
G 16.30
MGR-0001 Rev 3
SOUTHERN NUCLEAR PAGE
PLANT E. I. HATCH 10OF 16
DOCUMENT TITLE: DOCUMENT NUMBER: REVISIONNERSION
SCRAM DISCHARGE VOLUME ISOLATION VALVE 34SV-Cl 1-002-2S NO:
TIMING & CLOSURE TEST 4.2
7.3 ADJUSTMENT
CONTINUOUS
NOTE
This section only needs to be done if any of the valve closing or opening delay times can NOT meet the
acceptance criteria.
7.3.1 IF Scram Discharge Volume Vent and Drain Vlvs, 2C11-F035A & Band 2C11-F037,
do NOT meet the acceptance criteria for valve closing time, perform the following:
7.3.1.1 On the wall between MCCs 2R24-SO18 A and B (130RHR1 7),
ADJUST Speed Control Valve, 2C11 -F081, accordingly (OPEN to
increase closing speed, CLOSED to decrease it).
7.3.1.2 At Panel 2H1 1-P611, GAG or FINGER CLOSED relay 2C71 -K21 B.
7.3.1.3 At Panel 2H1 1-P611, GAG or FINGER CLOSED relay 2C71 -K21 D.
7.3.1.3.1 Note the closing time on all scram discharge volume vent and
drain valves following closure of 2C71 -K21 D.
7.3.1.4 At Panel 2H11-P611, RELEASE relay 2C71-K21D.
7.3.1.5 At Panel 2H1 1-P611, RELEASE relay 2C71 -K21 B.
7.3.1.6 Repeat steps 7.3.1.1 through 7.3.1.5 until the acceptance criteria for
valve closing time (steps 7.5.2.3-7.5.2.5) can be met. Record the final
closing times of the scram discharge valve vent and drain valves.
Scram Discharge Volume Vent VIv, 2C1 1-F01 OA __-Sec.
Scram Discharge Volume Vent VIv, 2C1 1-F035A _----Sec.
Scram Discharge Volume Vent VIv, 2C11-FOl OB ___--.Sec.
Scram Discharge Volume Vent VIv, 2C11 -F035B Sec.
Scram Discharge Volume Drain VIv, 2C11 -F1011 -Sec.
Scram Discharge Volume Drain VIv, 2C11 -F037 Sec.____-,ec
G16.30
MGR-0001 Rev 3
SOUTHERN NUCLEAR PAGE
PLANT E. I. HATCH 11 OF 16
DOCUMENT TITLE: DOCUMENT NUMBER: REVISIONNERSION
SCRAM DISCHARGE VOLUME ISOLATION VALVE 34SV-C11-002-2S NO:
TIMING & CLOSURE TEST 4.2
7.3.1.7 Calculate the difference in closing time between the valves listed below:
2C1 1 -F035A closing time Sec.
MINUS
2C1 1-F01OA closing time Sec. = Sec.
2C1 1-FO35B closing time -_ Sec.
MINUS
2C11 -F01OB closing time - Sec. = Sec.
2C11 -F037 closing time Sec.
MINUS
2C11 -F011 closing time - See.= Sec.
7.3.1.8 Verify all calculations in the previous step are correct.
7.3.1.9 Confirm that the difference in closing time between valves 2C1 1-FO35A
and 2C1 1-F01OA; 2C11 -F035B and 2C11 -F01 OB, and 2C11 -F037 and
2C11 -F011 is greater than or equal to 5 Seconds.
7.3.2 IF Scram Discharge Volume Vent and Drain Valves, 2C1 1-F01 0 A&B and 2C11 -F011,
do NOT meet the acceptance criteria for valve opening time delay, perform the following:
7.3.2.1 At the CRD Flow Control Area (130RAR21), ADJUST Speed Control
Valve, 2C11 -F086, accordingly (OPEN to decrease the time delay,
CLOSED to increase it).
