ML081330092: Difference between revisions

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{{Adams
#REDIRECT [[RS-08-045, Technical Specification Bases]]
| number = ML081330092
| issue date = 04/14/2008
| title = Technical Specification Bases
| author name =
| author affiliation = Exelon Generation Co, LLC, Exelon Nuclear
| addressee name =
| addressee affiliation = NRC/NRR
| docket = 05000373, 05000374
| license number = NPF-011, NPF-018
| contact person =
| case reference number = RS-08-045
| document type = Technical Specification, Bases Change
| page count = 742
}}
 
=Text=
{{#Wiki_filter:LaSalle County Power Station
 
Technical Specification Bases (TS Bases)
 
April 2008
 
LaSalle County Nuclear Power Station, Unit 1 and 2 Facility Operating License Nos. NPF-11 (Unit 1) and NPF-18 (Unit 2) NRC Docket Nos. STN 50-373 (Unit 1) and 50-374 (Unit 2)
 
LaSalle 1 and 2 i Revision 23
 
TABLE OF CONTENTS
 
B 2.0  SAFETY LIMITS (SLs)
B 2.1.1  Reactor Core SLs....................................B 2.1.1-1 B 2.1.2  Reactor Coolant System (RCS) Pressure SL ...........B 2.1.2-1
 
B 3.0  LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY...B 3.0-1 B 3.0  SURVEILLANCE REQUIREMENT (SR) APPLICABILITY............B 3.0-11
 
B 3.1  REACTIVITY CONTROL SYSTEMS B 3.1.1  SHUTDOWN MARGIN (SDM)...............................B 3.1.1-1 B 3.1.2  Reactivity Anomalies................................B 3.1.2-1 B 3.1.3  Control Rod OPERABILITY.............................B 3.1.3-1 B 3.1.4  Control Rod Scram Times.............................B 3.1.4-1 B 3.1.5  Control Rod Scram Accumulators......................B 3.1.5-1 B 3.1.6  Rod Pattern Control.................................B 3.1.6-1 B 3.1.7  Standby Liquid Control (SLC) System.................B 3.1.7-1 B 3.1.8  Scram Discharge Volume (SDV) Vent and Drain Valves..B 3.1.8-1
 
B 3.2  POWER DISTRIBUTION LIMITS B 3.2.1  AVERAGE PLANAR LINEAR HEAT GENERATION RATE  (APLHGR)..........................................B 3.2.1-1 B 3.2.2  MINIMUM CRITICAL POWER RATIO (MCPR).................B 3.2.2-1 B 3.2.3  LINEAR HEAT GENERATION RATE (LHGR) .................B 3.2.3-1
 
B 3.3  INSTRUMENTATION B 3.3.1.1  Reactor Protection System (RPS) Instrumentation.....B 3.3.1.1-1 B 3.3.1.2  Source Range Monitor (SRM) Instrumentation..........B 3.3.1.2-1 B 3.3.1.3  Oscillation Power Range Monitor (OPRM)      Instrumentation...................................B 3.3.1.3-1 B 3.3.2.1  Control Rod Block Instrumentation...................B 3.3.2.1-1 B 3.3.2.2  Feedwater System and Main Turbine High Water Level    Trip Instrumentation..............................B 3.3.2.2-1 B 3.3.3.1  Post Accident Monitoring (PAM) Instrumentation......B 3.3.3.1-1 B 3.3.3.2  Remote Shutdown Monitoring System...................B 3.3.3.2-1 B 3.3.4.1  End of Cycle Recirculation Pump Trip (EOC-RPT)  Instrumentation...................................B 3.3.4.1-1 B 3.3.4.2  Anticipated Transient Without Scram Recirculation  Pump Trip (ATWS-RPT) Instrumentation..............B 3.3.4.2-1 B 3.3.5.1  Emergency Core Cooling System (ECCS)    Instrumentation...................................B 3.3.5.1-1 B 3.3.5.2  Reactor Core Isolation Cooling (RCIC) System  Instrumentation...................................B 3.3.5.2-1 B 3.3.6.1  Primary Containment Isolation Instrumentation.......B 3.3.6.1-1 B 3.3.6.2  Secondary Containment Isolation Instrumentation.....B 3.3.6.2-1 B 3.3.7.1  Control Room Area Filtration (CRAF)  System Instrumentation............................B 3.3.7.1-1 B 3.3.8.1  Loss of Power (LOP) Instrumentation.................B 3.3.8.1-1
 
(continued)
 
LaSalle 1 and 2 ii Revision 23
 
TABLE OF CONTENTS 
 
B 3.3  INSTRUMENTATION  (continued)
B 3.3.8.2  Reactor Protection System (RPS) Electric Power Monitoring........................................B 3.3.8.2-1
 
B 3.4  REACTOR COOLANT SYSTEM (RCS)
B 3.4.1  Recirculation Loops Operating.......................B 3.4.1-1 B 3.4.2  Flow Control Valves (FCVs)..........................B 3.4.2-1 B 3.4.3  Jet Pumps...........................................B 3.4.3-1 B 3.4.4  Safety/Relief Valves (S/RVs)........................B 3.4.4-1 B 3.4.5  RCS Operational LEAKAGE.............................B 3.4.5-1 B 3.4.6  RCS Pressure Isolation Valve (PIV) Leakage..........B 3.4.6-1 B 3.4.7  RCS Leakage Detection Instrumentation...............B 3.4.7-1 B 3.4.8  RCS Specific Activity...............................B 3.4.8-1 B 3.4.9  Residual Heat Removal (RHR) Shutdown Cooling    System-Hot Shutdown...............................B 3.4.9-1 B 3.4.10  Residual Heat Removal (RHR) Shutdown Cooling    System-Cold Shutdown..............................B 3.4.10-1 B 3.4.11  RCS Pressure and Temperature (P/T) Limits...........B 3.4.11-1 B 3.4.12  Reactor Steam Dome Pressure.........................B 3.4.12-1
 
B 3.5  EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM B 3.5.1  ECCS-Operating......................................B 3.5.1-1 B 3.5.2  ECCS-Shutdown.......................................B 3.5.2-1 B 3.5.3  RCIC System.........................................B 3.5.3-1
 
B 3.6  CONTAINMENT SYSTEMS B 3.6.1.1  Primary Containment.................................B 3.6.1.1-1 B 3.6.1.2  Primary Containment Air Lock........................B 3.6.1.2-1 B 3.6.1.3  Primary Containment Isolation Valves (PCIVs)........B 3.6.1.3-1 B 3.6.1.4  Drywell and Suppression Chamber Pressure............B 3.6.1.4-1 B 3.6.1.5  Drywell Air Temperature.............................B 3.6.1.5-1 B 3.6.1.6  Suppression Chamber-to-Drywell Vacuum Breakers......B 3.6.1.6-1 B 3.6.2.1  Suppression Pool Average Temperature................B 3.6.2.1-1 B 3.6.2.2  Suppression Pool Water Level........................B 3.6.2.2-1 B 3.6.2.3  Residual Heat Removal (RHR) Suppression Pool    Cooling...........................................B 3.6.2.3-1 B 3.6.2.4  Residual Heat Removal (RHR) Suppression Pool Spray..B 3.6.2.4-1 B 3.6.3.1  Primary Containment Hydrogen Recombiners............B 3.6.3.1-1 B 3.6.3.2  Primary Containment Oxygen Concentration............B 3.6.3.2-1 B 3.6.4.1  Secondary Containment...............................B 3.6.4.1-1 B 3.6.4.2  Secondary Containment Isolation Valves (SCIVs)......B 3.6.4.2-1 B 3.6.4.3  Standby Gas Treatment (SGT) System..................B 3.6.4.3-1
 
  (continued)
LaSalle 1 and 2 iii Revision 27 TABLE OF CONTENTS  (continued)
 
B 3.7  PLANT SYSTEMS B 3.7.1  Residual Heat Removal Service Water    (RHRSW) System....................................B 3.7.1-1
 
B 3.7.2  Diesel Generator Cooling Water (DGCW) System........B 3.7.2-1 B 3.7.3  Ultimate Heat Sink (UHS)............................B 3.7.3-1 B 3.7.4  Control Room Area Filtration (CRAF) System..........B 3.7.4-1 B 3.7.5  Control Room Area Ventilation Air Conditioning    (AC) System.......................................B 3.7.5-1 B 3.7.6  Main Condenser Offgas...............................B 3.7.6-1 B 3.7.7  Main Turbine Bypass System..........................B 3.7.7-1 B 3.7.8  Spent Fuel Storage Pool Water Level.................B 3.7.8-1
 
B 3.8  ELECTRICAL POWER SYSTEMS B 3.8.1  AC Sources-Operating................................B 3.8.1-1 B 3.8.2  AC Sources-Shutdown.................................B 3.8.2-1 B 3.8.3  Diesel Fuel Oil and Starting Air....................B 3.8.3-1 B 3.8.4  DC Sources-Operating................................B 3.8.4-1 B 3.8.5  DC Sources-Shutdown.................................B 3.8.5-1 B 3.8.6  Battery Parameters..................................B 3.8.6-1 B 3.8.7  Distribution Systems-Operating......................B 3.8.7-1 B 3.8.8  Distribution Systems-Shutdown.......................B 3.8.8-1
 
B 3.9  REFUELING OPERATIONS B 3.9.1  Refueling Equipment Interlocks......................B 3.9.1-1 B 3.9.2  Refuel Position One-Rod-Out Interlock...............B 3.9.2-1 B 3.9.3  Control Rod Position................................B 3.9.3-1 B 3.9.4  Control Rod Position Indication.....................B 3.9.4-1 B 3.9.5  Control Rod OPERABILITY-Refueling...................B 3.9.5-1 B 3.9.6  Reactor Pressure Vessel (RPV) Water    Level-Irradiated Fuel.............................B 3.9.6-1 B 3.9.7  Reactor Pressure Vessel (RPV) Water Level-New    Fuel or Control Rods..............................B 3.9.7-1 B 3.9.8  Residual Heat Removal (RHR)-High Water Level........B 3.9.8-1 B 3.9.9  Residual Heat Removal (RHR)-Low Water Level.........B 3.9.9-1
 
B 3.10 SPECIAL OPERATIONS B 3.10.1  Reactor Mode Switch Interlock Testing...............B 3.10.1-1 B 3.10.2  Single Control Rod Withdrawal-Hot Shutdown..........B 3.10.2-1 B 3.10.3  Single Control Rod Withdrawal-Cold Shutdown.........B 3.10.3-1 B 3.10.4  Single Control Rod Drive (CRD)  Removal-Refueling.................................B 3.10.4-1 B 3.10.5  Multiple Control Rod Withdrawal-Refueling...........B 3.10.5-1 B 3.10.6  Control Rod Testing-Operating.......................B 3.10.6-1 B 3.10.7  SHUTDOWN MARGIN (SDM) Test-Refueling................B 3.10.7-1
 
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i  ......................................................................Revision 23 ii  ......................................................................Revision 23 iii  ......................................................................Revision 27
 
B 2.0 SAFETY LIMITS (SLs)
 
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B 3.0 LIMITING CONDITION FOR OPERATION (LCO) AND SURVEILLANCE REQUIREMENT (SR) APPLICABILITY
 
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B 3.2 POWER DISTRIBUTION LIMITS
 
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B 3.3 INSTRUMENTATION
 
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B 3.4 REACTOR COOLANT SYSTEM (RCS)
 
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B 3.6 CONTAINMENT SYSTEMS
 
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B 3.7 PLANT SYSTEMS
 
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B 3.8 ELECTRICAL POWER SYSTEMS
 
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B 3.9 REFUELING OPERATIONS 
 
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AFFECTED PAGE LIST - TECHNICAL SPECIFICATIONS BASES
 
LaSalle 1 and 2                                        Page 18 of 18                                          Revision 35 B 3.10 SPECIAL OPERATIONS
 
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B 2.1.1  Reactor Core SLs
 
BASES
 
BACKGROUND GDC 10 (Ref. 1) requires, and SLs ensure, that specified acceptable fuel design limits are not exceeded during steady
 
state operation, normal operational transients, and
 
anticipated operational occurrences (AOOs).
 
The fuel cladding integrity SL is set such that no
 
significant fuel damage is calculated to occur if the limit
 
is not violated. Because fuel damage is not directly
 
observable, a stepback approach is used to establish an SL, such that the MCPR is not less than the limit specified in
 
Specification 2.1.1.2. MCPR greater than the specified
 
limit represents a conservative margin relative to the
 
conditions required to maintain fuel cladding integrity.
 
The fuel cladding is one of the physical barriers that
 
separate the radioactive materials from the environs. The
 
integrity of this cladding barrier is related to its
 
relative freedom from perforations or cracking. Although
 
some corrosion or use related cracking may occur during the
 
life of the cladding, fission product migration from this
 
source is incrementally cumulative and continuously
 
measurable. Fuel cladding perforations, however, can result
 
from thermal stresses, which occur from reactor operation
 
significantly above design conditions.
 
While fission product migration from cladding perforation is
 
just as measurable as that from use related cracking, the
 
thermally caused cladding perforations signal a threshold
 
beyond which still greater thermal stresses may cause gross, rather than incremental, cladding deterioration. Therefore, the fuel cladding SL is defined with a margin to the
 
conditions that would produce onset of transition boiling (i.e., MCPR = 1.00). These conditions represent a
 
significant departure from the condition intended by design
 
for planned operation. The MCPR fuel cladding integrity SL
 
ensures that during normal operation and during AOOs, at
 
least 99.9% of the fuel rods in the core do not experience
 
transition boiling.
(continued)
Reactor Core SLs B 2.1.1  LaSalle 1 and 2 B 2.1.1-2 Revision 0 BASES BACKGROUND Operation above the boundary of the nucleate boiling regime (continued) could result in excessive cladding temperature because of the onset of transition boiling and the resultant sharp
 
reduction in heat transfer coefficient. Inside the steam
 
film, high cladding temperatures are reached, and a cladding
 
water (zirconium water) reaction may take place. This
 
chemical reaction results in oxidation of the fuel cladding
 
to a structurally weaker form. This weaker form may lose
 
its integrity, resulting in an uncontrolled release of
 
activity to the reactor coolant.
 
The reactor vessel water level SL ensures that adequate core
 
cooling capability is maintained during all MODES of reactor
 
operation. Establishment of Emergency Core Cooling System
 
instrumentation setpoints higher than this SL provides
 
margin such that the SL will not be reached or exceeded.
 
APPLICABLE The fuel cladding must not sustain damage as a result of SAFETY ANALYSES normal operation and AOOs. The reactor core SLs are established to preclude violation of the fuel design
 
criterion that a MCPR limit is to be established, such that
 
at least 99.9% of the fuel rods in the core would not be
 
expected to experience the onset of transition boiling.
 
The Reactor Protection System setpoints (LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation"), in
 
combination with other LCOs, are designed to prevent any
 
anticipated combination of transient conditions for Reactor
 
Coolant System water level, pressure, and THERMAL POWER
 
level that would result in reaching the MCPR Safety Limit.
 
Cores with fuel that is all from one vendor utilize that
 
vendor's critical power correlation for determination of
 
MCPR. For cores with fuel from more than one vendor, the
 
MCPR is calculated for all fuel in the core using the
 
licensed critical power correlations. This may be
 
accomplished by using each vendor's correlation for the
 
vendor's respective fuel. Alternatively, a single
 
correlation can be used for all fuel in the core. For fuel
 
that has not been manufactured by the vendor supplying the
 
critical power correlation, the input parameters to the
 
reload vendor's correlation are adjusted using benchmarking
 
data to yield conservative results compared with the
 
critical power correlation results from the co-resident
 
fuel.  (continued)
Reactor Core SLs B 2.1.1  LaSalle 1 and 2 B 2.1.1-3 Revision 35 BASES APPLICABLE 2.1.1.1 Fuel Cladding Integrity SAFETY ANALYSES (continued) The use of the AREVA correlation (SPCB) is valid for critical power calculations at pressures
> 571.4 psia and bundle mass fluxes
> 0.087 x 10 6 lb/hr-ft 2 (Refs. 2 and 3).
For operation at low pressures or low flows, the fuel cladding integrity SL is established by a limiting condition
 
on core THERMAL POWER, with the following basis:
 
Since the pressure drop in the bypass region is
 
essentially all elevation head, the core pressure drop
 
at low power and flows will always be
> 4.5 psi.
Analyses show that with a bundle flow of 28 x 10 3 lb/hr (approximately a mass velocity of
 
0.25 x 10 6 lb/hr-ft 2), bundle pressure drop is nearly independent of bundle power and has a value of
 
3.5 psi. Thus, the bundle flow with a 4.5 psi driving
 
head will be
> 28 x 10 3 lb/hr. Full scale critical power test data taken at pressures from 14.7 psia to
 
800 psia indicate that the fuel assembly critical
 
power at this flow is approximately 3.35 MWt. With
 
the design peaking factors, this corresponds to a
 
THERMAL POWER
> 50% RTP. Thus, a THERMAL POWER limit of 25% RTP for reactor pressure
< 785 psig is conservative. Although the SPCB correlation is valid at reactor steam dome pressures
> 600 psia, application of the fuel cladding integrity SL at
 
reactor steam dome pressure
< 785 psig is conservative.
 
2.1.1.2 MCPR The MCPR SL ensures sufficient conservatism in the operating
 
MCPR limit that, in the event of an AOO from the limiting
 
condition of operation, at least 99.9% of the fuel rods in
 
the core would be expected to avoid boiling transition. The
 
margin between calculated boiling transition (i.e.,
MCPR = 1.00) and the MCPR SL is based on a detailed
 
statistical procedure that considers the uncertainties in
 
monitoring the core operating state. One specific
 
uncertainty included in the SL is the uncertainty inherent
 
in the SPCB critical power correlation. References 2, 3 and 4 describe the methodology used in determining the MCPR SL.
(continued)
Reactor Core SLs B 2.1.1  LaSalle 1 and 2 B 2.1.1-4 Revision 35 BASES APPLICABLE 2.1.1.2 MCPR  (continued)
SAFETY ANALYSES The SPCB critical power correlation is based on a significant body of practical test data, providing a high
 
degree of assurance that the critical power, as evaluated by
 
the correlation, is within a small percentage of the actual
 
critical power being estimated. As long as the core
 
pressure and flow are within the range of validity of the
 
SPCB correlation, the assumed reactor conditions used in defining the SL introduce conservatism into the limit
 
because bounding high radial power factors and bounding flat
 
local peaking distributions are used to estimate the number
 
of rods in boiling transition. These conservatisms and the inherent accuracy of the SPCB correlation provide a reasonable degree of assurance that there would be no
 
transition boiling in the core during sustained operation at
 
the MCPR SL. If boiling transition were to occur, there is
 
reason to believe that the integrity of the fuel would not
 
be compromised. Significant test data accumulated by the
 
NRC and private organizations indicate that the use of a
 
boiling transition limitation to protect against cladding
 
failure is a very conservative approach. Much of the data
 
indicate that BWR fuel can survive for an extended period of
 
time in an environment of boiling transition.
 
2.1.1.3 Reactor Vessel Water Level
 
During MODES 1 and 2, the reactor vessel water level is
 
required to be above the top of the active irradiated fuel
 
to provide core cooling capability. With fuel in the
 
reactor vessel during periods when the reactor is shut down, consideration must be given to water level requirements due
 
to the effect of decay heat. If the water level should drop
 
below the top of the active irradiated fuel during this
 
period, the ability to remove decay heat is reduced. This
 
reduction in cooling capability could lead to elevated
 
cladding temperatures and clad perforation in the event that
 
the water level becomes
< 2/3 of the core height. The reactor vessel water level SL has been established at the
 
top of the active irradiated fuel to provide a point that
 
can be monitored and to also provide adequate margin for
 
effective action.
(continued)
 
Reactor Core SLs B 2.1.1  LaSalle 1 and 2 B 2.1.1-5 Revision 35 BASES  (continued)
 
SAFETY LIMITS The reactor core SLs are established to protect the integrity of the fuel clad barrier to prevent the release of
 
radioactive materials to the environs. SL 2.1.1.1 and
 
SL 2.1.1.2 ensure that the core operates within the fuel
 
design criteria. SL 2.1.1.3 ensures that the reactor vessel
 
water level is greater than the top of the active irradiated
 
fuel in order to prevent elevated clad temperatures and
 
resultant clad perforations.
 
APPLICABILITY SLs 2.1.1.1, 2.1.1.2, and 2.1.1.3 are applicable in all MODES.
SAFETY LIMIT 2.2 VIOLATIONS Exceeding an SL may cause fuel damage and create a potential
 
for radioactive releases in excess of 10 CFR 100, "Reactor
 
Site Criteria," limits (Ref. 5). Therefore, it is required to insert all insertable control rods and restore compliance
 
with the SL within 2 hours. The 2 hour Completion Time
 
ensures that the operators take prompt remedial action and
 
the probability of an accident occurring during this period
 
is minimal.
 
REFERENCES 1. 10 CFR 50, Appendix A, GDC 10.
: 2. ANF-524(P)(A), Revision 2, Supplement 1 Revision 2, Supplement 2, Advanced Nuclear Fuels Corporation
 
Critical Power Methodology for Boiling Water
 
Reactors/Advanced Nuclear Fuels Corporation Critical
 
Power Methodology for Boiling Water Reactors:
 
Methodology for Analysis of Assembly Channel Bowing
 
Effects/NRC Correspondence (as specified in Technical
 
Specification 5.6.5).
: 3. EMF-2209(P)(A), SPCB Critical Power Correlation, AREVA NP (as specified in Technical Specification 5.6.5).
: 4. EMF-2245(P)(A), Application of Siemens Power Corporation's Critical Power Correlations to Co-Resident Fuel, AREVA NP (as specified in Technical Specification 5.6.5). 
: 5. 10 CFR 100.
 
RCS Pressure SL B 2.1.2 LaSalle 1 and 2 B 2.1.2-1 Revision 0 B 2.0  SAFETY LIMITS (SLs)
 
B 2.1.2  Reactor Coolant System (RCS) Pressure SL
 
BASES
 
BACKGROUND The SL on reactor steam dome pressure protects the RCS against overpressurization. In the event of fuel cladding
 
failure, fission products are released into the reactor
 
coolant. The RCS then serves as the primary barrier in
 
preventing the release of fission products into the
 
atmosphere. Establishing an upper limit on reactor steam
 
dome pressure ensures continued RCS integrity. According to
 
10 CFR 50, Appendix A, GDC 14, "Reactor Coolant Pressure
 
Boundary," and GDC 15, "Reactor Coolant System Design" (Ref. 1), the reactor coolant pressure boundary (RCPB) shall
 
be designed with sufficient margin to ensure that the design
 
conditions are not exceeded during normal operation and
 
anticipated operational occurrences (AOOs).
 
During normal operation and AOOs, RCS pressure is limited
 
from exceeding the design pressure by more than 10%, in
 
accordance with Section III of the ASME Code (Ref. 2) for
 
the reactor pressure vessel, and by more than 20%, in
 
accordance with USAS B31.1-1967 Code (Ref. 3) for the RCS
 
piping. To ensure system integrity, all RCS components are
 
hydrostatically tested at 125% of design pressure, in
 
accordance with ASME Code requirements, prior to initial
 
operation when there is no fuel in the core. Following
 
inception of unit operation, RCS components shall be
 
pressure tested in accordance with the requirements of ASME
 
Code, Section XI (Ref. 4).
 
Overpressurization of the RCS could result in a breach of
 
the RCPB, reducing the number of protective barriers
 
designed to prevent radioactive releases from exceeding the
 
limits specified in 10 CFR 100, "Reactor Site Criteria" (Ref. 5). If this occurred in conjunction with a fuel
 
cladding failure, the number of protective barriers designed
 
to prevent radioactive releases from exceeding the limits
 
would be reduced.
(continued)
 
RCS Pressure SL B 2.1.2 LaSalle 1 and 2 B 2.1.2-2 Revision 0 BASES  (continued)
 
APPLICABLE The RCS safety/relief valves and the Reactor Protection SAFETY ANALYSES System Reactor Vessel Steam Dome Pressure-High Function have settings established to ensure that the RCS pressure SL will
 
not be exceeded.
 
The RCS pressure SL has been selected such that it is at a
 
pressure below which it can be shown that the integrity of
 
the system is not endangered. The reactor pressure vessel
 
is designed to ASME, Boiler and Pressure Vessel Code, Section III, 1968 Edition, including Addenda through the
 
winter of 1969 for Unit 1 and winter of 1970 (excluding
 
Appendix I) for Unit 2 (Ref. 6), which permits a maximum
 
pressure transient of 110%, 1375 psig, of design pressure
 
1250 psig. The SL of 1325 psig, as measured in the reactor
 
steam dome, is equivalent to 1375 psig at the lowest
 
elevation of the RCS. The RCS is designed to ASME Code, Section III, 1971 Edition, including Addenda through the
 
summer of 1971 (Ref. 7), for the reactor recirculation
 
piping, which permits a maximum pressure transient of 120%
 
of design pressures of 1150 psig for suction piping and
 
1250 psig for discharge piping. The recirculation pumps are
 
designed to ASME Code, Section III, 1971 Edition, including
 
Addenda through the summer of 1971 (Ref. 7). The RCS
 
pressure SL is selected to be the lowest transient
 
overpressure allowed by the applicable codes.
 
SAFETY LIMITS The maximum transient pressure allowable in the RCS pressure vessel under the ASME Code, Section III, is 110% of design
 
pressure. The maximum transient pressure allowable in the
 
RCS piping, valves, and fittings is 120% of design pressures
 
of 1150 psig for suction piping and 1250 psig for discharge
 
piping. The most limiting of these allowances is the 110%
 
of the reactor pressure vessel design pressure; therefore, the SL on maximum allowable RCS pressure is established at
 
1325 psig as measured at the reactor steam dome.
 
APPLICABILITY SL 2.1.2 applies in all MODES.
 
SAFETY LIMIT 2.2 VIOLATIONS Exceeding the RCS pressure SL may cause RCS failure and
 
create a potential for radioactive releases in excess of
 
10 CFR 100, "Reactor Site Criteria," limits (Ref. 5).
(continued)
RCS Pressure SL B 2.1.2 LaSalle 1 and 2 B 2.1.2-3 Revision 0 BASES SAFETY LIMIT 2.2 (continued)
VIOLATIONS Therefore, it is required to insert all insertable control
 
rods and restore compliance with the SL within 2 hours. The
 
2 hour Completion Time ensures that the operators take
 
prompt remedial action and also assures that the probability
 
of an accident occurring during this period is minimal.
 
REFERENCES 1. 10 CFR 50, Appendix A, GDC 14 and GDC 15.
: 2. ASME, Boiler and Pressure Vessel Code, Section III, Article NB-7000.
: 3. ASME, USAS, Power Piping Code, Section B31.1, 1967.
: 4. ASME, Boiler and Pressure Vessel Code, Section XI, Article IWB-5000.
: 5. 10 CFR 100.
: 6. ASME, Boiler and Pressure Vessel Code, Section III, 1968 Edition, Addenda, winter of 1969 (Unit 1) and
 
winter of 1970 (Unit 2).
: 7. ASME, Boiler and Pressure Vessel Code, Section III, 1971 Edition, Addenda, summer of 1971.
 
LCO Applicability B 3.0 LaSalle 1 and 2 B 3.0-1 Revision 0 B 3.0  LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY
 
BASES
 
LCOs LCO 3.0.1 through LCO 3.0.7 establish the general requirements applicable to all Specifications in Sections
 
===3.1 through===
3.10 and apply at all times, unless otherwise
 
stated.
LCO  3.0.1 LCO 3.0.1 establishes the Applicability statement within each individual Specification as the requirement for when
 
the LCO is required to be met (i.e., when the unit is in the
 
MODES or other specified conditions of the Applicability
 
statement of each Specification).
 
LCO  3.0.2 LCO 3.0.2 establishes that upon discovery of a failure to meet an LCO, the associated ACTIONS shall be met. The
 
Completion Time of each Required Action for an ACTIONS
 
Condition is applicable from the point in time that an
 
ACTIONS Condition is entered. The Required Actions
 
establish those remedial measures that must be taken within
 
specified Completion Times when the requirements of an LCO
 
are not met. This Specification establishes that:
: a. Completion of the Required Actions within the specified Completion Times constitutes compliance with
 
a Specification; and
: b. Completion of the Required Actions is not required when an LCO is met within the specified Completion
 
Time, unless otherwise specified.
 
There are two basic types of Required Actions. The first
 
type of Required Action specifies a time limit in which the
 
LCO must be met. This time limit is the Completion Time to
 
restore an inoperable system or component to OPERABLE status
 
or to restore variables to within specified limits. If this
 
type of Required Action is not completed within the
 
specified Completion Time, a shutdown may be required to
 
place the unit in a MODE or condition in which the
 
Specification is not applicable.  (Whether stated as a
 
Required Action or not, correction of the entered Condition
 
is an action that may always be considered upon entering 
 
(continued)
LCO Applicability B 3.0 LaSalle 1 and 2 B 3.0-2 Revision 0 BASES LCO  3.0.2 ACTIONS.)  The second type of Required Action specifies the (continued) remedial measures that permit continued operation of the unit that is not further restricted by the Completion Time.
 
In this case, compliance with the Required Actions provides
 
an acceptable level of safety for continued operation.
Completing the Required Actions is not required when an LCO
 
is met or is no longer applicable, unless otherwise stated
 
in the individual Specifications.
 
The nature of some Required Actions of some Conditions
 
necessitates that, once the Condition is entered, the
 
Required Actions must be completed even though the
 
associated Condition no longer exists. The individual LCO's
 
ACTIONS specify the Required Actions where this is the case.
 
An example of this is in LCO 3.4.11, "RCS Pressure and
 
Temperature (P/T) Limits."
 
The Completion Times of the Required Actions are also
 
applicable when a system or component is removed from
 
service intentionally. The reasons for intentionally
 
relying on the ACTIONS include, but are not limited to, performance of Surveillances, preventive maintenance, corrective maintenance, or investigation of operational
 
problems. Entering ACTIONS for these reasons must be done
 
in a manner that does not compromise safety. Intentional
 
entry into ACTIONS should not be made for operational
 
convenience. Additionally, if intentional entry into
 
ACTIONS would result in redundant equipment being
 
inoperable, alternatives should be used instead. Doing so
 
limits the time both subsystems/divisions of a safety
 
function are inoperable and limits the time conditions exist
 
which may result in LCO 3.0.3 being entered. Individual
 
Specifications may specify a time limit for performing an SR
 
when equipment is removed from service or bypassed for
 
testing. In this case, the Completion Times of the Required
 
Actions are applicable when this time limit expires, if the
 
equipment remains removed from service or bypassed.
 
When a change in MODE or other specified condition is
 
required to comply with Required Actions, the unit may enter
 
a MODE or other specified condition in which another
 
Specification becomes applicable. In this case, the
 
Completion Times of the associated Required Actions would
 
apply from the point in time that the new Specification
 
becomes applicable and the ACTIONS Condition(s) are entered.
 
(continued)
LCO Applicability B 3.0 LaSalle 1 and 2 B 3.0-3 Revision 0 BASES  (continued)
 
LCO  3.0.3 LCO 3.0.3 establishes the actions that must be implemented when an LCO is not met and:
: a. An associated Required Action and Completion Time is not met and no other Condition applies; or
: b. The condition of the unit is not specifically addressed by the associated ACTIONS. This means that
 
no combination of Conditions stated in the ACTIONS can
 
be made that exactly corresponds to the actual
 
condition of the unit. Sometimes, possible
 
combinations of Conditions are such that entering
 
LCO 3.0.3 is warranted; in such cases, the ACTIONS
 
specifically state a Condition corresponding to such
 
combinations and also that LCO 3.0.3 be entered
 
immediately.
This Specification delineates the time limits for placing
 
the unit in a safe MODE or other specified condition when
 
operation cannot be maintained within the limits for safe
 
operation as defined by the LCO and its ACTIONS. It is not
 
intended to be used as an operational convenience that
 
permits routine voluntary removal of redundant systems or
 
components from service in lieu of other alternatives that
 
would not result in redundant systems or components being
 
inoperable.
 
Upon entering LCO 3.0.3, 1 hour is allowed to prepare for an
 
orderly shutdown before initiating a change in unit
 
operation. This includes time to permit the operator to
 
coordinate the reduction in electrical generation with the
 
load dispatcher to ensure the stability and availability of
 
the electrical grid. The time limits specified to reach
 
lower MODES of operation permit the shutdown to proceed in a
 
controlled and orderly manner that is well within the
 
specified maximum cooldown rate and within the capabilities
 
of the unit, assuming that only the minimum required
 
equipment is OPERABLE. This reduces thermal stresses on
 
components of the Reactor Coolant System and the potential
 
for a plant upset that could challenge safety systems under
 
conditions to which this Specification applies. The use and
 
interpretation of specified times to complete the actions of
 
LCO 3.0.3 are consistent with the discussion of Section 1.3, Completion Times.
(continued)
LCO Applicability B 3.0 LaSalle 1 and 2 B 3.0-4 Revision 0 BASES LCO  3.0.3 A unit shutdown required in accordance with LCO 3.0.3 may be (continued) terminated and LCO 3.0.3 exited if any of the following occurs:  a. The LCO is now met.
: b. A Condition exists for which the Required Actions have now been performed.
: c. ACTIONS exist that do not have expired Completion Times. These Completion Times are applicable from the
 
point in time that the Condition is initially entered
 
and not from the time LCO 3.0.3 is exited.
The time limits of Specification 3.0.3 allow 37 hours for
 
the unit to be in MODE 4 when a shutdown is required during
 
MODE 1 operation. If the unit is in a lower MODE of
 
operation when a shutdown is required, the time limit for
 
reaching the next lower MODE applies. If a lower MODE is
 
reached in less time than allowed, however, the total
 
allowable time to reach MODE 4, or other applicable MODE, is
 
not reduced. For example, if MODE 2 is reached in 2 hours, then the time allowed for reaching MODE 3 is the next
 
11 hours, because the total time for reaching MODE 3 is not
 
reduced from the allowable limit of 13 hours. Therefore, if
 
remedial measures are completed that would permit a return
 
to MODE 1, a penalty is not incurred by having to reach a
 
lower MODE of operation in less than the total time allowed.
 
In MODES 1, 2, and 3, LCO 3.0.3 provides actions for
 
Conditions not covered in other Specifications. The
 
requirements of LCO 3.0.3 do not apply in MODES 4 and 5
 
because the unit is already in the most restrictive
 
Condition required by LCO 3.0.3. The requirements of LCO
 
3.0.3 do not apply in other specified conditions of the
 
Applicability (unless in MODE 1, 2, or 3) because the
 
ACTIONS of individual Specifications sufficiently define the
 
remedial measures to be taken.
 
Exceptions to LCO 3.0.3 are provided in instances where
 
requiring a unit shutdown, in accordance with LCO 3.0.3, would not provide appropriate remedial measures for the
 
associated condition of the unit. An example of this is in
 
LCO 3.7.8, "Spent Fuel Storage Pool Water Level."  LCO 3.7.8
 
has an Applicability of "During movement of irradiated fuel
 
(continued)
LCO Applicability B 3.0 LaSalle 1 and 2 B 3.0-5 Revision 20 BASES LCO  3.0.3 assemblies in the spent fuel storage pool."  Therefore, this (continued) LCO can be applicable in any or all MODES. If the LCO and the Required Actions of LCO 3.7.8 are not met while in
 
MODE 1, 2, or 3, there is no safety benefit to be gained by
 
placing the unit in a shutdown condition. The Required
 
Action of LCO 3.7.8 of "Suspend movement of fuel assemblies
 
in the spent fuel storage pool" is the appropriate Required
 
Action to complete in lieu of the actions of LCO 3.0.3.
 
These exceptions are addressed in the individual
 
Specifications.
 
LCO  3.0.4  LCO 3.0.4 establishes limitations on changes in MODES or other specified conditions in the Applicability when an LCO
 
is not met. It allows placing the unit in a MODE or other
 
specified condition stated in that Applicability (e.g., the
 
Applicability desired to be entered) when unit conditions
 
are such that the requirements of the LCO would not be met, in accordance with LCO 3.0.4.a, LCO 3.0.4.b, or LCO 3.0.4.c.
LCO 3.0.4.a allows entry into a MODE or other specified
 
condition in the Applicability with the LCO not met when the
 
associated ACTIONS to be entered permit continued operation
 
in the MODE or other specified condition in the
 
Applicability for an unlimited period of time. Compliance
 
with Required Actions that permit continued operation of the
 
unit for an unlimited period of time in a MODE or other
 
specified condition provides an acceptable level of safety
 
for continued operation. This is without regard to the
 
status of the unit before or after the MODE change. 
 
Therefore, in such cases, entry into a MODE or other
 
specified condition in the Applicability may be made in
 
accordance with the provisions of the Required Actions.
LCO 3.0.4.b allows entry into a MODE or other specified
 
condition in the Applicability with the LCO not met after
 
performance of a risk assessment addressing inoperable
 
systems and components, consideration of the results, determination of the acceptability of entering the MODE or
 
other specified condition in the Applicability, and
 
establishment of risk management actions, if appropriate.
 
The risk assessment may use quantitative, qualitative, or
 
blended approaches, and the risk assessment will be
 
conducted using the plant program, procedures, and criteria
 
in place to implement 10 CFR 50.65(a)(4), which requires
 
that risk impacts of maintenance activities to be assessed (continued)
LCO Applicability B 3.0 LaSalle 1 and 2 B 3.0-6 Revision 20 BASES LCO  3.0.4 and managed. The risk assessment, for the purposes of LCO    (continued) 3.0.4 (b), must take into account all inoperable Technical Specification equipment regardless of whether the equipment is included in the normal 10 CFR 50.65(a)(4) risk assessment scope. The risk assessments will be conducted using the procedures and guidance endorsed by Regulatory Guide 1.182, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants."  Regulatory Guide 1.182 endorses the guidance in Section 11 of NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." These documents address general guidance for conduct of the risk assessment, quantitative and qualitative guidelines for establishing risk management actions, and example risk management actions. These include actions to plan and conduct other activities in a manner that controls overall risk, increased risk awareness by shift and management personnel, actions to reduce the duration of the condition, actions to minimize the magnitude of risk increases (establishment of backup success paths or compensatory measures), and determination that the proposed MODE change is acceptable. Consideration should also be given to the probability of completing restoration such that the requirements of the LCO would be met prior to the expiration of ACTIONS Completion Times that would require exiting the Applicability.
LCO 3.0.4.b may be used with single, or multiple systems and components unavailable. NUMARC 93-01 provides guidance relative to consideration of simultaneous unavailability of multiple systems and components.
The results of the risk assessment shall be considered in determining the acceptability of entering the MODE or other specified condition in the Applicability, and any corresponding risk management actions. The LCO 3.0.4.b risk assessments do not have to be documented.
The Technical Specifications allow continued operation with equipment unavailable in MODE 1 for the duration of the Completion Time. Since this is allowable, and since in general the risk impact in that particular MODE bounds the risk of transitioning into and through the applicable MODES or other specified conditions in the Applicability of the LCO, the use of the LCO 3.0.4.b allowance should be generally acceptable, as long as the risk is assessed and managed as stated above. However, there is a small subset of (continued)
LCO Applicability B 3.0 LaSalle 1 and 2 B 3.0-7 Revision 19 BASES LCO  3.0.4 systems and components that have been determined to be more (continued) important to risk and use of the LCO 3.0.4.b allowance is prohibited. The LCOs governing these system and components contain Notes prohibiting the use of LCO 3.0.4.b by stating that LCO 3.0.4.b is not applicable.
LCO 3.0.4.c allows entry into a MODE or other specified condition in the Applicability with the LCO not met based on a Note in the Specification which states LCO 3.0.4.c is applicable. These specific allowances permit entry into MODES or other specified conditions in the Applicability when the associated ACTIONS to be entered do not provide for continued operation for an unlimited period of time and a risk assessment has not been performed. This allowance may apply to all the ACTIONS or to a specific Required Action of a Specification. The risk assessments performed to justify the use of LCO 3.0.4.b usually only consider systems and components. For this reason, LCO 3.0.4.c is typically applied to Specifications which describe values and parameters (e.g., RCS Specific Activity), and may be applied to other Specifications based on NRC plant-specific approval.
The provisions of this Specification should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated MODE or other specified condition in the Applicability.
The provisions of LCO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of LCO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown. In this context, a unit shutdown is defined as a change in MODE or other specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2, MODE 2 to MODE 3, and MODE 3 to MODE 4. Upon entry into a MODE or other specified condition in the Applicability with the LCO not met, LCO 3.0.1 and LCO 3.0.2 require entry into the applicable Conditions and Required Actions until the Condition is resolved, until the LCO is met, or until the unit is not within the Applicability of the Technical Specification. (continued)
LCO Applicability B 3.0 LaSalle 1 and 2 B 3.0-8 Revision 19 BASES  LCO  3.0.4 Surveillances do not have to be performed on the associated  (continued) inoperable equipment (or on variables outside the specified limits), as permitted by SR 3.0.1. Therefore, utilizing LCO 3.0.4 is not a violation of SR 3.0.1 or SR 3.0.4 for any Surveillances that have not been performed on inoperable equipment. However, SRs must be met to ensure OPERABILITY prior to declaring the associated equipment OPERABLE (or variable within limits) and restoring compliance with the affected LCO.
 
LCO  3.0.5 LCO 3.0.5 establishes the allowance for restoring equipment to service under administrative controls when it has been
 
removed from service or declared inoperable to comply with
 
ACTIONS. The sole purpose of this Specification is to
 
provide an exception to LCO 3.0.2 (e.g., to not comply with
 
the applicable Required Action(s)) to allow the performance
 
of required testing to demonstrate:
: a. The OPERABILITY of the equipment being returned to service; or
: b. The OPERABILITY of other equipment.
 
The administrative controls ensure the time the equipment is
 
returned to service in conflict with the requirements of the
 
ACTIONS is limited to the time absolutely necessary to
 
perform the required testing to demonstrate OPERABILITY.
 
This Specification does not provide time to perform any
 
other preventive or corrective maintenance.
 
