ML20077D173
| ML20077D173 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 07/18/1983 |
| From: | Kemper J PECO ENERGY CO., (FORMERLY PHILADELPHIA ELECTRIC |
| To: | Schwencer A Office of Nuclear Reactor Regulation |
| References | |
| NUDOCS 8307260406 | |
| Download: ML20077D173 (31) | |
Text
_-
PHILADELPHIA ELECTRIC COMPANY 2301 MARKET STREET P.O. BOX 8699 1881 1981 PHILADELPHI A. PA.19101 JUL181983
'2im eai.a w a
,o ~ s. - -
VICE PRESIDENT tusente nsme ano nasa maces Mr.
A.
Schwencer, Chief Docket Nos. 50-352 Licensing Branch No. 2 50-353 Division of Licensing U.
S.
Nuclear Regulatory Commission Washington, D.C.
20555
Subject:
Limerick Generating Station, Units I&2 Open Items from NRC Instrumentation and Control Systems Branch (ICSB)
Re f erence :
July 11, 1983 Meeting with ICSB in Bethesda, MD File:
GOVT l-1 (NRC)
Dear Mr. Schwencer:
During the reference meeting, information was requested by ICSB to resolve several open items.
Enclosed are marked up FSAR pages to provide the requested information.
This infor-mation will be incorporated in the August revision to the FSAR.
Where the information requested is not appropriate for incorporation into the FSAR, it is provided in this letter.
The following information is provided for the items discussed:
Item 1 - Instrumentation Setpoints Philadelphia Electric will propose Limerick unique Technical Specifications for instrumentation and controla consistent with the approved methodology employed in development of instrument setpoints.
Item 2 - At Power Testabilitv of Actuation Instrumentation The Limerick design includes on-line testing capability for the actuation instrumentation channels, logic and actuation devices associated with the PCRVICS, REIS, RAIS, HCRI,RCIC and ESW systems.
Surveillance testing o f instrumen-tation will include testing o f all the logic components.
Attached are marked up FSAR pages to reflect the details o f Limerick at power testability.
l 8307260406 830718 PDR ADOCK 050003g2
. Item 3 - Lif ting of Leads to Perform Surveillance Testing Lifting of leads are not required to perform surveillance tests.
The response to ques tion 4 21.36 is changed to reflect this and is attached.
Item 4 Engineered Safety Features Reset Controls Attached is the revised response to Question 421.7 which provides the requested information.
Item 5 - Manual Initiation of Safety Systems Additional information logic arrangement, on ment and power supply for RHR and core sensor assign-to supplement the response spray instrumentation to Ques tion 4 21.48 will be provided in a separate letter.
Item 6 - Capability for Safe Shutdown Following Loss Electrical Power of For all instrumentation and controls needed for s a fe shut-down, a loss af power is annunciated directly or indirectly t
in the control room.
i Operating procedures will be provided to instruct the operators to take appropriate actions.
Item 7 - Remote Shutdown System Within eighteen months of the scheduled fuel load date for Unit
!, design changes will be made to eliminate the need for jumpering, rewiring, or disconnecting circuits to achieve and maintain hot shutdown from a location locations remote from the control room.
Instruments or the remote shutdown panel are seismic grade (will operate on after an SSE).
A preoperation test performed after the modification is completed will demonstrate that redundant remote shutdown capability exists.
Item 8 - Post Accident Monitoring Instrumentation This remains under staff review.
No additional information is required.
Item 9 - Bypassed and Inoperable Status Indication Attached is the revised response to Question 421.33 which provides the requested information.
r
, Item 10 - High Energy Line. Breaks and Consequential Control System Failures Multiple ~ Control Systems Failures Item II s
Studies-for these items will be completed in August and. submitted at that time.
Sincerely,
- f. K)La.
JLP/gra/18&l9 Copy to:
See Attached Service List i
4 -
l' b
t, l
t A
i
- s cc: Judge Lawrence Brenner (w/o enclosure)
-Judge Richard F. Cole (w/o enclosure)
Judge Peter A. Morris (w/o enclosure)
Troy B. Conner, Jr., Esq.
(w/o enclosure)
Ann P. Hodgdon (w/o enclosure)
Mr. Frank R. Romano (w/o enclosure)
Mr. Robert L. Anthony (w/o enclosure)
Mr. Marvin I. Lewis (w/o_ enclosure)
Judith A. Dorsey, Esq.
(w/o enclosure)
Charles'W. Elliott, Esq.
(w/o enclosure)
Jacqueline I. Ruttenberg (w/o enclosure)
Thomas Y. Au, Esq.