7.3.2.2 At Panel 2H1-1 -P611, GAG or FINGER CLOSED relay 2C71 -K21 B.
7.3.2.3 At Panel 2H1-1-P61 1, GAG or FINGER CLOSED relay 2C71 -K21 D.
7.3.2.4 AFTER all of the scram discharge volume vent and drain valves
have CLOSED, RELEASE relay 2C71 -K21 D.
7.3.2.4.1 Note the valve opening time delay on all scram discharge
volume vent and drain valves.
7.3.2.5 At Panel 2H 11 -P611, RELEASE relay 2C71 -K21 B.
G16.30
MGR-0001 Rev 3
SOUTHERN NUCLEAR I PAGE
PLANT E. I. HATCH 12 OF 16
DOCUMENT TITLE: DOCUMENT NUMBER: REVISION/VERSION
SCRAM DISCHARGE VOLUME ISOLATION VALVE 34SV-C11-002-2S NO:
TIMING & CLOSURE TEST 4.2
7.3.2.6 Repeat steps 7.3.2.1 through 7.3.2.4.1 until the acceptance criteria for valve opening
time delay (step 7.5.2.6) can be met. Record the final opening time delays of the
scram discharge volume vent and drain valves.
Scram Discharge Volume Vent Vlv, 2C11 -F01OA -_Sec.
Scram Discharge Volume Vent Vlv, 2C11 -F035A Sec.
Scram Discharge Volume Vent VIv, 2C1 1-FOIOB Sec.
Scram Discharge Volume Vent VIv, 2C0 1-F035B Sec.
Scram Discharge Volume Drain Viv, 2C11 -FOl 1 Sec.
Scram Discharge Volume Drain VIv, 2C11-F037 Sec.
7.3.2.7 Calculate the difference in valve opening time delay between the valves listed below:
2C11 -FO10A opening delay Sec.
MINUS
2C11 -FO35A opening delay Sec.= Sec.
2C11-F01OB opening delay Sec.
MINUS
2C1 1-F035B opening delay Sec. = Sec.
2C11-F011 opening delay Sec.
MINUS
2C11 -F037 opening delay Sec.= - Sec.
7.3.2.8 Verify all calculations in the previous step are correct.
LIC. OPER.
7.3.2.9 Confirm that the difference in valve opening time delay between valves
2C11 -F01 OA and 2C11 -F035A, 2C11 -F010B and 2C11 -F035B, and
2C0 1-F011 and 2C11 -F037 is greater than or equal to 5 Seconds.
G16.30
MGR-0001 Rev 3
SOUTHERN NUCLEAR PAGE
PLANT E. I. HATCH .. 13 OF 16
DOCUMENT TITLE: DOCUMENT NUMBER: REVISIONNERSION
SCRAM DISCHARGE VOLUME ISOLATION VALVE 34SV-C11-002-2S NO:
TIMING & CLOSURE TEST 4.2
7.4 RESTORATION
7.4.1 At Panel 2H11-P609, REPLACE all relay faceplates.
7.4.2 At Panel 2H 11 -P611, REPLACE all relay faceplates. -4Ž
7.4.3 At Panel 2H1 1-P609, Confirm and VERIFY the following relays are DE-ENERGIZED:
2C71 -K21 A
VERIFIED
2C71 -K21 C
VERIFIED
7.4.4 At Panel 2H1-1 -P611, Confirm and VERIFY the following relays are DE-ENERGIZED:
2C71 -K21B
VERIFIED
4
-4
2C71 -K21 D
4
7.4.5
VERIFIED
-4-
At Panel 2H1 1-P603, confirm AND verify that all scram discharge volume vent and drain
valves are OPEN:
Scram Discharge Volume Vent Vlv, 2C0 1-F01OA
VERIFIED
Scram Discharge Volume Vent Vlv, 2C1 1-F035A
VERIFIED
Scram Discharge Volume Vent VIv, 2C0 1-F1010B
VERIFIED
Scram Discharge Volume Vent VIv, 2C11 -F035B 4Žkv
VERIFIED
Scram Discharge Volume Drain VIv, 2C11 -F011
Scram Discharge Volume Drain VIv, 2C1 1-F037
VERIFIED
-4'
VERIFIED
441V
G16.30
MGR-0001 Rev 3
SOUTHERN NUCLEAR I PAGE
PLANT E. I. HATCHF- 4OF16
DOCUMENT TITLE: DOCUMENT NUMBER: REVISIONNERSION
SCRAM DISCHARGE VOLUME ISOLATION VALVE 34SV-C11-002-2S NO:
TIMING & CLOSURE TEST 4.2
7.5 TEST RESULTS
7.5.1 Reason for test: (ý) Norm. Surv. ( )MWO #
( ) Other
7.5.2 Acceptance Criteria
7.5.2.1 ALL scram discharge volume vent and drain valves close when given a simulated
scram signal.