An example of demonstrating the OPERABILITY of the equipment
 
being returned to service is reopening a containment
 
isolation valve that has been closed to comply with Required
 
Actions, and must be reopened to perform the required
 
testing.
 
An example of demonstrating the OPERABILITY of other
 
equipment is taking an inoperable channel or trip system out
 
of the tripped condition to prevent the trip function from
 
occurring during the performance of required testing on
 
another channel in the other trip system. A similar example
 
of demonstrating the OPERABILITY of other equipment is
 
taking an inoperable channel or trip system out of the
 
tripped condition to permit the logic to function and
 
indicate the appropriate response during the performance of  required testing on another channel in the same trip system.
LCO Applicability B 3.0 LaSalle 1 and 2 B 3.0-9 Revision 19  (continued)
BASES (continued)
 
LCO  3.0.6 LCO 3.0.6 establishes an exception to LCO 3.0.2 for support systems that have an LCO specified in the Technical
 
Specifications (TS). This exception is provided because
 
LCO 3.0.2 would require that the Conditions and Required
 
Actions of the associated inoperable supported system's LCO
 
be entered solely due to the inoperability of the support
 
system. This exception is justified because the actions
 
that are required to ensure the plant is maintained in a
 
safe condition are specified in the support systems' LCO's
 
Required Actions. These Required Actions may include
 
entering the supported system's Conditions and Required
 
Actions or may specify other Required Actions.
When a support system is inoperable and there is an LCO
 
specified for it in the TS, the supported system(s) are
 
required to be declared inoperable if determined to be
 
inoperable as a result of the support system inoperability.
 
However, it is not necessary to enter into the supported  systems' Conditions and Required Actions unless directed to do so by the support system's Required Actions. The potential confusion and inconsistency of requirements
 
related to the entry into multiple support and supported
 
systems' LCO's Conditions and Required Actions are
 
eliminated by providing all the actions that are necessary
 
to ensure the plant is maintained in a safe condition in the
 
support system's Required Actions.
However, there are instances where a support system's
 
Required Action may either direct a supported system to be
 
declared inoperable or direct entry into Conditions and
 
Required Actions for the supported system. This may occur
 
immediately or after some specified delay to perform some
 
other Required Action. Regardless of whether it is
 
immediate or after some delay, when a support system's
 
Required Action directs a supported system to be declared
 
inoperable or directs entry into Conditions and Required
 
Actions for a supported system, the applicable Conditions
 
and Required Actions shall be entered in accordance with
 
LCO 3.0.2.
 
Specification 5.5.12, "Safety Function Determination
 
Program" (SFDP), ensures loss of safety function is detected
 
and appropriate actions are taken. Upon entry into LCO
 
3.0.6, an evaluation shall be made to determine if loss of
 
safety function exists. Additionally, other limitations, remedial actions, or compensatory actions may be identified  (continued)
LCO Applicability B 3.0 LaSalle 1 and 2 B 3.0-10 Revision 19 BASES LCO 3.0.6 as a result of the support system inoperability and (continued) corresponding exception to entering supported system Conditions and Required Actions. The SFDP implements the
 
requirements of LCO 3.0.6.
 
Cross division checks to identify a loss of safety function
 
for those support systems that support safety systems are
 
required. The cross division check verifies that the
 
supported systems of the redundant OPERABLE support system are
 
OPERABLE, thereby ensuring safety function is retained. If
 
this evaluation determines that a loss of safety function
 
exists, the appropriate Conditions and Required Actions of the
 
LCO in which the loss of safety function exists are required
 
to be entered.
 
This loss of safety function does not require the assumption of additional single failures or loss of offsite power. Since operation is being restricted in accordance with the ACTIONS
 
of the support system, any resulting temporary loss of
 
redundancy or single failure protection is taken into account.
 
Similarly, the ACTIONS for inoperable offsite circuit(s) and
 
inoperable diesel generator(s) provide the necessary
 
restriction for cross division inoperabilities. This explicit
 
cross division verification for inoperable AC electrical power
 
sources also acknowledges that support system(s) are not
 
declared inoperable solely as a result of inoperability of a
 
normal or emergency electrical power source (refer to the
 
definition of OPERABLE-OPERABILITY).
When a loss of safety function is determined to exist, and the
 
SFDP requires entry into the appropriate Conditions and
 
Required Actions of the LCO in which the loss of safety
 
function exists, consideration must be given to the specific
 
type of function affected. Where a loss of function is solely
 
due to a single Technical Specification support system (e.g.,
loss of automatic start due to inoperable instrumentation, or
 
loss of pump suction source due to low tank level) the
 
appropriate LCO is the LCO for the support system. The
 
ACTIONS for a support system LCO adequately addresses the
 
inoperabilities of that system without reliance on entering
 
its supported system LCO. When the loss of function is the
 
result of multiple support systems, the appropriate LCO is the
 
LCO for the supported system. 
  (continued)
 
LCO Applicability B 3.0 LaSalle 1 and 2 B 3.0-11 Revision 19 BASES (continued)
 
LCO  3.0.7 There are certain special tests and operations required to be performed at various times over the life of the unit. These
 
special tests and operations are necessary to demonstrate
 
select unit performance characteristics, to perform special
 
maintenance activities, and to perform special evolutions. 
 
Special Operations LCOs in Section 3.10 allow specified TS
 
requirements to be changed to permit performances of these
 
special tests and operations, which otherwise could not be
 
performed if required to comply with the requirements of these
 
TS. Unless otherwise specified, all the other TS requirements
 
remain unchanged. This will ensure all appropriate
 
requirements of the MODE or other specified condition not
 
directly associated with or required to be changed to perform
 
the special test or operation will remain in effect.
 
The Applicability of a Special Operations LCO represents a condition not necessarily in compliance with the normal requirements of the TS. Compliance with Special Operations
 
LCOs is optional. A special operation may be performed either
 
under the provisions of the appropriate Special Operations LCO
 
or under the other applicable TS requirements. If it is
 
desired to perform the special operation under the provisions
 
of the Special Operations LCO, the requirements of the Special
 
Operations LCO shall be followed. When a Special Operations
 
LCO requires another LCO to be met, only the requirements of
 
the LCO statement are required to be met regardless of that
 
LCO's Applicability (i.e., should the requirements of this
 
other LCO not be met, the ACTIONS of the Special Operations
 
LCO apply, not the ACTIONS of the other LCO). However, there
 
are instances where the Special Operations LCO's ACTIONS may
 
direct the other LCOs' ACTIONS be met. The Surveillances of
 
the other LCO are not required to be met, unless specified in
 
the Special Operations LCO. If conditions exist such that the
 
Applicability of any other LCO is met, all the other LCO's
 
requirements (ACTIONS and SRs) are required to be met
 
concurrent with the requirements of the Special Operations
 
LCO.
LCO  3.0.8 LCO 3.0.8 establishes the applicability of each Specification to both Unit 1 and Unit 2 operation. Whenever a requirement
 
applies to only one unit, or is different for each unit, this
 
will be identified in the appropriate section of the
 
Specification (e.g., Applicability, Surveillance, etc.) with
 
parenthetical reference, Notes, or other appropriate
 
presentation within the body of the requirement.
 
SR Applicability B 3.0 LaSalle 1 and 2 B 3.0-12 Revision 19 B 3.0  SURVEILLANCE REQUIREMENT (SR) APPLICABILITY
 
BASES
 
SRs SR 3.0.1 through SR 3.0.4 establish the general requirements applicable to all Specifications in Sections 3.1 through
 
3.10 and apply at all times, unless otherwise stated.
 
SR  3.0.1 SR 3.0.1 establishes the requirement that SRs must be met during the MODES or other specified conditions in the
 
Applicability for which the requirements of the LCO apply, unless otherwise specified in the individual SRs. This
 
Specification is to ensure that Surveillances are performed
 
to verify the OPERABILITY of systems and components, and
 
that variables are within specified limits. Failure to meet
 
a Surveillance within the specified Frequency, in accordance
 
with SR 3.0.2, constitutes a failure to meet an LCO.
Systems and components are assumed to be OPERABLE when the
 
associated SRs have been met. Nothing in this
 
Specification, however, is to be construed as implying that
 
systems or components are OPERABLE when:
: a. The systems or components are known to be inoperable, although still meeting the SRs; or
: b. The requirements of the Surveillance(s) are known to be not met between required Surveillance performances.
Surveillances do not have to be performed when the unit is
 
in a MODE or other specified condition for which the
 
requirements of the associated LCO are not applicable, unless otherwise specified. The SRs associated with a
 
Special Operations LCO are only applicable when the Special
 
Operations LCO is used as an allowable exception to the
 
requirements of a Specification.
 
Unplanned events may satisfy the requirements (including
 
applicable acceptance criteria) for a given SR. In this
 
case, the unplanned event may be credited as fulfilling the
 
performance of the SR.
 
(continued)
SR Applicability B 3.0 
 
LaSalle 1 and 2 B 3.0-13 Revision 19 BASES SR  3.0.1 Surveillances, including Surveillances invoked by Required (continued) Actions, do not have to be performed on inoperable equipment because the ACTIONS define the remedial measures that apply.
 
Surveillances have to be met and performed in accordance
 
with SR 3.0.2, prior to returning equipment to OPERABLE
 
status. Upon completion of maintenance, appropriate post maintenance
 
testing is required to declare equipment OPERABLE. This
 
includes ensuring applicable Surveillances are not failed
 
and their most recent performance is in accordance with
 
SR 3.0.2. Post maintenance testing may not be possible in
 
the current MODE or other specified conditions in the
 
Applicability due to the necessary unit parameters not
 
having been established. In these situations, the equipment
 
may be considered OPERABLE provided testing has been
 
satisfactorily completed to the extent possible and the
 
equipment is not otherwise believed to be incapable of
 
performing its function. This will allow operation to
 
proceed to a MODE or other specified condition where other
 
necessary post maintenance tests can be completed. Some
 
examples of this process are:
: a. Control rod drive maintenance during refueling that requires scram testing at  800 psig. However, if other appropriate testing is satisfactorily completed
 
and the scram time testing of SR 3.1.4.3 is satisfied, the control rod can be considered OPERABLE. This
 
allows startup to proceed to reach 800 psig to perform
 
other necessary testing.
: b. Reactor Core Isolation Cooling (RCIC) maintenance during shutdown that requires system functional tests
 
at a specified pressure. Provided other appropriate
 
testing is satisfactorily completed, startup can
 
proceed with RCIC considered OPERABLE. This allows
 
operation to reach the specified pressure to complete
 
the necessary post maintenance testing.
 
(continued)
SR Applicability B 3.0 
 
LaSalle 1 and 2 B 3.0-14 Revision 19 BASES  (continued)
 
SR  3.0.2 SR 3.0.2 establishes the requirements for meeting the specified Frequency for Surveillances and any Required
 
Action with a Completion Time that requires the periodic
 
performance of the Required Action on a "once per..."
interval.
SR 3.0.2 permits a 25% extension of the interval specified
 
in the Frequency. This extension facilitates Surveillance
 
scheduling and considers plant operating conditions that may
 
not be suitable for conducting the Surveillance (e.g.,
transient conditions or other ongoing Surveillance or
 
maintenance activities).
 
The 25% extension does not significantly degrade the
 
reliability that results from performing the Surveillance at
 
its specified Frequency. This is based on the recognition
 
that the most probable result of any particular Surveillance
 
being performed is the verification of conformance with the
 
SRs. The exceptions to SR 3.0.2 are those Surveillances for
 
which the 25% extension of the interval specified in the
 
Frequency does not apply. These exceptions are stated in
 
the individual Specifications. The requirements of
 
regulations take precedence over the TS. Therefore, when a
 
test interval is specified in the regulations, the test
 
interval cannot be extended by the TS, and the SR includes a
 
Note in the Frequency stating "SR 3.0.2 is not applicable."
 
As stated in SR 3.0.2, the 25% extension also does not apply
 
to the initial portion of a periodic Completion Time that
 
requires performance on a "once per..." basis. The 25%
 
extension applies to each performance after the initial
 
performance. The initial performance of the Required
 
Action, whether it is a particular Surveillance or some
 
other remedial action, is considered a single action with a
 
single Completion Time. One reason for not allowing the 25%
 
extension to this Completion Time is that such an action
 
usually verifies that no loss of function has occurred by
 
checking the status of redundant or diverse components or
 
accomplishes the function of the inoperable equipment in an
 
alternative manner.
 
(continued)
SR Applicability B 3.0 
 
LaSalle 1 and 2 B 3.0-15 Revision 19 BASES SR  3.0.2 The provisions of SR 3.0.2 are not intended to be used (continued) repeatedly merely as an operational convenience to extend Surveillance intervals (other than those consistent with
 
refueling intervals) or periodic Completion Time intervals
 
beyond those specified.
 
SR  3.0.3 SR 3.0.3 establishes the flexibility to defer declaring affected equipment inoperable or an affected variable
 
outside the specified limits when a Surveillance has not
 
been completed within the specified Frequency. A delay
 
period of up to 24 hours or up to the limit of the specified
 
Frequency, whichever is greater, applies from the point in
 
time it is discovered that the Surveillance has not been
 
performed in accordance with SR 3.0.2, and not at the time
 
that the specified Frequency was not met. This delay period
 
provides adequate time to complete Surveillances that have
 
been missed. This delay period permits the completion of a
 
Surveillance before complying with Required Actions or other
 
remedial measures that might preclude completion of the
 
Surveillance.
 
The basis for this delay period includes consideration of
 
unit conditions, adequate planning, availability of
 
personnel, the time required to perform the Surveillance, the safety significance of the delay in completing the
 
required Surveillance, and the recognition that the most
 
probable result of any particular Surveillance being
 
performed is the verification of conformance with the
 
requirements.
 
When a Surveillance with a Frequency based not on time
 
intervals, but upon specified unit conditions, operating
 
situations, or requirements of regulations (e.g., prior to
 
entering MODE 1 after each fuel loading, or in accordance
 
with 10 CFR 50, Appendix J, as modified by approved
 
exemptions, etc.) is discovered to not have been performed
 
when specified, SR 3.0.3 allows for the full delay period of
 
up to the specified Frequency to perform the Surveillance. 
 
However, since there is not a time interval specified, the
 
missed Surveillance should be performed at the first
 
reasonable opportunity.
 
(continued)
SR Applicability B 3.0 
 
LaSalle 1 and 2 B 3.0-16 Revision 19 BASES SR  3.0.3 SR 3.0.3 provides a time limit for, and allowances for the    (continued) performance of, Surveillances that become applicable as a consequence of MODE changes imposed by Required Actions.
 
Failure to comply with specified Frequencies for SRs is
 
expected to be an infrequent occurrence. Use of the delay
 
period established by SR 3.0.3 is a flexibility which is not
 
intended to be used as an operational convenience to extend
 
Surveillance intervals. While up to 24 hours or the limit
 
of the specified Frequency is provided to perform the missed
 
Surveillance, it is expected that the missed Surveillance
 
will be performed at the first reasonable opportunity. The
 
determination of the first reasonable opportunity should
 
include consideration of the impact on plant risk (from
 
delaying the Surveillance as well as any plant configuration
 
changes required or shutting the plant down to perform the
 
Surveillance) and impact on any analysis assumptions, in
 
addition to unit conditions, planning, availability of
 
personnel, and the time required to perform the
 
Surveillance. This risk impact should be managed through
 
the program in place to implement 10 CFR 50.65(a)(4) and its
 
implementation guidance, NRC Regulatory Guide 1.182, "Assessing and Managing Risk Before Maintenance Activities
 
at Nuclear Power Plants."  This Regulatory Guide addresses
 
consideration of temporary and aggregate risk impacts, determination of risk management action thresholds, and risk
 
management action up to and including plant shutdown. The
 
missed Surveillance should be treated as an emergent
 
condition as discussed in the Regulatory Guide. The risk
 
evaluation may use quantitative, qualitative, or blended
 
methods. The degree of depth and rigor of the evaluation
 
should be commensurate with the importance of the component.
 
Missed Surveillances for important components should be
 
analyzed quantitatively. If the results of the risk
 
evaluation determine the risk increase is significant, this
 
evaluation should be used to determine the safest course of
 
action. All missed Surveillances will be placed in the
 
licensee's Corrective Action Program.
If a Surveillance is not completed within the allowed delay
 
period, then the equipment is considered inoperable or the
 
variable then is considered outside the specified limits and
 
the Completion Times of the Required Actions for the
 
applicable LCO Conditions begin immediately upon expiration 
 
(continued)
SR Applicability B 3.0 
 
LaSalle 1 and 2 B 3.0-17 Revision 19 BASES SR  3.0.3 of the delay period. If a Surveillance is failed within the (continued) delay period, then the equipment is inoperable, or the variable is outside the specified limits and the Completion
 
Times of the Required Actions for the applicable LCO
 
Conditions begin immediately upon the failure of the
 
Surveillance.
 
Completion of the Surveillance within the delay period
 
allowed by this Specification, or within the Completion Time
 
of the ACTIONS, restores compliance with SR 3.0.1.
 
SR  3.0.4 SR 3.0.4 establishes the requirement that all applicable SRs must be met before entry into a MODE or other specified condition in the Applicability.
This Specification ensures that system and component OPERABILITY requirements and variable limits are met before entry into MODES or other specified conditions in the Applicability for which these systems and components ensure safe operation of the unit. The provisions of this Specification should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated MODE or other specified condition in the Applicability.
A provision is included to allow entry into a MODE or other specified condition in the Applicability when an LCO is not met due to Surveillance not being met in accordance with LCO 3.0.4. However, in certain circumstances, failing to meet an SR will not result in SR 3.0.4 restricting a MODE change or other specified condition change. When a system, subsystem, division, component, device, or variable is inoperable or outside its specified limits, the associated SR(s) are not required to be performed, per SR 3.0.1, which states that surveillances do not have to be performed on inoperable equipment. When equipment is inoperable, SR 3.0.4 does not apply to the associated SR(s) since the requirement for the SR(s) to be performed is removed. Therefore, failing to perform the Surveillance(s) within the specified Frequency does not result in an SR 3.0.4 restriction to changing MODES or other specified conditions of the Applicability.
However, since the LCO is not met in this instance, (continued)
SR Applicability B 3.0 
 
LaSalle 1 and 2 B 3.0-18 Revision 19 BASES  SR  3.0.4 LCO 3.0.4 will govern any restrictions that may  (or may    (continued) not) apply to MODE or other specified condition changes. SR 3.0.4 does not restrict changing MODES or other specified conditions of the Applicability when a Surveillance has not been performed within the specified Frequency, provided the requirement to declare the LCO not met has been delayed in accordance with SR 3.0.3.
The provisions of SR 3.0.4 shall not prevent entry into MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of SR 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown. In this context, a unit shutdown is defined as a change in MODE or other specified condition inn the Applicability associated with transitioning from MODE 1 to MODE 2, MODE 2 to MODE 3, and MODE 3 to MODE 4.
The precise requirements for performance of SRs are specified such that exceptions to SR 3.0.4 are not necessary. The specific time frames and conditions necessary for meeting the SRs are specified in the Frequency, in the Surveillance, or both. This allows performance of Surveillances when the prerequisite condition(s) specified in a Surveillance procedure require entry into the MODE or other specified condition in the Applicability of the associated LCO prior to the performance or completion of a Surveillance. A Surveillance that could not be performed until after entering the LCO's Applicability, would have its Frequency specified such that it is not "due" until the specific conditions needed are met. Alternately, the Surveillance may be stated in the form of a Note, as not required (to be met or performed) until a particular event, condition, or time has been reached. Further discussion of the specific formats of SRs' annotation is found in Section 1.4, Frequency.
 
SR  3.0.5 SR 3.0.5 establishes the applicability of each Surveillance to both Unit 1 and Unit 2 operation. Whenever a requirement
 
applies to only one unit, or is different for each unit, this will be identified with parenthetical reference, Notes, or other appropriate presentation within the SR.
 
SDM B 3.1.1 LaSalle 1 and 2 B 3.1.1-1 Revision 0 B 3.1  REACTIVITY CONTROL SYSTEMS
 
B 3.1.1  SHUTDOWN MARGIN (SDM)
 
BASES
 
BACKGROUND SDM requirements are specified to ensure:
: a. The reactor can be made subcritical from all operating conditions and transients and Design Basis Events;
: b. The reactivity transients associated with postulated accident conditions are controllable within acceptable
 
limits; and
: c. The reactor will be maintained sufficiently subcritical to preclude inadvertent criticality in the
 
shutdown condition.
 
These requirements are satisfied by the control rods, as
 
described in GDC 26 (Ref. 1), which can compensate for the
 
reactivity effects of the fuel and water temperature changes
 
experienced during all operating conditions.
 
APPLICABLE Having sufficient SDM assures that the reactor will become SAFETY ANALYSES and remain subcritical after all design basis accidents and transients. For example, SDM is assumed as an initial
 
condition for the control rod removal error during a
 
refueling accident (Ref. 2). The analysis of this
 
reactivity insertion event assumes the refueling interlocks
 
are OPERABLE when the reactor is in the refueling mode of
 
operation. These interlocks prevent the withdrawal of more
 
than one control rod from the core during refueling.
(Special consideration and requirements for multiple control
 
rod withdrawal during refueling are covered in Special
 
Operations LCO 3.10.5, "Multiple Control Rod
 
Withdrawal-Refueling.")  The analysis assumes this
 
condition is acceptable since the core will be shut down
 
with the highest worth control rod withdrawn, if adequate
 
SDM has been demonstrated.
 
Prevention or mitigation of positive reactivity insertion
 
events is necessary to limit the energy deposition in the
 
fuel, thereby preventing significant fuel damage, which
 
(continued)
SDM B 3.1.1 LaSalle 1 and 2 B 3.1.1-2 Revision 0 BASES APPLICABLE could result in undue release of radioactivity. Adequate SAFETY ANALYSES SDM ensures inadvertent criticalities do not cause (continued) significant fuel damage.
 
SDM satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).
 
LCO The specified SDM limit accounts for the uncertainty in the demonstration of SDM by testing. Separate SDM limits are
 
provided for testing where the highest worth control rod is
 
determined analytically or by measurement. This is due to
 
the reduced uncertainty in the SDM test when the highest
 
worth control rod is determined by measurement. When SDM is
 
demonstrated by calculations not associated with a test (e.g., to confirm SDM during the fuel loading sequence),
additional margin is included to account for uncertainties
 
in the calculation. To ensure adequate SDM, a design margin
 
is included to account for uncertainties in the design
 
calculations (Ref. 3).
 
APPLICABILITY In MODES 1 and 2, SDM must be provided to assure shutdown capability. In MODES 3 and 4, SDM is required to ensure the
 
reactor will be held subcritical with margin for a single
 
withdrawn control rod. SDM is required in MODE 5 to prevent
 
an inadvertent criticality during the withdrawal of a single
 
control rod from a core cell containing one or more fuel
 
assemblies (Ref. 2).
 
ACTIONS A.1 With SDM not within the limits of the LCO in MODE 1 or 2, SDM must be restored within 6 hours. Failure to meet the
 
specified SDM may be caused by a control rod that cannot be
 
inserted. The 6 hour Completion time is acceptable, considering that the reactor can still be shut down, assuming no additional failures of control rods to insert, and the low probability of an event occurring during this
 
interval.
 
(continued)
SDM B 3.1.1 LaSalle 1 and 2 B 3.1.1-3 Revision 0 BASES ACTIONS B.1 (continued)
If the SDM cannot be restored, the plant must be brought to
 
MODE 3 within 12 hours, to prevent the potential for further
 
reductions in available SDM (e.g., additional stuck control
 
rods). The allowed Completion Time of 12 hours is
 
reasonable, based on operating experience, to reach MODE 3
 
from full power conditions in an orderly manner and without
 
challenging plant systems.
 
C.1 With SDM not within limits in MODE 3, the operator must
 
immediately initiate action to fully insert all insertable
 
control rods. Action must continue until all insertable
 
control rods are fully inserted. This action results in the
 
least reactive condition for the core.
 
D.1, D.2, D.3, and D.4
 
With SDM not within limits in MODE 4, the operator must
 
immediately initiate action to fully insert all insertable
 
control rods. Action must continue until all insertable
 
control rods are fully inserted. This action results in the
 
least reactive condition for the core. Actions must also be
 
initiated within 1 hour to provide means for control of
 
potential radioactive releases. This includes ensuring
 
secondary containment is OPERABLE; at least one Standby Gas
 
Treatment (SGT) subsystem is OPERABLE; and secondary
 
containment isolation capability is available in each
 
associated secondary containment penetration flow path not
 
isolated that is assumed to be isolated to mitigate
 
radioactivity releases (i.e., at least one secondary
 
containment isolation valve and associated instrumentation
 
are OPERABLE, or other acceptable administrative controls to
 
assure isolation capability). These administrative controls
 
consist of stationing a dedicated operator, who is in
 
continuous communication with the control room, at the
 
controls of the isolation device. In this way, the
 
penetration can be rapidly isolated when a need for
 
secondary containment isolation is indicated. This (ensuring components are OPERABLE) may be performed as an (continued)
SDM B 3.1.1 LaSalle 1 and 2 B 3.1.1-4 Revision 0 BASES ACTIONS D.1, D.2, D.3, and D.4 (continued) administrative check, by examining logs or other
 
information, to determine if the components are out of
 
service for maintenance or other reasons. It is not
 
necessary to perform the Surveillances needed to demonstrate
 
the OPERABILITY of the components. If, however, any
 
required component is inoperable, then it must be restored
 
to OPERABLE status. In this case, SRs may need to be
 
performed to restore the component to OPERABLE status.
 
Actions must continue until all required components are
 
OPERABLE.
 
E.1, E.2, E.3, E.4, and E.5
 
With SDM not within limits in MODE 5, the operator must
 
immediately suspend CORE ALTERATIONS that could reduce SDM, e.g., insertion of fuel in the core or the withdrawal of
 
control rods. Suspension of these activities shall not
 
preclude completion of movement of a component to a safe
 
condition. Inserting control rods or removing fuel from the
 
core will reduce the total reactivity and are therefore
 
excluded from the suspended actions.
 
Action must also be immediately initiated to fully insert
 
all insertable control rods in core cells containing one or
 
more fuel assemblies. Action must continue until all
 
insertable control rods in core cells containing one or more
 
fuel assemblies have been fully inserted. Control rods in
 
core cells containing no fuel assemblies do not affect the
 
reactivity of the core and therefore do not have to be
 
inserted.
 
Action must also be initiated within 1 hour to provide means
 
for control of potential radioactive releases. This
 
includes ensuring secondary containment is OPERABLE; at
 
least one SGT subsystem is OPERABLE; and secondary
 
containment isolation capability is available in each
 
associated secondary containment penetration flow path not
 
isolated that is assumed to be isolated to mitigate
 
radioactivity releases (i.e., at least one secondary
 
containment isolation valve and associated instrumentation
 
are OPERABLE, or other acceptable administrative controls to
 
assure isolation capability). These administrative controls
 
(continued)
SDM B 3.1.1 LaSalle 1 and 2 B 3.1.1-5 Revision 0 BASES ACTIONS E.1, E.2, E.3, E.4, and E.5 (continued) consist of stationing a dedicated operator, who is in
 
continuous communication with the control room, at the
 
controls of the isolation device. In this way, the
 
penetration can be rapidly isolated when a need for
 
secondary containment isolation is indicated. This (ensuring components are OPERABLE) may be performed as an
 
administrative check, by examining logs or other
 
information, to determine if the components are out of
 
service for maintenance or other reasons. It is not
 
necessary to perform the Surveillances needed to demonstrate
 
the OPERABILITY of the components. If, however, any
 
required component is inoperable, then it must be restored
 
to OPERABLE status. In this case, SRs may need to be
 
performed to restore the component to OPERABLE status.
 
Actions must continue until all required components are
 
OPERABLE.
 
SURVEILLANCE SR  3.1.1.1 REQUIREMENTS Adequate SDM must be verified to ensure the reactor can be
 
made subcritical from any initial operating condition. This
 
can be accomplished by a test, an evaluation, or a
 
combination of the two. Adequate SDM is demonstrated by
 
testing before or during the first startup after fuel
 
movement, shuffling within the reactor pressure vessel, or
 
control rod replacement. Control rod replacement refers to
 
the decoupling and removal of a control rod from a core
 
location, and subsequent replacement with a new control rod
 
or a control rod from another core location. Since core
 
reactivity will vary during the cycle as a function of fuel
 
depletion and poison burnup, the beginning of cycle (BOC)
 
test must also account for changes in core reactivity during
 
the cycle. Therefore, to obtain the SDM, the initial
 
measured value must be increased by an adder, "R", which is
 
the difference between the calculated value of maximum core
 
reactivity during the operating cycle and the calculated BOC
 
core reactivity. If the value of R is negative (i.e., BOC
 
is the most reactive point in the cycle), no correction to
 
the BOC measured value is required (Ref. 4). For the SDM
 
demonstrations that rely solely on calculation of the
 
highest worth control rod, additional margin (0.10% k/k) must be added to the SDM limit of 0.28% k/k to account for uncertainties in the calculation.
(continued)
SDM B 3.1.1 LaSalle 1 and 2 B 3.1.1-6 Revision 0 BASES SURVEILLANCE SR  3.1.1.1 (continued)
REQUIREMENTS The SDM may be demonstrated during an in-sequence control
 
rod withdrawal, in which the highest worth control rod is
 
analytically determined, or during local criticals, where
 
the highest worth control rod is determined by testing.
 
Local critical tests require the withdrawal of out of
 
sequence control rods. This testing would therefore require
 
bypassing of the Rod Worth Minimizer to allow the out of
 
sequence withdrawal, and therefore additional requirements
 
must be met (see LCO 3.10.6, "Control Rod
 
Testing-Operating").
 
The Frequency of 4 hours after reaching criticality is
 
allowed to provide a reasonable amount of time to perform
 
the required calculations and appropriate verification.
 
During MODES 3 and 4, analytical calculation of SDM may be
 
used to assure the requirements of SR 3.1.1.1 are met. 
 
During MODE 5, adequate SDM is also required to ensure the
 
reactor does not reach criticality during control rod
 
withdrawals. An evaluation of each in vessel fuel movement
 
during fuel loading (including shuffling fuel within the
 
core) is required to ensure adequate SDM is maintained
 
during refueling. This evaluation ensures the intermediate
 
loading patterns are bounded by the safety analyses for the
 
final core loading pattern. For example, bounding analyses
 
that demonstrate adequate SDM for the most reactive
 
configurations during the refueling may be performed to
 
demonstrate acceptability of the entire fuel movement
 
sequence. These bounding analyses include additional
 
margins to the associated uncertainties. Spiral offload or
 
reload sequences inherently satisfy the SR, provided the
 
fuel assemblies are reloaded in the same configuration
 
analyzed for the new cycle. Removing fuel from the core
 
will always result in an increase in SDM.
 
REFERENCES 1. 10 CFR 50, Appendix A, GDC 26.
: 2. UFSAR, Section 15.4.1.1.
: 3. UFSAR, Section 4.3.2.4.1.
: 4. NEDE-24011-P-A, "GE Standard Application for Reactor Fuel," (as specified in Technical Specification
 
5.6.5).
Reactivity Anomalies B 3.1.2 LaSalle 1 and 2 B 3.1.2-1 Revision 0 B 3.1  REACTIVITY CONTROL SYSTEMS
 
B 3.1.2  Reactivity Anomalies
 
BASES
 
BACKGROUND In accordance with GDC 26, GDC 28, and GDC 29 (Ref. 1), reactivity shall be controllable such that subcriticality is
 
maintained under cold conditions and acceptable fuel design
 
limits are not exceeded during normal operation and
 
anticipated operational occurrences. Reactivity Anomalies
 
is used as a measure of the predicted versus measured core
 
reactivity during power operation. The continual
 
confirmation of core reactivity is necessary to ensure that
 
the Design Basis Accident (DBA) and transient safety
 
analyses remain valid. A large reactivity anomaly could be
 
the result of unanticipated changes in fuel reactivity, control rod worth, or operation at conditions not consistent
 
with those assumed in the predictions of core reactivity, and could potentially result in a loss of SDM or violation
 
of acceptable fuel design limits. Comparing predicted
 
versus measured core reactivity validates the nuclear
 
methods used in the safety analysis and supports the SDM
 
demonstrations (LCO 3.1.1, "SHUTDOWN MARGIN (SDM)") in
 
ensuring the reactor can be brought safely to cold, subcritical conditions.
When the reactor core is critical or in normal power operation, a reactivity balance exists and the net
 
reactivity is zero. A comparison of predicted and measured
 
reactivity is convenient under such a balance, since
 
parameters are being maintained relatively stable under
 
steady state power conditions. The positive reactivity
 
inherent in the core design is balanced by the negative
 
reactivity of the control components, thermal feedback, neutron leakage, and materials in the core that absorb
 
neutrons, such as burnable absorbers, producing zero net
 
reactivity.
 
In order to achieve the required fuel cycle energy output, the uranium enrichment in the new fuel loading and the fuel
 
loaded in the previous cycles provide excess positive
 
reactivity beyond that required to sustain steady state
 
operation at the beginning of cycle (BOC). When the reactor
 
is critical at RTP and operating moderator temperature, the
 
(continued)
Reactivity Anomalies B 3.1.2 LaSalle 1 and 2 B 3.1.2-2 Revision 0 BASES BACKGROUND excess positive reactivity is compensated by burnable (continued) absorbers (e.g., gadolinia), control rods, and whatever neutron poisons (mainly xenon and samarium) are present in
 
the fuel.
The predicted core reactivity, as represented by k effective (k eff), is calculated by a 3D core simulator code as a function of cycle exposure. This calculation is performed
 
for projected operating states and conditions throughout the
 
cycle. The monitored k eff is calculated by the core monitoring system for actual plant conditions and is then
 
compared to the predicted value for the cycle exposure.
 
APPLICABLE Accurate prediction of core reactivity is either an explicit SAFETY ANALYSES or implicit assumption in the accident analysis evaluations (Ref. 2). In particular, SDM and reactivity transients, such as control rod withdrawal accidents or rod drop
 
accidents, are very sensitive to accurate prediction of core
 
reactivity. These accident analysis evaluations rely on
 
computer codes that have been qualified against available
 
test data, operating plant data, and analytical benchmarks.
 
Monitoring reactivity anomaly provides additional assurance
 
that the nuclear methods provide an accurate representation
 
of the core reactivity.
The comparison between measured and predicted initial core
 
reactivity provides a normalization for the calculational
 
models used to predict core reactivity. If the measured and
 
predicted k eff for identical core conditions at BOC do not reasonably agree, then the assumptions used in the reload
 
cycle design analysis or the calculation models used to
 
predict k eff may not be accurate. If reasonable agreement between measured and predicted core reactivity exists at
 
BOC, then the prediction may be normalized to the measured
 
value. Thereafter, any significant deviations in the
 
measured k eff from the predicted k eff that develop during fuel depletion may be an indication that the assumptions of the
 
DBA and transient analyses are no longer valid, or that an
 
unexpected change in core conditions has occurred.
 
Reactivity Anomalies satisfy Criterion 2 of
 
10 CFR 50.36(c)(2)(ii).
 
(continued)
Reactivity Anomalies B 3.1.2 LaSalle 1 and 2 B 3.1.2-3 Revision 0 BASES  (continued)
 
LCO The reactivity anomaly limit is established to ensure plant operation is maintained within the assumptions of the safety
 
analyses. Large differences between monitored and predicted
 
core reactivity may indicate that the assumptions of the DBA
 
and transient analyses are no longer valid, or that the
 
uncertainties in the Nuclear Design Methodology are larger
 
than expected. A limit on the difference between the
 
monitored core k eff and the predicted core k eff of 1% k/k has been established based on engineering judgment. A
> 1% deviation in reactivity from that predicted is larger than
 
expected for normal operation and should therefore be
 
evaluated.
 
APPLICABILITY In MODE 1, most of the control rods are withdrawn and steady state operation is typically achieved. Under these
 
conditions, the comparison between predicted and monitored
 
core reactivity provides an effective measure of the
 
reactivity anomaly. In MODE 2, control rods are typically
 
being withdrawn during a startup. In MODES 3 and 4, all
 
control rods are fully inserted, and, therefore, the reactor
 
is in the least reactive state, where monitoring core
 
reactivity is not necessary. In MODE 5, fuel loading
 
results in a continually changing core reactivity. SDM
 
requirements (LCO 3.1.1) ensure that fuel movements are
 
performed within the bounds of the safety analysis, and an
 
SDM demonstration is required during the first startup
 
following operations that could have altered core reactivity (e.g., fuel movement, control rod replacement, control rod
 
shuffling). The SDM test, required by LCO 3.1.1, provides a
 
direct comparison of the predicted and monitored core
 
reactivity at cold conditions; therefore, Reactivity
 
Anomalies is not required during these conditions.
 
ACTIONS A.1 Should an anomaly develop between measured and predicted
 
core reactivity, the core reactivity difference must be
 
restored to within the limit to ensure continued operation
 
is within the core design assumptions. Restoration to
 
within the limit could be performed by an evaluation of the
 
core design and safety analysis to determine the reason for
 
the anomaly. This evaluation normally reviews the core
 
(continued)
Reactivity Anomalies B 3.1.2 LaSalle 1 and 2 B 3.1.2-4 Revision 0 BASES ACTIONS A.1 (continued) conditions to determine their consistency with input to
 
design calculations. Measured core and process parameters
 
are also normally evaluated to determine that they are
 
within the bounds of the safety analysis, and safety
 
analysis calculational models may be reviewed to verify that
 
they are adequate for representation of the core conditions.
 
The required Completion Time of 72 hours is based on the low
 
probability of a DBA during this period, and allows
 
sufficient time to assess the physical condition of the
 
reactor and complete the evaluation of the core design and
 
safety analysis.
 
B.1 If the core reactivity cannot be restored to within the
 
1% k/k limit, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant
 
must be brought to at least MODE 3 within 12 hours. The
 
allowed Completion Time of 12 hours is reasonable, based on
 
operating experience, to reach MODE 3 from full power
 
conditions in an orderly manner and without challenging
 
plant systems.
 
SURVEILLANCE SR  3.1.2.1 REQUIREMENTS Verifying the reactivity difference between the monitored
 
and predicted core k eff is within the limits of the LCO provides further assurance that plant operation is
 
maintained within the assumptions of the DBA and transient
 
analyses. The Core Monitoring System calculates the core
 
k eff for the reactor conditions obtained from plant instrumentation. A comparison of the monitored core k eff to the predicted core k eff at the same cycle exposure is used to calculate the reactivity difference. The comparison is
 
required when the core reactivity has potentially changed by
 
a significant amount. This may occur following a refueling
 
in which new fuel assemblies are loaded, fuel assemblies are
 
shuffled within the core, or control rods are replaced or
 
shuffled. Control rod replacement refers to the decoupling
 
and removal of a control rod from a core location, and 
 
(continued)
Reactivity Anomalies B 3.1.2 LaSalle 1 and 2 B 3.1.2-5 Revision 0 BASES SURVEILLANCE SR  3.1.2.1 (continued)
REQUIREMENTS subsequent replacement with a new control rod or a control
 
rod from another core location. Also, core reactivity
 
changes during the cycle. The 24 hour interval after
 
reaching equilibrium conditions following a startup is based
 
on the need for equilibrium xenon concentrations in the
 
core, such that an accurate comparison between the monitored
 
and predicted core k eff values can be made. For the purposes of this SR, the reactor is assumed to be at equilibrium
 
conditions when steady state operations (no control rod
 
movement or core flow changes) at  75% RTP have been obtained. The 1000 MWD/T Frequency was developed, considering the relatively slow change in core reactivity
 
with exposure and operating experience related to variations
 
in core reactivity. This comparison requires the core to be
 
operating at power levels which minimize the uncertainties
 
and measurement errors, in order to obtain meaningful
 
results. Therefore, the comparison is only done when in
 
MODE 1. The core weight, tons (T) in MWD/T, reflects metric
 
tons.
REFERENCES 1. 10 CFR 50, Appendix A, GDC 26, GDC 28, and GDC 29.
: 2. UFSAR, Chapter 15.
 
Control Rod OPERABILITY B 3.1.3 LaSalle 1 and 2 B 3.1.3-1 Revision 0 B 3.1  REACTIVITY CONTROL SYSTEMS
 
B 3.1.3  Control Rod OPERABILITY
 
BASES
 
BACKGROUND Control rods are components of the Control Rod Drive (CRD)
System, which is the primary reactivity control system for
 
the reactor. In conjunction with the Reactor Protection
 
System, the CRD System provides the means for the reliable
 
control of reactivity changes to ensure that under
 
conditions of normal operation, including anticipated
 
operational occurrences, specified acceptable fuel design
 
limits are not exceeded. In addition, the control rods
 
provide the capability to hold the reactor core subcritical
 
under all conditions and to limit the potential amount and
 
rate of reactivity increase caused by a malfunction in the
 
CRD System. The CRD System is designed to satisfy the
 
requirements of GDC 26, GDC 27, GDC 28, and GDC 29, (Ref. 1).
The CRD System consists of 185 locking piston control rod
 
drive mechanisms (CRDMs) and a hydraulic control unit for
 
each drive mechanism. The locking piston type CRDM is a
 
double acting hydraulic piston, which uses condensate water
 
as the operating fluid. Accumulators provide additional
 
energy for scram. An index tube and piston, coupled to the
 
control rod, are locked at fixed increments by a collet
 
mechanism. The collet fingers engage notches in the index
 
tube to prevent unintentional withdrawal of the control rod, but without restricting insertion.
 
This Specification, along with LCO 3.1.4, "Control Rod Scram
 
Times," LCO 3.1.5, "Control Rod Scram Accumulators," and
 
LCO 3.1.6, "Rod Pattern Control," ensure that the
 
performance of the control rods in the event of a Design
 
Basis Accident (DBA) or transient meets the assumptions used
 
in the safety analyses of References 2, 3, 4, 5, and 6.
 