(w/o enclosure)
Mr. Thomas Gerusky (w/o enclosure)
Director, Pennsylvania Emergency Management Agency (w/o enclosure)
Mr. Steven P. Hershey (w/o enclosure)
Donald.S. Bronstein, Esq.
(w/o enclosure)
Mr. Joseph H. White, III (w/o enclosure)
David Wersan, Esq.
(w/o enclosure)
Robert J. Sugarman, Esq.
(w/o enclosure)
Martha W. Bush, Esq.
(w/o enclosure)
Spence W. Perry, Esq.
(w/o enclosure)
Atomic Safety and Licensing Appeal Board (w/o enclosure)
Atomic Safety and Licensing Board Panel (w/o enclosure)
Docket and Service Section (w/o enclosure)
g n L F)
LGS FSAR the normal ventilation system.
See Figure 7.3-23 for the logic
_ diagram.
7.3.1.1.9.6 REIS Bypasses and Interlocks i
The hand switch of each isolation system, when in the " reset" position, provides inpet to a control room alarm.
The isolation system is interlocked with the standby gas treatment system and the reactor enclosure recirculation system.
7.3.1.1.9.7 REIS Redundancy and Diversity To maintain the redundancy of the mechanical equipment, controls and instrumentation are provided on a one-to-one basis with the mechanical equipment they serve.
The diversity of the NSSS-furnished LOCA signal is used.
7.3.1.1.9.8 REIS Actuated Devices The standby gas treatment system, reactor enclosure recirculation l
system, and the reactor enclosure isolation valves are actuated by this system.
See Sections 7.3.1.1.7'and 7.3.1.1.8, j.
respectively, for descriptions of the actuated systems.
7.3.1.1.9.9 REIS Separation t
The -controls, instruments, and power supplies of the isolation system'are physically separated and electrically independent for each of the redundant trip channels.
See Section 8.1.6.1 for a discussion of electrical system separation.
7.3.1.1.9.10 REIS Testability Verification of the operability of the initiating circuits may be i
made as follows:
l l
a.
Ihr tripping the individual radiation monitor circuits b.
By tripping the differential pressure input circuits
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c.
By manually initiating the' channels with hand ssitches'
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located in the control room d.
By tripping the LOCA signal circuits (reactor enclosure isolation system only) ygg (zft.(
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(m v4 LGS FSAR 7.3.1.1.17.5 RAIS Logic and Sequencing
-Cach channel of.the redundant isolation system is normally held in an energized (failsafe) mode so that an initiating signal or loss of power activates the channel and starts all the related systems.
The isolation signal seals-in upon initiation, and removal of the initiating signal does not deactivate the channel.
The channel may be reset to a normal co6dition only if the initiating condition, other than low building differential pressure, is no longer present.
A keylock reset is provided to bypass low building differential pressure to re-establish it with the normal ventilation system.
Figure 7.3-23 shows the logic diagram.
7.3.1.1.17.6 RAIS Bypasses and Interlocks The hand switch of each isolation system, when in the " reset" position, provides input to a control room alarm.
The isolation system is interlocked with the standby gas treatment system.
7.3.1.1.17.7 RAIS Redundancy and Diversity To maintain the redundancy of the mechanical equipment, controls and instrumentation are provided on a one-to-one basis with the
.s mechanical equipment they serve.
')
l 7.3.1.1.17.8 RAIS Actuated Devices s
The standby-gas treatment system and the refueling area isolation are actuated by this system.
Section 7.3.1.1.7 gives a description of the actuated system.
7.3.1.1.17.9 RAIS Separation The controls, instruments, and power supplies of the isolation system are physically separated and electrically independent for each of the redundant trip channels.
Secti0n 8.1.6.1 gives a discussion of. electrical system separation.
7.3.1.1.17.10 RAIS Testability Verification of-the' operability' ~of thr.4Mitistfhg circuits may be made as follows:
a.
By tripping the individual radiation monitor circuits b.
By tripping the differential pressure input circuits c.
By manually initiating the channels with hand switches,,,g }
located in the control room gg Tl$5.
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LGS FSAR 7.3.1.1.10.7 HCRI Redundancy and Diversity Tp maintain the redundancy of the mechanical equipment, controls and-instrumentation.are provided on a one-to-one basis with the mechanical equipment they serve.
-7.3.1.1.10.8 HCRI Actuated Devices The associated control enclosure chilled water system pumps are actuated by the control room HVAC supply fans.
See Section 7.3.1.
I 7.3.1.1.10.9 HCRI Separation The controls, instrumentation, and power supplies of the isolation system, emergency fresh air system, and control room HVAC are physically separated and electrically independent for each of the redundant trip channels.