7.5.2.2 ALL scram discharge volume vent and drain valves open when the signal is removed.
7.5.2.3 Valves,2C1 1-F01 OA, 2C11 -F01 OB and 2C1 1-F1011 close in less than or equal ,
to 55 Seconds.
7.5.2.4 Valves 2C11 -F035A, 2C 1-F035B and 2C1 1-F037 close in less than or equal i
to 60 Seconds.;
7.5.2.5 The difference in closing time between valves 2C11 -F035A and 2C11 -F101OA, 2C1 1
F035B and 2C1 1-F01 OB, and 2C1 1-F037 and 2C11 -FOl 1 is greater than or equal to
5 Seconds.
7.5.2.6 The difference in valve opening time delay between 2C11 -FO10A and 2C11 1-F035A,
2C1 1-F010B and 2C1 1-F035B, and 2C11-F011 and 2C11 -F037 is greater than or
equal to 5 Seconds.
7.5.2.7 Valve stem position agrees with light indication in Control Room.
(see steps 7.2.6 and 7.2.14)
G16.30
MGR-0001 Rev 3
SOUTHERN NUCLEAR PAGE
PLANT E. I. HATCH 15 OF 16
DOCUMENT TITLE: DOCUMENT NUMBER: REVISION/VERSION
SCRAM DISCHARGE VOLUME ISOLATION VALVE 34SV-C11-002-2S NO:
TIMING & CLOSURE TEST 4.2
7.5.3 Test Result:
(/) Satisfactory
Unsatisfactory
7.5.4 Unsatisfactory Conditions:
7.5.5 Comments/Corrective Actions:
7.5.6 Test Completed and/or Verified by:
AnkV >rne
PrIft Name Initials Date
ye oko /
Print Name Iniials Date
Date L
Print Name Initials
Date
/e Dat
Date
Print Name Initials
/Nn D
Print Name Initials Date
/
Print Name Initials Date
II.
Print Name Initials Date
/t /.
Print Name Date
Initials
G16.30
MGR-0001 Rev 3
SOUTHERN NUCLEAR PAGE
PLANT 1. HATCH 16 OF 16
DOCUMENT TITLE: DOCUMENT NUMBER: REVISION/VERSION
SCRAM DISCHARGE VOLUME ISOLATION VALVE 34SV-Cl 1-002-2S NO:
TIMING & CLOSURE TEST 4.2
7.6 TEST REVIEW
7.6.1 The Shift Supervisor will review the procedure data for completeness and indicate
concurrence with the test satisfactory/unsatisfactory determination by signing below.
Results Reviewed By: I
Shift Supervisor Date
7.6.2 The Shift Supervisor will forward this procedure, with all sign offs complete through 7.7.1
to the IST Engineer for IST and ANII review
IST Engineer / Date ANII / Date
7.6.3 The IST Engineer will forward this procedure, with all sign offs complete, to Document
Control for retention in accordance with 20AC-ADM-002-OS, Quality Assurance Records
Administration.
G 16.30
MGR-0001 Rev 3