APPLICABLE The analytical methods and assumptions used in the SAFETY ANALYSES evaluations involving control rods are presented in References 2, 3, 4, 5, and 6. The control rods provide the
 
primary means for rapid reactivity control (reactor scram),
for maintaining the reactor subcritical, and for limiting
 
the potential effects of reactivity insertion events caused
 
by malfunctions in the CRD System.
  (continued)
Control Rod OPERABILITY B 3.1.3 LaSalle 1 and 2 B 3.1.3-2 Revision 0 BASES APPLICABLE The capability of inserting the control rods provides SAFETY ANALYSES assurance that the assumptions for scram reactivity in the (continued) DBA and transient analyses are not violated. Since the SDM ensures the reactor will be subcritical with the highest
 
worth control rod withdrawn (assumed single failure), the
 
additional failure of a second control rod to insert could
 
invalidate the demonstrated SDM and potentially limit the
 
ability of the CRD System to hold the reactor subcritical.
 
If the control rod is stuck at an inserted position and
 
becomes decoupled from the CRD, a control rod drop accident (CRDA) can possibly occur. Therefore, the requirement that
 
all control rods be OPERABLE ensures the CRD System can
 
perform its intended function.
The control rods also protect the fuel from damage that
 
results in release of radioactivity. The limits protected
 
are the MCPR Safety Limit (SL) (see Bases for SL 2.1.1, "Reactor Core SLs," and LCO 3.2.2, "MINIMUM CRITICAL POWER
 
RATIO (MCPR)"), the 1% cladding plastic strain fuel design
 
limit (see Bases for LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT
 
GENERATION RATE (APLGHR)," and LCO 3.2.3, "LINEAR HEAT
 
GENERATION RATE (LHGR)"), and the fuel design limit (see
 
Bases for LCO 3.1.6, "Rod Pattern Control") during
 
reactivity insertion events.
 
The negative reactivity insertion (scram) provided by the
 
CRD System provides the analytical basis for determination
 
of plant thermal limits and provides protection against fuel
 
design limits during a CRDA. Bases for LCO 3.1.4, LCO 3.1.5, and LCO 3.1.6 discuss in more detail how the SLs
 
are protected by the CRD System.
 
Control rod OPERABILITY satisfies Criterion 3 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO OPERABILITY of an individual control rod is based on a combination of factors, primarily the scram insertion times, the control rod coupling integrity, and the ability to
 
determine the control rod position. Accumulator OPERABILITY
 
is addressed by LCO 3.1.5. The associated scram accumulator
 
status for a control rod only affects the scram insertion
 
times and therefore an inoperable accumulator does not (continued)
Control Rod OPERABILITY B 3.1.3 LaSalle 1 and 2 B 3.1.3-3 Revision 0 BASES LCO immediately require declaring a control rod inoperable. 
  (continued) Although not all control rods are required to be OPERABLE to satisfy the intended reactivity control requirements, strict
 
control over the number and distribution of inoperable
 
control rods is required to satisfy the assumptions of the
 
DBA and transient analyses.
OPERABILITY requirements for control rods also includes
 
correct assembly of the CRD housing supports.
 
APPLICABILITY In MODES 1 and 2, the control rods are assumed to function during a DBA or transient and are therefore required to be
 
OPERABLE in these MODES. In MODES 3 and 4, control rods are
 
not able to be withdrawn since the reactor mode switch is in
 
shutdown and a control rod block is applied. This provides
 
adequate requirements for control rod OPERABILITY during
 
these conditions. Control rod requirements in MODE 5 are
 
located in LCO 3.9.5, "Control Rod OPERABILITY-Refueling."
ACTIONS The ACTIONS Table is modified by a Note indicating that a separate Condition entry is allowed for each control rod.
 
This is acceptable, since the Required Actions for each
 
Condition provide appropriate compensatory actions for each
 
inoperable control rod. Complying with the Required Actions
 
may allow for continued operation, and subsequent inoperable
 
control rods are governed by subsequent Condition entry and
 
application of associated Required Actions.
 
A.1, A.2, A.3, and A.4
 
A control rod is considered stuck if it will not insert by
 
either CRD drive water or scram pressure. The Required
 
Actions are modified by a Note that allows the Rod Worth
 
Minimizer (RWM) to be bypassed if required to allow
 
continued operation. LCO 3.3.2.1, "Control Rod Block
 
Instrumentation," provides additional requirements when the
 
RWM is bypassed to ensure compliance with the CRDA analysis.
 
With one withdrawn control rod stuck, the local scram
 
reactivity rate assumptions may not be met if the stuck
 
  (continued)
Control Rod OPERABILITY B 3.1.3 LaSalle 1 and 2 B 3.1.3-4 Revision 0 BASES ACTIONS A.1, A.2, A.3, and A.4 (continued) control rod separation criteria are not met. Therefore, a
 
verification that the separation criteria are met must be
 
performed immediately. The separation criteria are not met
 
if: a) the stuck control rod occupies a location adjacent to
 
two "slow" control rods, b) the stuck control rod occupies a
 
location adjacent to one "slow" control rod, and the one "slow" control rod is also adjacent to another "slow" control rod, or c) if the stuck control rod occupies a
 
location adjacent to one "slow" control rod when there is
 
another pair of "slow" control rods elsewhere in the core
 
adjacent to one another. The description of "slow" control
 
rods is provided in LCO 3.1.4, "Control Rod Scram Times."
In addition, the associated control rod drive must be
 
disarmed within 2 hours. The allowed Completion Time of
 
2 hours is acceptable, considering the reactor can still be
 
shut down, assuming no additional control rods fail to
 
insert, and provides a reasonable amount of time to perform
 
the Required Action in an orderly manner. The control rod
 
must be isolated from both scram and normal insert and
 
withdraw pressure. Isolating the control rod from scram and
 
normal insert and withdraw pressure prevents damage to the
 
CRDM or reactor internals. The control rod isolation method
 
should also ensure cooling water to the CRD is maintained.
Monitoring of the insertion capability for each withdrawn
 
control rod must also be performed within 24 hours from
 
discovery of Condition A concurrent with THERMAL POWER
 
greater than the low power setpoint (LPSP) of the RWM.
 
SR 3.1.3.2 and SR 3.1.3.3 perform periodic tests of the
 
control rod insertion capability of withdrawn control rods.
 
Testing each withdrawn control rod ensures that a generic
 
problem does not exist. This Completion Time also allows
 
for an exception to the normal "time zero" for beginning the
 
allowed outage time "clock."  The Required Action A.3
 
Completion Time only begins upon discovery of Condition A
 
concurrent with THERMAL POWER greater than the actual LPSP
 
of the RWM, since the notch insertions may not be compatible
 
with the requirements of rod pattern control (LCO 3.1.6) and
 
the RWM (LCO 3.3.2.1). The allowed Completion Time provides
 
a reasonable time to test the control rods, considering the
 
potential for a need to reduce power to perform the tests.
(continued)
Control Rod OPERABILITY B 3.1.3 LaSalle 1 and 2 B 3.1.3-5 Revision 0 BASES ACTIONS A.1, A.2, A.3, and A.4 (continued)
To allow continued operation with a withdrawn control rod
 
stuck, an evaluation of adequate SDM is also required within
 
72 hours. Should a DBA or transient require a shutdown, to
 
preserve the single failure criterion an additional control
 
rod would have to be assumed to have failed to insert when
 
required. Therefore, the original SDM demonstration may not
 
be valid. The SDM must therefore be evaluated (by
 
measurement or analysis) with the stuck control rod at its
 
stuck position and the highest worth OPERABLE control rod
 
assumed to be fully withdrawn.
 
The allowed Completion Time of 72 hours to verify SDM is
 
adequate, considering that with a single control rod stuck
 
in a withdrawn position, the remaining OPERABLE control rods
 
are capable of providing the required scram and shutdown
 
reactivity. Failure to reach MODE 4 is only likely if an
 
additional control rod adjacent to the stuck control rod
 
also fails to insert during a required scram. Even with the
 
postulated additional single failure of an adjacent control
 
rod to insert, sufficient reactivity control remains to
 
reach MODE 3 conditions.
 
B.1 With two or more withdrawn control rods stuck, the plant
 
must be brought to MODE 3 within 12 hours. The occurrence of
 
more than one control rod stuck at a withdrawn position
 
increases the probability that the reactor cannot be shut
 
down if required. Insertion of all insertable control rods
 
eliminates the possibility of an additional failure of a
 
control rod to insert. The allowed Completion Time of
 
12 hours is reasonable, based on operating experience, to
 
reach MODE 3 from full power conditions in an orderly manner
 
and without challenging plant systems.
 
C.1 and C.2
 
With one or more control rods inoperable for reasons other
 
than being stuck in the withdrawn position, operation may
 
continue, provided the control rods are fully inserted (continued)
Control Rod OPERABILITY B 3.1.3 LaSalle 1 and 2 B 3.1.3-6 Revision 0 BASES ACTIONS C.1 and C.2 (continued) within 3 hours and disarmed (electrically or hydraulically)
 
within 4 hours. Inserting a control rod ensures the
 
shutdown and scram capabilities are not adversely affected.
 
The control rod is disarmed to prevent inadvertent
 
withdrawal during subsequent operations. The control rods
 
can be hydraulically disarmed by closing the drive water and
 
exhaust water isolation valves. Electrically, the control
 
rods can be disarmed by disconnecting power from all four
 
directional control valve solenoids. Required Action C.1 is
 
modified by a Note that allows the RWM to be bypassed if
 
required to allow insertion of the inoperable control rods
 
and continued operation. LCO 3.3.2.1 provides additional
 
requirements when the RWM is bypassed to ensure compliance
 
with the CRDA analysis.
 
The allowed Completion Times are reasonable, considering the
 
small number of allowed inoperable control rods, and provide
 
time to insert and disarm the control rods in an orderly
 
manner and without challenging plant systems.
 
D.1 and D.2
 
Out of sequence control rods may increase the potential
 
reactivity worth of a dropped control rod during a CRDA. At 10% RTP, the analyzed rod position sequence analysis (Refs. 7 and 8) requires inserted control rods not in
 
compliance with the analyzed rod position sequence to be
 
separated by at least two OPERABLE control rods in all
 
directions, including the diagonal (i.e., all other control
 
rods in a five-by-five array centered on the inoperable
 
control rod are OPERABLE). Therefore, if two or more
 
inoperable control rods are not in compliance with the
 
analyzed rod position sequence and not separated by at least
 
two OPERABLE control rods in all directions, action must be
 
taken to restore compliance with the analyzed rod position
 
sequence or restore the control rods to OPERABLE status. A
 
Note has been added to the Condition to clarify that the
 
Condition is not applicable when
> 10% RTP since the analyzed rod position sequence is not required to be
 
followed under these conditions, as described in the Bases
 
for LCO 3.1.6. The allowed Completion Time of 4 hours is
 
acceptable, considering the low probability of a CRDA
 
occurring.
 
(continued)
Control Rod OPERABILITY B 3.1.3 LaSalle 1 and 2 B 3.1.3-7 Revision 0 BASES ACTIONS E.1 (continued)
If any Required Action and associated Completion Time of
 
Condition A, C, or D are not met or nine or more inoperable
 
control rods exist, the plant must be brought to a MODE in
 
which the LCO does not apply. To achieve this status, the
 
plant must be brought to MODE 3 within 12 hours. This
 
ensures all insertable control rods are inserted and places
 
the reactor in a condition that does not require the active
 
function (i.e., scram) of the control rods. The number of
 
control rods permitted to be inoperable when operating above
 
10% RTP (i.e., no CRDA considerations) could be more than
 
the value specified, but the occurrence of a large number of
 
inoperable control rods could be indicative of a generic
 
problem, and investigation and resolution of the potential
 
problem should be undertaken. The allowed Completion Time
 
of 12 hours is reasonable, based on operating experience, to
 
reach MODE 3 from full power conditions in an orderly manner
 
and without challenging plant systems.
 
SURVEILLANCE SR  3.1.3.1 REQUIREMENTS The position of each control rod must be determined, to
 
ensure adequate information on control rod position is
 
available to the operator for determining control rod
 
OPERABILITY and controlling rod patterns. Control rod
 
position may be determined by the use of OPERABLE position
 
indicators, by moving control rods by single notch movement
 
to a position with an OPERABLE indicator (full-in, full-out, or numeric indicator) and then returning the control rods by
 
single notch movement to their original position, or by the
 
use of other appropriate methods. The 24 hour Frequency of
 
this SR is based on operating experience related to expected
 
changes in control rod position and the availability of
 
control rod position indications in the control room.
 
(continued)
Control Rod OPERABILITY B 3.1.3 LaSalle 1 and 2 B 3.1.3-8 Revision 0 BASES SURVEILLANCE SR  3.1.3.2 and SR  3.1.3.3 REQUIREMENTS (continued) Control rod insertion capability is demonstrated by inserting each partially or fully withdrawn control rod at
 
least one notch and observing that the control rod moves.
 
The control rod may then be returned to its original
 
position. This ensures the control rod is not stuck and is
 
free to insert on a scram signal. These Surveillances are
 
not required when THERMAL POWER is less than or equal to the
 
actual LPSP of the RWM since the notch insertions may not be
 
compatible with the requirements of the analyzed rod
 
position sequence (LCO 3.1.6) and the RWM (LCO 3.3.2.1).
 
The 7 day Frequency of SR 3.1.3.2 is based on operating
 
experience related to the changes in CRD performance and the
 
ease of performing notch testing for fully withdrawn control
 
rods. Partially withdrawn control rods are tested at a
 
31 day Frequency, based on the potential power reduction
 
required to allow the control rod movement, and considering
 
the large testing sample of SR 3.1.3.2. Furthermore, the
 
31 day Frequency takes into account operating experience
 
related to changes in CRD performance. At any time, if a
 
control rod is immovable, a determination of that control
 
rod's trippability (OPERABILITY) must be made and
 
appropriate action taken.
These SRs are modified by Notes that allow 7 days and 31
 
days respectively, after withdrawal of the control rod and
 
increasing power to above the LPSP, to perform the
 
Surveillance. This acknowledges that the control rod must
 
be first withdrawn and THERMAL POWER must be increased to
 
above the LPSP before performance of the Surveillance, and
 
therefore, the Notes avoid potential conflicts with SR 3.0.3
 
and SR 3.0.4.
 
(continued)
Control Rod OPERABILITY B 3.1.3 LaSalle 1 and 2 B 3.1.3-9 Revision 0 BASES SURVEILLANCE SR  3.1.3.4 REQUIREMENTS (continued) Verifying the scram time for each control rod to notch position 05 is  7 seconds provides reasonable assurance that the control rod will insert when required during a DBA
 
or transient, thereby completing its shutdown function.
 
This SR is performed in conjunction with the control rod
 
scram time testing of SR 3.1.4.1, SR 3.1.4.2, SR 3.1.4.3, and SR 3.1.4.4. The LOGIC SYSTEM FUNCTIONAL TEST in
 
LCO 3.3.1.1, "Reactor Protection System (RPS)
 
Instrumentation," and the functional testing of SDV vent and
 
drain valves in LCO 3.1.8, "Scram Discharge Volume (SDV)
 
Vent and Drain Valves," overlap this Surveillance to provide
 
complete testing of the assumed safety function. The
 
associated Frequencies are acceptable, considering the more
 
frequent testing performed to demonstrate other aspects of
 
control rod OPERABILITY and operating experience, which
 
shows scram times do not significantly change over an
 
operating cycle.
 
SR  3.1.3.5
 
Coupling verification is performed to ensure the control rod
 
is connected to the CRDM and will perform its intended
 
function when necessary. The Surveillance requires
 
verifying that a control rod does not go to the withdrawn
 
overtravel position when it is fully withdrawn. The
 
overtravel position feature provides a positive check on the
 
coupling integrity, since only an uncoupled CRD can reach
 
the overtravel position. The verification is required to be
 
performed anytime a control rod is withdrawn to the "full
 
out" position (notch position 48) or prior to declaring the
 
control rod OPERABLE after work on the control rod or CRD
 
System that could affect coupling. This includes control
 
rods inserted one notch and then returned to the "full out" position during the performance of SR 3.1.3.2. This
 
Frequency is acceptable, considering the low probability
 
that a control rod will become uncoupled when it is not
 
being moved and operating experience related to uncoupling
 
events.
(continued)
Control Rod OPERABILITY B 3.1.3 LaSalle 1 and 2 B 3.1.3-10 Revision 0 BASES  (continued)
 
REFERENCES 1. 10 CFR 50, Appendix A, GDC 26, GDC 27, GDC 28, and GDC 29. 
: 2. UFSAR, Section 4.3.2.5.
: 3. UFSAR, Section 4.6.1.1.2.
: 4. UFSAR, Section 5.2.2.2.
: 5. UFSAR, Section 15.4.
: 6. UFSAR, Section 15.4.9.
: 7. NEDO-21231, "Banked Position Withdrawal Sequence," Section 7.2, January 1977.
: 8. NFSR-0091, Commonwealth Edison Topical Report, Benchmark of CASMO/MICROBURN BWR Nuclear Design
 
Methods, (as specified in Technical Specification
 
5.6.5).
Control Rod Scram Times B 3.1.4 LaSalle 1 and 2 B 3.1.4-1 Revision 0 B 3.1  REACTIVITY CONTROL SYSTEMS
 
B 3.1.4  Control Rod Scram Times
 
BASES
 
BACKGROUND The scram function of the Control Rod Drive (CRD) System controls reactivity changes during anticipated operational
 
occurrences to ensure that specified acceptable fuel design
 
limits are not exceeded (Ref. 1). The control rods are
 
scrammed by positive means, using hydraulic pressure exerted
 
on the CRD piston.
When a scram signal is initiated, control air is vented from
 
the scram valves, allowing them to open by spring action.
 
Opening the exhaust valves reduces the pressure above the
 
main drive piston to atmospheric pressure, and opening the
 
inlet valve applies the accumulator or reactor pressure to
 
the bottom of the piston. Since the notches in the index
 
tube are tapered on the lower edge, the collet fingers are
 
forced open by cam action, allowing the index tube to move
 
upward without restriction because of the high differential
 
pressure across the piston. As the drive moves upward and
 
accumulator pressure drops below the reactor pressure, a
 
ball check valve opens, letting the reactor pressure
 
complete the scram action. If the reactor pressure is low, such as during startup, the accumulator will fully insert
 
the control rod within the required time without assistance
 
from reactor pressure.
 
APPLICABLE The analytical methods and assumptions used in evaluating SAFETY ANALYSES the control rod scram function are presented in References 2, 3, 4, 5, and 6. The Design Basis Accident (DBA) and
 
transient analyses assume that all of the control rods scram
 
at a specified insertion rate. The resulting negative scram
 
reactivity forms the basis for the determination of plant
 
thermal limits (e.g., the MCPR). Other distributions of
 
scram times (e.g., several control rods scramming slower
 
than the average time, with several control rods scramming
 
faster than the average time) can also provide sufficient
 
scram reactivity. Surveillance of each individual control
 
rod's scram time ensures the scram reactivity assumed in the
 
DBA and transient analyses can be met.
  (continued)
Control Rod Scram Times B 3.1.4 LaSalle 1 and 2 B 3.1.4-2 Revision 0 BASES APPLICABLE The scram function of the CRD System protects the MCPR SAFETY ANALYSES Safety Limit (SL) (see Bases for SL 2.1.1, "Reactor Core (continued) SLs," and LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)"), and the 1% cladding plastic strain fuel design limit (see
 
Bases for LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION
 
RATE (APLHGR)," and LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)"), which ensure that no fuel damage will occur if
 
these limits are not exceeded. Above 800 psig, the scram
 
function is designed to insert negative reactivity at a rate
 
fast enough to prevent the actual MCPR from becoming less
 
than the MCPR SL during the analyzed limiting power
 
transient. Below 800 psig, the scram function is assumed to
 
perform during the control rod drop accident (Ref. 6) and, therefore, also provides protection against violating fuel
 
design limits during reactivity insertion accidents (see
 
Bases for LCO 3.1.6, "Rod Pattern Control"). For the
 
reactor vessel overpressure protection analysis (Ref. 4),
the scram function, along with the safety/relief valves, ensure that the peak vessel pressure is maintained within
 
the applicable ASME Code limits.
 
Control rod scram times satisfy Criterion 3 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO The scram times specified in Table 3.1.4-1 are required to ensure that the scram reactivity assumed in the DBA and
 
transient analysis is met. To account for single failure
 
and "slow" scramming control rods, the scram times specified
 
in Table 3.1.4-1 are faster than those assumed in the design
 
basis analysis. The scram times have a margin to allow up
 
to 7.0% of the control rods (e.g., 185 x 7.0%  12) to have scram times that exceed the specified limits (i.e., "slow" control rods) assuming a single stuck control rod (as
 
allowed by LCO 3.1.3, "Control Rod OPERABILITY") and an
 
additional control rod failing to scram per the single
 
failure criterion. The scram times are specified as a
 
function of reactor steam dome pressure to account for the
 
pressure dependence of the scram times. The scram times are
 
specified relative to measurements based on reed switch
 
positions, which provide the control rod position
 
indication. The reed switch closes ("pickup") when the
 
index tube passes a specific location and then opens
 
("dropout") as the index tube travels upward. Verification
 
of the specified scram times in Table 3.1.4-1 is
 
accomplished through measurement of the "dropout" times. 
(continued)
Control Rod Scram Times B 3.1.4 LaSalle 1 and 2 B 3.1.4-3 Revision 0 BASES LCO To ensure that local scram reactivity rates are maintained (continued) within acceptable limits, no more than two of the allowed "slow" control rods may occupy adjacent (face or diagonal)
 
locations.
 
Table 3.1.4-1 is modified by two Notes, which state control
 
rods with scram times not within the limits of the Table are
 
considered "slow" and that control rods with scram times
 
> 7 seconds are considered inoperable as required by SR 3.1.3.4.
 
This LCO applies only to OPERABLE control rods since
 
inoperable control rods will be inserted and disarmed (LCO
 
3.1.3). Slow scramming control rods may be conservatively
 
declared inoperable and not accounted for as "slow" control
 
rods.
APPLICABILITY In MODES 1 and 2, a scram is assumed to function during transients and accidents analyzed for these plant
 
conditions. These events are assumed to occur during
 
startup and power operation; therefore, the scram function
 
of the control rods is required during these MODES. In
 
MODES 3 and 4, the control rods are not able to be withdrawn
 
since the reactor mode switch is in shutdown and a control
 
rod block is applied. This provides adequate requirements
 
for control rod scram capability during these conditions.
 
Scram requirements in MODE 5 are contained in LCO 3.9.5, "Control Rod OPERABILITY-Refueling."
ACTIONS A.1 When the requirements of this LCO are not met, the rate of
 
negative reactivity insertion during a scram may not be
 
within the assumptions of the safety analyses. Therefore, the plant must be brought to a MODE in which the LCO does
 
not apply. To achieve this status, the plant must be
 
brought to MODE 3 within 12 hours. The allowed Completion
 
Time of 12 hours is reasonable, based on operating
 
experience, to reach MODE 3 from full power conditions in an
 
orderly manner and without challenging plant systems.
 
(continued)
Control Rod Scram Times B 3.1.4 LaSalle 1 and 2 B 3.1.4-4 Revision 0 BASES  (continued)
 
SURVEILLANCE The four SRs of this LCO are modified by a Note stating that REQUIREMENTS during a single control rod scram time surveillance, the CRD pumps shall be isolated from the associated scram
 
accumulator. With the CRD pump isolated (i.e., charging
 
valve closed), the influence of the CRD pump head does not
 
affect the single control rod scram times. During a full
 
core scram, the CRD pump head would be seen by all control
 
rods and would have a negligible effect on the scram
 
insertion times.
 
SR  3.1.4.1
 
The scram reactivity used in DBA and transient analyses is
 
based on assumed control rod scram time. Measurement of the
 
scram times with reactor steam dome pressure  800 psig demonstrates acceptable scram times for the transients
 
analyzed in References 5 and 6.
 
Maximum scram insertion times occur at a reactor pressure of
 
approximately 800 psig because of the competing effects of
 
reactor steam dome pressure and stored accumulator energy.
 
Therefore, demonstration of adequate scram times at reactor
 
steam dome pressure  800 psig ensures that the scram times will be within the specified limits at higher pressures.
 
Limits are specified as a function of reactor pressure to
 
account for the sensitivity of the scram insertion times
 
with pressure and to allow a range of pressures over which
 
scram time testing can be performed. To ensure scram time
 
testing is performed within a reasonable time following a
 
shutdown  120 days, control rods are required to be tested before exceeding 40% RTP. This Frequency is acceptable, considering the additional Surveillances performed for
 
control rod OPERABILITY, the frequent verification of
 
adequate accumulator pressure, and the required testing of
 
control rods affected by fuel movement within the associated
 
core cell and by work on control rods or the CRD System.
 
SR  3.1.4.2
 
Additional testing of a sample of control rods is required
 
to verify the continued performance of the scram function
 
during the cycle. A representative sample contains at least
 
(continued)
Control Rod Scram Times B 3.1.4 LaSalle 1 and 2 B 3.1.4-5 Revision 0 BASES SURVEILLANCE SR  3.1.4.2 (continued)
REQUIREMENTS 10% of the control rods. The sample remains representative
 
if no more than 20% of the control rods in the sample tested
 
are determined to be "slow."  If more than 20% of the sample
 
is declared to be "slow" per the criteria in Table 3.1.4-1, additional control rods are tested until this 20% criterion (i.e., 20% of the entire sample size) is satisfied, or until
 
the total number of "slow" control rods (throughout the
 
core, from all Surveillances) exceeds the LCO limit. For
 
planned testing, the control rods selected for the sample
 
should be different for each test. Data from inadvertent
 
scrams should be used whenever possible to avoid unnecessary
 
testing at power, even if the control rods with data were
 
previously tested in a sample. The 120 day Frequency is
 
based on operating experience that has shown control rod
 
scram times do not significantly change over an operating
 
cycle. This Frequency is also reasonable, based on the
 
additional Surveillances done on the CRDs at more frequent
 
intervals in accordance with LCO 3.1.3 and LCO 3.1.5, "Control Rod Scram Accumulators."
 
SR  3.1.4.3
 
When work that could affect the scram insertion time is
 
performed on a control rod or the CRD System, testing must
 
be done to demonstrate that each affected control rod
 
retains adequate scram performance over the range of
 
applicable reactor pressures from zero to the maximum
 
permissible pressure. The scram testing must be performed
 
once before declaring the control rod OPERABLE. The
 
required scram time testing must demonstrate that the
 
affected control rod is still within acceptable limits. The
 
scram time limits for reactor pressures
< 800 psig are found in the Technical Requirements Manual (Ref. 7) and are
 
established based on a high probability of meeting the
 
acceptance criteria at reactor pressures  800 psig. Limits for reactor pressures  800 psig are found in Table 3.1.4-1.
If testing demonstrates the affected control rod does not
 
meet these limits, but is within 7-second limit of Table
 
3.1.4-1, Note 2, the control rod can be declared OPERABLE
 
and "slow."
(continued)
Control Rod Scram Times B 3.1.4 LaSalle 1 and 2 B 3.1.4-6 Revision 0 BASES SURVEILLANCE SR  3.1.4.3 (continued)
REQUIREMENTS Specific examples of work that could affect the scram times
 
include (but are not limited to) the following:  removal of
 
any CRD for maintenance or modification; replacement of a
 
control rod; and maintenance or modification of a scram
 
solenoid pilot valve, scram valve, accumulator isolation
 
valve, or check valves in the piping required for scram.
 
The Frequency of once prior to declaring the affected
 
control rod OPERABLE is acceptable because of the capability
 
of testing the control rod over a range of operating
 
conditions and the more frequent surveillances on other
 
aspects of control rod OPERABILITY.
 
SR  3.1.4.4
 
When work that could affect the scram insertion time is
 
performed on a control rod or CRD System, or when fuel
 
movement within the reactor pressure vessel occurs, testing
 
must be done to demonstrate each affected control rod is
 
still within the limits of Table 3.1.4-1 with the reactor
 
steam dome pressure  800 psig. Where work has been performed at high reactor pressure, the requirements of
 
SR 3.1.4.3 and SR 3.1.4.4 will be satisfied with one test.
 
For a control rod affected by work performed while shut
 
down, however, a zero pressure and a high pressure test may
 
be required. This testing ensures that the control rod
 
scram performance is acceptable for operating reactor
 
pressure conditions prior to withdrawing the control rod for
 
continued operation. Alternatively, a test during
 
hydrostatic pressure testing could also satisfy both
 
criteria. When fuel movement within the reactor pressure
 
vessel occurs, only those control rods associated with the
 
core cells affected by the fuel movement are required to be
 
scram time tested. During a routine refueling outage, it is
 
expected that all control rods will be affected.
 
The Frequency of once prior to exceeding 40% RTP is
 
acceptable because of the capability of testing the control
 
rod at the different conditions and the more frequent
 
surveillances on other aspects of control rod OPERABILITY.
 
(continued)
Control Rod Scram Times B 3.1.4 LaSalle 1 and 2 B 3.1.4-7 Revision 0 BASES  (continued)
 
REFERENCES 1. 10 CFR 50, Appendix A, GDC 10.
: 2. UFSAR, Section 4.3.2.5.
: 3. UFSAR, Section 4.6.1.1.2.
: 4. UFSAR, Section 5.2.2.
: 5. UFSAR, Section 15.4.
: 6. UFSAR, Section 15.4.9.
: 7. Technical Requirements Manual.
 
Control Rod Scram Accumulators B 3.1.5 LaSalle 1 and 2 B 3.1.5-1 Revision 0 B 3.1  REACTIVITY CONTROL SYSTEMS
 
B 3.1.5  Control Rod Scram Accumulators
 
BASES
 
BACKGROUND The control rod scram accumulators are part of the Control Rod Drive (CRD) System and are provided to ensure that the
 
control rods scram under varying reactor conditions. The
 
control rod scram accumulators store sufficient energy to
 
fully insert a control rod at any reactor vessel pressure. 
 
The accumulator is a hydraulic cylinder with a free floating
 
piston. The piston separates the water used to scram the
 
control rods from the nitrogen, which provides the required
 
energy. The scram accumulators are necessary to scram the
 
control rods within the required insertion times of
 
LCO 3.1.4, "Control Rod Scram Times."
APPLICABLE The analytical methods and assumptions used in evaluating SAFETY ANALYSES the control rod scram function are presented in References 1, 2, 3, and 4. The Design Basis Accident (DBA)
 
and transient analyses assume that all of the control rods
 
scram at a specified insertion rate. OPERABILITY of each
 
individual control rod scram accumulator, along with
 
LCO 3.1.3, "Control Rod OPERABILITY," and LCO 3.1.4, ensures
 
that the scram reactivity assumed in the DBA and transient
 
analyses can be met. The existence of an inoperable
 
accumulator may invalidate prior scram time measurements for
 
the associated control rod.
The scram function of the CRD System, and, therefore, the
 
OPERABILITY of the accumulators, protects the MCPR Safety
 
Limit (see Bases for SL 2.1.1, "Reactor Core SLs," and
 
LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)") and the 1%
 
cladding plastic strain fuel design limit (see Bases for
 
LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)," and LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)"), which ensure that no fuel damage will occur if
 
these limits are not exceeded (see Bases for LCO 3.1.4). 
 
Also, the scram function at low reactor vessel pressure (i.e., startup conditions) provides protection against
 
violating fuel design limits during reactivity insertion
 
accidents (see Bases for LCO 3.1.6, "Rod Pattern Control").
 
(continued)
Control Rod Scram Accumulators B 3.1.5 LaSalle 1 and 2 B 3.1.5-2 Revision 0 BASES APPLICABLE Control rod scram accumulators satisfy Criterion 3 of SAFETY ANALYSES 10 CFR 50.36(c)(2)(ii).
 
  (continued)
 
LCO The OPERABILITY of the control rod scram accumulators is required to ensure that adequate scram insertion capability
 
exists when needed over the entire range of reactor
 
pressures. The OPERABILITY of the scram accumulators is
 
based on maintaining adequate accumulator pressure.
 
APPLICABILITY In MODES 1 and 2, the scram function is required for mitigation of DBAs and transients and, therefore, the scram
 
accumulators must be OPERABLE to support the scram function.
 
In MODES 3 and 4, control rods are not able to be withdrawn
 
since the reactor mode switch is in shutdown and a control
 
rod block is applied. This provides adequate requirements
 
for control rod scram accumulator OPERABILITY under these
 
conditions. Requirements for scram accumulators in MODE 5
 
are contained in LCO 3.9.5, "Control Rod OPERABILITY-
 
Refueling."
ACTIONS The ACTIONS Table is modified by a Note indicating that a separate Condition entry is allowed for each control rod
 
scram accumulator. This is acceptable since the Required
 
Actions for each Condition provide appropriate compensatory
 
action for each inoperable accumulator. Complying with the
 
Required Actions may allow for continued operation and
 
subsequent inoperable accumulators governed by subsequent
 
Condition entry and application of associated Required
 
Actions.
A.1 and A.2
 
With one control rod scram accumulator inoperable and the
 
reactor steam dome pressure  900 psig, the control rod may be declared "slow," since the control rod will still scram
 
at the reactor operating pressure but may not satisfy the
 
required  scram times in Table 3.1.4-1. Required Action A.1
 
is modified  by a Note, which clarifies that declaring the
 
control rod "slow" is only applicable if the associated
 
(continued)
Control Rod Scram Accumulators B 3.1.5 LaSalle 1 and 2 B 3.1.5-3 Revision 0 BASES ACTIONS A.1 and A.2 (continued) control rod scram time was within the limits of
 
Table 3.1.4-1 during the last scram time Surveillance. 
 
Otherwise, the control rod may already be considered "slow" and the further degradation of scram performance with an
 
inoperable accumulator could result in excessive scram
 
times. In this event, the associated control rod is
 
declared inoperable (Required Action A.2) and LCO 3.1.3
 
entered. This would result in requiring the affected
 
control rod to be fully inserted and disarmed, thereby
 
satisfying its intended function in accordance with ACTIONS
 
of LCO 3.1.3.
 
The allowed Completion Time of 8 hours is considered
 
reasonable, based on the large number of control rods
 
available to provide the scram function and the ability of
 
the affected control rod to scram only with reactor pressure
 
at high reactor pressures.
 
B.1, B.2.1, and B.2.2
 
With two or more control rod scram accumulators inoperable
 
and reactor steam dome pressure  900 psig, adequate pressure must be supplied to the charging water header. 
 
With inadequate charging water pressure, all of the
 
accumulators could become inoperable, resulting in a
 
potentially severe degradation of the scram performance. 
 
Therefore, within 20 minutes from discovery of charging
 
water header pressure
< 940 psig concurrent with Condition B, adequate charging water header pressure must be
 
restored. The allowed Completion Time of 20 minutes is
 
considered a reasonable time to place a CRD pump into
 
service to restore the charging header pressure, if
 
required. This Completion Time also recognizes the ability
 
of the reactor pressure alone to fully insert all control
 
rods.
 
The control rod may be declared "slow," since the control
 
rod will still scram using only reactor pressure, but may
 
not satisfy the times in Table 3.1.4-1. Required
 
Action B.2.1 is modified by a Note indicating that declaring
 
the control rod "slow" is only applicable if the associated
 
  (continued)
Control Rod Scram Accumulators B 3.1.5 LaSalle 1 and 2 B 3.1.5-4 Revision 0 BASES ACTIONS B.1, B.2.1, and B.2.2 (continued) control rod scram time was within the limits of
 
Table 3.1.4-1 during the last scram time Surveillance. 
 
Otherwise, the control rod may already be considered "slow" and the further degradation of scram performance with an
 
inoperable accumulator could result in excessive scram
 
times. In this event, the associated control rod is
 
declared inoperable (Required Action B.2.2) and LCO 3.1.3
 
entered. This would result in requiring the affected
 
control rod to be fully inserted and disarmed, thereby
 
satisfying its intended function in accordance with ACTIONS
 
of LCO 3.1.3.
 
The allowed Completion Time of 1 hour is considered
 
reasonable, based on the ability of only the reactor
 
pressure to scram the control rods and the low probability
 
of a DBA or transient occurring while the affected
 
accumulators are inoperable.
 
C.1 and C.2
 
With one or more control rod scram accumulators inoperable
 
and the reactor steam dome pressure
< 900 psig, the pressure supplied to the charging water header must be adequate to
 
ensure that accumulators remain charged. With the reactor
 
steam dome pressure
< 900 psig, the function of the accumulators in providing the scram force becomes much more
 
important since the scram function could become severely
 
degraded during a depressurization event or at low reactor
 
pressures. Therefore, immediately upon discovery of
 
charging water header pressure
< 940 psig, concurrent with Condition C, all control rods associated with inoperable
 
accumulators must be verified to be fully inserted. 
 
Withdrawn control rods with inoperable scram accumulators
 
may fail to scram under these low pressure conditions. The
 
associated control rods must also be declared inoperable
 
within 1 hour. The allowed Completion Time of 1 hour is
 
reasonable for Required Action C.2, considering the low
 
probability of a DBA or transient occurring during the time
 
the accumulator is inoperable.
 
(continued)
Control Rod Scram Accumulators B 3.1.5 LaSalle 1 and 2 B 3.1.5-5 Revision 0 BASES ACTIONS D.1 (continued)
The reactor mode switch must be immediately placed in the
 
shutdown position if either Required Action and associated
 
Completion Time associated with loss of the CRD pump (Required Actions B.1 and C.1) cannot be met. This ensures
 
that all insertable control rods are inserted and that the
 
reactor is in a condition that does not require the active
 
function (i.e., scram) of the control rods. This Required
 
Action is modified by a Note stating that the Required
 
Action is not applicable if all control rods associated with
 
the inoperable scram accumulators are fully inserted, since
 
the function of the control rods has been performed.
 
SURVEILLANCE SR  3.1.5.1 REQUIREMENTS SR 3.1.5.1 requires that the accumulator pressure be checked
 
every 7 days to ensure adequate accumulator pressure exists
 
to provide sufficient scram force. The primary indicator of
 
accumulator OPERABILITY is the accumulator pressure. A
 
minimum accumulator pressure is specified, below which the
 
capability of the accumulator to perform its intended
 
function becomes degraded and the accumulator is considered
 
inoperable. The minimum accumulator pressure of 940 psig is
 
well below the expected pressure of 980 psig to 1200 psig. 
 
Declaring the accumulator inoperable when the minimum
 
pressure is not maintained ensures that significant
 
degradation in scram times does not occur. The 7 day
 
Frequency has been shown to be acceptable through operating
 
experience and takes into account indications available in
 
the control room.
 
REFERENCES 1. UFSAR, Section 4.3.2.5.3.
: 2. UFSAR, Section 4.6.1.1.2.
: 3. UFSAR, Section 5.2.2.2.2.3.
: 4. UFSAR, Section 15.4.
 
Rod Pattern Control B 3.1.6 LaSalle 1 and 2 B 3.1.6-1 Revision 0 B 3.1  REACTIVITY CONTROL SYSTEMS
 
B 3.1.6  Rod Pattern Control
 
BASES
 
BACKGROUND Control rod patterns during startup conditions are controlled by the operator and the Rod Worth Minimizer (RWM)
(LCO 3.3.2.1, "Control Rod Block Instrumentation"), so that
 
only specified control rod sequences and relative positions
 
are allowed over the operating range of all control rods
 
inserted to 10% RTP. The sequences effectively limit the
 
potential amount of reactivity addition that could occur in
 
the event of a control rod drop accident (CRDA).
This Specification assures that the control rod patterns are
 
consistent with the assumptions of the CRDA analyses of
 
References 1, 2, and 3.
 
APPLICABLE The analytical methods and assumptions used in evaluating SAFETY ANALYSES the CRDA are summarized in References 1, 2, 3, 4, and 5.
CRDA analyses assume that the reactor operator follows
 
prescribed withdrawal sequences. These sequences define the
 
potential initial conditions for the CRDA analysis. The RWM (LCO 3.3.2.1) provides backup to operator control of the
 
withdrawal sequences to ensure that the initial conditions
 
of the CRDA analysis are not violated.
Prevention or mitigation of positive reactivity insertion
 
events is necessary to limit the energy deposition in the
 
fuel, thereby preventing significant fuel damage, which
 
could result in undue release of radioactivity. Since the
 
failure consequences for UO 2 have been shown to be insignificant below fuel energy depositions of 300 cal/gm (Ref. 6), the fuel design limit of 280 cal/gm provides a
 
margin of safety from significant core damage, which would
 
result in release of radioactivity (Ref. 7). Generic
 
evaluations (Refs. 8 and 9) of a design basis CRDA (i.e., a
 
CRDA resulting in a peak fuel energy deposition of
 
280 cal/gm) have shown that if the peak fuel enthalpy
 
remains below 280 cal/gm, then the maximum reactor pressure
 
will be less than the required ASME Code limits (Ref. 10)
 
and the calculated offsite doses will be well within the (continued)
Rod Pattern Control B 3.1.6 LaSalle 1 and 2 B 3.1.6-2 Revision 17 BASES APPLICABLE required limits (Ref. 11). Cycle-specific CRDA analyses are SAFETY ANALYSES performed that assume eight inoperable control rods with at (continued) least two cell separation and confirm the fuel energy deposition is less that 280 cal/gm.
Control rod patterns analyzed in the cycle specific analyses
 
follow predetermined sequencing rules (analyzed rod position
 
sequence). The analyzed rod position sequence is applicable
 
from the condition of all control rods fully inserted to
 
10% RTP (Ref. 5). The control rods are required to be moved
 
in groups, with all control rods assigned to a specific
 
group required to be within specified banked positions (e.g., between notches 08 and 12). The banked positions are
 
defined to minimize the maximum incremental control rod
 
worths without being overly restrictive during normal plant
 
operation. Cycle specific analyses ensure that the 280
 
cal/gm fuel design limit will not be violated during a CRDA
 
under worst case scenarios. The cycle specific analyses (Refs. 1, 2, 3, 4, and 5) also evaluate the effect of fully
 
inserted, inoperable control rods not in compliance with the
 
sequence, to allow a limited number (i.e., eight) and
 
distribution of fully inserted, inoperable control rods.
 
Specific analyses may also be performed for atypical
 
operating conditions (e.g., fuel leaker suppression).
 