See Section 8.1.6.1.14 for a discussion of the electrical system separation.
7.3.1.1.10.10 HCRI Testability Verification of the operability of the initiating circuits of the isolation system may be made as follows:
By tripping the' individual radiation monitor circuits
.a.
b.
By tripping the individual chlorine monitor circuits c.
By manually initiating the channels by hand switches 1ccated in the control room.
Verification of the operability of the initiating circuits of the emergency fresh air system may be made as follows:
i lo By putting each fan in the " auto" mode and tripping the isolation channel 2.
-By putting each fan in the " standby" mode and tripping the isolation channel when the other fan is shut down Verification of.the operability of the initiating
" '~
~
circuit) df" the' 'coiitYol 'r'o'om' HVAC ~f'ansniay be' made 'by
~
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~
putting each fan in the " auto" mode when-the other fan
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of the pair is shut down.
In addition, all fsns may be manually tested by hand switches from the control room.
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s v #S LGS FSAR 7.3.1.1.2.11 PCRVICS Testability
~
PCRVICS is capable ci complete testing in overlapping portions during power operation.
Operation of the level, pressure, flow,
)
differential flow, and vacuum sensors may be verified by cross-i comparison of instrument channels.
In addition, these transmitters may be valved out of service one at a time and functionally tested using a test pressure source.
The channel i
trip units and trip relays can be calibrated and tested by i
injecting a calibration signal.
t l
The main steam line radiation measuring amplifier is provided with a test switch and internal test source by which operability can be verified.
The operation of the isolation temperature sensors can be verified by cross-comparison of instrument channels.
They can also be functionally tested by applying a heat source to the temperature sensing elements.
Control room indications of logic trip include annunciation, panel lights, and computer printout.. The condition of each sensor is indicated by at least one of these methods in addition to annunciators common to sensors of one variable.
The +M h ogic relays can be tested either by tripping a transmitter or trip unit or by actuating thg1"pual isolation a
switch in a given logic division.
The MStV adicator lights and
(
i trip annunciators indicate a logic trip.
Other isolation valve l
logic can be likewise tested in conjunction with logic test gyg
,,uc switches provided for this purpose. MEEfmt.J uc; meo c;n =e L,(",,,ogard +
ed celenvid vpecoted csGe c TA'd individ"2'!y tcst;d.
Ma*er-ap^ ret =A
=
isolan on veh ae c3n Sc r* m=11y cleoca indiviaua :; 4vu ic: t i ng.
main steam line valves can be
-'y exercised (individually)
(from&oll" en to closed.
actual trip function at full l
[
speed can be e
reduced power by placing individual MSIV selector s s in the cod pnmiti W e position tndi -
lights indicate valve closure.
~~~
The MSIVs mechanical components can be tested manually to any position at full power in a " slow test" mode.
This " slow test"
,,e vatet is used to exercise the valve mechanical componentsfeuly.
Full gr e rud, closure simulating actual auto isolation conditions can be performed on individual MSIVs at reduced power by placing the l
MSIV selector switch in the closed position.
This tests the isolation solenoids and-walve, mechanical-components at full isolation speed and actual auto-isolation conditions.
In either test, the valve closure can be verified by valve position indicator lights.
Other PCRVICS valve testing must be split into two sections.
The motor controls and mechanical components for motor-operated
-_}
valves that are isolated under normal reactor conditions may be tested only at shutdown.
Motor controls and valves that are not i
7.3-52
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- b f t. tJ LGS FSAR normally' isolated can be tested by. tripping the control logic and verifying valve closure by valve position indicator lights.
7.3.1.1.2.12 PCRVICS Environmental Considerations The physical and electrical arrangement of the PCRVICS was selected.so that no single physical event can prevent achievement of isolation functions.
Motor operators for valves inside the
~
drywell are of the totally-enclosed type; those outside the containment have weatherproof-type enclosures.
Solenoid valves, whether used for direct valve isolation or as an air pilot, are provided with watertight enclosures.
All cables and operators are capable of operation in the most unfavorable ambient conditions anticipated for normal operations.
Temperature, pressure, humidity, and radiation are considered in the selection of equipment for the system.
Cables used-in high-radiation areas have radiation-resistant insulation.
Shielded-cables are used where necessary to eliminate interference from magnetic fields.
Special consideration has been given to isolation requirements during a LOCA inside the drywell.
Components of the PCRVICS that are located inside the drywell and must operate during a LOCA are 4
th.e cables, contro1' mechanisms, and valve operators of isolation
- T.
valves inside the drywell.
These isolation components are
-f required to be' functional in a LOCA environment Section 3.11.
Electrical cables are selected.with insulation designed for this service.
Closing mechanisms and valve operators are considered satisfactory for use in the PCRVICS only after completion of environmental testing under LOCA conditions or submission of evidence from the manufacturer describing the results of suitable prior tests.
7.3.1.1.2.13 PCRVICS Operational Considerations 7.3.1.1.2.13.1 PCRVICS General-Information
-The PCRVICS is not required for normal operation.
This system automatically isolates the appropriate pipeline when one of the monitored variables exceeds preset limits.
No operator action is required for at least 10 minutes following automatic initiation.
The operator,can manually close all other isolation valves.
.t A11' automatic isolation valves can be c1'osed by manual operation of switches in the control room.
7.3.1.1.2.13.2 PCRVICS Reactor Operator Information In general, once icolation is initiated, the valve continues to close even if the condition that caused isolation is restored to l
normal.
The reactor operator must manually reset the tripped logic and operate switches in'the control room to reopen a valve 7.3-53 I
...~.
Testability is discussed in Sections ?.3.2.2.2.2 ' T ;r.d a
cJ.3.2.2.2.2.1.19.
~7.3.1.1.2.4.6.8 Environmental Considerations This subsystem is designed and has been qualified to meet the environmental conditions indicated in Section 3.11.
In addition, thin subsystem has been seismically qualified as described in Section 3.10.
i 7.3.1.1.2.4.7 PCRVICS - Reactor Enclosure Ventilation Exhaust Radiation Monitoring System - Instrumentation and Controls The purpose of thic system is to indicate when excessive amounts of radioactivity exist in the reactor enclosure ventilation exhaust and to provide signals for initiation of appropriate action so that the release of radioactive gases to the environment is limited to levels below the guidelines of published regulations.
The radiation monitoring system is shown in Figure 7.3-11, and its specifications are given in Table 7.6-1 The system consists of four independent channels monitoring the reactor zone.
See Section 7.6.1.1.2 for a detailed description of this system.
. f 7.3.1.1.2.4.8 PCRVICS - Refueling Area Ventilation Exhaust Radiation Monioring System - Instrumentation and Controls The purpose of this system is to indicate when excessive amounts of radioactivity exist in the refueling area ventilation exhaust and to provide signals for initiation of appropriate action so that the release of radioactive gases to the environment is limited to levels below the guidelines of published regulations.
The radiation monitoring system is shown in Figure-7.3-11, and its specifications are given in Table 7.6-1.
The system consists of independent channels, monitoring the refueling area.
See Section 7.6.1.1.3 for a detailed description of this system.
Rev. 16, 01283 7.3-40
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A complete description of pN Q ndependence between divisions is 31sen in sect. ton
,i.1.2.2.
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4+3 L 1_ '. '. 9 - "PCI Testabi} ity getc The-HPCT' instrumentation and control system is capable of being tested during normal unit operation to verify the operability of each system component.
Testing of the initiation sensors that are located outside the drywel) is accomplished by valving out each sensor, ont at a time, and applying a test pressure source.
This verifies the operability of the sensor.
Trip units located in the auxiliary equipment room are calibrated individually by a calibration source with verification of setpoint by a digital readout located on the calibration module.
a.
Calibration and test controls for the sensors are located in the reactor enclosure.
Calibration and test controls for the trip units are located in the auxiliary equipment room.
To gain access to the calibration points of each sensor, a cover plate must be removed.
The control room operator is responsible for granting
.(
access to the calibration points.
Only properly qualified plant personnel are granted access for testing
'N or calibration adjustments.
In addition to the above tests, operability of the sensors can be verified by cross-checking instrument readouts in the auxiliary equipment room at any time during operation, l
b.
Test jacks are provided to test the logic.
Annunciation is provided in the control room whenever a test plug is insert _ed in a ia indicate to the control room l'cfc -- '6perator that th ystem is in the test status. pl c fc o
Operation of the tes ug switches initiates the,"PCI-system.
Injection into the reactor is prevented by an interlock, actuated only when the test plug is, inserted, g,c,g which prevents the opening of one of the "PCI' discharge valves.
The test can be repeated with the other discharge valve interlocked closed.
The manual initiation switch can also be tested at this time.
This sequence of tests ensures that all components are with the operation of m %phe MFC3Edoes not interfere tested.
A logic test gf ee-ECCS equipment if required
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by an initiation signal.
t
/Lc/C The functional performance of the "PCj system can be c.
f verified by pumping water from the condensate storage tank, through the full flow test lines, and back to the 711 V Rev. h C
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7
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condensate storage tank.
If a to6W were to occur during this mode of operation, the valve line-up would automatically be changed so that water can be pumped to the reactor.