When performing a shutdown of the plant, an optional rod position sequence (Ref. 13) may be used provided that all withdrawn control rods have been confirmed to be coupled.
The rods may be inserted without the need to stop at intermediate positions since the possibility of a CRDA is eliminated by the confirmation that withdrawn control rods are coupled. When using the optional (Ref. 13) control rod sequence for shutdown, the rod worth minimizer may be reprogrammed to enforce the requirements of the improved control rod insertion process.
In order to use the Reference 13 shutdown process, an extra check is required in order to consider a control rod to be "confirmed" to be coupled. This extra check ensures that no single operator error can result in an incorrect coupling check. For purposes of this shutdown process, the method for confirming that control rods are coupled varies depending on the position of the control rod in the core.
Details on this coupling confirmation requirement are provided in Reference 13. 
  (continued)
Rod Pattern Control B 3.1.6 LaSalle 1 and 2 B 3.1.6-3 Revision 17 BASES APPLICABLE The plant is in compliance with the rod position sequence SAFETY ANALYSES required by this LCO when the requirements of Reference 13    (continued) are met.
Rod pattern control satisfies the requirements of Criterion 3 of 10 CFR 50.36(c)(2)(ii).
 
LCO Compliance with the prescribed control rod sequences minimizes the potential consequences of a CRDA by limiting
 
the initial conditions to those consistent with the analyzed
 
rod position sequence. This LCO only applies to OPERABLE
 
control rods. For inoperable control rods required to be
 
inserted, separate requirements are specified in LCO 3.1.3, "Control Rod OPERABILITY," consistent with the allowances
 
for inoperable control rods in the analyzed rod position
 
sequence.
 
APPLICABILITY In MODES 1 and 2, when THERMAL POWER is  10% RTP, the CRDA is a Design Basis Accident (DBA) and, therefore, compliance
 
with the assumptions of the safety analysis is required. 
 
When THERMAL POWER is
> 10% RTP, there is no credible control rod configuration that results in a control rod
 
worth that could exceed the 280 cal/gm fuel design limit
 
during a CRDA (Ref. 4 and 5). In MODES 3 and 4, the reactor
 
is shutdown and the control rods are not able to be
 
withdrawn since the reactor mode switch is in shutdown and a
 
control rod block is applied, therefore a CRDA is not
 
postulated to occur. In MODE 5, since the reactor is shut
 
down and only a single control rod can be withdrawn from a
 
core cell containing fuel assemblies, adequate SDM ensures
 
that the consequences of a CRDA are acceptable, since the
 
reactor will remain subcritical with a single control rod
 
withdrawn.
 
ACTIONS A.1 and A.2 With one or more OPERABLE control rods not in compliance
 
with the prescribed control rod sequence, action may be
 
taken to either correct the control rod pattern or declare
 
the associated control rods inoperable within 8 hours. 
 
Noncompliance with the prescribed sequence may be the result
 
of "double notching," drifting from a control rod drive 
 
Rod Pattern Control B 3.1.6 LaSalle 1 and 2 B 3.1.6-4 Revision 17 (continued)
BASES    ACTIONS  A.1 and A.2 (continued) cooling water transient, leaking scram valves, or a power 
 
reduction to  10% RTP before establishing the correct  control rod pattern. The number of OPERABLE control rods not in compliance with the prescribed sequence is limited to
 
eight to prevent the operator from attempting to correct a  control rod pattern that significantly deviates from the prescribed sequence.
 
Required Action A.1 is modified by a Note, which allows the RWM to be bypassed to allow the affected control rods to be
 
returned to their correct position. LCO 3.3.2.1 requires
 
verification of control rod movement by a second licensed
 
operator (Reactor Operator or Senior Reactor Operator) or by
 
a task qualified member of the technical staff (e.g., a
 
shift technical advisor or reactor engineer). This helps to
 
ensure that the control rods will be moved to the correct
 
position. A control rod not in compliance with the
 
prescribed sequence is not considered inoperable except as
 
required by Required Action A.2. The allowed Completion
 
Time of 8 hours is reasonable, considering the restrictions
 
on the number of allowed out of sequence control rods and
 
the low probability of a CRDA occurring during the time the
 
control rods are out of sequence.
B.1 and B.2
 
If nine or more OPERABLE control rods are out of sequence, the control rod pattern significantly deviates from the
 
prescribed sequence. Control rod withdrawal should be
 
suspended immediately to prevent the potential for further
 
deviation from the prescribed sequence. Control rod
 
insertion to correct control rods withdrawn beyond their
 
allowed position is allowed since, in general, insertion of
 
control rods has less impact on control rod worth than
 
withdrawals have. Required Action B.1 is modified by a Note
 
that allows the RWM to be bypassed to allow the affected
 
control rods to be returned to their correct position. 
 
LCO 3.3.2.1 requires verification of control rod movement by
 
a second licensed operator (Reactor Operator or Senior
 
Reactor Operator) or by a task qualified member of the
 
technical staff (e.g., a shift technical advisor or reactor
 
engineer).
 
Rod Pattern Control B 3.1.6 LaSalle 1 and 2 B 3.1.6-5 Revision 17 (continued)
BASES ACTIONS  B.1 and B.2 (continued) 
 
With nine or more OPERABLE control rods not in compliance
 
with analyzed rod position sequence, the reactor mode switch 
 
must be placed in the shutdown position within 1 hour. With
 
the reactor mode switch in shutdown, the reactor is shut
 
down, and therefore does not meet the applicability 
 
requirements of this LCO. The allowed Completion Time of
 
1 hour is reasonable to allow insertion of control rods to
 
restore compliance, and is appropriate relative to the low
 
probability of a CRDA occurring with the control rods out of
 
sequence.
 
SURVEILLANCE SR  3.1.6.1 REQUIREMENTS The control rod pattern is verified to be in compliance with
 
the analyzed rod position sequence at a 24 hour Frequency, ensuring the assumptions of the CRDA analyses are met. The
 
24 hour Frequency of this Surveillance was developed
 
considering that the primary check of the control rod
 
pattern compliance with the analyzed rod position sequence
 
is performed by the RWM (LCO 3.3.2.1). The RWM provides
 
control rod blocks to enforce the required control rod
 
sequence and is required to be OPERABLE when operating at 10% RTP.
 
REFERENCES 1. UFSAR, Section 15.4.10.
: 2. XN-NF-80-19(P)(A), Volume 1, Supplement 2, Section 7.1, Exxon Nuclear Methodology for Boiling Water
 
Reactor-Neutronics Methods for Design and Analysis, (as specified in Technical Specification 5.6.5).
: 3. NEDE-24011-P-A, "GE Standard Application for Reactor Fuel," (as specified in Technical Specification
 
5.6.5). 
: 4. Letter from T.A. Pickens (BWROG) to G.C. Lainas (NRC), "Amendment 17 to General Electric Licensing Topical
 
Report NEDE-24011-P-A," BWROG-8644, August 15, 1986.
: 5. NFSR-0091, Benchmark of CASMO/MICROBURN BWR Nuclear Design Methods, Commonwealth Edison Topical Report, Rod Pattern Control B 3.1.6 LaSalle 1 and 2 B 3.1.6-6 Revision 17 (as specified in Technical Specification 5.6.5). (continued)
Rod Pattern Control B 3.1.6 LaSalle 1 and 2 B 3.1.6-7 Revision 17 BASES 
 
REFERENCES  6. NUREG-0979, "NRC Safety Evaluation Report for GESSAR II (continued)  BWR/6 Nuclear Island Design, Docket No. 50-447,"
Section 4.2.1.3.2, April 1983.
: 7. NUREG-0800, "Standard Review Plan," Section 15.4.9, "Radiological Consequences of Control Rod Drop
 
Accident (BWR)," Revision 2, July 1981.
: 8. NEDO-21778-A, "Transient Pressure Rises Affected Fracture Toughness Requirements for Boiling Water
 
Reactors," December 1978.
: 9. NEDO-10527, "Rod Drop Accident Analysis for Large BWRs," (including Supplements 1 and 2), March 1972.
: 10. ASME, Boiler and Pressure Vessel Code.
: 11. 10 CFR 100.11, "Determination of Exclusion Area Low Population Zone and Population Center Distance." 
: 12. NEDO-21231, "Banked Position Withdrawal Sequence," January 1977.
: 13. NEDO-33091-A, Revision 2, "Improved BPWS Control Rod Insertion Process," July 2004.
 
SLC System B 3.1.7 LaSalle 1 and 2 B 3.1.7-1 Revision 0 B 3.1  REACTIVITY CONTROL SYSTEMS
 
B 3.1.7  Standby Liquid Control (SLC) System
 
BASES
 
BACKGROUND The SLC System is designed to provide the capability of bringing the reactor, at any time in a fuel cycle, from full
 
power and minimum control rod inventory (which is at the
 
peak of the xenon transient) to a subcritical condition with
 
the reactor in the most reactive xenon free state without
 
taking credit for control rod movement. The SLC System
 
satisfies the requirements of 10 CFR 50.62 (Ref. 1) on
 
anticipated transient without scram (ATWS).
The SLC System consists of a boron solution storage tank, two positive displacement pumps, two explosive valves, which
 
are provided in parallel for redundancy, and associated
 
piping and valves used to transfer borated water from the
 
storage tank to the reactor pressure vessel (RPV). The
 
borated solution is discharged near the bottom of the core
 
shroud, where it then mixes with the cooling water rising
 
through the core.
 
APPLICABLE The SLC System is manually initiated from the main control SAFETY ANALYSES room, as directed by the emergency operating procedures, if the operator determines the reactor cannot be shut down, or
 
kept shut down, with the control rods. The SLC System is
 
used in the event that not enough control rods can be
 
inserted to accomplish shutdown and cooldown in the normal
 
manner. The SLC System injects borated water into the
 
reactor core to compensate for all of the various reactivity
 
effects that could occur during plant operation. To meet
 
this objective, it is necessary to inject a quantity of
 
boron that produces a reactivity change equivalent to a
 
concentration of 660 ppm of enriched boron in the reactor
 
core at 68
&deg;F. To ensure this objective is met, a sodium pentaborate solution enriched with boron-10 is used. The
 
shutdown analysis assumes a sodium pentaborate solution with
 
enriched boron is used (Ref. 2). A 45% enriched sodium
 
pentaborate solution is also used to satisfy the
 
requirements of Reference 1. To allow for potential leakage
 
and imperfect mixing in the reactor system, an additional
 
amount of boron equal to 25% of the amount cited above is
 
added (Ref. 2). An additional 250 ppm is provided to (continued)
SLC System B 3.1.7 LaSalle 1 and 2 B 3.1.7-2 Revision 0 BASES APPLICABLE accommodate dilution in the RPV by the residual heat removal SAFETY ANALYSES shutdown cooling piping. The volume versus concentration (continued) limits in Figure 3.1.7-1 are calculated such that the required concentration is achieved. This quantity of
 
borated solution is the amount that is above the pump
 
suction shutoff level in the boron solution storage tank. 
 
No credit is taken for the portion of the tank volume that
 
cannot be injected.
 
The SLC System satisfies Criterion 4 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO The OPERABILITY of the SLC System provides backup capability for reactivity control, independent of normal reactivity
 
control provisions provided by the control rods. The
 
OPERABILITY of the SLC System is based on the conditions of
 
the borated solution in the storage tank and the
 
availability of a flow path to the RPV, including the
 
OPERABILITY of the pumps and valves. Two SLC subsystems are
 
required to be OPERABLE, each containing an OPERABLE pump, an explosive valve and associated piping, valves, and
 
instruments and controls to ensure an OPERABLE flow path.
 
APPLICABILITY In MODES 1 and 2, shutdown capability is required. In MODES 3 and 4, control rods are not able to be withdrawn
 
since the reactor mode switch is in shutdown and a control
 
rod block is applied. This provides adequate controls to
 
ensure the reactor remains subcritical. In MODE 5, only a
 
single control rod can be withdrawn from a core cell
 
containing fuel assemblies. Demonstration of adequate SDM (LCO 3.1.1, "SHUTDOWN MARGIN (SDM)") ensures that the
 
reactor will not become critical. Therefore, the SLC System
 
is not required to be OPERABLE during these conditions, when
 
only a single control rod can be withdrawn.
 
ACTIONS A.1 If one SLC System subsystem is inoperable, the inoperable
 
subsystem must be restored to OPERABLE status within 7 days.
 
In this condition, the remaining OPERABLE subsystem is
 
adequate to perform the shutdown function. However, the
 
overall reliability is reduced because a single failure in
 
(continued)
SLC System B 3.1.7 LaSalle 1 and 2 B 3.1.7-3 Revision 0 BASES ACTIONS A.1 (continued) the remaining OPERABLE subsystem could result in reduced SLC
 
System shutdown capability and inability to meet the
 
requirements of Reference 1. The 7 day Completion Time is
 
based on the availability of an OPERABLE subsystem capable
 
of performing the unit shutdown function and the low
 
probability of a Design Basis Accident (DBA) or severe
 
transient occurring concurrent with the failure of the
 
Control Rod Drive System to shut down the reactor. 
 
B.1 If both SLC subsystems are inoperable, at least one
 
subsystem must be restored to OPERABLE status within
 
8 hours. The allowed Completion Time of 8 hours is
 
considered acceptable, given the low probability of a DBA or
 
transient occurring concurrent with the failure of the
 
control rods to shut down the reactor.
 
C.1 If any Required Action and associated Completion Time is not
 
met, the plant must be brought to a MODE in which the LCO
 
does not apply. To achieve this status, the plant must be
 
brought to MODE 3 within 12 hours. The allowed Completion
 
Time of 12 hours is reasonable, based on operating
 
experience, to reach MODE 3 from full power conditions in an
 
orderly manner and without challenging plant systems.
 
SURVEILLANCE SR  3.1.7.1, SR  3.1.7.2, and SR  3.1.7.3 REQUIREMENTS SR 3.1.7.1 through SR 3.1.7.3 are 24 hour Surveillances, verifying certain characteristics of the SLC System (e.g.,
the volume and temperature of the borated solution in the
 
storage tank), thereby ensuring the SLC System OPERABILITY
 
without disturbing normal plant operation. These
 
Surveillances ensure the proper borated solution and
 
temperature, including the temperature (using the local
 
indicator) of the pump suction piping up to the storage tank
 
outlet valves, are maintained. Maintaining a minimum
 
specified borated solution temperature is important in
 
(continued)
SLC System B 3.1.7 LaSalle 1 and 2 B 3.1.7-4 Revision 0 BASES SURVEILLANCE SR  3.1.7.1, SR  3.1.7.2, and SR  3.1.7.3 (continued)
REQUIREMENTS ensuring that the boron remains in solution and does not
 
precipitate out in the storage tank or in the pump suction
 
piping. The 24 hour Frequency of these SRs is based on
 
operating experience that has shown there are relatively
 
slow variations in the measured parameters of volume and
 
temperature.
 
SR  3.1.7.4 and SR  3.1.7.6
 
SR 3.1.7.4 verifies the continuity of the explosive charges
 
in the injection valves to ensure proper operation will
 
occur if required. Other administrative controls, such as
 
those that limit the shelf life of the explosive charges, must be followed. The 31 day Frequency is based on
 
operating experience that has demonstrated the reliability
 
of the explosive charge continuity.
 
SR 3.1.7.6 verifies each valve in the system is in its
 
correct position, but does not apply to the squib (i.e.,
explosive) valves. Verifying the correct alignment for
 
manual, power operated, and automatic valves in the SLC
 
System flow path ensures that the proper flow paths will
 
exist for system operation. A valve is also allowed to be
 
in the nonaccident position, provided it can be aligned to
 
the accident position from the control room, or locally by a
 
dedicated operator at the valve control. This is acceptable
 
since the SLC System is a manually initiated system. This
 
Surveillance does not apply to valves that are locked, sealed, or otherwise secured in position, since they were
 
verified to be in the correct position prior to locking, sealing, or securing. This verification of valve alignment
 
does not apply to valves that cannot be inadvertently
 
misaligned, such as check valves. This SR does not require
 
any testing or valve manipulation; rather, it involves
 
verification that those valves capable of being
 
mispositioned are in the correct positions. The 31 day
 
Frequency is based on engineering judgment and is consistent
 
with the procedural controls governing valve operation that
 
ensure correct valve positions.
 
(continued)
SLC System B 3.1.7 LaSalle 1 and 2 B 3.1.7-5 Revision 0 BASES SURVEILLANCE SR  3.1.7.5 REQUIREMENTS (continued) This Surveillance requires an examination of the sodium pentaborate solution by using chemical analysis to ensure
 
the proper concentration of sodium pentaborate exists in the
 
storage tank. SR 3.1.7.5 must be performed anytime boron or
 
water is added to the storage tank solution to establish
 
that the sodium pentaborate solution concentration is within
 
the specified limits. This Surveillance must be performed
 
anytime the temperature is restored to within the limits of
 
Figure 3.1.7-1, to ensure no significant boron precipitation
 
occurred. The 31 day Frequency of this Surveillance is
 
appropriate because of the relatively slow variation of
 
sodium pentaborate concentration between surveillances.
 
SR  3.1.7.7
 
Demonstrating each SLC System pump develops a flow rate 41.2 gpm at a discharge pressure  1220 psig ensures that pump performance has not degraded during the fuel cycle.
 
This minimum pump flow rate requirement ensures that, when
 
combined with the sodium pentaborate solution concentration
 
requirements, the rate of negative reactivity insertion from
 
the SLC System will adequately compensate for the positive
 
reactivity effects encountered during power reduction, cooldown of the moderator, and xenon decay. This test 
 
confirms one point on the pump design curve, and is
 
indicative of overall performance. Such inservice tests
 
confirm component OPERABILITY and detect incipient failures
 
by indicating abnormal performance. The Frequency of this
 
Surveillance is in accordance with the Inservice Testing
 
Program.
 
SR  3.1.7.8 and SR  3.1.7.9
 
These Surveillances ensure that there is a functioning flow
 
path from the boron solution storage tank to the RPV, including the firing of an explosive valve. The replacement
 
charge for the explosive valve shall be from the same
 
manufactured batch as the one fired or from another batch
 
that has been certified by having one of that batch
 
successfully fired. The pump and explosive valve tested (continued)
SLC System B 3.1.7 LaSalle 1 and 2 B 3.1.7-6 Revision 0 BASES SURVEILLANCE SR  3.1.7.8 and SR  3.1.7.9 (continued)
REQUIREMENTS should be alternated such that both complete flow paths are
 
tested every 48 months, at alternating 24 month intervals.
 
The Surveillance may be performed in separate steps to
 
prevent injecting boron into the RPV. An acceptable method
 
for verifying flow from the pump to the RPV is to pump
 
demineralized water from a test tank through one SLC
 
subsystem and into the RPV. The 24 month Frequency is based
 
on the need to perform this Surveillance under the
 
conditions that apply during a plant outage and the
 
potential for an unplanned transient if the Surveillance
 
were performed with the reactor at power. Operating
 
experience has shown these components usually pass the
 
Surveillance test when performed at the 24 month Frequency;
 
therefore, the Frequency was concluded to be acceptable from
 
a reliability standpoint.
 
Demonstrating that all heat traced piping in the flow path
 
between the boron solution storage tank and the storage tank
 
outlet valves to the injection pumps is unblocked ensures
 
that there is a functioning flow path for injecting the
 
sodium pentaborate solution. An acceptable method for
 
verifying that the suction piping up to the storage tank
 
outlet valves is unblocked is to verify flow from the
 
storage tank to the test tank. Upon completion of this
 
verification, the pump suction piping between the storage
 
tank outlet valve and pump suction must be drained and
 
flushed with demineralized water, since the piping is not
 
heat traced. The 24 month Frequency is acceptable since
 
there is a low probability that the subject piping will be
 
blocked due to precipitation of the boron from solution in
 
the heat traced piping. This is especially true in light of
 
the daily temperature verification of this piping required
 
by SR 3.1.7.3. However, if, in performing SR 3.1.7.3, it is
 
determined that the temperature of this piping has fallen
 
below the specified minimum, SR 3.1.7.9 must be performed
 
once within 24 hours after the piping temperature is
 
restored within the limits of Figure 3.1.7-2.
 
REFERENCES 1. 10 CFR 50.62.
: 2. UFSAR, Section 9.3.5.3.
 
SDV Vent and Drain Valves B 3.1.8 LaSalle 1 and 2 B 3.1.8-1 Revision 0 B 3.1  REACTIVITY CONTROL SYSTEMS
 
B 3.1.8  Scram Discharge Volume (SDV) Vent and Drain Valves
 
BASES
 
BACKGROUND The SDV vent and drain valves are normally open and discharge any accumulated water in the SDV to ensure that
 
sufficient volume is available at all times to allow a
 
complete scram. During a scram, the SDV vent and drain
 
valves close to contain reactor water. The SDV consists of
 
header piping that connects to each hydraulic control unit (HCU) and drains into an instrument volume. There are two
 
headers and two instrument volumes, each receiving
 
approximately one half of the control rod drive (CRD)
 
discharges. The two instrument volumes are connected to a
 
common drain line with two valves in series. Each header is
 
connected to a common vent line with two valves in series.
 
The header piping is sized to receive and contain all the
 
water discharged by the CRDs during a scram. The design and
 
functions of the SDV are described in Reference 1.
 
APPLICABLE The Design Basis Accident and transient analyses assume all SAFETY ANALYSES the control rods are capable of scramming. The primary function of the SDV is to limit the amount of reactor
 
coolant discharged during a scram. The acceptance criteria
 
for the SDV vent and drain valves are that they operate
 
automatically to:
: a. Close during scram to limit the amount of reactor coolant discharged so that adequate core cooling is
 
maintained and offsite doses remain within the limits
 
of 10 CFR 100 (Ref. 2); and
: b. Open on scram reset to maintain the SDV vent and drain path open so there is sufficient volume to accept the
 
reactor coolant discharged during a scram.
 
Isolation of the SDV can also be accomplished by manual
 
closure of the SDV valves. Additionally, the discharge of
 
reactor coolant to the SDV can be terminated by scram reset
 
or closure of the HCU manual isolation valves. For a
 
bounding leakage case, the offsite doses are well within the
 
limits of 10 CFR 100 (Ref. 2) and adequate core cooling is
 
maintained (Ref. 3). The SDV vent and drain valves also (continued)
SDV Vent and Drain Valves B 3.1.8 LaSalle 1 and 2 B 3.1.8-2 Revision 0 BASES APPLICABLE allow continuous drainage of the SDV during normal plant SAFETY ANALYSES operation to ensure the SDV has sufficient capacity (continued) to contain the reactor coolant discharge during a full core scram. To automatically ensure this capacity, a reactor
 
scram (LCO 3.3.1.1, "Reactor Protection System (RPS)
 
Instrumentation") is initiated if the SDV water level
 
exceeds a specified setpoint. The setpoint is chosen such
 
that all control rods are inserted before the SDV has
 
insufficient volume to accept a full scram.
SDV vent and drain valves satisfy Criterion 3 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO The OPERABILITY of all SDV vent and drain valves ensures that, during a scram, the SDV vent and drain valves will
 
close to contain reactor water discharged to the SDV piping.
 
Since the vent and drain lines are provided with two valves
 
in series, the single failure of one valve in the open
 
position will not impair the isolation function of the
 
system. Additionally, the valves are required to be open to
 
ensure that a path is available for the SDV piping to drain
 
freely at other times.
 
APPLICABILITY In MODES 1 and 2, a scram may be required, and therefore, the SDV vent and drain valves must be OPERABLE. In MODES 3
 
and 4, control rods are not able to be withdrawn since the
 
reactor mode switch is in shutdown and a control rod block
 
is applied. Also, during MODE 5, only a single control rod
 
can be withdrawn from a core cell containing fuel
 
assemblies. Therefore, the SDV vent and drain valves are
 
not required to be OPERABLE in these MODES since the reactor
 
is subcritical and only one rod may be withdrawn and subject
 
to scram.
 
ACTIONS The ACTIONS Table is modified by a Note indicating that a separate Condition entry is allowed for each SDV vent and
 
drain line. This is acceptable, since the Required Actions
 
for each Condition provide appropriate compensatory actions
 
for each inoperable SDV line. Complying with the Required
 
Actions may allow for continued operation, and subsequent
 
inoperable SDV lines are governed by subsequent Condition
 
entry and application of associated Required Actions.
(continued)
SDV Vent and Drain Valves B 3.1.8 LaSalle 1 and 2 B 3.1.8-3 Revision 0 BASES ACTIONS The ACTIONS Table is modified by a second Note stating that (continued) an isolated line may be unisolated under administrative control to allow draining and venting of the SDV.
 
When a line is isolated, the potential for an inadvertent
 
scram due to high SDV level is increased. During these
 
periods, the line may be unisolated under administrative
 
control. This allows any accumulated water in the line to
 
be drained, to preclude a reactor scram on SDV high level.
 
This is acceptable, since the administrative controls ensure
 
the valve can be closed quickly, by a dedicated operator at
 
the valve controls, if a scram occurs with the valve open.
 
A.1 When one SDV vent or drain valve is inoperable in one or
 
more lines, the line must be isolated to contain the reactor
 
coolant during a scram. The 7 day Completion Time is
 
reasonable, given the level of redundancy in the lines and
 
the low probability of a scram occurring during the time the
 
valve(s) are inoperable and the line(s) not isolated. The
 
SDV is still isolable since the redundant valve in the
 
affected line is OPERABLE. During these periods, the single
 
failure criterion may not be preserved, and a higher risk
 
exists to allow reactor water out of the primary system
 
during a scram.
 
B.1 If both valves in a line are inoperable, the line must be
 
isolated to contain the reactor coolant during a scram. The
 
8 hour Completion Time to isolate the line is based on the
 
low probability of a scram occurring while the line is not
 
isolated and unlikelihood of significant CRD seal leakage.
 
C.1 If any Required Action and associated Completion Time is not
 
met, the plant must be brought to a MODE in which the LCO
 
does not apply. To achieve this status, the plant must be (continued)
SDV Vent and Drain Valves B 3.1.8 LaSalle 1 and 2 B 3.1.8-4 Revision 0 BASES ACTIONS C.1 (continued) brought to MODE 3 within 12 hours. The allowed Completion
 
Time of 12 hours is reasonable, based on operating
 
experience, to reach MODE 3 from full power conditions in an
 
orderly manner and without challenging plant systems.
 
SURVEILLANCE SR  3.1.8.1 REQUIREMENTS During normal operation, the SDV vent and drain valves
 
should be in the open position (except when performing
 
SR 3.1.8.2) to allow for drainage of the SDV piping.
 
Verifying that each valve is in the open position ensures
 
that the SDV vent and drain valves will perform their
 
intended function during normal operation. This SR does not
 
require any testing or valve manipulation; rather, it
 
involves verification that the valves are in the correct
 
position. The 31 day Frequency is based on engineering
 
judgment and is consistent with the procedural controls
 
governing valve operation, which ensure correct valve
 
positions. Improper valve position (closed) would not
 
affect the isolation function.
 
SR  3.1.8.2
 
During a scram, the SDV vent and drain valves should close
 
to contain the reactor water discharged to the SDV piping.
 
Cycling each valve through its complete range of motion (closed and open) ensures that the valve will function
 
properly during a scram. The 92 day Frequency is based on
 
operating experience and takes into account the level of
 
redundancy in the system design.
 
SR  3.1.8.3
 
SR 3.1.8.3 is an integrated test of the SDV vent and drain
 
valves to verify total system performance. After receipt of
 
a simulated or actual scram signal, the closure of the SDV
 
vent and drain valves is verified. The closure time of
 
30 seconds after a receipt of a scram signal is based on the
 
bounding leakage case evaluated in the accident analysis.
 
Similarly, after receipt of a simulated or actual scram
 
(continued)
SDV Vent and Drain Valves B 3.1.8 LaSalle 1 and 2 B 3.1.8-5 Revision 0 BASES SURVEILLANCE SR  3.1.8.3 (continued) reset signal, the opening of the SDV vent and drain valves
 
is verified. The LOGIC SYSTEM FUNCTIONAL TEST in
 
LCO 3.3.1.1 and the scram time testing of control rods in
 
LCO 3.1.3, "Control Rod OPERABILITY," overlap this
 
Surveillance to provide complete testing of the assumed
 
safety function. The 24 month Frequency is based on the
 
need to perform this Surveillance under the conditions that
 
apply during a plant outage and the potential for an
 
unplanned transient if the Surveillance were performed with
 
the reactor at power. Operating experience has shown these
 
components usually pass the Surveillance when performed at
 
the 24 month Frequency; therefore, the Frequency was
 
concluded to be acceptable from a reliability standpoint.
 
REFERENCES 1. UFSAR, Section 4.6.1.1.2.
: 2. 10 CFR 100.
: 3. NUREG-0803, "Generic Safety Evaluation Report Regarding Integrity of BWR Scram System Piping,"
August 1981.
 
APLHGR B 3.2.1 LaSalle 1 and 2 B 3.2.1-1 Revision 0 B 3.2  POWER DISTRIBUTION LIMITS
 
B 3.2.1  AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)
 
BASES
 
BACKGROUND The APLHGR is a measure of the average LHGR of all the fuel rods in a fuel assembly at any axial location. Limits on
 
the APLHGR are specified to ensure that criteria specified
 
in 10 CFR 50.46 are met during the postulated design basis
 
loss of coolant accident (LOCA). 
 
APPLICABLE The analytical methods and assumptions used in evaluating SAFETY ANALYSES Design Basis Accidents (DBAs) that determine APLHGR limits are presented in UFSAR, Chapters 4, 6, and 15, and in
 
References 1 and 2.
LOCA analyses are performed to ensure that the APLHGR limits
 
are adequate to meet the peak cladding temperature (PCT) and
 
maximum oxidation limits of 10 CFR 50.46. The analysis is
 
performed using calculational models that are consistent
 
with the requirements of 10 CFR 50, Appendix K. A complete
 
discussion of the analysis code is provided in References 1
 
and 2. The PCT following a postulated LOCA is a function of
 
the average heat generation rate of all the rods of a fuel
 
assembly at any axial location and is not strongly
 
influenced by the rod to rod power distribution within an
 
assembly. A conservative multiplier is applied to the LHGR
 
and APLHGR assumed in the LOCA analysis to account for the
 
uncertainty associated with the measurement of the APLHGR.
 
APLHGR limits are typically set high enough such that the
 
LHGR limits are more limiting than the APLHGR limits.
 
For single recirculation loop operation, a conservative
 
multiplier is applied to the exposure dependent APLHGR
 
limits for two loop operation. This additional limitation
 
is due to the conservative analysis assumption of an earlier
 
departure from nucleate boiling with one recirculation loop
 
available, resulting in a more severe cladding heatup during
 
a LOCA.
 
The APLHGR satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).
 
(continued)
APLHGR B 3.2.1 LaSalle 1 and 2 B 3.2.1-2 Revision 0 BASES  (continued)
 
LCO The APLHGR limits specified in the COLR are the result of the DBA analyses. For two recirculation loops operating, the limit is dependent on exposure. With only one
 
recirculation loop in operation, in conformance with the
 
requirements of LCO 3.4.1, "Recirculation Loops Operating,"
the limit is determined by multiplying the exposure
 
dependent APLHGR limit by a conservative multiplier
 
determined by a specific single recirculation loop analysis.
 
APPLICABILITY The APLHGR limits are derived from LOCA analyses that are assumed to occur at high power levels. Studies and
 
operating experience have shown that as power is reduced, the margin to the required APLHGR limits increases. This
 
trend continues down to the power range of 5% to 15% RTP
 
when entry into MODE 2 occurs. When in MODE 2, the
 
intermediate range monitor (IRM) scram function and the
 
average power range monitor (APRM) scram function provide
 
prompt scram initiation during any significant transient, thereby effectively removing any APLHGR limit compliance
 
concern in MODE 2. Therefore, at THERMAL POWER levels 25% RTP, the reactor operates with substantial margin to the APLHGR limits; thus, this LCO is not required.
 
ACTIONS A.1 If any APLHGR exceeds the required limits, an assumption
 
regarding an initial condition of the DBA analyses may not
 
be met. Therefore, prompt action is taken to restore the
 
APLHGR(s) to within the required limits such that the plant
 
will be operating within analyzed conditions and within the
 
design limits of the fuel rods. The 2 hour Completion Time
 
is sufficient to restore the APLHGR(s) to within its limits
 
and is acceptable based on the low probability of a DBA
 
occurring simultaneously with the APLHGR out of
 
specification.
(continued)
APLHGR B 3.2.1 LaSalle 1 and 2 B 3.2.1-3 Revision 0 BASES ACTIONS B.1 (continued)
If the APLHGR cannot be restored to within its required
 
limits within the associated Completion Time, the plant must
 
be brought to a MODE or other specified condition in which
 
the LCO does not apply. To achieve this status, THERMAL
 
POWER must be reduced to
< 25% RTP within 4 hours. The allowed Completion Time is reasonable, based on operating
 
experience, to reduce THERMAL POWER to
< 25% RTP in an orderly manner and without challenging plant systems.
 
SURVEILLANCE SR  3.2.1.1 REQUIREMENTS APLHGRs are required to be initially calculated within
 
12 hours after THERMAL POWER is  25% RTP and then every 24 hours thereafter. They are compared to the specified
 
limits in the COLR to ensure that the reactor is operating
 
within the assumptions of the safety analysis. The 24 hour
 
Frequency is based on both engineering judgment and
 
recognition of the slowness of changes in power distribution
 
under normal conditions. The 12 hour allowance after
 
THERMAL POWER  25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power
 
levels.
REFERENCES 1. NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel," (as specified in Technical
 
Specification 5.6.5).
: 2. EMF-94-217(NP), Revision 1, "Boiling Water Reactor Licensing Methodology Summary," November 1995.
 
MCPR B 3.2.2 LaSalle 1 and 2 B 3.2.2-1 Revision 0 B 3.2  POWER DISTRIBUTION LIMITS
 
B 3.2.2  MINIMUM CRITICAL POWER RATIO (MCPR)
 
BASES
 
BACKGROUND MCPR is a ratio of the fuel assembly power that would result in the onset of boiling transition to the actual fuel
 
assembly power. The MCPR Safety Limit (SL) is set such that
 
99.9% of the fuel rods are expected to avoid boiling
 
transition if the limit is not violated (refer to the Bases
 
for SL 2.1.1.2). The operating limit MCPR is established to
 
ensure that no fuel damage results during anticipated
 
operational occurrences (AOOs). Although fuel damage does
 
not necessarily occur if a fuel rod actually experiences
 
boiling transition (Ref. 1), the critical power at which
 
boiling transition is calculated to occur has been adopted
 
as a fuel design criterion.
The onset of transition boiling is a phenomenon that is
 
readily detected during the testing of various fuel bundle
 
designs. Based on these experimental data, correlations
 
have been developed to predict critical bundle power (i.e.,
the bundle power level at the onset of transition boiling)
 
for a given set of plant parameters (e.g., reactor vessel
 
pressure, flow, and subcooling). Because plant operating
 
conditions and bundle power levels are monitored and
 
determined relatively easily, monitoring the MCPR is a
 
convenient way of ensuring that fuel failures due to
 
inadequate cooling do not occur.
 
APPLICABLE The analytical methods and assumptions used in evaluating SAFETY ANALYSES the AOOs to establish the operating limit MCPR are presented in References 2, 3, 4, 5, 6, 7, 8, and 9. To ensure that
 
the MCPR SL is not exceeded during any transient event that
 
occurs with moderate frequency, limiting transients have
 
been analyzed to determine the largest reduction in critical
 
power ratio (CPR). The types of transients evaluated are
 
loss of flow, increase in pressure and power, positive
 
reactivity insertion, and coolant temperature decrease. The
 
limiting transient yields the largest change in CPR (CPR). When the largest CPR is added to the MCPR SL, the required operating limit MCPR is obtained.
(continued)
MCPR B 3.2.2 LaSalle 1 and 2 B 3.2.2-2 Revision 0 BASES APPLICABLE The MCPR operating limits derived from the transient SAFETY ANALYSES analysis are dependent on the operating core flow and power (continued) state (MCPR f and MCPR p , respectively) to ensure adherence to fuel design limits during the worst transient that occurs
 
with moderate frequency as identified in the UFSAR, Chapter
 
15 (Ref. 5).
Flow dependent MCPR limits are determined by steady state
 
thermal hydraulic methods with key physics response inputs
 
benchmarked using the three dimensional BWR simulator code (Ref. 8) and the multichannel thermal hydraulic code (Ref. 9) to analyze slow flow runout transients on a
 
cycle-specific basis. For core flows less than rated, the
 
established MCPR operating limit is adjusted to provide
 
protection of the MCPR SL in the event of an uncontrolled
 
recirculation flow increase to the physical limit of the
 
pump. Protection is provided for manual and automatic flow
 
control by applying appropriate flow dependent MCPR
 
operating limits. The MCPR operating limit for a given
 
power/flow state is the greater of the rated conditions MCPR
 
operating limit or the power dependent MCPR operating limit.
 
For automatic flow control, in addition to protecting the
 
MCPR SL during the flow run-up event, protection is provided
 
by the flow dependent MCPR operating limit to prevent
 
exceeding the rated flow MCPR operating limit during an
 
automatic flow increase to rated core flow.
 
Power dependent MCPR limits (MCPR p) are determined on a cycle-specific basis. These limits are established to protect the core from plant transients other than core flow
 
increases, including pressurization and local control rod
 
withdrawal events.
 
The MCPR satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).
 
LCO The MCPR operating limits specified in the COLR are the result of the Design Basis Accident (DBA) and transient
 
analysis. MCPR operating limits which include the effects
 
of analyzed equipment out-of-service are also included in
 
the COLR. The MCPR operating limits are determined by the
 
larger of the MCPR f and MCPR p limits.  (continued)
MCPR B 3.2.2 LaSalle 1 and 2 B 3.2.2-3 Revision 0 BASES  (continued)
 
APPLICABILITY The MCPR operating limits are primarily derived from transient analyses that are assumed to occur at high power
 
levels. Below 25% RTP, the reactor is operating at a slow
 
recirculation pump speed and the moderator void ratio is
 
small. Surveillance of thermal limits below 25% RTP is
 
unnecessary due to the inherent margin that ensures that the
 
MCPR SL is not exceeded even if a limiting transient occurs.
Studies of the variation of limiting transient behavior have
 
been performed over the range of power and flow conditions.
 
These studies (Ref. 5) encompass the range of key actual
 
plant parameter values important to typically limiting
 
transients. The results of these studies demonstrate that a
 
margin is expected between performance and the MCPR
 
requirements, and that margins increase as power is reduced
 
to 25% RTP. This trend is expected to continue to the 5% to
 
15% power range when entry into MODE 2 occurs. When in
 
MODE 2, the intermediate range monitor (IRM) and average
 
power range monitor (APRM) provide rapid scram initiation
 
for any significant power increase transient, which
 
effectively eliminates any MCPR compliance concern.
 
Therefore, at THERMAL POWER levels
< 25% RTP, the reactor is operating with substantial margin to the MCPR limits and
 
this LCO is not required.
 
ACTIONS A.1 If any MCPR is outside the required limits, an assumption
 
regarding an initial condition of the design basis transient
 
analyses may not be met. Therefore, prompt action should be
 
taken to restore the MCPR(s) to within the required limits
 
such that the plant remains operating within analyzed
 
conditions. The 2 hour Completion Time is normally
 
sufficient to restore the MCPR(s) to within its limits and
 
is acceptable based on the low probability of a transient or
 
DBA occurring simultaneously with the MCPR out of
 
specification.
 
B.1 If the MCPR cannot be restored to within the required limits
 
within the associated Completion Time, the plant must be
 
brought to a MODE or other specified condition in which the
 
LCO does not apply. To achieve this status, THERMAL POWER (continued)
MCPR B 3.2.2 LaSalle 1 and 2 B 3.2.2-4 Revision 0 BASES ACTIONS B.1 (continued) must be reduced to
< 25% RTP within 4 hours. The allowed Completion Time is reasonable, based on operating
 
experience, to reduce THERMAL POWER to
< 25% RTP in an orderly manner and without challenging plant systems.
 
SURVEILLANCE SR  3.2.2.1 REQUIREMENTS The MCPR is required to be initially calculated within
 
12 hours after THERMAL POWER is  25% RTP and then every 24 hours thereafter. It is compared to the specified limits
 
in the COLR to ensure that the reactor is operating within
 
the assumptions of the safety analysis. The 24 hour
 
Frequency is based on both engineering judgment and
 
recognition of the slowness of changes in power distribution
 
during normal operation. The 12 hour allowance after
 
THERMAL POWER reaches  25% RTP is acceptable given the inherent margin to operating limits at low power levels.
 
SR  3.2.2.2
 
Because the transient analyses may take credit for
 
conservatism in the control rod scram speed performance, it
 
must be demonstrated that the specific scram speed
 
distribution is consistent with that used in the transient
 
analyses. SR 3.2.2.2 determines the actual scram speed
 
distribution and compares it with the assumed distribution.
 
The MCPR operating limit is then determined based either on
 
the applicable limit associated with scram times of
 
LCO 3.1.4, "Control Rod Scram Times," or the realistic scram
 
times. The scram time dependent MCPR limits are contained
 
in the COLR. This determination must be performed within 72
 
hours after each set of control rod scram time tests
 
required by SR 3.1.4.1, SR 3.1.4.2, and SR 3.1.4.4 because
 
the effective scram speed distribution may change during the
 
cycle or after maintenance that could affect scram times.
 
The 72 hour Completion Time is acceptable due to the
 
relatively minor changes in the actual control rod scram
 
speed distribution expected during the fuel cycle.
 
(continued)
MCPR B 3.2.2 LaSalle 1 and 2 B 3.2.2-5 Revision 0 BASES  (continued)
 
REFERENCES 1. NUREG-0562, June 1979.
: 2. NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel" (as specified in Technical
 
Specification 5.6.5).
: 3. UFSAR, Chapter 4.
: 4. UFSAR, Chapter 6.
: 5. UFSAR, Chapter 15.
: 6. EMF-94-217(NP) , Revision 1, "Boiling Water Reactor Licensing Methodology Summary," November 1995.
: 7. NFSR-0091, Benchmark of CASMO/MICROBURN BWR Nuclear Design Methods, Commonwealth Edison Topical Report, (as  specified in Technical Specification 5.6.5).
: 8. XN-NF-80-19(P)(A), Volume 1, Exxon Nuclear Methodology for Boiling Water Reactors-Neutronic Methods for
 
Design and Analysis, (as specified in Technical
 
Specification 5.6.5).
: 9. XN-NF-80-19(P)(A), Volume 3, Exxon Nuclear Methodology for Boiling Water Reactors-THERMEX Thermal Limits
 
Methodology Summary Description, (as specified in
 
Technical Specification 5.6.5).
 