During the above testing, the operation of the s s em can be observed in the control room by panel lamps, indicators, recorders, annunciators, and computer printout.
7.3.1.t.1.1.1 HPCI Environmental Consideration The only HPCI s stem control component' locate inside the primary containment that must remain functional in t e environment resulting from a A is the control mechan sm for_the inboard isolation valve o the HPCI system turbine steam line.
The environmental ca ilitites of this valve are discussed in Section 7.3.1.1.2. 3.
The HPCI system c ntrol and
~
s instrumentation equipment located outsi e the primary containment is selected in cons: deration of the no mal and accident environments in whic it must operate These conditions are discussed in Section
.11.
7.3.1.1.1.1.11 HPCI erational nsiderations 7.3.1.1.1.1.11.1 HPCI neral formation I
The HPCI system is not r uir for normal operations.
Under abnormal or accident cond ti s, initiation and control are provided automatically fo a
least 10 minutes when they are required.
After that tim perator action can assist the automatic controls to sust n core cooling.
7.3.1.1.1.1.11.2 HPCI Re et r Operator Information A detection system cont nuous y confirms the integrity of the HPCI injection piping o the actor vessel.
The HPCI discharge to the reactor vessel 's throu h a CS system line and sparger.
A differential pressure sensor a asures the pressure difference l>etween the two CS s nsor syst injection lines.
If the CS piping is sound, th pressure d.fference is very small between
.these lines.
If in egrity is lost,-increasing differential pressure initiates an alarm in t e main control room.
Pressure in the HPCI pump ction line is monitored by pressure transmitters, whi h initiate ala s in the control room on high W3C
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LGS FSAR 7.3.1.1.11.8 ESW Actuated Devices The devices' actuated by the. initiation of.the'ESW pumps are the loop valving and the water / source and return valving and/or sluice gates.
7.3.1.1.11.9 ESW Separation The controls and instrumentation dre physically and electrically separated for each of the four ESW pumps.- ESW pump A controls and instruments are in Division I; ESW pump B is in Division II; ESW pump C is in Division III; and ESW pump D is in. Division IV.
The controls for the ESW valves are assigned to various divisions so that a single active failure cannot disable a complete ESW loop.
In cases where two valves are in series to shut off a flow path, the valves are assigned to two different divisions Likewise, in cases where two valves are used to provide ~ redundant flow paths in a single loop, the dalves are assigned to two different divisions.
Loop A valves are in Divisions I7and III, and loop B valves are in' Divisions II and IV.
The manual control loop selection valves for each diesel-generator are 'in the same division as the~
associated diesel-generator.
f Loop A pressure and differential flow indication are in Division I, and the Loop B. instruments arelin.; Division II.
7.3.1.1.11.10 ESW Testability
)
es'~ Verificatio bilit lon circuits is made when each of the d ne s~is op'erationally tested.
- Also, pu, valves can be manual] 'resteds a hand switches in the gntrol room.
7.3.1.1.11.11 ESW Environmental Considerations The control equipment for the ESW system is located in the.
reactor enclosure, diesel-generator enclosures, spray pond pump d
house, and the control room.
See Section 3.~11 for environmental consideratio6s. r s
7.3.1.1.11.12 ESW Operational Considerations 7.3.1.1.11.12.1 ESW General Information The ESW system is not required for normal. operation.
The system is initiated automatically on a signal based on the status of the diesel-generators.
~, -
7.3-82
'OUESTION 421.3_6.
The FSAR information which discusses conformance to Regulatory Guide 1.118 and IEEE 338 is insufficient.
Further discussion is re, quired.
As a minimum, provide the following information:
a)
Section 7.1.2.5.26 of the FSAR states that the removal of fuses.and"other equipment not hard-wired into the protection system willibe'used only for.the purpose of deactivating I&C
' circuits.
Identify where procedures require such operation.
Provide further discussion to describe how the Limerick procedures for the protection systems conform to Regulatory a
P
. Guide 1'.118 (Rev. 1) Position C.6 guidelines.
Identify and
_ provide jus'tification for any exceptions.
s 1
b)
Discuss response time testing, including sensors, for the NSSS'and BOP supplied instruments and systems in relation to the guidance provided in.R.G. 1.118 and IEEE 338, Section 6.3.4.
Include in your discussion the effects of thermo wells, restrictions, orifices, or other interfaces with the process variable and the sensor or instrument in relation to the overall response.
c)
Provide examples and descriptions of typical response time
~
tests for RPS and ESF systems.
RESPONSE
Evaluation of the systems to be surveillance tested has determined that the actions required will include tha liftin3 of L-leads endiopening of circuit breakers.
This action is required in a limited number of cases. JEbe leed; will be lifted. caly during a taet--conduc4:d during a refueling cut g: :nd will bring -
up an aut-of-sem viwalarmJ. hat wil-1--not-eleer -ith the leed 14f ted.
The circuit breakers will be opened during monthly
)
-testing but will also bring up an out-of-service alarm that will not clear with the breaker open. %f A ^'^ '
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- Sensor response time testing for pressure and~ differential pressure.(level) sensors for the reactor protection system will be performed using a precise hydraulic pressure signal as the input.
Response of the sensor output and the final actuation 1
device will be measured.
Neutron detectors are exempt from g
response. time testing; response ti,me wil1 be measured from the p'
. input of the first electronic component in the channel.
Except l~
for the MSIVs, individual sensor response times and logic system J esponse times are not required for isolation systems because the l}{
signal / delay (sensor response) is concurrent with the 13-second (g
421.36-1 1:
Rev. 19, 04/83
(
OUESTION 421.7 (Sections 7.1 and 7.7) l Some of the primary methods the Staff uses to convey information to licensees and applicants based on operating experience are Office Of Inspection and Enforcement (IE) Bulletins, Circulars and Information Notices.
Although only the IE Bulletins require written responses, the staff expects licensees and applicants to take appropriate action (s) on the information provided in the
- Circulars and Information Notices. applicable to their design.
Included in Attachment 1 is a list of IE Bulletins, Circulars and Information Notices that are applicable to BWRs.
Provide a discussion which includes the following:
1.
Procedures for determining the applicability of the IEB, IEC, and IEIN to your facility.
2.
Procedures or methods for factoring the applicable information or criteria into the Limerick design.
i 3.-
Details of specific design modifications and their implementation resulting from items 1 and 2.
i 4.-
DetaiJed analysis and results for IEB 79-27 and IEB 80-06.
5.
Detailed analysis and results for IEIN 79-22 to assure that consequential control system failures following a high energy line break do not result in event sequences more severe than those shown in the FSAR accident analyses (Chapter 15).
~
RESPONSE
o 1.
The procedure that is used for evaluating and processing IEBs, IECs, and IEINs at Limerick is given in Appendix X to the Limerick Quality Assurance Plan.
2.
As noted in Section X-4.2.1 of the Quality Assurance Plan, the responsible group determines what actions are required to address the concerns of each IEB, IEC or IEIN.
These actions are noted in the response to the Project Manager.
In accordance with Section X-4.2.7, the Project Manager indicates in a log the corrective action needed to close out i
each item.
That item is closed only when the final action is complete.
3.
The actions taken by PECo for Limerick, in regards to the IE l '.
Bulletins, Circulars and Info Notices are listed in Table l
421.7-1.
421.7-1 Rev. 20, 05/83
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--_m
The detailed response and analysis for IEB 79-27 is contained in the response to SRAI(15).
The following is the detailed analysis and results for IEB 80-06.
IEB 80-6 requires that safety-related equipment remain in its emergency mode on reset of an engineered safety features actuation signal.
To determine whether or not all safety-related equipment remains in its emergency mode on isolation signal reset, schematic drawings for all Limerick systems. serving safety-related functions were reviewed.
The review showed that a number of valves were subject to reverting to their normal mode on isolation signal reset.
All continuous duty loads were found to remain in their emergency mode on isolation signal reset.
In general.,. control schemes of safety-related valves found not to remain in their emergency mode on reset of an isolation signal were revised to provide a control switch interlock with.the isolation signal reset circuit (Figure 421.7-1).
To reset an isolation signal, every valve subject to reverting to normal mode on reset of the isolation signal must.have its control switch placed in the closed position.
A normally open contact of each of the valve control switches is wired in series with the isolation signal reset contact.
On manual placement of all of the subject control switches in the closed position, the permissive series of control switch contacts will all'be closed, thus allowing the isolation signal reset contact to complete the reset circuit.
On'the bases of the design review, the following systems and valve control schemes were modified as described above:
~
(
System Valve No.
I Containment Atmospheric HV57-117 SV57-133 l
Control HV57-118 SV57-183 HV57-104 SV57-191 t
HV57-114 SV57-181 l
HV57-123 SV57-132 HV57-124 SV57-134 HV57-121 SV57-150 HB57-131 SV57-141 SV57-184 SV57-142 l
SV57-185 SV57-143 SV57-186 SV57-144 SV57-190 SV57-145 SV57-195 SV57-159 Rev. 20, 05/83 421.7-2
LGS FSAR-
HV59-129A HV59-131 Instrument Gas System HV59-102 HV59-135 i
HV59-129B Nuclear Steam Shutoff HV41-1F084 HV51-1F079A System HV41-1F085 HV51-1F079B HV43-1F019 HV51-1F080A HV43-1F020 HV51-1F080B Liquid Radwaste Collection HV61-110 HV61-130 HV61-111 HV61-131 In addition to the foregoing valves, drywell purge exhaunt fan inlet isolation valves HV76-030 and HV76-031 were found to revert to their normal mode on isolation signal reset.