LHGR B 3.2.3 LaSalle 1 and 2 B 3.2.3-1 Revision 14 B 3.2  POWER DISTRIBUTION LIMITS
 
B 3.2.3  LINEAR HEAT GENERATION RATE (LHGR)
 
BASES  BACKGROUND The LHGR is a measure of the heat generation rate of a fuel rod in a fuel assembly at any axial location. Limits on the
 
LHGR are specified to ensure that fuel design limits are not
 
exceeded anywhere in the core during normal operation, including anticipated operational occurrences (AOOs), and to ensure that the peak cladding temperature (PCT) during the postulated design basis loss of coolant accident (LOCA) does not exceed the limits specified in 10 CFR 50.46. Exceeding the LHGR limit could potentially result in fuel damage and
 
subsequent release of radioactive materials. Fuel design
 
limits are specified to ensure that fuel system damage, fuel
 
rod failure or inability to cool the fuel does not occur
 
during the normal operations and anticipated operating
 
conditions identified in References 1 and 2.
APPLICABLE The analytical methods and assumptions used in evaluating SAFETY ANALYSES the fuel system design and establish LHGR limits are presented in References 1, 2, 3, 4, 5, and 6. The fuel assembly is designed to ensure (in conjunction with the core
 
nuclear and thermal hydraulic design, plant equipment, instrumentation, and protection system) that fuel damage
 
will not result in the release of radioactive materials in
 
excess of the guidelines of 10 CFR, Parts 20, 50, and 100. 
 
A mechanism that could cause fuel damage during normal
 
operations and operational transients and that is considered
 
in fuel evaluations is a rupture of the fuel rod cladding
 
caused by strain from the relative expansion of the UO 2 pellet. A value of 1% plastic strain of the fuel cladding has been
 
defined as the limit below which fuel damage caused by
 
overstraining of the fuel cladding is not expected to occur (Ref. 7).
 
Fuel design evaluations have been performed and demonstrate
 
that the 1% fuel cladding plastic strain design limit is not
 
exceeded during continuous operation with LHGRs up to the
 
operating limit specified in the COLR. The analysis also
 
includes allowances for short term transient excursions
 
above the operating limit while still remaining within the
 
AOO limits, plus an allowance for densification power
 
spiking.
 
The LHGR satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).
 
(continued)
LHGR B 3.2.3 LaSalle 1 and 2 B 3.2.3-2 Revision 0 BASES  (continued)
 
LCO The LHGR is a basic assumption in the fuel design analysis.
The fuel has been designed to operate at rated core power
 
with sufficient design margin to the LHGR calculated to
 
cause a 1% fuel cladding plastic strain. The operating
 
limit to accomplish this objective is specified in the COLR.
 
APPLICABILITY The LHGR limits are derived from fuel design analysis that is limiting at high power level conditions. At core thermal
 
power levels
< 25% RTP, the reactor is operating with margin to the LHGR limits and, therefore, the Specification is only
 
required when the reactor is operating at  25% RTP.
 
ACTIONS A.1 If any LHGR exceeds its required limit, an assumption
 
regarding an initial condition of the fuel design analysis
 
is not met. Therefore, prompt action should be taken to
 
restore the LHGR(s) to within its required limits such that
 
the plant is operating within analyzed conditions. The
 
2 hour Completion Time is normally sufficient to restore the
 
LHGR(s) to within its limits and is acceptable based on the
 
low probability of a transient or Design Basis Accident
 
occurring simultaneously with the LHGR out of specification.
 
B.1 If the LHGR cannot be restored to within its required limits
 
within the associated Completion Time, the plant must be
 
brought to a MODE or other specified condition in which the
 
LCO does not apply. To achieve this status, THERMAL POWER
 
must be reduced to
< 25% RTP within 4 hours. The allowed Completion Time is reasonable, based on operating
 
experience, to reduce THERMAL POWER to
< 25% RTP in an orderly manner and without challenging plant systems.
 
SURVEILLANCE SR  3.2.3.1 REQUIREMENTS The LHGRs are required to be initially calculated within
 
12 hours after THERMAL POWER is  25% RTP and then every 24 hours thereafter. They are compared with the LHGR limits
 
in the COLR to ensure that the reactor is operating within (continued)
LHGR B 3.2.3 LaSalle 1 and 2 B 3.2.3-3 Revision 14 BASES SURVEILLANCE SR  3.2.3.1 (continued)
REQUIREMENTS the assumptions of the safety analysis. The 24 hour
 
Frequency is based on both engineering judgment and
 
recognition of the slowness of changes in power distribution
 
under normal conditions. The 12 hour allowance after
 
THERMAL POWER  25% RTP is achieved is acceptable given the inherent margin to operating limits at lower power levels.
 
REFERENCES 1. UFSAR, Chapter 4.
: 2. UFSAR, Chapter 15.
: 3. XN-NF-80-19(P)(A), Advanced Nuclear Fuel Methodology for Boiling Water Reactors.
: 4. XN-NF-81-58(P)(A), RODEX2 Fuel Rod Thermal-Mechanical Response Evaluation Model.
: 5. NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel" (as specified in Technical Specification 5.6.5).
: 6. EMF-85-74(P)(A), RODEX2A (BWR) Fuel Rod Thermal-Mechanical Evaluation Model.
: 7. NUREG-0800, Section 4.2.II A.2(g), Revision 2, July 1981.
 
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-1 Revision 0 B 3.3  INSTRUMENTATION
 
B 3.3.1.1  Reactor Protection System (RPS) Instrumentation
 
BASES
 
BACKGROUND The RPS initiates a reactor scram when one or more monitored parameters exceed their specified limit to preserve the
 
integrity of the fuel cladding and the reactor coolant
 
pressure boundary (RCPB), and minimize the energy that must
 
be absorbed following a loss of coolant accident (LOCA).
 
This can be accomplished either automatically or manually.
The protection and monitoring functions of the RPS have been
 
designed to ensure safe operation of the reactor. This is
 
achieved by specifying limiting safety system settings (LSSS) in terms of parameters directly monitored by the RPS, as well as LCOs on other reactor system parameters, and
 
equipment performance. The LSSS are defined in this
 
Specification as the Allowable Values, which, in conjunction
 
with the LCOs, establish the threshold for protective system
 
action to prevent exceeding acceptable limits, including
 
Safety Limits (SLs), during Design Basis Accidents (DBAs).
 
The RPS, as described in the UFSAR, Section 7.2 (Ref. 1),
includes sensors, relays, bypass circuits, and switches that
 
are necessary to cause initiation of a reactor scram.
 
Functional diversity is provided by monitoring a wide range
 
of dependent and independent parameters. The input
 
parameters to the scram logic are from instrumentation that
 
monitors reactor vessel water level; reactor vessel
 
pressure; neutron flux; main steam line isolation valve
 
position; turbine control valve (TCV) fast closure, trip oil
 
pressure low; turbine stop valve (TSV) position; drywell
 
pressure and scram discharge volume (SDV) water level; as
 
well as reactor mode switch in shutdown position and manual
 
scram signals. There are at least four redundant sensor
 
input signals from each of these parameters. Most channels
 
include instrument switches or electronic equipment (e.g.,
trip units) that compares measured input signals with
 
pre-established setpoints. When a setpoint is exceeded, the
 
channel outputs an RPS trip signal to the trip logic.
 
The RPS is comprised of two independent trip systems (A
 
and B), with two logic channels in each trip system (logic
 
channels A1 and A2, B1 and B2), as described in Reference 1.
(continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-2 Revision 0 BASES BACKGROUND The outputs of the logic channels in a trip system are (continued) combined in a one-out-of-two logic so either channel can trip the associated trip system. The tripping of both trip
 
systems will produce a reactor scram. This logic
 
arrangement is referred to as one-out-of-two taken twice
 
logic. Each trip system can be reset by use of a reset
 
switch. If a full scram occurs (both trip systems trip), a
 
relay prevents reset of the trip systems for 10 seconds.
 
This 10 second delay on reset is only possible if the
 
conditions that caused the scram have been cleared. This
 
ensures that the scram function will be completed.
 
Two pilot scram valves are located in the hydraulic control
 
unit (HCU) for each control rod drive (CRD). Each pilot
 
scram valve is solenoid operated, with the solenoids
 
normally energized. The pilot scram valves control the air
 
supply to the scram inlet and outlet valves for the
 
associated CRD. When either pilot scram valve solenoid is
 
energized, air pressure holds the scram valves closed and, therefore, both pilot scram valve solenoids must be
 
de-energized to cause a control rod to scram. The scram
 
valves control the supply and discharge paths for the CRD
 
water during a scram. One of the pilot scram valve
 
solenoids for each CRD is controlled by trip system A, and
 
the other solenoid is controlled by trip system B. Any trip
 
of trip system A in conjunction with any trip in trip system
 
B results in de-energizing both solenoids, air bleeding off, scram valves opening, and control rod scram.
 
The backup scram valves, which energize on a scram signal to
 
depressurize the scram air header, are also controlled by
 
the RPS. Additionally, the RPS System controls the SDV vent
 
and drain valves such that when both trip systems trip, the
 
SDV vent and drain valves close to isolate the SDV.
 
APPLICABLE The actions of the RPS are assumed in the safety analyses SAFETY ANALYSES, of References 2, 3, and 4. The RPS initiates a reactor LCO, and scram when monitored parameter values exceed the Allowable APPLICABILITY Values specified by the setpoint methodology and listed in Table 3.3.1.1-1 to preserve the integrity of the fuel
 
cladding, the RCPB, and the containment by minimizing the
 
energy that must be absorbed following a LOCA.
(continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-3 Revision 0 BASES APPLICABLE RPS instrumentation satisfies Criterion 3 of SAFETY ANALYSES, 10 CFR 50.36(c)(2)(ii). Functions not specifically credited LCO, and in the accident analysis are retained for the overall APPLICABILITY redundancy and diversity of the RPS as required by the NRC (continued) approved licensing basis.
 
The OPERABILITY of the RPS is dependent on the OPERABILITY
 
of the individual instrumentation channel Functions
 
specified in Table 3.3.1.1-1. Each Function must have a
 
required number of OPERABLE channels per RPS trip system, with their setpoints within the specified Allowable Value, where appropriate. The actual setpoint is calibrated
 
consistent with applicable setpoint methodology assumptions.
 
Each channel must also respond within its assumed response
 
time, where applicable.
 
Allowable Values are specified for each RPS Function
 
specified in the Table. Nominal trip setpoints are
 
specified in the setpoint calculations. The nominal
 
setpoints are selected to ensure that the actual setpoints
 
do not exceed the Allowable Value between successive CHANNEL
 
CALIBRATIONS. Operation with a trip setpoint less
 
conservative than the nominal trip setpoint, but within its
 
Allowable Value, is acceptable. A channel is inoperable if
 
its actual trip setpoint is not within its required
 
Allowable Value.
 
Trip setpoints are those predetermined values of output at
 
which an action should take place. The setpoints are
 
compared to the actual process parameter (e.g., reactor
 
vessel water level), and when the measured output value of
 
the process parameter exceeds the setpoint, the associated
 
device (e.g., trip unit) changes state. The analytic limits
 
are derived from the limiting values of the process
 
parameters obtained from the safety analysis. The trip
 
setpoints are determined from the analytic limits, corrected
 
for defined process, calibration, and instrumentation
 
errors. The Allowable Values are then determined, based on
 
the trip setpoint values, by accounting for the calibration
 
based errors. These calibration based errors are limited to
 
reference accuracy, instrument drift, errors associated with
 
measurement and test equipment, and calibration tolerance of
 
loop components. The trip setpoints and Allowable Values
 
determined in this manner provide adequate protection
 
(continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-4 Revision 0 BASES APPLICABLE because instrument uncertainties, process effects, SAFETY ANALYSES, calibration tolerances, instrument drift, and severe LCO, and environment errors (for channels that must function in harsh APPLICABILITY environments as defined by 10 CFR 50.49) are accounted for (continued) and appropriately applied for the instrumentation.
 
The OPERABILITY of pilot scram valves and associated
 
solenoids, backup scram valves, and SDV valves, described in
 
the Background section, are not addressed by this LCO.
 
The individual Functions are required to be OPERABLE in the
 
MODES or other conditions specified in the Table that may
 
require an RPS trip to mitigate the consequences of a design
 
basis accident or transient. To ensure a reliable scram
 
function, a combination of Functions is required in each
 
MODE to provide primary and diverse initiation signals.
 
The only MODES specified in Table 3.3.1.1-1 are MODES 1 and
 
2, and MODE 5 with any control rod withdrawn from a core
 
cell containing one or more fuel assemblies. No RPS
 
Function is required in MODES 3 and 4, since all control
 
rods are fully inserted and the Reactor Mode Switch Shutdown
 
Position control rod withdrawal block (LCO 3.3.2.1) does not
 
allow any control rod to be withdrawn. Under these
 
conditions, the RPS function is not required to be OPERABLE.
 
In MODE 5, control rods withdrawn from a core cell
 
containing no fuel assemblies do not affect the reactivity
 
of the core and therefore are not required to have the
 
capability to scram. Provided all other control rods remain
 
inserted, no RPS Function is required. In this condition, the required SDM (LCO 3.1.1) and refuel position one-rod-out
 
interlock (LCO 3.9.2) ensure that no event requiring RPS
 
will occur.
 
The specific Applicable Safety Analyses, LCO, and
 
Applicability discussions are listed below on a Function by
 
Function basis.
 
1.a. Intermediate Range Monitor (IRM) Neutron Flux-High
 
The IRMs monitor neutron flux levels from the upper range of
 
the source range monitors (SRMs) to the lower range of the
 
average power range monitors (APRMs). The IRMs are capable
 
of generating trip signals that can be used to prevent fuel (continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-5 Revision 0 BASES APPLICABLE 1.a. Intermediate Range Monitor (IRM) Neutron Flux-High SAFETY ANALYSES, (continued)
 
LCO, and APPLICABILITY damage resulting from abnormal operating transients in the intermediate power range. In this power range, the most
 
significant source of reactivity change is due to control
 
rod withdrawal. The IRM provides a diverse protection
 
function from the rod worth minimizer (RWM), which monitors
 
and controls the movement of control rods at low power. The
 
RWM prevents the withdrawal of an out of sequence control
 
rod during startup that could result in an unacceptable
 
neutron flux excursion (Ref. 5). The IRM provides a backup
 
to the APRM in mitigation of the neutron flux excursion.
 
However, to demonstrate the capability of the IRM System to
 
mitigate control rod withdrawal events, a generic analysis
 
has been performed (Ref. 6) to evaluate the consequences of
 
control rod withdrawal events during startup that are
 
mitigated only by the IRM. This analysis, which assumes
 
that one IRM channel in each trip system is bypassed, demonstrates that the IRMs provide protection against local
 
control rod withdrawal errors and results in peak fuel
 
enthalpy below the 170 cal/gm fuel failure threshold
 
criterion.
The IRMs are also capable of limiting other reactivity
 
excursions during startup, such as cold water injection
 
events, although no credit is specifically assumed.
 
The IRM System is divided into two groups of IRM channels, with four IRM channels inputting to each trip system. The
 
analysis of Reference 6 assumes that one channel in each
 
trip system is bypassed. Therefore, six channels with three
 
channels in each trip system are required for IRM
 
OPERABILITY to ensure that no single instrument failure will
 
preclude a scram from this Function on a valid signal. This
 
trip is active in each of the 10 ranges of the IRM, which
 
must be selected by the operator to maintain the neutron
 
flux within the monitored level of an IRM range.
The analysis of Reference 6 has adequate conservatism to
 
permit the IRM Allowable Value specified in Table 3.3.1.1-1.
(continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-6 Revision 0 BASES APPLICABLE 1.a. Intermediate Range Monitor (IRM) Neutron Flux-High SAFETY ANALYSES, (continued)
 
LCO, and APPLICABILITY The Intermediate Range Monitor Neutron Flux-High Function must be OPERABLE during MODE 2 when control rods may be
 
withdrawn and the potential for criticality exists. In
 
MODE 5, when a cell with fuel has its control rod withdrawn, the IRMs provide monitoring for and protection against
 
unexpected reactivity excursions. In MODE 1, the APRM
 
System, the RWM and Rod Block Monitor provide protection
 
against control rod withdrawal error events and the IRMs are
 
not required. The IRMs are automatically bypassed when the
 
Reactor Mode Switch is in the run position.
 
1.b. Intermediate Range Monitor-Inop
 
This trip signal provides assurance that a minimum number of
 
IRMs are OPERABLE. Anytime an IRM mode switch is moved to
 
any position other than "Operate," the detector voltage
 
drops below a preset level, or a module is not plugged in, an inoperative trip signal will be received by the RPS
 
unless the IRM is bypassed. Since only one IRM in each trip
 
system may be bypassed, only one IRM in each RPS trip system
 
may be inoperable without resulting in an RPS trip signal.
 
This Function was not specifically credited in the accident
 
analysis, but it is retained for the overall redundancy and
 
diversity of the RPS as required by the NRC approved
 
licensing basis.
 
Six channels of Intermediate Range Monitor-Inop with three
 
channels in each trip system are required to be OPERABLE to
 
ensure that no single instrument failure will preclude a
 
scram from this Function on a valid signal.
 
There is no Allowable Value for this Function.
 
This Function is required to be OPERABLE when the
 
Intermediate Range Monitor Neutron Flux-High Function is
 
required.
(continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-7 Revision 0 BASES APPLICABLE 2.a. Average Power Range Monitor Neutron Flux-High, SAFETY ANALYSES, Setdown LCO, and APPLICABILITY The APRM channels receive input signals from the local power (continued) range monitors (LPRM) within the reactor core, which provide an indication of the power distribution and local power
 
changes. The APRM channels average these LPRM signals to
 
provide a continuous indication of average reactor power
 
from a few percent to greater than RTP. For operation at
 
low power (i.e., MODE 2), the Average Power Range Monitor
 
Neutron Flux-High, Setdown Function is capable of
 
generating a trip signal that prevents fuel damage resulting
 
from abnormal operating transients in this power range. For
 
most operation at low power levels, the Average Power Range
 
Monitor Neutron Flux-High, Setdown Function will provide a
 
secondary scram to the Intermediate Range Monitor Neutron
 
Flux-High Function because of the relative setpoints. With
 
the IRMs at Range 9 or 10, it is possible that the Average
 
Power Range Monitor Neutron Flux-High, Setdown Function
 
will provide the primary trip signal for a corewide increase
 
in power. The initial core, fuel cycle independent analysis
 
provided in Reference 5 indicates that a primary trip signal
 
from the Average Power Range Monitor Neutron Flux-High, Setdown Function would provide acceptable results.
The safety analyses (Ref. 5) take credit for the Average
 
Power Range Monitor Neutron Flux-High, Setdown Function.
 
This Function ensures that, before the reactor mode switch
 
is placed in the run position, reactor power does not exceed
 
25% RTP (SL 2.1.1.1) when operating at low reactor pressure
 
and low core flow. Therefore, it prevents fuel damage
 
during significant reactivity increases with THERMAL POWER
 
< 25% RTP.
 
The APRM System is divided into two groups of channels with
 
three APRM channel inputs to each trip system. The system
 
is designed to allow one channel in each trip system to be
 
bypassed. Any one APRM channel in a trip system can cause
 
the associated trip system to trip. Four channels of
 
Average Power Range Monitor Neutron Flux-High, Setdown, with two channels in each trip system are required to be
 
OPERABLE to ensure that no single failure will preclude a
 
scram from this Function on a valid signal. In addition, to (continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-8 Revision 0 BASES APPLICABLE 2.a. Average Power Range Monitor Neutron Flux-High, SAFETY ANALYSES, Setdown (continued)
LCO, and APPLICABILITY provide adequate coverage of the entire core, at least 14 LPRM inputs are required for each APRM channel, with at
 
least two LPRM inputs from each of the four axial levels at
 
which the LPRMs are located.
The Allowable Value is based on preventing significant
 
increases in power when THERMAL POWER is
< 25% RTP.
 
The Average Power Range Monitor Neutron Flux-High, Setdown
 
Function must be OPERABLE during MODE 2 when control rods
 
may be withdrawn and the potential for fuel damage from
 
abnormal operating transients exists. In MODE 1, the
 
Average Power Range Monitor Neutron Flux-High Function
 
provides protection against reactivity transients and the
 
RWM and Rod Block Monitor protect against control rod
 
withdrawal error events.
 
2.b. Average Power Range Monitor Flow Biased Simulated Thermal Power-Upscale
 
The Average Power Range Monitor Flow Biased Simulated
 
Thermal Power-Upscale Function monitors neutron flux to
 
approximate the THERMAL POWER being transferred to the
 
reactor coolant. The APRM neutron flux is electronically
 
filtered with a time constant representative of the fuel
 
heat transfer dynamics to generate a signal proportional to
 
the THERMAL POWER in the reactor. The trip level is varied
 
as a function of recirculation drive flow (i.e., at lower
 
core flows the setpoint is reduced proportional to the
 
reduction in power experienced as core flow is reduced) but
 
is clamped at an upper limit that is always lower than the
 
Average Power Range Monitor Fixed Neutron Flux-High
 
Function Allowable Value. The Average Power Range Monitor
 
Flow Biased Simulated Thermal Power-Upscale Function
 
provides protection against transients where THERMAL POWER
 
increases slowly (such as the loss of feedwater heating
 
event) and protects the fuel cladding integrity by ensuring
 
that the MCPR SL is not exceeded. During these events, the
 
THERMAL POWER increase does not significantly lag the
 
neutron flux response and, because of a lower trip setpoint,  (continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-9 Revision 0 BASES APPLICABLE 2.b. Average Power Range Monitor Flow Biased Simulated SAFETY ANALYSES, Thermal Power-Upscale (continued)
LCO, and APPLICABILITY will initiate a scram before the high neutron flux scram.
For rapid neutron flux increase events, the THERMAL POWER
 
lags the neutron flux and the Average Power Range Monitor
 
Fixed Neutron Flux-High Function will provide a scram
 
signal before the Average Power Range Monitor Flow Biased
 
Simulated Thermal Power-Upscale Function setpoint is
 
exceeded.
The APRM System is divided into two groups of channels with
 
three APRM inputs to each trip system. The system is
 
designed to allow one channel in each trip system to be
 
bypassed. Any one Average Power Range Monitor channel in a
 
trip system can cause the associated trip system to trip.
 
Four channels of Average Power Range Monitor Flow Biased
 
Simulated Thermal Power-Upscale, with two channels in each
 
trip system arranged in one-out-of-two logic, are required
 
to be OPERABLE to ensure that no single instrument failure
 
will preclude a scram from this Function on a valid signal.
 
In addition, to provide adequate coverage of the entire
 
core, at least 14 LPRM inputs are required for each APRM
 
channel, with at least two LPRM inputs from each of the four
 
axial levels at which the LPRMs are located. Each APRM
 
channel receives two independent, redundant flow signals
 
representative of total recirculation drive flow. The total
 
drive flow signals are generated by four flow units, two of
 
which supply signals to the trip system A APRMs, while the
 
other two supply signals to the trip system B APRMs. Each
 
flow unit signal is provided by summing the flow signals
 
from the two recirculation loops. These redundant flow
 
signals are sensed from four pairs of elbow taps, two on
 
each recirculation loop. No single active component failure
 
can cause more than one of these two redundant signals to
 
read incorrectly. To obtain the most conservative reference
 
signals, the total flow signals from the two flow units (associated with a trip system as described above) are
 
routed to a low auction circuit associated with each APRM.
 
Each APRM's auction circuit selects the lower of the two
 
flow unit signals for use as the scram trip reference for
 
that particular APRM. Each required Average Power Range
 
Monitor Flow Biased Simulated (continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-10 Revision 0 BASES APPLICABLE 2.b. Average Power Range Monitor Flow Biased Simulated SAFETY ANALYSES, Thermal Power-Upscale (continued)
LCO, and APPLICABILITY Thermal Power-Upscale channel only requires an input from one OPERABLE flow unit, since the individual APRM channel
 
will perform the intended function with only one OPERABLE
 
flow unit input. However, in order to maintain single
 
failure criteria for the Function, at least one required
 
Average Power Range Monitor Flow Biased Simulated Thermal
 
Power-Upscale channel in each trip system must be capable
 
of maintaining an OPERABLE flow unit signal in the event of
 
a failure of an auction circuit, or a flow unit, in the
 
associated trip system (e.g., if a flow unit is inoperable, one of the two required Average Power Range Monitor Flow
 
Biased Simulated Thermal Power-Upscale channels in the
 
associated trip system must be considered inoperable).
Although the Average Power Range Monitor Flow Biased
 
Simulated Thermal Power-Upscale Function is not
 
specifically credited in the safety analysis, the associated
 
Allowable Value provides additional margin from transient
 
induced fuel damage beyond that provided by the Average
 
Power Range Monitor Fixed Neutron Flux-High Function.  "W,"
in the Allowable Value column of Table 3.3.1.1-1, is the
 
percentage of recirculation loop flow which provides a rated
 
core flow of 108.5 million lbs/hr. The THERMAL POWER time
 
constant of  7 seconds is based on the fuel heat transfer dynamics and provides a signal that is proportional to the
 
THERMAL POWER.
 
The Average Power Range Monitor Flow Biased Simulated
 
Thermal Power-Upscale Function is required to be OPERABLE
 
in MODE 1 when there is the possibility of generating
 
excessive THERMAL POWER and potentially exceeding the SL
 
applicable to high pressure and core flow conditions (MCPR
 
SL). During MODES 2 and 5, other IRM and APRM Functions
 
provide protection for fuel cladding integrity.
 
2.c. Average Power Range Monitor Fixed Neutron Flux-High
 
The APRM channels provide the primary indication of neutron
 
flux within the core and respond almost instantaneously to
 
neutron flux increases. The Average Power Range Monitor
 
Fixed Neutron Flux-High Function is capable of generating a (continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-11 Revision 0 BASES APPLICABLE 2.c. Average Power Range Monitor Fixed Neutron Flux-High SAFETY ANALYSES, (continued)
 
LCO, and APPLICABILITY trip signal to prevent fuel damage or excessive Reactor Coolant System (RCS) pressure. For the overpressurization
 
protection analysis of Reference 2, the Average Power Range
 
Monitor Fixed Neutron Flux-High Function is assumed to
 
terminate the main steam isolation valve (MSIV) closure
 
event and, along with the safety/relief valves (S/RVs),
limits the peak reactor pressure vessel (RPV) pressure to
 
less than the ASME Code limits. The control rod drop
 
accident (CRDA) analysis (Ref. 8) takes credit for the
 
Average Power Range Monitor Fixed Neutron Flux-High
 
Function to terminate the CRDA. The recirculation flow
 
control failure event also credits this function (Ref. 4).
The APRM System is divided into two groups of channels with
 
three APRM channels inputting to each trip system. The
 
system is designed to allow one channel in each trip system
 
to be bypassed. Any one APRM channel in a trip system can
 
cause the associated trip system to trip. Four channels of
 
Average Power Range Monitor Fixed Neutron Flux-High with
 
two channels in each trip system arranged in a
 
one-out-of-two logic are required to be OPERABLE to ensure
 
that no single instrument failure will preclude a scram from
 
this Function on a valid signal. In addition, to provide
 
adequate coverage of the entire core, at least 14 LPRM
 
inputs are required for each APRM channel, with at least two
 
LPRM inputs from each of the four axial levels at which the
 
LPRMs are located.
 
The Allowable Value is based on the Analytical Limit assumed
 
in the CRDA analyses.
 
The Average Power Range Monitor Fixed Neutron Flux-High
 
Function is required to be OPERABLE in MODE 1 where the
 
potential consequences of the analyzed transients could
 
result in the SLs (e.g., MCPR and RCS pressure) being
 
exceeded. Although the Average Power Range Monitor Fixed
 
Neutron Flux-High Function is assumed in the CRDA analysis (Ref. 8) that is applicable in MODE 2, the Average Power
 
Range Monitor Neutron Flux-High, Setdown Function (continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-12 Revision 0 BASES APPLICABLE 2.c. Average Power Range Monitor Fixed Neutron Flux-High SAFETY ANALYSES, (continued)
 
LCO, and APPLICABILITY conservatively bounds the assumed trip and, together with the assumed IRM trips, provides adequate protection.
 
Therefore, the Average Power Monitor Fixed Neutron
 
Flux-High Function is not required in MODE 2.
 
2.d. Average Power Range Monitor-Inop
 
This signal provides assurance that a minimum number of
 
APRMs are OPERABLE. Anytime an APRM mode switch is moved to
 
any position other than Operate, an APRM module is
 
unplugged, or the APRM has too few LPRM inputs (< 14), an inoperative trip signal will be received by the RPS, unless
 
the APRM is bypassed. Since only one APRM in each trip
 
system may be bypassed, only one APRM in each trip system
 
may be inoperable without resulting in an RPS trip signal.
 
This Function was not specifically credited in the accident
 
analysis, but it is retained for the overall redundancy and
 
diversity of the RPS as required by the NRC approved
 
licensing basis.
 
Four channels of Average Power Range Monitor-Inop with two
 
channels in each trip system are required to be OPERABLE to
 
ensure that no single failure will preclude a scram from
 
this Function on a valid signal.
 
There is no Allowable Value for this Function.
 
This Function is required to be OPERABLE in the MODES where
 
the other APRM Functions are required.
: 3. Reactor Vessel Steam Dome Pressure-High
 
An increase in the RPV pressure during reactor operation
 
compresses the steam voids and results in a positive
 
reactivity insertion. This causes the neutron flux and
 
THERMAL POWER transferred to the reactor coolant to
 
increase, which could challenge the integrity of the fuel
 
cladding and the RCPB. No specific safety analysis takes
 
direct credit for this Function. However, the Reactor (continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-13 Revision 0 BASES APPLICABLE 3. Reactor Vessel Steam Dome Pressure-High  (continued)
SAFETY ANALYSES, LCO, and Vessel Steam Dome Pressure-High Function initiates a scram APPLICABILITY for transients that result in a pressure increase, counteracting the pressure increase by rapidly reducing core
 
power. For the overpressurization protection analysis of
 
Reference 2, the reactor scram (the analyses conservatively
 
assume scram on the Average Power Range Monitor Fixed
 
Neutron Flux-High signal, not the Reactor Vessel Steam Dome
 
Pressure-High or the Main Steam Isolation Valve-Closure
 
signals), along with the S/RVs, limits the peak RPV pressure
 
to less than the ASME Section III Code limits.
High reactor pressure signals are initiated from four
 
pressure switches that sense reactor pressure. The Reactor
 
Vessel Steam Dome Pressure-High Allowable Value is chosen
 
to provide a sufficient margin to the ASME Section III Code
 
limits during the event.
 
Four channels of Reactor Vessel Steam Dome Pressure-High
 
Function, with two channels in each trip system arranged in
 
a one-out-of-two logic, are required to be OPERABLE to
 
ensure that no single instrument failure will preclude a
 
scram from this Function on a valid signal. The Function is
 
required to be OPERABLE in MODES 1 and 2 since the RCS is
 
pressurized and the potential for pressure increase exists.
: 4. Reactor Vessel Water Level-Low, Level 3
 
Low RPV water level indicates the capability to cool the
 
fuel may be threatened. Should RPV water level decrease too
 
far, fuel damage could result. Therefore, a reactor scram
 
is initiated at Level 3 to substantially reduce the heat
 
generated in the fuel from fission. The Reactor Vessel
 
Water Level-Low, Level 3 Function is assumed in the
 
analysis of the recirculation line break (Ref. 3). The
 
reactor scram reduces the amount of energy required to be
 
absorbed and, along with the actions of the Emergency Core
 
Cooling Systems (ECCS), ensures that the fuel peak cladding
 
temperature remains below the limits of 10 CFR 50.46.
(continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-14 Revision 0 BASES APPLICABLE 4. Reactor Vessel Water Level-Low, Level 3  (continued)
SAFETY ANALYSES, LCO, and Reactor Vessel Water Level-Low, Level 3 signals are APPLICABILITY initiated from four differential pressure transmitters that sense the difference between the pressure due to a constant
 
column of water (reference leg) and the pressure due to the
 
actual water level (variable leg) in the vessel.
Four channels of Reactor Vessel Water Level-Low, Level 3
 
Function, with two channels in each trip system arranged in
 
a one-out-of-two logic, are required to be OPERABLE to
 
ensure that no single instrument failure will preclude a
 
scram from this Function on a valid signal.
The Reactor Vessel Water Level-Low, Level 3 Allowable Value
 
is selected to ensure that, for transients involving loss of
 
all normal feedwater flow, initiation of the low pressure
 
ECCS at RPV Water Level 1 will not be required.
 
The Function is required in MODES 1 and 2 where considerable
 
energy exists in the RCS resulting in the limiting
 
transients and accidents. ECCS initiations at Reactor
 
Vessel Water Level-Low Low, Level 2 and Low Low Low, Level 1 provide sufficient protection for level transients
 
in all other MODES.
: 5. Main Steam Isolation Valve-Closure
 
MSIV closure results in loss of the main turbine and the
 
condenser as a heat sink for the Nuclear Steam Supply System
 
and indicates a need to shut down the reactor to reduce heat
 
generation. Therefore, a reactor scram is initiated on a
 
Main Steam Isolation Valve-Closure signal before the MSIVs
 
are completely closed in anticipation of the complete loss
 
of the normal heat sink and subsequent overpressurization
 
transient. However, for the overpressurization protection
 
analysis of Reference 2, the Average Power Range Monitor
 
Fixed Neutron Flux-High Function, along with the S/RVs, limits the peak RPV pressure to less than the ASME Code
 
limits. That is, the direct scram on position switches for
 
MSIV closure events is not assumed in the overpressurization
 
analysis. Additionally, MSIV closure is assumed in the
 
transients analyzed in Reference 4 (e.g., low steam line
 
pressure, manual closure of MSIVs, high steam line flow).
 
(continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-15 Revision 0 BASES APPLICABLE 5. Main Steam Isolation Valve-Closure  (continued)
SAFETY ANALYSES, LCO, and The reactor scram reduces the amount of energy required to APPLICABILITY be absorbed and, along with the actions of the ECCS, ensures that the fuel peak cladding temperature remains below the
 
limits of 10 CFR 50.46.
 
MSIV closure signals are initiated from position switches
 
located on each of the eight MSIVs. Each MSIV has two
 
position switches; one inputs to RPS trip system A while the
 
other inputs to RPS trip system B. Thus, each RPS trip
 
system receives an input from eight Main Steam Isolation
 
Valve-Closure channels, each consisting of one position
 
switch. The logic for the Main Steam Isolation
 
Valve-Closure Function is arranged such that either the
 
inboard or outboard valve on three or more of the main steam
 
lines (MSLs) must close in order for a scram to occur. In
 
addition, certain combinations of valves closed in two lines
 
will result in a half scram.
 
The Main Steam Isolation Valve-Closure Allowable Value is
 
specified to ensure that a scram occurs prior to a
 
significant reduction in steam flow, thereby reducing the
 
severity of the subsequent pressure transient.
 
Sixteen channels of the Main Steam Isolation Valve-Closure
 
Function with eight channels in each trip system are
 
required to be OPERABLE to ensure that no single instrument
 
failure will preclude the scram from this Function on a
 
valid signal. This Function is only required in MODE 1
 
since, with the MSIVs open and the heat generation rate
 
high, a pressurization transient can occur if the MSIVs
 
close. In MODE 2, the heat generation rate is low enough so
 
that the other diverse RPS functions provide sufficient
 
protection.
: 6. Drywell Pressure-High
 
High pressure in the drywell could indicate a break in the
 
RCPB. A reactor scram is initiated to minimize the
 
possibility of fuel damage and to reduce the amount of
 
energy being added to the coolant and the drywell. The (continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-16 Revision 0 BASES APPLICABLE 6. Drywell Pressure-High (continued)
SAFETY ANALYSES, LCO, and Drywell Pressure-High Function is a secondary scram signal APPLICABILITY to Reactor Vessel Water Level-Low, Level 3 for LOCA analysis. This Function was not specifically credited with
 
the Appendix K accident analysis to initiate a reactor trip, but is retained for the overall redundancy and diversity of
 
the RPS as required by the NRC approved licensing basis.
The reactor scram reduces the amount of energy required to
 
be absorbed and, along with the actions of the ECCS, ensures
 
that the fuel peak cladding temperature remains below the
 
limits of 10 CFR 50.46.
 
High drywell pressure signals are initiated from four
 
pressure switches that sense drywell pressure. The
 
Allowable Value was selected to be as low as possible and be
 
indicative of a LOCA inside primary containment.
 
Four channels of Drywell Pressure-High Function, with two
 
channels in each trip system, are required to be OPERABLE to
 
ensure that no single instrument failure will preclude a
 
scram from this Function on a valid signal. The Function is
 
required in MODES 1 and 2 where considerable energy exists
 
in the RCS, resulting in the limiting transients and
 
accidents.
 
7.a, b. Scram Discharge Volume Water Level-High
 
The SDV receives the water displaced by the motion of the
 
CRD pistons during a reactor scram. Should this volume fill
 
to a point where there is insufficient volume to accept the
 
displaced water, control rod insertion would be hindered.
 
Therefore, a reactor scram is initiated when the remaining
 
free volume is still sufficient to accommodate the water
 
from a full core scram. However, even though the two types
 
of Scram Discharge Volume Water Level-High Functions are an
 
input to the RPS logic, no credit is taken for a scram
 
initiated from these Functions for any of the design basis
 
accidents or transients analyzed in the UFSAR. However, they are retained to ensure that the RPS remains OPERABLE.
 
(continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-17 Revision 0 BASES APPLICABLE 7.a, b. Scram Discharge Volume Water Level-High SAFETY ANALYSES, (continued)
 
LCO, and APPLICABILITY SDV water level is measured by two diverse methods. The level in each of the two SDVs is measured by two float type
 
level switches and two transmitters and trip units for a
 
total of eight level signals. The outputs of these devices
 
are arranged so that there is a signal from a level switch
 
and a transmitter and trip unit to each RPS logic channel.
 
The level measurement instrumentation satisfies the
 
recommendations of Reference 9.
The Allowable Value is chosen low enough to ensure that
 
there is sufficient volume in the SDV to accommodate the
 
water from a full scram.
 
Four channels of each type of Scram Discharge Volume Water
 
Level-High Function, with two channels of each type in each
 
trip system, are required to be OPERABLE to ensure that no
 
single instrument failure will preclude a scram from these
 
Functions on a valid signal. These Functions are required
 
in MODES 1 and 2, and in MODE 5 with any control rod
 
withdrawn from a core cell containing one or more fuel
 
assemblies, since these are the MODES and other specified
 
conditions when control rods are withdrawn. At all other
 
times, this Function may be bypassed.
: 8. Turbine Stop Valve-Closure Closure of the TSVs results in the loss of a heat sink that
 
produces reactor pressure, neutron flux, and heat flux
 
transients that must be limited. Therefore, a reactor scram
 
is initiated at the start of TSV closure in anticipation of
 
the transients that would result from the closure of these
 
valves. The Turbine Stop Valve-Closure is the primary
 
scram signal for the turbine trip event analyzed in
 
Reference 4. For this event, the reactor scram reduces the
 
amount of energy required to be absorbed and, along with the
 
actions of the End of Cycle Recirculation Pump Trip (EOC-RPT) System, ensures that the MCPR SL is not exceeded.
(continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-18 Revision 0 BASES APPLICABLE 8. Turbine Stop Valve-Closure  (continued)
SAFETY ANALYSES, LCO, and Turbine Stop Valve-Closure signals are initiated by valve APPLICABILITY stem position switches at each stop valve. Two switches are associated with each stop valve. One of the two switches
 
provides input to RPS trip system A; the other, to RPS trip
 
system B. Thus, each RPS trip system receives an input from
 
four Turbine Stop Valve-Closure channels, each consisting
 
of one valve stem position switch. The logic for the
 
Turbine Stop Valve-Closure Function is such that three or
 
more TSVs must be closed to produce a scram. In addition, certain combinations of two valves closed will result in a
 
half scram.
This Function must be enabled at THERMAL POWER  25% RTP.
This is normally accomplished automatically by pressure
 
switches sensing turbine first stage pressure; therefore, opening the turbine bypass valves may affect the OPERABILITY
 
of this Function.
The Turbine Stop Valve-Closure Allowable Value is selected
 
to detect imminent TSV closure thereby reducing the severity
 
of the subsequent pressure transient.
 
Eight channels of Turbine Stop Valve-Closure Function, with
 
four channels in each trip system, are required to be
 
OPERABLE to ensure that no single instrument failure will
 
preclude a scram from this Function even if one TSV should
 
fail to close. This Function is required, consistent with
 
analysis assumptions, whenever THERMAL POWER is  25% RTP.
This Function is not required when THERMAL POWER is
 
< 25% RTP since the Reactor Vessel Steam Dome Pressure-High and the Average Power Range Monitor Fixed Neutron Flux-High
 
Functions are adequate to maintain the necessary safety
 
margins. 
: 9. Turbine Control Valve Fast Closure, Trip Oil Pressure-Low
 
Fast closure of the TCVs results in the loss of a heat sink
 
that produces reactor pressure, neutron flux, and heat flux
 
transients that must be limited. Therefore, a reactor scram
 
is initiated on TCV fast closure in anticipation of the (continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-19 Revision 0 BASES APPLICABLE 9. Turbine Control Valve Fast Closure, Trip Oil SAFETY ANALYSES, Pressure-Low (continued)
LCO, and APPLICABILITY transients that would result from the closure of these valves. The Turbine Control Valve Fast Closure, Trip Oil
 
Pressure-Low Function is the primary scram signal for the
 
generator load rejection event analyzed in Reference 4. For
 
this event, the reactor scram reduces the amount of energy
 
required to be absorbed and, along with the actions of the
 
EOC-RPT System, ensures that the MCPR SL is not exceeded.
Turbine Control Valve Fast Closure, Trip Oil Pressure-Low
 
signals are initiated by the EHC fluid pressure to each
 
control valve. There is one pressure switch associated with
 
each control valve, the signal from each switch being
 
assigned to a separate RPS logic channel. This Function
 
must be enabled at THERMAL POWER  25% RTP. This is accomplished automatically by pressure switches sensing
 
turbine first stage pressure; therefore, opening the turbine
 
bypass valves may affect the OPERABILITY of this Function.
The Turbine Control Valve Fast Closure, Trip Oil
 
Pressure-Low Allowable Value is selected high enough to
 
detect imminent TCV fast closure.
Four channels of Turbine Control Valve Fast Closure, Trip
 
Oil Pressure-Low Function, with two channels in each trip
 
system arranged in a one-out-of-two logic, are required to
 
be OPERABLE to ensure that no single instrument failure will
 
preclude a scram from this Function on a valid signal. This
 
Function is required, consistent with the analysis
 
assumptions, whenever THERMAL POWER is  25% RTP. This Function is not required when THERMAL POWER is
< 25% RTP since the Reactor Vessel Steam Dome Pressure-High and the
 
Average Power Range Monitor Fixed Neutron Flux-High
 
Functions are adequate to maintain the necessary safety
 
margins.  (continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-20 Revision 0 BASES APPLICABLE 10. Reactor Mode Switch-Shutdown Position SAFETY ANALYSES, LCO, and The Reactor Mode Switch-Shutdown Position Function provides APPLICABILITY signals, via the manual scram logic channels, that are (continued) redundant to the automatic protective instrumentation channels and provide manual reactor trip capability. This
 
Function was not specifically credited in the accident
 
analysis, but it is retained for the overall redundancy and
 
diversity of the RPS as required by the NRC approved
 
licensing basis.
The reactor mode switch is a single switch with four
 
channels (one from each of the four independent banks of
 
contacts), each of which inputs into one of the RPS logic
 
channels.
 
There is no Allowable Value for this Function since the
 
channels are mechanically actuated based solely on reactor
 
mode switch position.
 
Four channels of Reactor Mode Switch-Shutdown Position
 
Function, with two channels in each trip system, are
 
available and required to be OPERABLE. The Reactor Mode
 
Switch-Shutdown Position Function is required to be
 
OPERABLE in MODES 1 and 2, and in MODE 5 with any control
 
rod withdrawn from a core cell containing one or more fuel
 
assemblies, since these are the MODES and other specified
 
conditions when control rods are withdrawn.
: 11. Manual Scram
 
The Manual Scram push button channels provide signals, via
 
the manual scram logic channels, to each of the four RPS
 
logic channels that are redundant to the automatic
 
protective instrumentation channels and provide manual
 
reactor trip capability. This Function was not specifically
 
credited in the accident analysis, but it is retained for
 
the overall redundancy and diversity of the RPS as required
 
by the NRC approved licensing basis.
 
There is one Manual Scram push button channel for each of
 
the four RPS logic channels. In order to cause a scram it
 
is necessary that at least one channel in each trip system
 
be actuated.
(continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-21 Revision 0 BASES APPLICABLE 11. Manual Scram (continued)
SAFETY ANALYSES, LCO, and There is no Allowable Value for this Function since the APPLICABILITY channels are mechanically actuated based solely on the position of the push buttons.
Four channels of Manual Scram with two channels in each trip
 
system arranged in a one-out-of-two logic, are available and
 
required to be OPERABLE in MODES 1 and 2, and in MODE 5 with
 
any control rod withdrawn from a core cell containing one or
 
more fuel assemblies, since these are the MODES and other
 
specified conditions when control rods are withdrawn.
 
ACTIONS Note 1 has been provided to modify the ACTIONS related to RPS instrumentation channels. Section 1.3, Completion
 
Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables
 
expressed in the Condition, discovered to be inoperable or
 
not within limits, will not result in separate entry into
 
the Condition. Section 1.3 also specifies that Required
 
Actions of the Condition continue to apply for each
 
additional failure, with Completion Times based on initial
 
entry into the Condition. However, the Required Actions for
 
inoperable RPS instrumentation channels provide appropriate
 
compensatory measures for separate, inoperable channels. As
 
such, Note 1 has been provided that allows separate
 
Condition entry for each inoperable RPS instrumentation
 
channel. Note 2 has been provided to modify the ACTIONS for the RPS
 
instrumentation functions of APRM Flow Biased Simulated
 
Thermal Power-Upscale (Function 2.b) and APRM Fixed Neutron
 
Flux-High (Function 2.c) when they are inoperable due to
 
failure of SR 3.3.1.1.2 and gain adjustments are necessary.
 
Note 2 allows entry into associated Conditions and Required
 
Actions to be delayed for up to 2 hours if the APRM is
 
indicating a lower power value than the calculated power (i.e., the gain adjustment factor (GAF) is high (non-
 
conservative)), and for up to 12 hours if the APRM is
 
indicating a higher power value than the calculated power (continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-22 Revision 0 BASES ACTIONS (i.e., the GAF is low (conservative)). The GAF for any (continued) channel is defined as the power value determined by the heat balance divided by the APRM reading for that channel. Upon
 
completion of the gain adjustment, or expiration of the
 
allowed time, the channel must be returned to OPERABLE
 
status or the applicable Condition entered and the Required
 
Actions taken. This Note is based on the time required to
 
perform gain adjustments on multiple channels and additional
 
time is allowed when the GAF is out of limits but
 
conservative.
 
A.1 and A.2
 
Because of the diversity of sensors available to provide
 
trip signals and the redundancy of the RPS design, an
 
allowable out of service time of 12 hours has been shown to
 
be acceptable (Ref. 10) to permit restoration of any
 
inoperable required channel to OPERABLE status. However, this out of service time is only acceptable provided the
 
associated Function's inoperable channel is in one trip
 
system and the Function still maintains RPS trip capability (refer to Required Actions B.1, B.2, and C.1 Bases.)  If the
 
inoperable channel cannot be restored to OPERABLE status
 
within the allowable out of service time, the channel or the
 
associated trip system must be placed in the tripped
 
condition per Required Actions A.1 and A.2. Placing the
 
inoperable channel in trip (or the associated trip system in
 
trip) would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and
 
allow operation to continue. Alternately, if it is not
 
desired to place the channel (or trip system) in trip (e.g.,
as in the case where placing the inoperable channel in trip
 
would result in a scram or recirculation pump trip (RPT)),
Condition D must be entered and its Required Action taken.
 
B.1 and B.2
 
Condition B exists when, for any one or more Functions, at
 
least one required channel is inoperable in each trip
 
system. In this condition, provided at least one channel
 
per trip system is OPERABLE, the RPS still maintains trip
 
capability for that Function, but cannot accommodate a
 
single failure in either trip system.
(continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-23 Revision 0 BASES ACTIONS B.1 and B.2 (continued)
Required Actions B.1 and B.2 limit the time the RPS scram
 
logic for any Function would not accommodate single failure
 
in both trip systems (e.g., one-out-of-one and
 
one-out-of-one arrangement for a typical four channel
 
Function). The reduced reliability of this logic
 
arrangement was not evaluated in Reference 10 for the
 
12 hour Completion Time. Within the 6 hour allowance, the
 
associated Function will have all required channels either
 
OPERABLE or in trip (or in any combination) in one trip
 
system.
 
Completing one of these Required Actions restores RPS to an
 
equivalent reliability level as that evaluated in
 
Reference 10, which justified a 12 hour allowable out of
 
service time as presented in Condition A. The trip system
 
in the more degraded state should be placed in trip or, alternatively, all the inoperable channels in that trip
 
system should be placed in trip (e.g., a trip system with
 
two inoperable channels could be in a more degraded state
 
than a trip system with four inoperable channels, if the two
 
inoperable channels are in the same Function while the four
 
inoperable channels are all in different Functions). The
 
decision as to which trip system is in the more degraded
 
state should be based on prudent judgment and current plant
 
conditions (i.e., what MODE the plant is in). If this
 
action would result in a scram or RPT, it is permissible to
 
place the other trip system or its inoperable channels in
 
trip. The 6 hour Completion Time is judged acceptable based on the
 
remaining capability to trip, the diversity of the sensors
 
available to provide the trip signals, the low probability
 
of extensive numbers of inoperabilities affecting all
 
diverse Functions, and the low probability of an event
 
requiring the initiation of a scram.
 
Alternately, if it is not desired to place the inoperable
 
channels (or one trip system) in trip (e.g., as in the case
 
where placing the inoperable channel or associated trip
 
system in trip would result in a scram or RPT), Condition D
 
must be entered and its Required Action taken.
(continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-24 Revision 0 BASES ACTIONS C.1 (continued)
Required Action C.1 is intended to ensure that appropriate
 
actions are taken if multiple, inoperable, untripped
 
channels within the same trip system for the same Function
 
result in the Function not maintaining RPS trip capability.
 
A Function is considered to be maintaining RPS trip
 
capability when sufficient channels are OPERABLE or in trip (or the associated trip system is in trip), such that both
 
trip systems will generate a trip signal from the given
 
Function on a valid signal. For the typical Function with
 
one-out-of-two taken twice logic and the IRM and APRM
 
Functions, this would require both trip systems to have one
 
channel OPERABLE or in trip (or the associated trip system
 
in trip). For Function 5 (Main Steam Isolation
 
Valve-Closure), this would require both trip systems to
 
have each channel associated with the MSIVs in three MSLs (not necessarily the same MSLs for both trip systems),
OPERABLE or in trip (or the associated trip system in trip).
 
For Function 8 (Turbine Stop Valve-Closure), this would
 
require both trip systems to have three channels, each
 
OPERABLE or in trip (or the associated trip system in trip).
The Completion Time is intended to allow the operator time
 
to evaluate and repair any discovered inoperabilities. The
 
1 hour Completion Time is acceptable because it minimizes
 
risk while allowing time for restoration or tripping of
 
channels.
 
D.1 Required Action D.1 directs entry into the appropriate
 
Condition referenced in Table 3.3.1.1-1. The applicable
 
Condition specified in the Table is Function and MODE or
 
other specified condition dependent and may change as the
 
Required Action of a previous Condition is completed. Each
 
time an inoperable channel has not met any Required Action
 
of Condition A, B, or C, and the associated Completion Time
 
has expired, Condition D will be entered for that channel
 
and provides for transfer to the appropriate subsequent
 
Condition.
(continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-25 Revision 0 BASES ACTIONS E.1, F.1, and G.1 (continued)
If the channel(s) is not restored to OPERABLE status or
 
placed in trip (or the associated trip system placed in
 
trip) within the allowed Completion Time, the plant must be
 
placed in a MODE or other specified condition in which the
 
LCO does not apply. The Completion Times are reasonable, based on operating experience, to reach the specified
 
condition from full power conditions in an orderly manner
 
and without challenging plant systems. In addition, the
 
Completion Time of Required Action E.1 is consistent with
 
the Completion Time provided in LCO 3.2.2, "MINIMUM CRITICAL
 
POWER RATIO (MCPR)."
H.1 If the channel(s) is not restored to OPERABLE status or
 
placed in trip (or the associated trip system placed in
 
trip) within the allowed Completion Time, the plant must be
 
placed in a MODE or other specified condition in which the
 
LCO does not apply. This is done by immediately initiating
 
action to fully insert all insertable control rods in core
 
cells containing one or more fuel assemblies. Control rods
 
in core cells containing no fuel assemblies do not affect
 
the reactivity of the core and are, therefore, not required
 
to be inserted. Action must continue until all insertable
 
control rods in core cells containing one or more fuel
 
assemblies are fully inserted.
 
SURVEILLANCE As noted at the beginning of the SRs, the SRs for each RPS REQUIREMENTS instrumentation Function are located in the SRs column of Table 3.3.1.1-1.
The Surveillances are modified by a Note to indicate that, when a channel is placed in an inoperable status solely for
 
performance of required Surveillances, entry into associated
 
Conditions and Required Actions may be delayed for up to
 
6 hours, provided the associated Function maintains RPS trip
 
capability. Upon completion of the Surveillance, or
 
expiration of the 6 hour allowance, the channel must be
 
returned to OPERABLE status or the applicable Condition
 
(continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-26 Revision 0 BASES SURVEILLANCE entered and Required Actions taken. This Note is based on REQUIREMENTS the RPS reliability analysis (Ref. 10) assumption of the (continued) average time required to perform channel surveillance. That analysis demonstrated that the 6 hour testing allowance does
 
not significantly reduce the probability that the RPS will
 
trip when necessary.
 
SR  3.3.1.1.1
 
Performance of the CHANNEL CHECK once every 12 hours ensures
 
that a gross failure of instrumentation has not occurred. A
 
CHANNEL CHECK is normally a comparison of the parameter
 
indicated on one channel to a similar parameter on other
 
channels. It is based on the assumption that instrument
 
channels monitoring the same parameter should read
 
approximately the same value. Significant deviations
 
between the instrument channels could be an indication of
 
excessive instrument drift on one of the channels or
 
something even more serious. A CHANNEL CHECK will detect
 
gross channel failure; thus, it is key to verifying the
 
instrumentation continues to operate properly between each
 
CHANNEL CALIBRATION.
 
Agreement criteria are determined by the plant staff based
 
on a combination of the channel instrument uncertainties, including indication and readability. If a channel is
 
outside the criteria, it may be an indication that the
 
instrument has drifted outside its limit.
 
The Frequency is based upon operating experience that
 
demonstrates channel failure is rare. The CHANNEL CHECK
 
supplements less formal, but more frequent, checks of
 
channels during normal operational use of the displays
 
associated with the channels required by the LCO.
 
SR  3.3.1.1.2
 
To ensure that the APRMs are accurately indicating the true
 
core average power, the APRMs are calibrated to the reactor
 
power calculated from a heat balance. The Frequency of once
 
per 7 days is based on minor changes in LPRM sensitivity, which could affect the APRM reading between performances of
 
SR 3.3.1.1.8.
 
(continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-27 Revision 0 BASES SURVEILLANCE SR  3.3.1.1.2 (continued)
REQUIREMENTS An allowance is provided that requires the SR to be
 
performed only at  25% RTP because it is difficult to accurately maintain APRM indication of core THERMAL POWER
 
consistent with a heat balance when
< 25% RTP. At low power levels, a high degree of accuracy is unnecessary because of
 
the inherent margin to thermal limits (MCPR and APLHGR). At 25% RTP, the Surveillance is required to have been satisfactorily performed within the last 7 days in
 
accordance with SR 3.0.2. A Note is provided which allows
 
an increase in THERMAL POWER above 25% if the 7 day
 
Frequency is not met per SR 3.0.2. In this event, the SR
 
must be performed within 12 hours after reaching or
 
exceeding 25% RTP. Twelve hours is based on operating
 
experience and in consideration of providing a reasonable
 
time in which to complete the SR.
 
SR  3.3.1.1.3
 
The Average Power Range Monitor Flow Biased Simulated
 
Thermal Power-Upscale Function uses the recirculation loop
 
drive flows to vary the trip setpoint. This SR ensures that
 
the total loop drive flow signals from the flow unit used to
 
vary the setpoint are appropriately compared to a calibrated
 
flow signal and therefore the APRM Function accurately
 
reflects the required setpoint as a function of flow. Each
 
flow signal from the respective flow unit must be  100% of the calibrated flow signal. If the flow unit signal is not
 
within the limit, one required APRM that receives an input
 
from the inoperable flow unit must be declared inoperable.
The Frequency of 7 days is based on engineering judgment, operating experience, and the reliability of this
 
instrumentation.
 
SR  3.3.1.1.4
 
A CHANNEL FUNCTIONAL TEST is performed on each required
 
channel to ensure that the channel will perform the intended
 
function. A successful test of the required contact(s) of a
 
(continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-28 Revision 0 BASES SURVEILLANCE SR  3.3.1.1.4 (continued)
REQUIREMENTS channel relay may be performed by the verification of the
 
change of state of a single contact of the relay. This
 
clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a
 
relay. This is acceptable because all of the other required
 
contacts of the relay are verified by other Technical
 
Specifications and non-Technical Specifications tests at
 
least once per refueling interval with applicable
 
extensions.
 
Any setpoint adjustment shall be consistent with the
 
assumptions of the current plant specific setpoint
 
methodology.
 
As noted, SR 3.3.1.1.4 is not required to be performed when
 
entering MODE 2 from MODE 1 since testing of the MODE 2
 
required IRM and APRM Functions cannot be performed in
 
MODE 1 without utilizing jumpers, lifted leads, or movable
 
links. This allows entry into MODE 2 if the 7 day Frequency
 
is not met per SR 3.0.2. In this event, the SR must be
 
performed within 24 hours after entering MODE 2 from MODE 1.
 
Twenty-four hours is based on operating experience and in
 
consideration of providing a reasonable time in which to
 
complete the SR.
A Frequency of 7 days provides an acceptable level of system
 
average unavailability over the Frequency interval and is
 
based on reliability analysis (Ref. 10).
 
SR  3.3.1.1.5
 
A CHANNEL FUNCTIONAL TEST is performed on each required
 
channel to ensure that the channel will perform the intended
 
Function. A successful test of the required contact(s) of a
 
channel relay may be performed by the verification of the
 
change of state of a single contact of the relay. This
 
clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a
 
relay. This is acceptable because all of the other required
 
contacts of the relay are verified by other Technical
 
Specifications and non-Technical Specifications tests at (continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-29 Revision 0 BASES SURVEILLANCE SR  3.3.1.1.5 (continued)
REQUIREMENTS least once per refueling interval with applicable
 
extensions. In accordance with Reference 10, the scram
 
contactors must be tested as part of the Manual Scram
 
Function. A Frequency of 7 days provides an acceptable
 
level of system average availability over the Frequency and
 
is based on the reliability analysis of Reference 10.  (The
 
Manual Scram Function's CHANNEL FUNCTIONAL TEST Frequency
 
was credited in the analysis to extend many automatic scram
 
Functions' Frequencies.)
 
SR  3.3.1.1.6 and SR  3.3.1.1.7
 
These Surveillances are established to ensure that no gaps
 
in neutron flux indication exist from subcritical to power
 
operation for monitoring core reactivity status.
 
The overlap between SRMs and IRMs is required to be
 
demonstrated to ensure that reactor power will not be
 
increased into a region without adequate neutron flux
 
indication. This is required prior to fully withdrawing
 
SRMs since indication is being transitioned from the SRMs to
 
the IRMs.
 
The overlap between IRMs and APRMs is of concern when
 
reducing power into the IRM range. On power increases, the
 
system design will prevent further increases (initiate a rod
 
block) if adequate overlap is not maintained. The IRM/APRM
 
and SRM/IRM overlap are acceptable if a  decade overlap exists.
 
As noted, SR 3.3.1.1.7 is only required to be met during
 
entry into MODE 2 from MODE 1. That is, after the overlap
 
requirement has been met and indication has transitioned to
 
the IRMs, maintaining overlap is not required (APRMs may be
 
reading downscale once in MODE 2).
 
If overlap for a group of channels is not demonstrated (e.g., IRM/APRM overlap), the reason for the failure of the
 
Surveillance should be determined and the appropriate (continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-30 Revision 23 BASES SURVEILLANCE SR  3.3.1.1.6 and SR  3.3.1.1.7 (continued)
REQUIREMENTS channel(s) declared inoperable. Only those appropriate
 
channel(s) that are required in the current MODE or
 
condition should be declared inoperable.
 
A Frequency of 7 days is reasonable based on engineering
 
judgment and the reliability of the IRMs and APRMs.
 
SR  3.3.1.1.8 LPRM gain settings are determined from the local flux
 
profiles measured by the Traversing Incore Probe (TIP)
 
System. This establishes the relative local flux profile
 
for appropriate representative input to the APRM System.
 
The 1000 effective full power hours (EFPH) Frequency is
 
based on operating experience with LPRM sensitivity changes.
 
SR 3.3.1.1.8 also ensures the operability of the OPRM system (specification 3.3.1.3).
 
SR  3.3.1.1.9 and SR  3.3.1.1.12
 
A CHANNEL FUNCTIONAL TEST is performed on each required
 
channel to ensure that the channel will perform the intended
 
function. A successful test of the required contact(s) of a
 
channel relay may be performed by the verification of the
 
change of state of a single contact of the relay. This
 
clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a
 
relay. This is acceptable because all of the other required
 
contacts of the relay are verified by other Technical
 
Specifications and non-Technical Specifications tests at
 
lease once per refueling interval with applicable
 
extensions. Any setpoint adjustment shall be consistent
 
with the assumptions of the current plant specific setpoint
 
methodology.
 
The 92 day Frequency of SR 3.3.1.1.9 is based on the
 
reliability analysis of Reference 10.
 
The 24 month Frequency of SR 3.3.1.1.12 is based on the need
 
to perform this Surveillance under the conditions that apply
 
during a plant outage and the potential for an unplanned (continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-31 Revision 13 BASES SURVEILLANCE SR  3.3.1.1.9 and SR  3.3.1.1.12 (continued)
REQUIREMENTS transient if the Surveillance were performed with the
 
reactor at power. Operating experience has shown that these
 
components usually pass the Surveillance when performed at
 
the 24 month Frequency.
 
SR  3.3.1.1.10, SR  3.3.1.1.11, and SR  3.3.1.1.13
 
A CHANNEL CALIBRATION is a complete check of the instrument
 
loop, including associated trip unit, and the sensor. This
 
test verifies the channel responds to the measured parameter
 
within the necessary range and accuracy. CHANNEL
 
CALIBRATION leaves the channel adjusted to account for
 
instrument drifts between successive calibrations consistent
 
with the plant specific setpoint methodology.
 
Note 1 of SR 3.3.1.1.11 and SR 3.3.1.1.13 states that
 
neutron detectors are excluded from CHANNEL CALIBRATION
 
because of the difficulty of simulating a meaningful signal.
 
Changes in neutron detector sensitivity are compensated for
 
by performing the 7 day calorimetric calibration (SR 3.3.1.1.2) and the 1000 EFPH LPRM calibration against
 
the TIPs (SR 3.3.1.1.8). A second Note to SR 3.3.1.1.11 and
 
SR 3.3.1.1.13 is provided that requires the APRM and IRM SRs
 
to be performed within 24 hours of entering MODE 2 from MODE
: 1. Testing of the MODE 2 APRM and IRM Functions cannot be
 
performed in MODE 1 without utilizing jumpers, lifted leads, or movable links. This Note allows entry into MODE 2 from
 
MODE 1 if the associated Frequency is not met per SR 3.0.2.
Twenty-four hours is based on operating experience and in
 
consideration of providing a reasonable time in which to
 
complete the SR. The Frequencies of SR 3.3.1.1.10 and
 
SR 3.3.1.1.11 are based upon the assumption of a 92 day and
 
184 day calibration interval, respectively, in the
 
determination of the magnitude of equipment drift in the
 
setpoint analysis. The Frequency of SR 3.3.1.1.13 is based on the assumption of a 24 month calibration interval in the
 
determination of the magnitude of equipment drift in the
 
setpoint analysis.
(continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-32 Revision 0 BASES SURVEILLANCE SR  3.3.1.1.14 REQUIREMENTS (continued) The Average Power Range Monitor Flow Biased Simulated Thermal Power-Upscale Function uses an electronic filter
 
circuit to generate a signal proportional to the core
 
THERMAL POWER from the APRM neutron flux signal. This
 
filter circuit is representative of the fuel heat transfer
 
dynamics that produce the relationship between the neutron
 
flux and the core THERMAL POWER. The filter time constant
 
must be verified to ensure that the channel is accurately
 
reflecting the desired parameter.
The Frequency of 24 months is based on engineering judgment
 
and reliability of the components.
 
SR  3.3.1.1.15
 
The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the
 
OPERABILITY of the required trip logic for a specific
 
channel. The functional testing of control rods, in
 
LCO 3.1.3, "Control Rod OPERABILITY," and SDV vent and drain
 
valves, in LCO 3.1.8, "Scram Discharge Volume (SDV) Vent and
 
Drain Valves," overlaps this Surveillance to provide
 
complete testing of the assumed safety function.
The 24 month Frequency is based on the need to perform this
 
Surveillance under the conditions that apply during a plant
 
outage and the potential for an unplanned transient if the
 
Surveillance were performed with the reactor at power.
 
Operating experience has shown that these components usually
 
pass the Surveillance when performed at the 24 month
 
Frequency.
 
SR  3.3.1.1.16
 
This SR ensures that scrams initiated from the Turbine Stop
 
Valve-Closure and Turbine Control Valve Fast Closure, Trip
 
Oil Pressure-Low Functions will not be inadvertently
 
bypassed when THERMAL POWER is  25% RTP. This involves calibration of the bypass channels. Adequate margins for
 
(continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-33 Revision 15 BASES SURVEILLANCE SR  3.3.1.1.16 (continued)
REQUIREMENTS the instrument setpoint methodology are incorporated into
 
the Allowable Value and the actual setpoint. Because main
 
turbine bypass flow can affect this setpoint
 
nonconservatively (THERMAL POWER is derived from turbine
 
first stage pressure), the main turbine bypass valves must
 
remain closed during in-service calibration at THERMAL POWER 25% RTP, if performing the calibration using actual turbine first stage pressure, to ensure that the calibration
 
is valid.
If any bypass channel setpoint is nonconservative (i.e., the
 
Functions are bypassed at  25% RTP, either due to open main turbine bypass valve(s) or other reasons), then the affected
 
Turbine Stop Valve-Closure and Turbine Control Valve Fast
 
Closure, Trip Oil Pressure-Low Functions are considered
 
inoperable. Alternatively, the bypass channel can be placed
 
in the conservative condition (nonbypass). If placed in the
 
nonbypass condition, this SR is met and the channel is
 
considered OPERABLE.
 
The Frequency of 24 months is based on engineering judgment
 
and reliability of the components.
 
SR  3.3.1.1.17
 
This SR ensures that the individual channel response times
 
are less than or equal to the maximum values assumed in the
 
accident analysis. The RPS RESPONSE TIME acceptance
 
criteria are included in Reference 11.
 
RPS RESPONSE TIME may be verified by actual response time
 
measurements in any series of sequential, overlapping, or
 
total channel measurements. However, the sensor for Function 4 is allowed to be excluded from specific RPS RESPONSE TIME measurement if the conditions of Reference 12
 
are satisfied. If these conditions are satisfied, sensor
 
response time may be allocated based on either assumed
 
design sensor response time or the manufacturer's stated
 
design response time. When the requirements of Reference 12 are not satisfied, sensor response time must be measured. 
(continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-34 Revision 15 BASES SURVEILLANCE SR  3.3.1.1.17 (continued)
REQUIREMENTS Also, regardless of whether or not the sensor response time is measured, the response time for the remaining portion of
 
the channel, including the trip unit and relay logic, is
 
required to be measured. The sensor and relay/logic components for Function 3 are assumed to operate at the design response time and therefore, are excluded from specific RPS RESPONSE TIME measurement. This allowance is supported by References 12 and 14, which determined that significant degradation of the channel response time can be detected during performance of other Technical Specification surveillance requirements. In addition, the response time of the limit switches for Function 8 may be assumed to be
 
the design limit switch response time and therefore, are
 
excluded from the RPS RESPONSE TIME testing. This is
 
allowed, as documented in Reference 13, since the actual
 
measurement of the limit switch response time is not
 
practicable as this test is done during the refueling outage
 
when the turbine stop valves are fully closed, and thus the
 
limit switch in the RPS circuitry is open. The design limit
 
switch response time is 10 ms.
 
As noted (Note 1), neutron detectors are excluded from RPS
 
RESPONSE TIME testing. The principles of detector operation
 
virtually ensure an instantaneous response time. Note 3
 
modifies the starting point of the RPS RESPONSE TIME test
 
for Function 9, since this starting point (start of turbine
 
control valve fast closure) corresponds to safety analysis
 
assumptions.
 
RPS RESPONSE TIME tests are conducted on a 24 month
 
STAGGERED TEST BASIS. Note 2 requires STAGGERED TEST BASIS
 
Frequency to be determined based on 4 channels per trip
 
system, in lieu of the 8 channels specified in Table
 
3.3.1.1-1 for the MSIV Closure Function. This Frequency is
 
based on the logic interrelationships of the various
 
channels required to produce an RPS scram signal. 
 
Therefore, staggered testing results in response time
 
verification of these devices every 24 months. The 24 month
 
Frequency is consistent with the refueling cycle and is
 
based upon plant operating experience, which shows that
 
random failures of instrumentation components causing
 
serious time degradation, but not channel failure, are
 
infrequent. (continued)
RPS Instrumentation B 3.3.1.1
 
LaSalle 1 and 2 B 3.3.1.1-35 Revision 15 BASES  (continued)
 
REFERENCES 1. UFSAR, Section 7.2.
: 2. UFSAR, Section 5.2.2.
: 3. UFSAR, Section 6.3.3.
: 4. UFSAR, Chapter 15.
: 5. UFSAR, Section 15.4.1.
: 6. NEDO-23842, "Continuous Control Rod Withdrawal in the Startup Range," April 18, 1978. 7. UFSAR, Section 7.6.3.3.
: 8. UFSAR, Section 15.4.9.
: 9. Letter, P. Check (NRC) to G. Lainas (NRC), "BWR Scram Discharge System Safety Evaluation," December 1, 1980.
: 10. NEDC-30851-P-A, "Technical Specification Improvement Analyses for BWR Reactor Protection System,"
March 1988.
: 11. Technical Requirements Manual.
: 12. NEDO-32291-A, "System Analyses for the Elimination of Selected Response Time Testing Requirements," October
 
1995. 13. Letter, W. G. Guldemond (NRC) to C. Reed (ComEd), dated January 28, 1987.
: 14. NEDO-32291-A Supplement 1, "System Analysis for the Elimination of Selected Response Time Testing Requirements," October 1999.
 
SRM Instrumentation B 3.3.1.2
 
LaSalle 1 and 2 B 3.3.1.2-1 Revision 0 B 3.3  INSTRUMENTATION
 
B 3.3.1.2  Source Range Monitor (SRM) Instrumentation
 
BASES
 
BACKGROUND The SRMs provide the operator with information relative to the neutron level at very low flux levels in the core. As
 
such, the SRM indication is used by the operator to monitor
 
the approach to criticality and to determine when
 
criticality is achieved. The SRMs are not fully withdrawn
 
until the count rate is greater than a minimum allowed count
 
rate (a control rod block is set at this condition). After
 
SRM to intermediate range monitor (IRM) overlap is
 
demonstrated (as required by SR 3.3.1.1.6), the SRMs are
 
normally fully withdrawn from the core.
The SRM subsystem of the Neutron Monitoring System (NMS)
 
consists of four channels. Each of the SRM channels can be
 
bypassed, but only one at any given time, by the operation
 
of a bypass switch. Each channel includes one detector that
 
can be physically positioned in the core. Each detector
 
assembly consists of a miniature fission chamber with
 
associated cabling, signal conditioning equipment, and
 
electronics associated with the various SRM functions. The
 
signal conditioning equipment converts the current pulses
 
from the fission chamber to analog DC currents that
 
correspond to the count rate. Each channel also includes
 
indication, alarm, and control rod blocks. However, this
 
LCO specifies OPERABILITY requirements only for the
 
monitoring and indication functions of the SRMs.
 
During refueling, shutdown, and low power operations, the
 
primary indication of neutron flux levels is provided by the
 
SRMs or special movable detectors connected to the normal
 
SRM circuits. The SRMs provide monitoring of reactivity
 
changes during fuel or control rod movement and give the
 
control room operator early indication of unexpected
 
subcritical multiplication that could be indicative of an
 
approach to criticality.
 
APPLICABLE Prevention and mitigation of prompt reactivity excursions SAFETY ANALYSES during refueling and low power operation are provided by LCO 3.9.1, "Refueling Equipment Interlocks"; LCO 3.1.1, "SHUTDOWN MARGIN (SDM)"; LCO 3.3.1.1, "Reactor Protection (continued)
SRM Instrumentation B 3.3.1.2
 
LaSalle 1 and 2 B 3.3.1.2-2 Revision 0 BASES APPLICABLE System (RPS) Instrumentation," Intermediate Range Monitor SAFETY ANALYSES (IRM) Neutron Flux High and Average Power Range Monitor (continued) (APRM) Neutron Flux-High, Setdown Functions; and LCO 3.3.2.1, "Control Rod Block Instrumentation."  The SRMs have no safety function and are not assumed to
 
function during any UFSAR design basis accident or transient
 
analysis. However, the SRMs provide the only on scale
 
monitoring of neutron flux levels during startup and
 
refueling. Therefore, they are being retained in the
 
Technical Specifications.
 
LCO During startup in MODE 2, three of the four SRM channels are required to be OPERABLE to monitor the reactor flux level
 
prior to and during control rod withdrawal, to monitor
 
subcritical multiplication and reactor criticality, and to
 
monitor neutron flux level and reactor period until the flux
 
level is sufficient to maintain the IRM on Range 3 or above.
 
All channels but one are required in order to provide a
 
representation of the overall core response during those
 
periods when reactivity changes are occurring throughout the
 
core. In MODES 3 and 4, with the reactor shut down, two SRM
 
channels provide redundant monitoring of flux levels in the
 
core.
 
In MODE 5, during a spiral offload or reload, an SRM outside
 
the fueled region will no longer be required to be OPERABLE, since it is not capable of monitoring neutron flux in the
 
fueled region of the core. Thus, CORE ALTERATIONS are
 
allowed in a quadrant with no OPERABLE SRM in an adjacent
 
quadrant, as provided in the Table 3.3.1.2-1, footnote (b),
requirement that the bundles being spiral reloaded or spiral
 
offloaded are all in a single fueled region containing at
 
least one OPERABLE SRM is met. Spiral reloading and
 
offloading encompass reloading or offloading a cell on the
 
edges of a continuous fueled region (the cell can be
 
reloaded or offloaded in any sequence).
 
In nonspiral routine operations, two SRMs are required to be
 
OPERABLE to provide redundant monitoring of reactivity
 
changes occurring in the reactor core. Because of the local
 
nature of reactivity changes during refueling, adequate
 
(continued)
SRM Instrumentation B 3.3.1.2
 
LaSalle 1 and 2 B 3.3.1.2-3 Revision 0 BASES LCO coverage is provided by requiring one SRM to be OPERABLE in (continued) the quadrant of the reactor core where CORE ALTERATIONS are being performed and the other SRM to be OPERABLE in an
 
adjacent quadrant containing fuel. These requirements
 
ensure that the reactivity of the core will be continuously
 
monitored during CORE ALTERATIONS.
Special movable detectors, according to Table 3.3.1.2-1, footnote (c), may be used in MODE 5 in place of the normal
 
SRM nuclear detectors. These special detectors must be
 
connected to the normal SRM circuits in the NMS such that
 
the applicable neutron flux indication can be generated.
 
These special detectors provide more flexibility in
 
monitoring reactivity changes during fuel loading, since
 
they can be positioned anywhere within the core during
 
refueling. They must still meet the location requirements
 
of SR 3.3.1.2.2, and all other required SRs for SRMs.
 
For an SRM channel to be considered OPERABLE, it must be
 
providing neutron flux monitoring indication. In addition, in MODE 5, the required SRMs must be inserted to the normal
 
operating level and be providing continuous visual
 
indication in the control room.
 
APPLICABILITY The SRMs are required to be OPERABLE in MODE 2 prior to the IRMs being on scale on Range 3, and MODES 3, 4, and 5, to
 
provide for neutron monitoring. In MODE 1, the APRMs
 
provide adequate monitoring of reactivity changes in the
 
core; therefore, the SRMs are not required. In MODE 2, with
 
IRMs on Range 3 or above, the IRMs provide adequate
 
monitoring and the SRMs are not required.
 
ACTIONS A.1 and B.1 In MODE 2, with the IRMs on Range 2 or below, SRMs provide
 
the means of monitoring core reactivity and criticality.
 
With any number of the required SRMs inoperable, the ability
 
to monitor is degraded. Therefore, a limited time is
 
allowed to restore the inoperable channels to OPERABLE
 
status.
 
Providing that at least one SRM remains OPERABLE, Required
 
Action A.1 allows 4 hours to restore the required SRMs to
 
OPERABLE status. This is a reasonable time since there is (continued)
SRM Instrumentation B 3.3.1.2
 
LaSalle 1 and 2 B 3.3.1.2-4 Revision 0 BASES ACTIONS A.1 and B.1 (continued) adequate capability remaining to monitor the core, limited
 
risk of an event during this time, and sufficient time to
 
take corrective actions to restore the required SRMs to
 
OPERABLE status or to establish alternate IRM monitoring
 
capability. During this time, control rod withdrawal and
 
power increase are not precluded by this Required Action.
 
Having the ability to monitor the core with at least one
 
SRM, proceeding to IRM Range 3 or greater (with overlap
 
required by SR 3.3.1.1.6) and thereby exiting the
 
Applicability of this LCO, is acceptable for ensuring
 
adequate core monitoring and allowing continued operation.
 
With three required SRMs inoperable, Required Action B.1
 
allows no positive changes in reactivity (control rod
 
withdrawal must be immediately suspended) due to the
 
inability to monitor the changes. Required Action A.1 still
 
applies and allows 4 hours to restore monitoring capability
 
prior to requiring control rod insertion. This allowance is
 
based on the limited risk of an event during this time, provided that no control rod withdrawals are allowed, and
 
the desire to concentrate efforts on repair, rather than to
 
immediately shut down, with no SRMs OPERABLE.
 
C.1 In MODE 2 with the IRMs on Range 2 or below, if the required
 
number of SRMs is not restored to OPERABLE status within the
 
allowed Completion Time, the reactor shall be placed in
 
MODE 3. With all control rods fully inserted, the core is
 
in its least reactive state with the most margin to
 
criticality. The allowed Completion Time of 12 hours is
 
reasonable, based on operating experience, to reach MODE 3
 
in an orderly manner and without challenging plant systems.
 
D.1 and D.2
 
With one or more required SRM channels inoperable in MODE 3
 
or 4, the neutron flux monitoring capability is degraded or
 
nonexistent. The requirement to fully insert all insertable
 
control rods ensures that the reactor will be at its minimum
 
reactivity level while no neutron monitoring capability is
 
available. Placing the reactor mode switch in the shutdown (continued)
SRM Instrumentation B 3.3.1.2
 
LaSalle 1 and 2 B 3.3.1.2-5 Revision 0 BASES ACTIONS D.1 and D.2 (continued) position prevents subsequent control rod withdrawal by
 
maintaining a control rod block. The allowed Completion
 
Time of 1 hour is sufficient to accomplish the Required
 
Action, and takes into account the low probability of an
 
event requiring the SRM occurring during this time.
 
E.1 and E.2
 
With one or more required SRMs inoperable in MODE 5, the
 
capability to detect local reactivity changes in the core
 
during refueling is degraded. CORE ALTERATIONS must be
 
immediately suspended, and action must be immediately
 
initiated to fully insert all insertable control rods in
 
core cells containing one or more fuel assemblies.
 
Suspending CORE ALTERATIONS prevents the two most probable
 
causes of reactivity changes, fuel loading and control rod
 
withdrawal, from occurring. Inserting all insertable
 
control rods ensures that the reactor will be at its minimum
 
reactivity, given that fuel is present in the core.
 
Suspension of CORE ALTERATIONS shall not preclude completion
 
of the movement of a component to a safe, conservative
 
position.
 
Action (once required to be initiated) to insert control
 
rods must continue until all insertable rods in core cells
 
containing one or more fuel assemblies are inserted.
 
SURVEILLANCE As noted at the beginning of the SRs, the SRs for each SRM REQUIREMENTS Applicable MODE or other specified condition are found in the SRs column of Table 3.3.1.2-1.
 
SR  3.3.1.2.1 and SR  3.3.1.2.3
 
Performance of the CHANNEL CHECK ensures that a gross
 
failure of instrumentation has not occurred. A CHANNEL
 
CHECK is normally a comparison of the parameter indicated on
 
one channel to the same parameter indicated on other similar
 
channels. It is based on the assumption that instrument
 
channels monitoring the same parameter should read
 
approximately the same value. Significant deviations 
 
(continued)
SRM Instrumentation B 3.3.1.2
 
LaSalle 1 and 2 B 3.3.1.2-6 Revision 0 BASES SURVEILLANCE SR  3.3.1.2.1 and SR  3.3.1.2.3  (continued)
REQUIREMENTS between the instrument channels could be an indication of
 
excessive instrument drift in one of the channels or
 
something even more serious. A CHANNEL CHECK will detect
 
gross channel failure; thus, it is key to verifying the
 
instrumentation continues to operate properly between each
 
CHANNEL CALIBRATION.
 
Agreement criteria are determined by the plant staff, based
 
on a combination of the channel instrument uncertainties, including indication and readability. If a channel is
 
outside the criteria, it may be an indication that the
 
instrument has drifted outside its limit.
 
The Frequency of once every 12 hours for SR 3.3.1.2.1 is
 
based on operating experience that demonstrates channel
 
failure is rare. While in MODES 3 and 4, reactivity changes
 
are not expected; therefore, the 12 hour Frequency is
 
relaxed to 24 hours for SR 3.3.1.2.3. The CHANNEL CHECK
 
supplements less formal, but more frequent, checks of
 
channels during normal operational use of the displays
 
associated with the channels required by the LCO.
 
SR  3.3.1.2.2
 
To provide adequate coverage of potential reactivity changes
 
in the core, one SRM is required to be OPERABLE in the
 
quadrant where CORE ALTERATIONS are being performed, and the
 
other OPERABLE SRM must be in an adjacent quadrant
 
containing fuel. Note 1 states that this SR is required to
 
be met only during CORE ALTERATIONS. It is not required to
 
be met at other times in MODE 5 since core reactivity
 
changes are not occurring. This Surveillance consists of a
 
review of plant logs to ensure that SRMs required to be
 
OPERABLE for given CORE ALTERATIONS are, in fact, OPERABLE.
 