Thus, if the valves were in their open purge mode on receipt of an isolation signal, the valves would revert to the open purge mode isolation signal reset.
To ensure that these i
valves remain in their closed emergency mode on isolation signal reset, the valve control schemes were modified to the, j
configuration shown on Figure 421.7-2.
The auxiliary relpy j
(95-2) is picked up by the normally closed isolation signal contacts and by the placement of the valve control svitch in the "CLOSE" position.
Once picked up, the auxiliary seals itself in with a contact around the valve control switch "CLOSE" contact..The valves are placed-in the "OPEN" purge position through a contact from the auxiliary relay and the placement of the valve control switch'in the "OPEN" position.
On receipt of an isolation signal, the normally closed isolation signal contacts open, thus dropping out the auxiliary relay, which in turn opens the auxiliary relay seal in circuit and de-energizes the valve "OPEN" circuit, thus closing the valve.
Resetting the isolation signal will not re-energize the auxiliary relay because the valve control switch is in the "OPEN" position.
Thus, the valve "OPEN" circuit will remain de-energized and the val,ves will remain l
closed.
The following are exceptions to IE Bulletin 80-06 guidance a.
Reactor Core Isolation Cooling System (RCIC)
All actuated equipment remains in its abnormal condition, e.xcept for the RCIC system inboard and outboard steam line isolation valves, E51-F007 and E51-F008.
b.
High Pressure Coolan't Injection System (HPCI)
All actuated equipment remains in its abnormal condition, except for the HPCI system inboard and 421.7-3 Rev. 20, 05/83
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outboard steam line isolation valves, E41-F002 and E41-F003.
1 The reset control for the HPCI/RCIC isolation logi A do not strictly meet the intent of IE Bulletin 80-06,, hut we believe the design is acceptable..
There are twd -
completely independent isolation logics for the HPCI and RCIC.
Each of these logics consists of two logic channels, one for the inboard valves and one for the outboard valves.
Each of these logic channels is sealed in until a reset switch in that logic is depressed.
Therefore activation of the reset switch only affects
. one logic channel and will only cause the inborad or outboard valves to open on the system being reset.
The line will remain isolated, i.e.,
in its safe mode, until both the isolation logics for each system are reset.
In addition, the logic reset has no effect if the initiation signal is still present.
D The results of this review will be verified as part of *-
the system preoperational testing.
5.-
The analysis performed in response to.IEIN 79-22 is given in Exhibit 421.7-1.
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LGS TSAR QUESTION 421.33 (Section 7.1 and 7.6)
Section 7.1.2.5.5 and 7.1.2.5.11 of the FSAR provide conflicting inforeetion in relation to bypass and inoperable status' indication.
Discuss in detail the design of the bypassed and inoperable st tus indication using detailed schematics.
Include the following information in the discussion:
- 1.. Compliance with the recommendations of R. G.
1.47 and R. G.
1.22 Position D.3a and 3b, 2.
The design philosophy used in the selection of equipment / systems to be monitored, including auxiliary and support systems, 3.
How the design of the bypass and inoperable status indication systems comply with positions 81 through B6 of ICSB 3 ranch Technical Posi. tion No. 21, and 4.
The list of system automatic and manual bypasses within the BOP and NSSS scope of supply as it pertains to the recommendations of R. G.
1.47.
5.
Include details relating to the general information provided in Section 7.2.2.1.2.3.1.14 of the FSAR during the discussion.
RESPONSE
The design of the bypassed and inoperable status indication is described below.
a.
Compliance to Regulatory Guide 1.47 is discussed in l
revised Section 7.1.2.5.11 and in the analysis sections l
cf the systems to which Regulatory Guide 1.47 is L
applicable (listed below).
D.3a The indications of system inoperability provided under the guidelines of Regulatory Guide 1.47 are l
used by the operator to prevent, throuch l
administrative procedures, the bypassing of a redundant channel of a protection system.
The conditions that render the system inoperable during test are annunciated.
The conditions that automatically bring up the out-of-service alarm are identifiable to the operator in the control room by means of the out-of-service status light.
421.33-1 Rev. 19, 04/83 u --.