In the event that only one SRM is required to be OPERABLE, per Table 3.3.1.2-1, footnote (b), only the a. portion of
 
this SR is effectively required. Note 2 clarifies that more
 
than one of the three requirements can be met by the same
 
OPERABLE SRM. The 12 hour Frequency is based upon operating
 
experience and supplements operational controls over
 
refueling activities, which include steps to ensure that the
 
SRMs required by the LCO are in the proper quadrant.
 
(continued)
SRM Instrumentation B 3.3.1.2
 
LaSalle 1 and 2 B 3.3.1.2-7 Revision 0 BASES SURVEILLANCE SR  3.3.1.2.4 REQUIREMENTS (continued) This Surveillance consists of a verification of the SRM instrument readout to ensure that the SRM reading is greater
 
than a specified minimum count rate with the detector fully
 
inserted. This ensures that the detectors are indicating
 
count rates indicative of neutron flux levels within the
 
core. With few fuel assemblies loaded, the SRMs will not
 
have a high enough count rate to satisfy the SR. Therefore, allowances are made for loading sufficient "source" material, in the form of irradiated fuel assemblies, to
 
establish the minimum count rate.
To accomplish this, the SR is modified by a Note that states
 
that the count rate is not required to be met on an SRM that
 
has less than or equal to four fuel assemblies adjacent to
 
the SRM and no other fuel assemblies are in the associated
 
core quadrant. With four or less fuel assemblies loaded
 
around each SRM and no other fuel assemblies in the
 
associated quadrant, even with a control rod withdrawn the
 
configuration will not be critical. When movable detectors
 
are being used, detector location must be selected such that
 
each group of fuel assemblies is separated by at least two
 
fuel cells from any other fuel assemblies.
 
The Frequency is based upon channel redundancy and other
 
information available in the control room, and ensures that
 
the required channels are frequently monitored while core
 
reactivity changes are occurring. When no reactivity
 
changes are in progress, the Frequency is relaxed from
 
12 hours to 24 hours.
 
SR  3.3.1.2.5 and SR  3.3.1.2.6
 
Performance of a CHANNEL FUNCTIONAL TEST demonstrates the
 
associated channel will function properly. A successful
 
test of the required contact(s) of a channel relay may be
 
performed by the verification of the change of state of a
 
single contact of the relay. This clarifies what is an
 
acceptable CHANNEL FUNCTIONAL TEST of a relay. This is
 
acceptable because all of the other required contacts of the
 
relay are verified by other Technical Specifications and
 
(continued)
SRM Instrumentation B 3.3.1.2
 
LaSalle 1 and 2 B 3.3.1.2-8 Revision 0 BASES SURVEILLANCE SR  3.3.1.2.5 and SR  3.3.1.2.6 (continued)
REQUIREMENTS Non-Technical Specifications tests at least once per
 
refueling interval with applicable extensions. SR 3.3.1.2.5
 
is required in MODE 5, and the 7 day Frequency ensures that
 
the channels are OPERABLE while core reactivity changes
 
could be in progress. This 7 day Frequency is reasonable, based on operating experience and on other Surveillances (such as a CHANNEL CHECK) that ensure proper functioning
 
between CHANNEL FUNCTIONAL TESTS.
 
SR 3.3.1.2.6 is required to be met in MODE 2 with IRMs on
 
Range 2 or below and in MODES 3 and 4. Since core
 
reactivity changes do not normally take place in MODES 3 and
 
4 and core reactivity changes are due only to control rod
 
movement in MODE 2, the Frequency is extended from 7 days to
 
31 days. The 31 day Frequency is based on operating
 
experience and on other Surveillances (such as CHANNEL
 
CHECK) that ensure proper functioning between CHANNEL
 
FUNCTIONAL TESTS.
 
Verification of the signal to noise ratio also ensures that
 
the detectors are inserted to a normal operating level. In
 
a fully withdrawn condition, the detectors are sufficiently
 
removed from the fueled region of the core to essentially
 
eliminate neutrons from reaching the detector. Any count
 
rate obtained while fully withdrawn is assumed to be "noise" only.
 
With few fuel assemblies loaded, the SRMs will not have a
 
high enough count rate to determine the signal to noise
 
ratio. Therefore, allowances are made for loading
 
sufficient "source" material, in the form of irradiated fuel
 
assemblies, to establish the conditions necessary to
 
determine the signal to noise ratio. To accomplish this, SR
 
3.3.1.2.5 is modified by a Note that states that the
 
determination of signal to noise ratio is not required to be
 
met on an SRM that has less than or equal to four fuel
 
assemblies adjacent to the SRM and no other fuel assemblies
 
are in the associated core quadrant. With four or less fuel
 
assemblies loaded around each SRM and no other fuel
 
assemblies in the associated quadrant, even with a control
 
rod withdrawn the configuration will not be critical.
 
(continued)
SRM Instrumentation B 3.3.1.2
 
LaSalle 1 and 2 B 3.3.1.2-9 Revision 0 BASES SURVEILLANCE SR  3.3.1.2.5 and SR  3.3.1.2.6 (continued)
REQUIREMENTS The Note to SR 3.3.1.2.6 allows the Surveillance to be
 
delayed until entry into the specified condition of the
 
Applicability. The SR must be performed in MODE 2 within
 
12 hours of entering MODE 2 with IRMs on Range 2 or below.
 
The allowance to enter the Applicability with the 31 day
 
Frequency not met is reasonable, based on the limited time
 
of 12 hours allowed after entering the Applicability and the
 
inability to perform the Surveillance while at higher power
 
levels. Although the Surveillance could be performed while
 
on IRM Range 3, the plant would not be expected to maintain
 
steady state operation at this power level. In this event, the 12 hour Frequency is reasonable, based on the SRMs being
 
otherwise verified to be OPERABLE (i.e., satisfactorily
 
performing the CHANNEL CHECK) and the time required to
 
perform the Surveillances.
 
SR  3.3.1.2.7
 
Performance of a CHANNEL CALIBRATION verifies the
 
performance of the SRM detectors and associated circuitry.
 
The Frequency considers the plant conditions required to
 
perform the test, the ease of performing the test, and the
 
likelihood of a change in the system or component status.
 
The neutron detectors are excluded from the CHANNEL
 
CALIBRATION (Note 1) because they cannot readily be
 
adjusted. The detectors are fission chambers that are
 
designed to have a relatively constant sensitivity over the
 
range, and with an accuracy specified for a fixed useful
 
life.
 
Note 2 to the Surveillance allows the Surveillance to be
 
delayed until entry into the specified condition of the
 
Applicability. The SR must be performed in MODE 2 within 12
 
hours of entering MODE 2 with IRMs on Range 2 or below. The
 
allowance to enter the Applicability with the 24 month
 
Frequency not met is reasonable, based on the limited time
 
of 12 hours allowed after entering the Applicability and the
 
inability to perform the Surveillance while at higher power
 
levels. Although the Surveillance could be performed while (continued)
SRM Instrumentation B 3.3.1.2
 
LaSalle 1 and 2 B 3.3.1.2-10 Revision 0 BASES SURVEILLANCE SR  3.3.1.2.7 (continued)
REQUIREMENTS on IRM Range 3, the plant would not be expected to maintain
 
steady state operation at this power level. In this event, the 12 hour Frequency is reasonable, based on the SRMs being
 
otherwise verified to be OPERABLE (i.e., satisfactorily
 
performing the CHANNEL CHECK) and the time required to
 
perform the Surveillances.
 
REFERENCES None.
 
OPRM Instrumentation B 3.3.1.3 LaSalle 1 and 2 B 3.3.1.3-1 Revision 30 B 3.3  INSTRUMENTATION B 3.3.1.3 OSCILLATION POWER RANGE MONITOR (OPRM) INSTRUMENTATION
 
BASES BACKGROUND General Design Criteria 10 (GDC 10) requires the reactor core and associated coolant, control, and protection
 
systems to be designed with appropriate margin to assure
 
that acceptable fuel design limits are not exceeded during any condition of normal operation, including the effects of anticipated operational occurrences. Additionally, GDC 12
 
requires the reactor core and associated coolant, control
 
and protection systems to be designed to assure that power
 
oscillations which can result in conditions exceeding acceptable fuel design limits are either not possible or can be reliably and readily detected and suppressed. The
 
OPRM System provides compliance with GDC 10 and GDC 12, thereby providing protection from exceeding the fuel
 
minimum critical power ratio (MCPR) safety limit.
References 1, 2, and 3 describe three separate algorithms for detecting stability related oscillations:  the period
 
based detection algorithm, the amplitude based algorithm, and the growth rate algorithm. The OPRM System hardware implements these algorithms in microprocessor based modules. These modules execute the algorithms based on
 
local power range monitor (LPRM) inputs and generate alarms
 
and trips based on these calculations. These trips result
 
in tripping the Reactor Protection System (RPS) when the
 
appropriate RPS trip logic is satisfied, as described in the Bases for LCO 3.3.1.1, "Reactor Protection System (RPS)
 
Instrumentation."  Only the period based detection
 
algorithm is used for safety analysis. The remaining
 
algorithms provide defense in depth and additional
 
protection against unanticipated oscillations.
The period based detection algorithm detects a stability related oscillation based on the occurrence of a fixed
 
number of consecutive LPRM signal period confirmations
 
coincident with the LPRM signal peak to average amplitude exceeding a specified setpoint. Upon detection of a stability related oscillation, a trip is generated for that
 
OPRM channel.
(continued)
 
OPRM Instrumentation B 3.3.1.3 LaSalle 1 and 2 B 3.3.1.3-2 Revision 23 BASES  BACKGROUND The OPRM System consists of 4 OPRM trip channels, each    (continued) channel consisting of two OPRM modules. Each OPRM module receives input from LPRMs. Each OPRM module also receives input from the RPS average power range monitor (APRM) power and flow signals to automatically enable the trip function of the OPRM module. The outputs of the OPRM trip channels input to the associated RPS trip channels which are configured into a one-out-of-two taken twice trip logic as describe in the Bases for Section 3.3.1.1.
Each OPRM module is continuously tested by a self-test function. On detection of any OPRM module failure, either a Trouble alarm or INOP alarm is activated. The OPRM module provides an INOP alarm when the self-test feature indicates that the OPRM module may not be capable of meeting its functional requirements.
APPLICABLE It has been shown that BWR cores may exhibit SAFETY ANALYSIS thermal-hydraulic reactor instabilities in high power and low flow portions of the core power to flow operating domain (Reference 4). GDC 10 requires the reactor core and associated coolant, control, and protection systems to be designed with appropriate margin to assure that acceptable fuel design limits are not exceed during any condition of normal operation, including the effects of anticipated operational occurrences. GDC 12 requires assurance that power oscillations which can result in conditions exceeding acceptable fuel design limits are either not possible or can be reliably and readily detected and suppressed. The OPRM System provides compliance with GDC 10 and GDC 12 by detecting the onset of oscillations and suppressing them by initiating a reactor scram. This assures that the MCPR safety limit will not be violated for anticipated oscillations.
The OPRM Instrumentation satisfies Criterion 3 of 10 CFR 50.36(c) (2) (ii).
The OPERABILITY of the OPRM System is dependent on the OPERABILITY of the four individual instrumentation channels with their setpoints within the specified normal setpoint.
Each channel must also respond within its assumed response time. (continued)
 
OPRM Instrumentation B 3.3.1.3 LaSalle 1 and 2 B 3.3.1.3-3 Revision 23 BASES  APPLICABLE The nominal setpoints for the OPRM Period Based Trip SAFETY ANALYSES Function are specified in the Core Operating Limits Report.    (continued) The trip setpoints are treated as nominal setpoints and do not require additional allowances for uncertainty.
Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter value and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The OPRM period based setpoint is determined by cycle specific analysis based on positive margin between the Safety Limit MCPR and the Operating Limit MCPR minus the change in CPR (CPR). This methodology was approved for use by the NRC in Reference 5.
LCO Four channels of the OPRM System are required to be OPERABLE to ensure that stability related oscillations are detected and suppressed prior to exceeding the MCPR safety limit. Only one of the two OPRM modules (with an active period based detection algorithm) is required for OPRM channel OPERABILITY. The minimum number of LPRMs required to maintain the APRM system OPERABLE per LCO 3.3.1.1 provides an adequate number of LPRMs to maintain an OPRM channel OPERABLE.
APPLICABILITY The OPRM instrumentation is required to be OPERABLE in order to detect and suppress neutron flux oscillations in the event of thermal-hydraulic instability. As described in References 1, 2, 3, and 9, the region of anticipated oscillation is defined by THERMAL POWER  28.6% rated thermal power (RTP) and recirculation drive flow < 60% of rated recirculation drive flow. The OPRM trip is required  to be enabled in this region, and the OPRM must be capable of enabling the trip function as a result of anticipated transients that place the core in that power/flow condition. Therefore the OPRM instrumentation is required to be OPERABLE with THERMAL POWER  25% RTP. It is not necessary for the OPRM instrumentation to be OPERABLE with THERMAL POWER < 25% RTP because the MCPR safety limit is not applicable below 25% RTP. 
  (continued)
OPRM Instrumentation B 3.3.1.3 LaSalle 1 and 2 B 3.3.1.3-4 Revision 23 BASES  (continued)
ACTIONS The Note has been provided to modify the ACTIONS related to the OPRM instrumentation channels. Section 1.3 Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limit will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable OPRM instrumentation channel provide appropriate compensatory measures for separate inoperable channels. As such, this Note has been provided that allows a separate Condition entry for each inoperable OPRM instrumentation channel.
A.1, A.2 and A.3 Because of the reliability and on-line self-testing of the OPRM instrumentation and the redundancy of the RPS design, an allowable out of service time of 30 days has been shown to be acceptable (Ref. 6) to permit restoration of any inoperable channel to OPERABLE status. However, this out of service time is only acceptable provided the OPRM instrumentation still maintains OPRM trip capability (refer to Required Actions B.1 and B.2 Bases). The remaining OPERABLE OPRM channels continue to provide trip capability (see Condition B). The remaining OPRM modules have high reliability. With this high reliability, there is a low probability of a subsequent channel failure within the allowable out of service time. In addition, the OPRM modules continue to perform on-line self-testing and alert the operator if any further system degradation occurs.
If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the OPRM channel or associated RPS trip system must be placed in the tripped condition per Required Actions A.1 and A.2.
Placing the inoperable OPRM channel in trip (or the associated RPS trip system in trip) would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. 
(continued)
 
OPRM Instrumentation B 3.3.1.3 LaSalle 1 and 2 B 3.3.1.3-5 Revision 23 BASES  ACTIONS A.1, A.2 and A.3 (continued)
Alternately, if it is not desired to place the OPRM channel (or RPS trip system) in trip, the alternate method of detecting and suppressing thermal hydraulic instability oscillation is required (Required Action A.3). This alternate method is described in Reference 7. It consists of avoidance of the region where oscillations are possible, exiting this region if it is entered due to unforeseen circumstances, and increased operator awareness and monitoring for neutron flux oscillations while taking action to exit the region. If indications of oscillation, as described in Reference 7, are observed by the operator, the operator will take the actions described by procedures, which include initiating a manual scram of the reactor.
Continued operation with one OPRM channel inoperable, but not tripped, is permissible if the OPRM system maintains trip capability, since the combination of the alternate method and the OPRM trip capability provides adequate protection against oscillations.
B.1 and B.2 Required Action B.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped OPRM channels within the same RPS trip system result in not maintaining OPRM trip capability. The OPRM trip function is considered to be maintained when sufficient OPRM channels are OPERABLE or in trip (or the associated RPS trip system is in trip), such that both trip systems will generate a trip signal from the OPRM Period Based Trip Function on a valid signal.
Because of the low probability of the occurrence of an instability, 12 hours is an acceptable time to initiate the alternate method of detecting and suppressing thermal hydraulic instability oscillations described in Required Action A.3 above. The alternate method of detecting and suppressing thermal hydraulic instability oscillations avoids the region where oscillations are possible and would adequately address detection and mitigation in the event of instability oscillations. Based on industry operating experience with actual instability oscillations, the operator would be able to recognize instabilities during this time and take action to suppress them through a manual    scram. Since plant operation is minimized in areas where (continued)
 
OPRM Instrumentation B 3.3.1.3 LaSalle 1 and 2 B 3.3.1.3-6 Revision 23 BASES  ACTIONS B.1 and B.2 (continued) oscillations may occur, operation for 120 days without OPRM trip capability is considered acceptable with implementation of an alternate method of detecting and suppressing thermal hydraulic instability oscillations.
C.1    With any Required Action and associated Completion Time not met, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER must be reduced to < 25% RTP within 4 hours. Reducing THERMAL POWER to < 25% RTP places the plant in a region where instabilities cannot occur. The 4 hours is reasonable, based on operating experience, to reduce THERMAL POWER < 25% RTP from full power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE The Surveillances are modified by a Note to indicate that, REQUIREMENTS when a channel is placed in an inoperable status solely for the performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours, provided the associated Function maintains trip capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken.
This Note is based on the RPS reliability analysis (Ref. 8) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hours testing allowance does not significantly reduce the probability that the RPS will trip when necessary.
SR  3.3.1.3.1 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all  of the other required contacts of the relay are verified by (continued)
 
OPRM Instrumentation B 3.3.1.3 LaSalle 1 and 2 B 3.3.1.3-7 Revision 23 BASES  SURVEILLANCE SR  3.3.1.3.1 (continued)
REQUIREMENTS    other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.
A Frequency of 184 days provides an acceptable level of system average unavailability over the Frequency interval and is based on the reliability analysis (Ref. 6).
SR 3.3.1.3.2 LPRM gain settings are determined from the local flux profiles measured by the Traversing Incore Probe (TIP)
System. This establishes the relative local flux profile for appropriate representative input to the OPRM System.
The 1000 effective full power hours (EFPH) Frequency is based on operating experience with LPRM sensitivity changes. SR  3.3.1.3.3 The CHANNEL CALIBRATION is a complete check of the instrument loop. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations, consistent with the plant specific setpoint methodology.
Calibration of the channel provides a check of the internal reference voltage and the internal processor clock frequency. It also compares the desired trip setpoint with those in the processor memory. Since the OPRM is a digital system, the internal reference voltage and processor clock frequency are, in turn, used to automatically calibrate the internal analog to digital converters. The nominal setpoints for the period based detection algorithm are specified in the COLR. As noted, neutron detectors are excluded from CHANNEL CALIBRATION because of difficulty of simulating a meaningful signal. Changes in neutron detector sensitivity are compensated for by performing the 1000 effective full power hour (EFPH) calibration against the TIPs (SR 3.3.1.3.2). SR 3.3.1.3.2 thus also ensures the operability of the OPRM instrumentation. 
(continued)
 
OPRM Instrumentation B 3.3.1.3 LaSalle 1 and 2 B 3.3.1.3-8 Revision 23 BASES  SURVEILLANCE SR  3.3.1.3.3 (continued)
REQUIREMENTS The nominal setpoints for the OPRM trip function for the period based detection algorithm (PBDA) are specified in the Core Operating Limits Report. The PBDA trip setpoints are the number of confirmation counts required to permit a trip signal and the peak to average amplitude required to generate a trip signal.
The Frequency of 24 months is based upon the assumption of the magnitude of equipment drift provided by the equipment supplier (Ref. 6).
SR 3.3.1.3.4 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The functional testing of control rods, in LCO 3.1.3, "Control Rod OPERABILITY," and scram discharge volume (SDV) vent and drain valves, in LCO 3.1.8, "Scram Discharge Volume (SDV) Vent and Drain Valves," overlaps this Surveillance to provide complete testing of the assumed safety function. The OPRM self-test function may be utilized to perform this testing for those components that it is designed to monitor.
The 24 month Frequency is based on engineering judgment and reliability of the components. Operating experience has shown these components usually pass the surveillance when performed at the 24 month Frequency.
SR 3.3.1.3.5 This SR ensures that trips initiated from the OPRM System  will not be bypassed (i.e., fail to enable) when THERMAL POWER is  28.6% RTP and recirculation drive flow is < 60%
of rated recirculation drive flow. This normally involves calibration of the bypass channels. The 28.6% RTP value is the plant specific value for the enable region, as described in Reference 9.
These values have been conservatively selected so that specific, additional uncertainty allowances need not be applied. Specifically, the THERMAL POWER, the Average Power Range Monitor (APRM) establishes the reference signal to enable the OPRM system at 28.6% RTP. Thus, the nominal (continued)
 
OPRM Instrumentation B 3.3.1.3 LaSalle 1 and 2 B 3.3.1.3-9 Revision 23 BASES  SURVEILLANCE SR 3.3.1.3.5 (continued)
REQUIREMENTS  setpoints corresponding to the values listed above (28.6%
of RTP and 60% of rated recirculation drive flow) will be used to establish the enabled region of the OPRM System trips.  (References 1, 2, 5, 9, and 11)
If any bypass channel setpoint is nonconservative (i.e., the OPRM module is bypassed at  28.6% RTP and < 60% of rated recirculation drive flow), then the affected OPRM module is considered inoperable. Alternately, the bypass channel can be placed in the conservative condition (nonbypass). If placed in the nonbypass condition, this SR is met and the module is considered OPERABLE.
The Frequency of 24 months is based on engineering judgment and reliability components.
SR 3.3.1.3.6 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis. The OPRM self-test function may be utilized to perform this testing for those components it is designed to monitor. The RPS RESPONSE TIME acceptance criteria are included in Reference 10.
RPS RESPONSE TIME may be verified by actual response time measurements in any series of sequential, overlapping, or total channel measurements. As noted, neutron detectors are excluded from RPS RESPONSE TIME testing because the principles of detector operation virtually ensure an instantaneous response time. RPS RESPONSE TIME tests are  conducted on a 24 month STAGGERED TEST BASIS. This Frequency is consistent with the refueling cycle and is based upon operating experience, which shows that random failures of instrumentation components causing serious time degradation, but not channel failure, are infrequent.
REFERENCES 1. NEDC-39160, "BWR Owners Group Long-Term Stability Solutions Licensing Methodology," June 1991.
: 2. NEDO-39160, "BWR Owners Group Long-Term Stability Solutions Licensing Methodology," Supplement 1, March 1992.  (continued)
 
OPRM Instrumentation B 3.3.1.3 LaSalle 1 and 2 B 3.3.1.3-10 Revision 23 BASES  REFERENCES 3. NRC Letter, A. Thandani to L. A. England, "Acceptance        (continued)  for Referencing of Topical Report NEDO-31960,      Supplement 1, 'BWR Owners Group Long-Term Stability    Solutions Licensing Methodology,'" July 12, 1994. 
: 4. Generic Letter 94-02, "Long-Term Solutions and Upgrade of Interim Operating Recommendations for Thermal-Hydraulic Instabilities in Boiling Water Reactors," July 11, 1994.
: 5. NEDO-32465-A, "BWR Owners Group Reactor Stability Detect and Suppress Solution Licensing Basis Methodology and Reload Application," August 1996.
: 6. CENPD-400-P, Rev. 01 "Generic Topical Report for the    ABB Option III Oscillation Power Range Monitor (OPRM)," May 1995. 
: 7. BWROG Letter BWROG-9479, "Guidelines for Stability Interim Correction Action," June 6, 1994. 
: 8. NEDC-30851-P-A, "Technical Specification Improvement Analysis for BWR Reactor Protection System," March 1988. 
: 9. NEDC-32701P, "Power Uprate Safety Analysis Report for LaSalle County Station Units 1 and 2," Revision 2.
: 10. Technical Requirements Manual.
: 11. Letter from K. P. Donovan (BWR Owners' Group) to U.S.
NRC, "Guidelines for Stability Option III 'Enabled Region, '" dated September 17, 1996. 
 
Control Rod Block Instrumentation B 3.3.2.1
 
LaSalle 1 and 2 B 3.3.2.1-1 Revision 0 B 3.3  INSTRUMENTATION
 
B 3.3.2.1  Control Rod Block Instrumentation
 
BASES
 
BACKGROUND Control rods provide the primary means for control of reactivity changes. Control rod block instrumentation
 
includes channel sensors, logic circuitry, switches, and
 
relays that are designed to ensure that specified fuel
 
design limits are not exceeded for postulated transients and
 
accidents. During high power operation, the rod block
 
monitor (RBM) provides protection for control rod withdrawal
 
error events. During low power operations, control rod
 
blocks from the rod worth minimizer (RWM) enforce specific
 
control rod sequences designed to mitigate the consequences
 
of the control rod drop accident (CRDA). During shutdown
 
conditions, control rod blocks from the Reactor Mode
 
Switch-Shutdown Position Function ensure that all control
 
rods remain inserted to prevent inadvertent criticalities.
The purpose of the RBM is to limit control rod withdrawal if
 
localized neutron flux exceeds a predetermined setpoint
 
during control rod manipulations (Ref. 1). It is assumed to
 
function to block further control rod withdrawal to preclude
 
a MCPR Safety Limit (SL) violation. The RBM supplies a trip
 
signal to the Reactor Manual Control System (RMCS) to
 
appropriately inhibit control rod withdrawal during power
 
operation above the 30% RATED THERMAL POWER setpoint when a
 
non peripheral control rod is selected. The RBM has two
 
channels, either of which can initiate a control rod block
 
when the channel output exceeds the control rod block
 
setpoint. One RBM channel inputs into one RMCS rod block
 
circuit and the other RBM channel inputs into the second
 
RMCS rod block circuit. The RBM channel signal is generated
 
by averaging a set of local power range monitor (LPRM)
 
signals. One RBM channel averages the signals from LPRM
 
detectors at the A and C positions in the assigned LPRM
 
assemblies. The second RBM channel averages the signals
 
from the LPRM detectors at the B and D positions.
 
Assignment of LPRM assemblies to be used in RBM averaging is
 
controlled by the selection of control rods. With no
 
control rod selected, the RBM output is set to zero.
 
However, when a control rod is selected, the gain of each (continued)
Control Rod Block Instrumentation B 3.3.2.1
 
LaSalle 1 and 2 B 3.3.2.1-2 Revision 0 BASES BACKGROUND RBM channel output is normalized to an assigned average (continued) power range monitor (APRM) channel. The assigned APRM channel is on the same RPS trip system as the RBM channel.
 
The gain setting is held constant during the movement of
 
that particular control rod to provide an indication of the
 
change in the relative local power level. If the APRM used
 
to normalize the RBM reading is indicating
< 30% or a peripheral control rod is selected, the RBM is zeroed and
 
the RBM is bypassed (Refs. 1 and 2).
If any LPRM detector assigned to an RBM is bypassed, the
 
computed average signal is adjusted automatically to
 
compensate for the number of LPRM signals. The minimum
 
number of LPRM inputs required for each RBM channel to
 
prevent an instrument inoperative alarm is four when using
 
four LPRM assemblies, three when using three LPRM
 
assemblies, and two when using two LPRM assemblies. If the
 
normalizing APRM channel is bypassed, a second APRM channel
 
automatically provides the normalizing signal (Refs. 1 and
 
2).
 
In addition, to preclude rod movement with an inoperable
 
RBM, a downscale trip and an inoperable trip are provided.
 
The purpose of the RWM is to control rod patterns during
 
startup and shutdown, such that only specified control rod
 
sequences and relative positions are allowed over the
 
operating range from all control rods inserted to 10% RTP.
 
The sequences effectively limit the potential amount and
 
rate of reactivity increase during a CRDA. Prescribed
 
control rod sequences are stored in the RWM, which will
 
initiate control rod withdrawal and insert blocks when the
 
actual sequence deviates beyond allowances from the stored
 
sequence. The RWM determines the actual sequence based on
 
position indication for each control rod. The RWM also uses
 
steam flow signals to determine when the reactor power is
 
above the preset power level at which the RWM is
 
automatically bypassed. The RWM is a single channel system
 
that provides input into both RMCS rod block circuits (Refs.
 
2 and 3).
 
With the reactor mode switch in the shutdown position, a
 
control rod withdrawal block is applied to all control rods
 
to ensure that the shutdown condition is maintained. This
 
Function prevents inadvertent criticality as the result of a
 
(continued)
Control Rod Block Instrumentation B 3.3.2.1
 
LaSalle 1 and 2 B 3.3.2.1-3 Revision 0 BASES BACKGROUND control rod withdrawal during MODE 3 or 4, or during MODE 5 (continued) when the reactor mode switch is required to be in the shutdown position. The reactor mode switch has two
 
channels, each inputting into a separate RMCS rod block
 
circuit. Each reactor mode switch channel has contacts
 
permitting control rod withdrawal in the reactor mode switch
 
positions of run, startup, and refuel interlocked with other
 
plant conditions. With the reactor mode switch in shutdown, the RMCS circuits do not receive a permissive for control
 
rod withdrawal. A rod block in either RMCS circuit will
 
provide a control rod block to all control rods.
 
APPLICABLE 1. Rod Block Monitor SAFETY ANALYSES, LCO, and The RBM is designed to prevent violation of the MCPR APPLICABILITY SL and the cladding 1% plastic strain fuel design limit that may result from a single control rod withdrawal error (RWE)
 
event. The analytical methods and assumptions used in
 
evaluating the RWE event are summarized in Reference 4. The
 
cycle-specific analysis considers the continuous withdrawal
 
of the maximum worth control rod at its maximum drive speed
 
from the reactor, which is operating at rated power with a
 
control rod pattern that results in the core being placed on
 
thermal design limits. The condition is analyzed to ensure
 
that the results obtained are conservative; the approach
 
also serves to demonstrate the function of the RBM.
The RBM Function satisfies Criterion 3 of
 
10 CFR 50.36(c)(2)(ii).
 
Two channels of the RBM are required to be OPERABLE, with
 
their setpoints within the appropriate Allowable Values in
 
the CORE OPERATING LIMITS REPORT to ensure that no single
 
instrument failure can preclude a rod block from this
 
Function. The actual setpoints are calibrated consistent
 
with applicable setpoint methodology.
 
Nominal trip setpoints are specified in the setpoint
 
calculations. The nominal setpoints are selected to ensure
 
that the setpoints do not exceed the Allowable Values
 
between successive CHANNEL CALIBRATIONS. Operation with a
 
trip setpoint less conservative than the nominal trip (continued)
Control Rod Block Instrumentation B 3.3.2.1
 
LaSalle 1 and 2 B 3.3.2.1-4 Revision 0 BASES APPLICABLE setpoint, but within its Allowable Value, is acceptable.
SAFETY ANALYSES, Trip setpoints are those predetermined values of output at LCO, and which an action should take place. The setpoints are APPLICABILITY compared to the actual process parameter (e.g., reactor (continued) power), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g.,
trip unit) changes state. The analytic limits are derived
 
from the limiting values of the process parameters obtained
 
from the safety analysis. The trip setpoints are determined
 
from the analytic limits, corrected for defined process, calibration, and instrument errors. The Allowable Values
 
are then determined, based on the trip setpoint values, by
 
accounting for the calibration based errors. These
 
calibration based errors are limited to reference accuracy, instrument drift, errors associated with measurement and
 
test equipment, and calibration tolerance of loop
 
components. The trip setpoints and Allowable Values
 
determined in this manner provide adequate protection
 
because instrument uncertainties, process effects, calibration tolerances, instrument drift, and severe
 
environment errors (for channels that must function in harsh
 
environments as defined by 10 CFR 50.49) are accounted for
 
and appropriately applied for the instrumentation.
The RBM is assumed to mitigate the consequences of an RWE
 
event when operating  30% RTP and a non-peripheral control rod is selected. Below this power level or if a peripheral
 
control rod is selected, the consequences of an RWE event
 
will not exceed the MCPR SL and, therefore, the RBM is not
 
required to be OPERABLE (Ref. 4). 
: 2. Rod Worth Minimizer
 
The RWM enforces the analyzed rod position sequence to
 
ensure that the initial conditions of the CRDA analysis are
 
not violated. The analytical methods and assumptions used
 
in evaluating the CRDA are summarized in References 5, 6, and 7. The analyzed rod position sequence requires that
 
control rods be moved in groups, with all control rods
 
assigned to a specific group required to be within specified
 
banked positions. Requirements that the control rod
 
sequence is in compliance with the analyzed rod position
 
sequence are specified in LCO 3.1.6, "Rod Pattern Control." 
 
  (continued)
Control Rod Block Instrumentation B 3.3.2.1
 
LaSalle 1 and 2 B 3.3.2.1-5 Revision 17 BASES APPLICABLE 2. Rod Worth Minimizer (continued)
SAFETY ANALYSES,  LCO, and When performing a shutdown of the plant, an optional control APPLICABILITY rod sequence (Ref. 10) may be used if the coupling of each    withdrawn control rod has been confirmed. The rods may be inserted without the need to stop at intermediate positions.
When using the Reference 10 control rod insertion sequence for shutdown, the rod worth minimizer may be reprogrammed to enforce the requirements of the improved control rod insertion process.
The RWM Function satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
 
Since the RWM is a system designed to act as a backup to
 
operator control of the rod sequences, only one channel of
 
the RWM is available and required to be OPERABLE (Ref. 7).
 
Special circumstances provided for in the Required Action of
 
LCO 3.1.3, "Control Rod OPERABILITY," and LCO 3.1.6 may
 
necessitate bypassing the RWM to allow continued operation
 
with inoperable control rods, or to allow correction of a
 
control rod pattern not in compliance with the analyzed rod
 
position sequence. The RWM may be bypassed as required by
 
these conditions, but then it must be considered inoperable
 
and the Required Actions of this LCO followed.
 
Compliance with the analyzed rod position sequence, and
 
therefore OPERABILITY of the RWM, is required in MODES 1
 
and 2 when THERMAL POWER is  10% RTP. When THERMAL POWER is > 10% RTP, there is no possible control rod configuration that results in a control rod worth that could exceed the
 
280 cal/gm fuel design limit during a CRDA (Refs. 6 and 7).
 
In MODES 3 and 4, all control rods are required to be
 
inserted into the core; therefore, a CRDA cannot occur. In
 
MODE 5, since only a single control rod can be withdrawn
 
from a core cell containing fuel assemblies, adequate SDM
 
ensures that the consequences of a CRDA are acceptable, since the reactor will be subcritical.
: 3. Reactor Mode Switch-Shutdown Position
 
During MODES 3 and 4, and during MODE 5 when the reactor
 
mode switch is in the shutdown position, the core is assumed
 
to be subcritical; therefore, no positive reactivity
 
insertion events are analyzed. The Reactor Mode (continued)
Control Rod Block Instrumentation B 3.3.2.1
 
LaSalle 1 and 2 B 3.3.2.1-6 Revision 17 BASES APPLICABLE 3. Reactor Mode Switch-Shutdown Position (continued) SAFETY ANALYSES, LCO, and Switch-Shutdown Position control rod withdrawal block APPLICABILITY  ensures that the reactor remains subcritical by blocking control rod withdrawal, thereby preserving the assumptions
 
of the safety analysis. 
 
The Reactor Mode Switch-Shutdown Position Function
 
satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
 
Two channels are required to be OPERABLE to ensure that no single channel failure will preclude a rod block when required. There is no Allowable Value for this Function
 
since the channels are mechanically actuated based solely on
 
reactor mode switch position.
During shutdown conditions (MODES 3 and 4, and MODE 5 when
 
the reactor mode switch is in the shutdown position), no
 
positive reactivity insertion events are analyzed because
 
assumptions are that control rod withdrawal blocks are
 
provided to prevent criticality. Therefore, when the
 
reactor mode switch is in the shutdown position, the control
 
rod withdrawal block is required to be OPERABLE. During
 
MODE 5 with the reactor mode switch in the refueling
 
position, the refuel position one-rod-out interlock (LCO 3.9.2, "Refuel Position One-Rod-Out Interlock")
 
provides the required control rod withdrawal blocks.
 
ACTIONS A.1 With one RBM channel inoperable, the remaining OPERABLE
 
channel is adequate to perform the control rod block
 
function; however, overall reliability is reduced because a
 
single failure in the remaining OPERABLE channel can result
 
in no control rod block capability for the RBM. For this
 
reason, Required Action A.1 requires restoration of the
 
inoperable channel to OPERABLE status. The Completion Time
 
of 24 hours is based on the low probability of an event
 
occurring coincident with a failure in the remaining
 
OPERABLE channel.
 
B.1 If Required Action A.1 is not met and the associated
 
Completion Time has expired, the inoperable channel must be
 
placed in trip within 1 hour. If both RBM channels are  (continued)
Control Rod Block Instrumentation B 3.3.2.1
 
LaSalle 1 and 2 B 3.3.2.1-7 Revision 17 BASES ACTIONS B.1 (continued)
 
inoperable, the RBM is not capable of performing its 
 
intended function; thus, one channel must also be placed in
 
trip. This initiates a control rod withdrawal block, thereby ensuring that the RBM function is met.
 
The 1 hour Completion Time is intended to allow the operator
 
time to evaluate and repair any discovered inoperabilities
 
and is acceptable because it minimizes risk while allowing
 
time for restoration or tripping of inoperable channels.
 
C.1, C.2.1.1, C.2.1.2, and C.2.2
 
With the RWM inoperable during a reactor startup, the
 
operator is still capable of enforcing the prescribed
 
control rod sequence. However, the overall reliability is
 
reduced because a single operator error can result in
 
violating the control rod sequence. Therefore, control rod
 
movement must be immediately suspended except by scram.
 
Alternatively, startup may continue if at least 12 control
 
rods have already been withdrawn, or a reactor startup with
 
an inoperable RWM during withdrawal of one or more of the
 
first 12 control rods was not performed in the last
 
12 months. These requirements minimize the number of
 
reactor startups initiated with the RWM inoperable.
 
Required Actions C.2.1.1 and C.2.1.2 require verification of
 
these conditions by review of plant logs and control room
 
indications. Once Required Action C.2.1.1 or C.2.1.2 is
 
satisfactorily completed, control rod withdrawal may proceed
 
in accordance with the restrictions imposed by Required
 
Action C.2.2. Required Action C.2.2 allows for the RWM
 
Function to be performed manually and requires a double
 
check of compliance with the prescribed rod sequence by a
 
second licensed operator (Reactor Operator or Senior Reactor
 
Operator) or other task qualified member of the technical
 
staff (e.g., shift technical advisor or reactor engineer).
 
The RWM may be bypassed under these conditions to allow
 
continued operations. In addition, Required Actions of
 
LCO 3.1.3 and LCO 3.1.6 may require bypassing the RWM, during which time the RWM must be considered inoperable with
 
Condition C entered and its Required Actions taken.
(continued)
Control Rod Block Instrumentation B 3.3.2.1
 
LaSalle 1 and 2 B 3.3.2.1-8 Revision 0 BASES ACTIONS D.1 (continued)
With the RWM inoperable during a reactor shutdown, the
 
operator is still capable of enforcing the prescribed
 
control rod sequence. Required Action D.1 allows for the
 
RWM Function to be performed manually and requires a double
 
check of compliance with the prescribed rod sequence by a
 
second licensed operator (Reactor Operator or Senior Reactor
 
Operator) or other task qualified member of the technical
 
staff (e.g., shift technical advisor or reactor engineer).
 
The RWM may be bypassed under these conditions to allow the
 
reactor shutdown to continue.
 
E.1 and E.2
 
With one Reactor Mode Switch-Shutdown Position control rod
 
withdrawal block channel inoperable, the remaining OPERABLE
 
channel is adequate to perform the control rod withdrawal
 
block function. However, since the Required Actions are
 
consistent with the normal action of an OPERABLE Reactor
 
Mode Switch-Shutdown Position Function (i.e., maintaining
 
all control rods inserted), there is no distinction between
 
having one or two channels inoperable.
 
In both cases (one or both channels inoperable), suspending
 
all control rod withdrawal and initiating action to fully
 
insert all insertable control rods in core cells containing
 
one or more fuel assemblies will ensure that the core is
 
subcritical with adequate SDM ensured by LCO 3.1.1. Control
 
rods in core cells containing no fuel assemblies do not
 
affect the reactivity of the core and are therefore not
 
required to be inserted. Action must continue until all
 
insertable control rods in core cells containing one or more
 
fuel assemblies are fully inserted.
 
SURVEILLANCE As noted at the beginning of the SRs, the SRs for each REQUIREMENTS Control Rod Block instrumentation Function are found in the SRs column of Table 3.3.2.1-1.
The Surveillances are modified by a second Note to indicate
 
that when an RBM channel is placed in an inoperable status
 
solely for performance of required Surveillances, entry into
 
associated Conditions and Required Actions may be delayed (continued)
Control Rod Block Instrumentation B 3.3.2.1
 
LaSalle 1 and 2 B 3.3.2.1-9 Revision 0 BASES SURVEILLANCE for up to 6 hours provided the associated Function maintains REQUIREMENTS control rod block capability. Upon completion of the (continued) Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the
 
applicable Condition entered and Required Actions taken.
 
This Note is based on the reliability analysis (Ref. 8)
 
assumption of the average time required to perform channel
 
Surveillance. That analysis demonstrated that the 6 hour
 
testing allowance does not significantly reduce the
 
probability that a control rod block will be initiated when
 
necessary.
 
SR  3.3.2.1.1
 
A CHANNEL FUNCTIONAL TEST is performed for each RBM channel
 
to ensure that the entire channel will perform the intended
 
function. It includes the Reactor Manual Control
 
Multiplexing System input. A successful test of the
 
required contact(s) of a channel relay may be performed by
 
the verification of the change of state of a single contact
 
of the relay. This clarifies what is an acceptable CHANNEL
 
FUNCTIONAL TEST of a relay. This is acceptable because all
 
of the other required contacts of the relay are verified by
 
other Technical Specifications and non-Technical
 
Specifications tests at least once per refueling interval
 
with applicable extensions.
 
Any setpoint adjustment shall be consistent with the
 
assumptions of the current plant specific setpoint
 
methodology. The Frequency of 92 days is based on
 
reliability analyses (Ref. 9).
 
SR  3.3.2.1.2 and SR  3.3.2.1.3
 
A CHANNEL FUNCTIONAL TEST is performed for the RWM to ensure
 
that the entire system will perform the intended function.
 