LGS FSAR D.3b A manual out-of-service switch is provided to annunciate any bypass condition that does not automatically energize the system out-of-service annunciator.
A single status light indicates that
.the annunciator has been manually actuated.
Individual indication for oach manually-induced inoperability is not provided.
b.
In accordance with the requirements of Regulatory Guide 1.47, bypassed and inoperable status indication has been provided for all plant protection systems.
These systems are listed below.
Also listed are the conditions that cause annunciation of system inoperability.
All auxiliary and supporting systems to protection systems are monitored as part of the protection system availability in accordance with Regulatory Guide 1.47.
The inoperability of these support systems causes the actuation of the out-of-service annunciator for the protection system that these systems support.
A status light is provided to indicate that the inoperability of the support system is the cause of inoperability of the protection system.
Equipment monitored within a prott tion system is that equipment which, when bypassed or removed from service, will cause inoperability of a redundant (one division) portion of the protection system.
Bypass or removal of equipment will automatically initiate the system level out-of-service annunciator and illuminate a status light on the system control panel indicating the cause of the out-of-service condition.
Equipment that is bypassed or removed from service not more than once per year is not monitored.
A manual out-of-service switch is provided for this equipment and for other equipment that cannot be monitored.
c.
Con'formance to BTP ICSB 21 is discussed below, by position:
J B1.
Individual indicator lights are arranged together on a control room panel to indicate what function of the system is out of service, bypassed, or otherwise inoperable.
All bypass and inoperability indicators both at a system level and component level are grouped only with items that will prevent a system from operating if needed.
B2.
Limerick has only one control room.
When a i
protective function of a shared system is bypassed,
(
Rev. 19, 04/83 421.33-2
it is annunciated on the annunciator panel for the shared system, and status indication for the system i
is provided on the control panel for the shared system.
B3.
As a result of design, preoperational testing, and
-startup. testing, no erroneous bypass indication is anticipated.
Capability for cancelling bypass indications is not provided.
B4.
These indication provisions serve to supplement administrative controls and to aid the operator in assessing the availability of component and system level protective actions.
This indication does.not perform a safety function.
85.
All circuits are electrically independent of the plant safety systems to prevent the possibility of adverse effects.
- B6.
The'out-of-service annunciators can be tested by depressing the annunciator test switches on the control room benchboards.
Each status indicating light can be tested by depressing the light assembly.
d.
The individual out-of-service condition that initiates a system level out-of-service alarm is listed below.
i 1.
Pump breaker control power undervoltage 2.
Pump breaker not connected 3.
Pump breaker locked out 4.
Loss of power to relay logic 5.
Loss of power to control valve or valve motor overload 6.
System logic in test
. 7.
Trip unit in calibration or failure 8.
Loss of power to trip unit or trip unit out of file 9.
Manual out of service 10.
Loss of system support HVAC 11.
Valves operated from the control room that are not automatically positioned by the initiation signal 421.33-3 Rev. 19, 04/83
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12.
Transfer switch out of position For the specific alarms that are associated with a system, refer to the functional control diagram for that system as listed.in Chapter 7 figures and to the schematics E-648 as listed in Table 1.7-1.
Systems monitored as discussed above are as follows:
FSAR Fioure l
1.
Reactor Protection System 7.2-1
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2.
Core Spray System 7.3-9 l
3.
Primary Containment & Reactor Vessel Isolation Control System 7.3-8 4.
High Pressure Coolant Injection System 7.3-7 l
5.
Residual Heat Removal System 7.3-10 6.
Emergency Service Water System Table 1.7-1 7.
Standby AC Power System Table 1.7-1 8.
Reactor Core Isolation Cooling 7.4-1 9.
Residual Heat Removal System -
Shutdown Cooling Mode 7.3-10 l
- 10. Reactor Enclosure Isolation System 7.3-8 & 7.3-23 l
- 11. Standby Gas Treatment System 7.3-23 l
- 12. Reactor Enclosure Recirculation System 7.3-23
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- 13. Control Enclosure HVAC Systems 7.3-24
- 14. Neutron Monitoring System 7.6-1
- 15. Standby Liquid Control System Table 1.7-1
- 16. MSIV Leakage Control System 7.3-8
- 17. Combustible Gas Control System Table 1.7-1 Regulatory Guide 1.47. compliance for Items 11, 12, and 13 above is through the use of a trouble alarm in the control room that will direct the operator to a local control panel in the control j
enclosure for more information.
For items 14 through 17, alarms I
are provided in the control room that provide the cause of the out-of-service condition.
No status lights are provided.
I W%W 0 e.
Details of the administrative procedures that control access as a means for bypassing are contained in Section 7.2.2.1.1.1.8.
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