A successful test of the required contact(s) of a channel
 
relay may be performed by the verification of the change of
 
state of a single contact of the relay. This clarifies what
 
is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This
 
is acceptable because all of the other required contacts of
 
the relay are verified by other Technical Specifications and
 
non-Technical Specifications tests at least once per
 
(continued)
Control Rod Block Instrumentation B 3.3.2.1
 
LaSalle 1 and 2 B 3.3.2.1-10 Revision 0 BASES SURVEILLANCE SR  3.3.2.1.2 and SR  3.3.2.1.3 (continued)
REQUIREMENTS refueling interval with applicable extensions. The CHANNEL
 
FUNCTIONAL TEST for the RWM is performed by attempting to
 
withdraw a control rod not in compliance with the prescribed
 
sequence and verifying a control rod block occurs and by
 
verifying proper annunciation of the selection error of at
 
least one out-of-sequence control rod. As noted in the SRs, SR 3.3.2.1.2 is not required to be performed until 1 hour
 
after any control rod is withdrawn at  10% RTP in MODE 2 and SR 3.3.2.1.3 is not required to be performed until
 
1 hour after THERMAL POWER is  10% RTP in MODE 1. The Note to SR 3.3.2.1.2 allows entry into MODE 2 on a startup and
 
entry into MODE 2 concurrent with a power reduction to 10% RTP during a shutdown to perform the required Surveillance if the 92 day Frequency is not met per
 
SR 3.0.2. The Note to SR 3.3.2.1.3 allows a THERMAL POWER
 
reduction to  10% RTP in MODE 1 to perform the required Surveillance if the 92 day Frequency is not met per
 
SR 3.0.2. The 1 hour allowances are based on operating
 
experience and in consideration of providing a reasonable
 
time in which to complete the SRs. Operating experience has
 
shown that these components usually pass the Surveillances
 
when performed at the 92 day Frequency. Therefore, the
 
Frequency was concluded to be acceptable from a reliability
 
standpoint.
 
SR  3.3.2.1.4
 
A CHANNEL CALIBRATION is a complete check of the instrument
 
loop and the sensor. This test verifies the channel
 
responds to the measured parameter within the necessary
 
range and accuracy. CHANNEL CALIBRATION leaves the channel
 
adjusted to account for instrument drifts between successive
 
calibrations consistent with the plant specific setpoint
 
methodology.
 
As noted, neutron detectors are excluded from the CHANNEL
 
CALIBRATION because they are passive devices, with minimal
 
drift, and because of the difficulty of simulating a
 
meaningful signal. Neutron detectors are adequately tested
 
in SR 3.3.1.1.2 and SR 3.3.1.1.8.
(continued)
Control Rod Block Instrumentation B 3.3.2.1
 
LaSalle 1 and 2 B 3.3.2.1-11 Revision 0 BASES SURVEILLANCE SR  3.3.2.1.4 (continued)
REQUIREMENTS The Frequency is based upon the assumption of a 92 day
 
calibration interval in the determination of the magnitude
 
of equipment drift in the setpoint analysis.
 
SR  3.3.2.1.5
 
The RBM is automatically bypassed when power is below a
 
specified value or if a peripheral control rod is selected.
 
The power level is determined from the APRM signals input to
 
each RBM channel. The automatic bypass setpoint must be
 
verified periodically to be < 30% RTP. In addition, it must
 
also be verified that the RBM is not bypassed when a control
 
rod that is not a peripheral control rod is selected (only
 
one non-peripheral control rod is required to be verified).
 
If any bypass setpoint is nonconservative, then the affected
 
RBM channel is considered inoperable. Alternatively, the
 
APRM channel can be placed in the conservative condition to
 
enable the RBM. If placed in this condition, the SR is met
 
and the RBM channel is not considered inoperable. As noted, neutron detectors are excluded from the Surveillance because
 
they are passive devices, with minimal drift, and because of
 
the difficulty of simulating a meaningful signal. Neutron
 
detectors are adequately tested in SR 3.3.1.1.2 and
 
SR 3.3.1.1.8. The 92 day Frequency is based on the actual
 
trip setpoint methodology utilized for these channels.
 
SR  3.3.2.1.6
 
The RWM is automatically bypassed when power is above a
 
specified value. The power level is determined from steam
 
flow signal. The automatic bypass setpoint must be verified
 
periodically to be > 10% RTP. If the RWM low power setpoint
 
is nonconservative, then the RWM is considered inoperable. 
 
Alternately, the low power setpoint channel can be placed in
 
the conservative condition (nonbypass). If placed in the
 
nonbypassed condition, the SR is met and the RWM is not
 
considered inoperable. The Frequency is based on the trip
 
setpoint methodology utilized for the low power setpoint
 
channel.
(continued)
Control Rod Block Instrumentation B 3.3.2.1
 
LaSalle 1 and 2 B 3.3.2.1-12 Revision 0 BASES SURVEILLANCE SR  3.3.2.1.7 REQUIREMENTS (continued) A CHANNEL FUNCTIONAL TEST is performed for the Reactor Mode Switch-Shutdown Position Function to ensure that the entire
 
channel will perform the intended function. A successful
 
test of the required contact(s) of a channel relay may be
 
performed by the verification of the change of state of a
 
single contact of the relay. This clarifies what is an
 
acceptable CHANNEL FUNCTIONAL TEST of a relay. This is
 
acceptable because all of the other required contacts of the
 
relay are verified by other Technical Specifications and
 
non-Technical Specifications tests at least once per
 
refueling interval with applicable extensions. The CHANNEL
 
FUNCTIONAL TEST for the Reactor Mode Switch-Shutdown
 
Position Function is performed by attempting to withdraw any
 
control rod with the reactor mode switch in the shutdown
 
position and verifying a control rod block occurs.
As noted in the SR, the Surveillance is not required to be
 
performed until 1 hour after the reactor mode switch is in
 
the shutdown position, since testing of this interlock with
 
the reactor mode switch in any other position cannot be
 
performed without using jumpers, lifted leads, or movable
 
links. This allows entry into MODES 3 and 4 if the 24 month
 
Frequency is not met per SR 3.0.2. The 1 hour allowance is
 
based on operating experience and in consideration of
 
providing a reasonable time in which to complete the SRs.
 
The 24 month Frequency is based on the need to perform this
 
Surveillance under the conditions that apply during a plant
 
outage and the potential for an unplanned transient if the
 
Surveillance were performed with the reactor at power.
 
Operating experience has shown these components usually pass
 
the Surveillance when performed at the 24 month Frequency.
 
SR  3.3.2.1.8
 
The RWM will only enforce the proper control rod sequence if
 
the rod sequence is properly input into the RWM computer.
 
This SR ensures that the proper sequence is loaded into the
 
RWM so that it can perform its intended function. The
 
Surveillance is performed once prior to declaring RWM
 
OPERABLE following loading of sequence into RWM, since this
 
is when rod sequence input errors are possible.
 
(continued)
Control Rod Block Instrumentation B 3.3.2.1
 
LaSalle 1 and 2 B 3.3.2.1-13 Revision 0 BASES SURVEILLANCE SR  3.3.2.1.9 REQUIREMENTS (continued) LCO 3.1.3 and LCO 3.1.6 may require individual control rods to be bypassed (taken out of service) in the RWM to allow
 
insertion of an inoperable control rod or correction of a
 
control rod pattern not in compliance with the analyzed rod
 
position sequence. With the control rods bypassed (taken
 
out of service) in the RWM, the RWM will provide insert and
 
withdraw blocks for bypassed control rods that are fully
 
inserted and a withdraw block for bypassed control rods that
 
are not fully inserted. To ensure the proper bypassing and
 
movement of those affected control rods, a second licensed
 
operator (Reactor Operator or Senior Reactor Operator) or
 
other task qualified member of the technical staff (e.g.,
shift technical advisor or reactor engineer) must verify the
 
bypassing and position of these control rods. Compliance
 
with this SR allows the RWM to be OPERABLE with these
 
control rods bypassed. 
 
REFERENCES 1. UFSAR, Section 7.7.6.3.
: 2. UFSAR, Section 7.7.2.2.3.
: 3. UFSAR, Section 7.7.7.2.3.
: 4. UFSAR, Section 15.4.2.3.
: 5. UFSAR, Section 15.4.9.
: 6. "Modifications to the Requirements for Control Rod Drop Accident Mitigating Systems," BWR Owners' Group, July 1986.
: 7. NRC SER, "Acceptance of Referencing of Licensing Topical Report NEDE-24011-P-A," "General Electric
 
Standard Application for Reactor Fuel, Revision 8, Amendment 17," December 27, 1987.
: 8. GENE-770-06-1-A, "Addendum to Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service
 
Times for Selected Instrumentation Technical
 
Specifications," December 1992.
(continued)
Control Rod Block Instrumentation B 3.3.2.1
 
LaSalle 1 and 2 B 3.3.2.1-14 Revision 17 BASES REFERENCES 9. NEDC-30851-P-A, Supplement 1, "Technical Specification (continued)  Improvement Analysis for BWR Control Rod Block Instrumentation," October 1988.
: 10. NEDO-33091-A, Revision 2, "Improved BPWS Control Rod Insertion Process," July 2004.
 
Feedwater System and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2
 
LaSalle 1 and 2 B 3.3.2.2-1 Revision 0 B 3.3  INSTRUMENTATION
 
B 3.3.2.2 Feedwater System and Main Turbine High Water Level Trip Instrumentation
 
BASES
 
BACKGROUND The Feedwater System and Main Turbine High Water Level Trip Instrumentation is designed to detect a potential failure of
 
the Feedwater Level Control System that causes excessive
 
feedwater flow.
With excessive feedwater flow, the water level in the
 
reactor vessel rises toward the high water level, Level 8
 
reference point, causing the trip of the two feedwater pump
 
turbines, the motor-driven feedwater pump and the main
 
turbine.
 
Reactor Vessel Water Level-High, Level 8 signals are
 
provided by differential pressure transmitters that sense
 
the difference between the pressure due to a constant column
 
of water (reference leg) and the pressure due to the actual
 
water level in the reactor vessel (variable leg). Four
 
channels of Reactor Vessel Water Level-High, Level 8
 
instrumentation are provided as input to the initiation
 
logic that trips the two feedwater pump turbines, the motor-
 
driven feedwater pump and the main turbine. Trip channels A
 
and B each receive an input from Reactor Vessel Water
 
Level-High, Level 8 channels and trip channel C receives an
 
input from two Reactor Vessel Water Level-High, Level 8
 
channels. Trip channel C has one instrument that shares the
 
same narrow range variable leg with trip channel A, and a
 
second instrument that shares the narrow range variable leg
 
with the instrument of trip channel B. Each of the trip
 
channels will trip if any Reactor Vessel Water Level-High, Level 8 channel trips. Each of the three trip channel
 
outputs are provided as inputs to the individual trip logics
 
associated with each feedwater pump turbine, the motor-
 
driven feedwater pump, and the main turbine. The trip
 
channel inputs are arranged in a two-out-of-three logic for
 
each initiation logic. The channels include electronic
 
equipment (e.g., trip units) that compares measured input
 
signals with pre- established setpoints. When the setpoint
 
is exceeded, the channel output relay actuates, which then
 
outputs a feedwater system and main turbine trip signal to
 
the trip logic.
 
(continued)
Feedwater System and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2
 
LaSalle 1 and 2 B 3.3.2.2-2 Revision 0 BASES BACKGROUND A trip of the feedwater pump turbines and the motor-driven (continued) feedwater pump limits further increase in reactor vessel water level by limiting further addition of feedwater to the
 
reactor vessel. A trip of the main turbine and closure of
 
the stop valves protects the turbine from damage due to
 
water entering the turbine.
 
APPLICABLE The Feedwater System and Main Turbine High Water Level Trip SAFETY ANALYSES Instrumentation is assumed to be capable of providing a trip of the feedwater turbines, the motor-driven feedwater pump, and the main turbine in the design basis transient analysis
 
for a feedwater controller failure, maximum demand event (Ref. 1). The Level 8 trip indirectly initiates a reactor
 
scram from the main turbine trip (above 25% RTP) and trips
 
the feedwater pumps, thereby terminating the event. The
 
reactor scram mitigates the reduction in MCPR.
Feedwater System and Main Turbine High Water Level Trip
 
Instrumentation satisfies Criterion 3 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO The LCO requires four channels (combined into three trip channels) of the Reactor Vessel Water Level-High, Level 8
 
instrumentation to be OPERABLE to ensure that no single
 
instrument failure or variable leg failure will prevent the
 
feedwater pump turbines, the motor-driven feedwater pump, and main turbine to trip on a valid Level 8 signal. Two of
 
the three trip channels are needed to provide trip signals
 
in order for the feedwater and main turbine and motor-driven
 
feedwater pump trips to occur. Each channel must have its
 
setpoint set within the specified Allowable Value of
 
SR 3.3.2.2.3. The Allowable Value is set to ensure that the
 
thermal limits are not exceeded during the event. The
 
actual setpoint is calibrated to be consistent with the
 
applicable setpoint methodology assumptions. Nominal trip
 
setpoints are specified in the setpoint calculations. The
 
nominal setpoints are selected to ensure that the setpoints
 
do not exceed the Allowable Value between successive CHANNEL
 
CALIBRATIONS. Operation with a trip setpoint less
 
conservative than the nominal trip setpoint, but within its
 
Allowable Value, is acceptable. A channel is inoperable if
 
its actual trip setpoint is not within its required
 
Allowable Value.
(continued)
Feedwater System and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2
 
LaSalle 1 and 2 B 3.3.2.2-3 Revision 0 BASES LCO Trip setpoints are those predetermined values of output at (continued) which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor
 
vessel water level), and when the measured output value of
 
the process parameter exceeds the setpoint, the associated
 
device (e.g., trip unit) changes state. The analytic limits
 
are derived from the limiting values of the process
 
parameters obtained from the safety analysis. The trip
 
setpoints are determined from the analytic limits, corrected
 
for defined process, calibration, and instrument errors.
 
The Allowable Values are then determined, based on the trip
 
setpoint values, by accounting for the calibration based
 
errors. These calibration based errors are limited to
 
reference accuracy, instrument drift, errors associated with
 
measurement and test equipment, and calibration tolerance of
 
loop components. The trip setpoints and Allowable Values
 
determined in this manner provide adequate protection
 
because instrument uncertainties, process effects, calibration tolerances, instrument drift, and severe
 
environment errors (for channels that must function in harsh
 
environments as defined by 10 CFR 50.49) are accounted for
 
and appropriately applied for the instrumentation.
 
APPLICABILITY The Feedwater System and Main Turbine High Water Level Trip Instrumentation is required to be OPERABLE at  25% RTP to ensure that the fuel cladding integrity Safety Limit and the
 
cladding 1% plastic strain limit are not violated during the
 
feedwater controller failure, maximum demand event. As
 
discussed in the Bases for LCO 3.2.1, "AVERAGE PLANAR LINEAR
 
HEAT GENERATION RATE (APLHGR)," LCO 3.2.2, "MINIMUM CRITICAL
 
POWER RATIO (MCPR)," and LCO 3.2.3, "LINEAR HEAT GENERATION
 
RATE," sufficient margin to these limits exists below
 
25% RTP; therefore, these requirements are only necessary
 
when operating at or above this power level.
 
ACTIONS A Note has been provided to modify the ACTIONS related to Feedwater System and Main Turbine High Water Level Trip
 
Instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent
 
divisions subsystems, components, or variables expressed in
 
the Condition, discovered to be inoperable or not within
 
limits, will not result in separate entry into the
 
Condition. Section 1.3 also specifies that Required Actions (continued)
Feedwater System and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2
 
LaSalle 1 and 2 B 3.3.2.2-4 Revision 0 BASES ACTIONS of the Condition continue to apply for each additional (continued) failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable
 
Feedwater System and Main Turbine High Water Level Trip
 
Instrumentation channels provide appropriate compensatory
 
measures for separate inoperable channels. As such, a Note
 
has been provided that allows separate Condition entry for
 
each inoperable Feedwater System and Main Turbine High Water
 
Level Trip Instrumentation channel.
 
A.1 With one or more channels inoperable and trip capability
 
maintained, the remaining OPERABLE channels can provide the
 
required trip signal. However, overall instrumentation
 
reliability is reduced because a single failure in one of
 
the remaining channels concurrent with feedwater controller
 
failure, maximum demand event, or a variable leg failure may
 
result in the instrumentation not being able to perform its
 
intended function. Therefore, continued operation is only
 
allowed for a limited time. If the inoperable channel
 
cannot be restored to OPERABLE status within the Completion
 
Time, the channel must be placed in the tripped condition
 
per Required Action A.1. Placing the inoperable channel in
 
trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and
 
allow operation to continue with no further restrictions.
 
Alternately, if it is not desired to place the channel in
 
trip (e.g., as in the case where placing the inoperable
 
channel in trip would result in a feedwater turbine, motor-
 
driven feedwater pump, or main turbine trip), Condition C
 
must be entered and its Required Action taken.
 
The Completion Time of 7 days is based on the low
 
probability of the event occurring coincident with a single
 
failure in a remaining OPERABLE channel.
 
B.1 With the feedwater system and main turbine high water level
 
trip capability not maintained, the feedwater system and
 
main turbine high water level trip instrumentation cannot
 
perform its design function. Therefore, continued operation
 
(continued)
Feedwater System and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2
 
LaSalle 1 and 2 B 3.3.2.2-5 Revision 0 BASES ACTIONS B.1 (continued) is only permitted for a 2 hour period, during which
 
feedwater system and main turbine high water level trip
 
capability must be restored. The trip capability is
 
considered maintained when sufficient channels are OPERABLE
 
or in trip such that the feedwater system and main turbine
 
high water level trip logic will generate a trip signal on a
 
valid signal. This requires two of the three trip channels
 
to have one feedwater system and main turbine high water
 
level channel OPERABLE or in trip. If the required channels
 
cannot be restored to OPERABLE status or placed in trip, Condition C must be entered and its Required Action taken.
 
The 2 hour Completion Time is sufficient for the operator to
 
take corrective action, and takes into account the
 
likelihood of an event requiring actuation of Feedwater
 
System and Main Turbine High Water Level Trip
 
Instrumentation occurring during this period. It is also
 
consistent with the 2 hour Completion Time provided in
 
LCO 3.2.2 for Required Action A.1, since this
 
instrumentation's purpose is to preclude a MCPR violation.
 
C.1 and C.2
 
With the channel(s) not restored to OPERABLE status or
 
placed in trip, THERMAL POWER must be reduced to
< 25% RTP within 4 hours. As discussed in the Applicability section
 
of the Bases, operation below 25% RTP results in sufficient
 
margin to the required limits, and the Feedwater System and
 
Main Turbine High Water Level Trip Instrumentation is not
 
required to protect fuel integrity during the feedwater
 
controller failure, maximum demand event. Alternatively, if
 
a channel is inoperable solely due to an inoperable motor-
 
driven feedwater pump breaker or feedwater stop valve, the
 
affected feedwater pump(s) may be removed from service since
 
this performs the intended function of the instrumentation.
 
The allowed Completion Time of 4 hours is based on operating
 
experience to reduce THERMAL POWER to
< 25% RTP from full power conditions in an orderly manner and without
 
challenging plant systems.
 
(continued)
Feedwater System and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2
 
LaSalle 1 and 2 B 3.3.2.2-6 Revision 0 BASES  (continued)
 
SURVEILLANCE The Surveillances are modified by a Note to indicate that REQUIREMENTS when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated
 
Conditions and Required Actions may be delayed for up to
 
6 hours provided the Function maintains feedwater system and
 
main turbine high water level trip capability. Upon
 
completion of the Surveillance, or expiration of the 6 hour
 
allowance, the channel must be returned to OPERABLE status
 
or the applicable Condition entered and Required Actions
 
taken. This Note is based on the reliability analysis (Ref. 2) assumption that 6 hours is the average time
 
required to perform channel Surveillance. That analysis
 
demonstrated that the 6 hour testing allowance does not
 
significantly reduce the probability that the feedwater pump
 
turbines, motor-driven feedwater pump, and main turbine will
 
trip when necessary.
 
SR  3.3.2.2.1
 
Performance of the CHANNEL CHECK once every 12 hours ensures
 
that a gross failure of instrumentation has not occurred. A
 
CHANNEL CHECK is normally a comparison of the parameter
 
indicated on one channel to a similar parameter on other
 
channels. It is based on the assumption that instrument
 
channels monitoring the same parameter should read
 
approximately the same value. Significant deviations
 
between instrument channels could be an indication of
 
excessive instrument drift in one of the channels, or
 
something even more serious. A CHANNEL CHECK will detect
 
gross channel failure; thus, it is key to verifying the
 
instrumentation continues to operate properly between each
 
CHANNEL CALIBRATION.
Agreement criteria are determined by the plant staff based
 
on a combination of the channel instrument uncertainties, including indication and readability. If a channel is
 
outside the criteria, it may be an indication that the
 
instrument has drifted outside its limits.
 
The Frequency is based on operating experience that
 
demonstrates channel failure is rare. The CHANNEL CHECK
 
supplements less formal, but more frequent, checks of
 
channel status during normal operational use of the displays
 
associated with the channels required by the LCO.
(continued)
Feedwater System and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2
 
LaSalle 1 and 2 B 3.3.2.2-7 Revision 0 BASES SURVEILLANCE SR  3.3.2.2.2 REQUIREMENTS (continued) A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended
 
function. A successful test of the required contact(s) of a
 
channel relay may be performed by the verification of the
 
change of state of a single contact of the relay. This
 
clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a
 
relay. This is acceptable because all of the other required
 
contacts of the relay are verified by other Technical
 
Specifications and non-Technical Specifications tests at
 
least once per refueling interval with applicable
 
extensions. Any setpoint adjustment shall be  consistent
 
with the assumptions of the current plant specific setpoint
 
methodology.
The Frequency of 92 days is based on reliability analysis (Ref. 2).
 
SR  3.3.2.2.3
 
CHANNEL CALIBRATION is a complete check of the instrument
 
loop and the sensor. This test verifies the channel
 
responds to the measured parameter within the necessary
 
range and accuracy. CHANNEL CALIBRATION leaves the channel
 
adjusted to account for instrument drifts between successive
 
calibrations consistent with the plant specific setpoint
 
methodology.
 
The Frequency is based upon the assumption of a 24 month
 
calibration interval in the determination of the magnitude
 
of equipment drift in the setpoint analysis.
 
SR  3.3.2.2.4
 
The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the
 
OPERABILITY of the required trip logic for a specific
 
channel. The system functional test of the feedwater and
 
main turbine stop valves and the motor-driven feedwater pump
 
breaker is included as part of this Surveillance and
 
overlaps the LOGIC SYSTEM FUNCTIONAL TEST to provide
 
(continued)
Feedwater System and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2
 
LaSalle 1 and 2 B 3.3.2.2-8 Revision 0 BASES SURVEILLANCE SR  3.3.2.2.4 (continued)
REQUIREMENTS complete testing of the assumed safety function. Therefore, if a turbine stop valve or motor feedwater pump breaker is
 
incapable of operating, the associated instrumentation would
 
also be inoperable. The 24 month Frequency is based on the
 
need to perform this Surveillance under the conditions that
 
apply during a plant outage and the potential for an
 
unplanned transient if the Surveillance were performed with
 
the reactor at power. Operating experience has shown that
 
these components usually pass the Surveillance when
 
performed at the 24 month Frequency.
 
REFERENCES 1. UFSAR, Section 15.1.2A.
: 2. GENE-770-06-1-A, "Bases for Changes to Surveillance Test Intervals and Allowed Out-Of-Service Times for
 
Selected Instrumentation Technical Specifications,"
December 1992.
 
PAM Instrumentation B 3.3.3.1
 
LaSalle 1 and 2 B 3.3.3.1-1 Revision 0 B 3.3  INSTRUMENTATION
 
B 3.3.3.1  Post Accident Monitoring (PAM) Instrumentation
 
BASES
 
BACKGROUND The primary purpose of the PAM instrumentation is to display, in the control room, plant variables that provide
 
information required by the control room operators during
 
accident situations. This information provides the
 
necessary support for the operator to take the manual
 
actions for which no automatic control is provided and that
 
are required for safety systems to accomplish their safety
 
functions for Design Basis Events. The instruments that
 
monitor these variables are designated as Type A, Category I, and non-Type A, Category I in accordance with
 
Regulatory Guide 1.97 (Ref. 1).
The OPERABILITY of the accident monitoring instrumentation
 
ensures that there is sufficient information available on
 
selected plant parameters to monitor and assess plant status
 
and behavior following an accident. This capability is
 
consistent with the recommendations of Reference 1.
 
APPLICABLE The PAM instrumentation LCO ensures the OPERABILITY of SAFETY ANALYSES Regulatory Guide 1.97, Type A, variables so that the control room operating staff can:
* Perform the diagnosis specified in the Emergency Operating Procedures (EOP). These variables are
 
restricted to preplanned actions for the primary
 
success path of Design Basis Accidents (DBAs)
(e.g., loss of coolant accident (LOCA)); and
* Take the specified, preplanned, manually controlled actions for which no automatic control is provided, which are required for safety systems to accomplish
 
their safety function.
 
The PAM instrumentation LCO also ensures OPERABILITY of
 
Category I, non-Type A, variables. This ensures the control
 
room operating staff can:
* Determine whether systems important to safety are performing their intended functions; (continued)
PAM Instrumentation B 3.3.3.1
 
LaSalle 1 and 2 B 3.3.3.1-2 Revision 0 BASES APPLICABLE
* Determine the potential for causing a gross breach of SAFETY ANALYSES  the barriers to radioactivity release;
 
  (continued)
* Determine whether a gross breach of a barrier has occurred; and
* Initiate action necessary to protect the public and to obtain an estimate of the magnitude of any impending
 
threat. The plant specific Regulatory Guide 1.97 analysis (Ref. 2)
 
documents the process that identified Type A and Category I, non-Type A, variables.
 
PAM instrumentation that meets the definition of Type A in
 
Regulatory Guide 1.97 satisfies Criterion 3 of
 
10 CFR 50.36(c)(2)(ii). Category I, non-Type A, instrumentation is retained in the Technical Specifications (TS) because it is intended to assist operators in
 
minimizing the consequences of accidents. Therefore, these
 
Category I, non-Type A, variables are important for reducing
 
public risk.
 
LCO LCO 3.3.3.1 requires two OPERABLE channels for all but one Function to ensure no single failure prevents the operators
 
from being presented with the information necessary to
 
determine the status of the unit and to bring the unit to, and maintain it in, a safe condition following an accident.
 
Furthermore, providing two channels allows a CHANNEL CHECK
 
during the post accident phase to confirm the validity of
 
displayed information.
The exception of the two channel requirement is primary
 
containment isolation valve (PCIV) position. In this case, the important information is the status of the primary
 
containment penetrations. The LCO requires one position
 
indicator for each active (e.g., automatic) PCIV. This is
 
sufficient to redundantly verify the isolation status of
 
each isolable penetration either via indicated status of the
 
active valve and prior knowledge of passive valve or via
 
system boundary status. If a normally active PCIV is known
 
to be closed and deactivated, position indication is not
 
needed to determine status. Therefore, the position
 
indication for closed and deactivated valves is not required
 
to be OPERABLE.
 
(continued)
PAM Instrumentation B 3.3.3.1
 
LaSalle 1 and 2 B 3.3.3.1-3 Revision 0 BASES LCO Listed below is a discussion of the specified instrument (continued) Functions listed in Table 3.3.3.1-1.
: 1. Reactor Steam Dome Pressure
 
Reactor steam dome pressure is a Type A and Category I
 
variable provided to support monitoring of Reactor Coolant
 
System (RCS) integrity and to verify operation of the
 
Emergency Core Cooling Systems (ECCS). Two independent
 
pressure transmitters with a range of 0 psig to 1500 psig
 
monitor pressure. Wide range recorders are the primary
 
indication used by the operator during an accident.
 
Therefore, the PAM Specification deals specifically with
 
this portion of the instrument channel.
: 2. Reactor Vessel Water Level
 
Reactor vessel water level is a Category I variable provided
 
to support monitoring of core cooling and to verify
 
operation of the ECCS. The wide range and fuel zone range
 
water level channels provide the PAM Reactor Vessel Water
 
Level Function. The range of the recorded/indicated level
 
is from the top of the feedwater control range (just above
 
the high level turbine trip point) down to a point just
 
below the bottom of the active fuel. Reactor vessel water
 
level is measured by six independent differential pressure
 
transmitters (i.e., four wide range channels and two fuel
 
zone range channels). These channels provide output to
 
recorders and indicators. Each division of the required
 
reactor vessel water level channels must include a recorder.
 
These instruments are the primary indication used by the
 
operator during an accident. Therefore, the PAM
 
Specification deals specifically with this portion of the
 
instrument channel.
 
The reactor vessel water level instruments are uncompensated
 
for variation in reactor water density and are calibrated to
 
be most accurate at a specific vessel pressure and
 
temperature. The wide range instruments are calibrated at
 
1000 psig reactor pressure with appropriate temperature
 
compensation and no jet pump flow. The fuel zone range
 
instruments are calibrated at saturated conditions at 0 psig
 
with no jet pump flow.
(continued)
PAM Instrumentation B 3.3.3.1
 
LaSalle 1 and 2 B 3.3.3.1-4 Revision 0 BASES LCO 3. Suppression Pool Water Level (continued)
Suppression pool water level is a Type A and Category I
 
variable provided to detect a breach in the reactor coolant
 
pressure boundary (RCPB). This variable is also used to
 
verify and provide long term surveillance of ECCS function.
 
The wide range suppression pool water level measurement
 
provides the operator with sufficient information to assess
 
the status of the RCPB and to assess the status of the water
 
supply to the ECCS. The wide range water level indicators
 
monitor the suppression pool level from 14 feet above normal
 
level down to the lowest ECCS suction point. Two wide range
 
suppression pool water level signals are transmitted from
 
separate transmitters and are continuously displayed on two
 
control room indicators, and separately recorded on two
 
recorders in the control room. These instruments are the
 
primary indication used by the operator during an accident.
 
Therefore, the PAM Specification deals specifically with
 
this portion of the instrument channel.
: 4. Drywell Pressure
 
Drywell pressure is a Type A and Category I variable
 
provided to detect a breach of the RCPB and to verify ECCS
 
functions that operate to maintain RCS integrity. There are
 
four drywell pressure monitoring channels, two wide range
 
channels and two narrow range channels. The combined range
 
of these instruments is from -5 to 200 psig. The signals
 
from the drywell pressure monitoring channels are
 
continuously recorded and displayed on two control room
 
recorders and the wide range channels are also displayed on
 
indicators. These instruments are the primary indication
 
used by the operator during an accident. Therefore, the PAM
 
Specification deals specifically with this portion of the
 
instrument channel.
: 5. Primary Containment Gross Gamma Radiation
 
Primary containment gross gamma radiation is a Category 1
 
variable provided to monitor for the potential of
 
significant radiation releases and to provide release
 
assessment for use by operators in determining the need to
 
invoke site emergency plans.
(continued)
PAM Instrumentation B 3.3.3.1
 
LaSalle 1 and 2 B 3.3.3.1-5 Revision 0 BASES LCO 5. Primary Containment Gross Gamma Radiation (continued)
Two redundant radiation detectors are located inside the
 
drywell that have a range of 10 0 R/hr to 10 8 R/hr. These radiation monitors display on recorders located in the
 
control room. Two radiation monitors/recorders are required
 
to be OPERABLE (one per division). Therefore, the PAM
 
Specification deals specifically with this portion of the
 
instrument channel.
: 6. Penetration Flow Path Primary Containment Isolation Valve (PCIV) Position
 
PCIV (excluding check valves, relief valves, manual valves, CRD solenoid valves, vacuum breakers, and excess flow check
 
valves) position is a Category I variable provided for
 
verification of containment integrity. In the case of PCIV
 
position, the important information is the isolation status
 
of the containment penetration. The LCO requires one
 
channel of valve position indication in the control room to
 
be OPERABLE for each active PCIV in a containment
 
penetration flow path requiring post-accident valve position
 
indication, i.e., two total channels of PCIV position
 
indication for a penetration flow path with two active
 
valves requiring post-accident valve position indication.
 
For containment penetrations with only one active PCIV
 
having control room indication, Note (b) requires a single
 
channel of valve position indication to be OPERABLE. This
 
is sufficient to verify redundantly the isolation status of
 
each isolable penetration via indicated status of the active
 
valve, as applicable, and prior knowledge of passive valve
 
or system boundary status. If a penetration is isolated, position indication for the PCIV(s) in the associated
 
penetration flow path is not needed to determine status.
 
Therefore, the position indication for valves in an isolated
 
penetration is not required to be OPERABLE. Each
 
penetration is treated separately and each penetration flow
 
path is considered a separate function. Therefore, separate
 
Condition entry is allowed for each inoperable penetration
 
flow path.
(continued)
PAM Instrumentation B 3.3.3.1
 
LaSalle 1 and 2 B 3.3.3.1-6 Revision 24 BASES LCO 6. Penetration Flow Path Primary Containment Isolation Valve (PCIV) Position (continued)
The indication for each PCIV is provided in the control
 
room. Indicator lights illuminate to indicate PCIV
 
position. Therefore, the PAM Specification deals
 
specifically with this portion of the instrumentation
 
channel.
7,8 (Deleted)
: 9. Suppression Pool Water Temperature
 
Suppression pool water temperature is a Type A and
 
Category I variable provided to detect a condition that
 
could potentially lead to containment breach, and to verify
 
the effectiveness of ECCS actions taken to prevent
 
containment breach. The suppression pool water temperature
 
instrumentation allows operators to detect trends in
 
suppression pool water temperature in sufficient time to
 
take action to prevent steam quenching vibrations in the
 
suppression pool. There are 14 total RTD instrument wells in the suppression pool. Each RTD well has two RTDs. Each (continued)
 
PAM Instrumentation B 3.3.3.1
 
LaSalle 1 and 2 B 3.3.3.1-7 Revision 24 BASES LCO 9. Suppression Pool Water Temperature (continued) channel receives input from the RTDs in 7 wells for a total of 14 RTDs. A channel is considered OPERABLE if it receives input from at least one OPERABLE RTD from each of the 7 wells. The RTDs are distributed throughout the pool area so as to be able to redundantly detect a stuck open
 
safety/relief valve continuous discharge into the pool.
 
The output for each channel of sensors is recorded on an
 
independent recorder in the control room. These recorders
 
are the primary indication used by the operator during an
 
accident. Therefore, the PAM Specification deals
 
specifically with this portion of the instrument channels.
 
APPLICABILITY The PAM instrumentation LCO is applicable in MODES 1 and 2.
These variables are related to the diagnosis and preplanned
 
actions required to mitigate DBAs. The applicable DBAs are
 
assumed to occur in MODES 1 and 2. In MODES 3, 4, and 5, plant conditions are such that the likelihood of an event
 
that would require PAM instrumentation is extremely low;
 
therefore, PAM instrumentation is not required to be
 
OPERABLE in these MODES.
 
ACTIONS A Note has been provided to modify the ACTIONS related to PAM instrumentation channels. Section 1.3, Completion
 
Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables
 
expressed in the Condition, discovered to be inoperable or
 
not within limits, will not result in separate entry into
 
the Condition. Section 1.3 also specifies that Required
 
(continued)
 
PAM Instrumentation B 3.3.3.1
 
LaSalle 1 and 2 B 3.3.3.1-8 Revision 0 BASES ACTIONS Actions of the Condition continue to apply for each (continued) additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for
 
inoperable PAM instrumentation channels provide appropriate
 
compensatory measures for separate inoperable functions. As
 
such, a Note has been provided that allows separate
 
Condition entry for each inoperable PAM Function.
 
A.1 When one or more Functions have one required channel that is
 
inoperable, the required inoperable channel must be restored
 
to OPERABLE status within 30 days. The 30 day Completion
 
Time is based on operating experience and takes into account
 
the remaining OPERABLE channel or remaining isolation
 
barrier (in the case of primary containment penetrations
 
with only one PCIV), the passive nature of the instrument (no critical automatic action is assumed to occur from these
 
instruments), and the low probability of an event requiring
 
PAM instrumentation during this interval.
 
B.1 If a channel has not been restored to OPERABLE status in
 
30 days, this Required Action specifies initiation of
 
actions in accordance with Specification 5.6.6, which
 
requires a written report to be submitted to the NRC. This
 
report discusses the results of the root cause evaluation of
 
the inoperability and identifies proposed restorative
 
actions. This Required Action is appropriate in lieu of a
 
shutdown requirement since another OPERABLE channel is
 
monitoring the Function, an alternative method of monitoring
 
is available and given the likelihood of plant conditions
 
that would require information provided by this
 
instrumentation.
 
C.1 When one or more Functions have two required channels that
 
are inoperable (i.e., two channels inoperable in the same
 
Function), one channel in the Function should be restored to
 
OPERABLE status within 7 days. The Completion Time of
 
(continued)
PAM Instrumentation B 3.3.3.1
 
LaSalle 1 and 2 B 3.3.3.1-9 Revision 0 BASES ACTIONS C.1 (continued) 7 days is based on the relatively low probability of an
 
event requiring PAM instrument operation and the
 
availability of alternate means to obtain the required
 
information. Continuous operation with two required
 
channels inoperable in a Function is not acceptable because
 
the alternate indications may not fully meet all performance
 
qualification requirements applied to the PAM
 
instrumentation. Therefore, requiring restoration of one
 
inoperable channel of the Function limits the risk that the
 
PAM Function will be in a degraded condition should an
 
accident occur. 
 
D.1 This Required Action directs entry into the appropriate
 
Condition referenced in Table 3.3.3.1-1. The applicable
 
Condition referenced in the Table is Function dependent.
 
Each time an inoperable channel has not met the Required
 
Action of Condition C, and the associated Completion Time
 
has expired, Condition D is entered for that channel and
 
provides for transfer to the appropriate subsequent
 
Condition.
 
E.1 For the majority of Functions in Table 3.3.3.1-1, if the 
 
Required Action and associated Completion Time of
 
Condition C is not met, the plant must be placed in a MODE
 
in which the LCO does not apply. This is done by placing
 
the plant in at least MODE 3 within 12 hours. The allowed
 
Completion Times are reasonable, based on operating
 
experience, to reach the required plant condition from full
 
power conditions in an orderly manner and without
 
challenging plant systems.
 
F.1 Since alternate means of monitoring primary containment
 
gross gamma radiation have been developed and tested, the
 
Required Action is not to shut down the plant but rather to
 
follow the directions of Specification 5.6.6. These (continued)
PAM Instrumentation B 3.3.3.1
 
LaSalle 1 and 2 B 3.3.3.1-10 Revision 0 BASES ACTIONS F.1 (continued) alternate means may be temporarily installed if the normal
 
PAM channel cannot be restored to OPERABLE status within the
 
allotted time. The report provided to the NRC should
 
discuss the alternate means used, describe the degree to
 
which the alternate means are equivalent to the installed
 
PAM channels, justify the areas in which they are not
 
equivalent, and provide a schedule for restoring the normal
 
PAM channels.
 
SURVEILLANCE As noted at the beginning of the SRs, the following SRs REQUIREMENTS apply to each PAM instrumentation Function in Table 3.3.3.1-1.
 
The Surveillances are modified by a second Note to indicate
 
that when a channel is placed in an inoperable status solely
 
for performance of required Surveillances, entry into
 
associated Conditions and Required Actions may be delayed
 
for up to 6 hours, provided the other required channel in
 
the associated Function is OPERABLE. Upon completion of the
 
Surveillance, or expiration of the 6 hour allowance, the
 
channel must be returned to OPERABLE status or the
 
applicable Condition entered and Required Actions taken.
 
The 6 hour testing allowance is acceptable since it does not
 
significantly reduce the probability of properly monitoring
 
post-accident parameters, when necessary.
 
SR  3.3.3.1.1
 
Performance of the CHANNEL CHECK once every 31 days ensures
 
that a gross instrumentation failure has not occurred. A
 
CHANNEL CHECK is normally a comparison of the parameter
 
indicated on one channel to a similar parameter on other
 
channels. It is based on the assumption that instrument
 
channels monitoring the same parameter should read
 
approximately the same value. Significant deviations
 
between instrument channels could be an indication of
 
excessive instrument drift in one of the channels or of
 
something even more serious. A CHANNEL CHECK will detect
 
gross channel failure; thus, it is key to verifying the
 
instrumentation continues to operate properly between each
 
CHANNEL CALIBRATION. 
(continued)
PAM Instrumentation B 3.3.3.1
 
LaSalle 1 and 2 B 3.3.3.1-11 Revision 18 BASES SURVEILLANCE SR  3.3.3.1.1 (continued)
REQUIREMENTS Agreement criteria are determined by the plant staff based
 
on a combination of the channel instrument uncertainties, including indication and readability. If a channel is
 
outside the criteria, it may be an indication that the
 
sensor or the signal processing equipment has drifted
 
outside its limit. 
 
The Frequency of 31 days is based upon plant operating
 
experience with regard to channel OPERABILITY and drift, which demonstrates that failure of more than one channel of
 
a given function in any 31 day interval is rare. The
 
CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of those
 
displays associated with the channels required by the LCO.
 
SR  3.3.3.1.2 (Deleted)
SR  3.3.3.1.3
 
A CHANNEL CALIBRATION is performed every 24 months. For Function 6, the CHANNEL CALIBRATION shall consist of
 
verifying that the position indication conforms to the
 
actual valve position. CHANNEL CALIBRATION is a complete
 
check of the instrument loop including the sensor. The test
 
verifies that the channel responds to the measured parameter
 
with the necessary range and accuracy. The 24 month Frequency for CHANNEL CALIBRATION is based on operating experience and consistency with the refueling cycles.
 
REFERENCES 1. Regulatory Guide 1.97, "Instrumentation for Light-Water Cooled Nuclear Power Plants to Assess
 
Plant and Environs Conditions During and Following an
 
Accident," Revision 2, December 1980.
: 2. NRC Safety Evaluation Report, "Commonwealth Edison Company, LaSalle County Station, Unit Nos. 1 and 2, Conformance to Regulatory Guide 1.97," dated August
 
20, 1987.
 
Remote Shutdown Monitoring System B 3.3.3.2
 
LaSalle 1 and 2 B 3.3.3.2-1 Revision 0 B 3.3  INSTRUMENTATION
 
B 3.3.3.2  Remote Shutdown Monitoring System
 
BASES
 
BACKGROUND The Remote Shutdown Monitoring System provides the control room operator with sufficient instrumentation to support
 
maintaining the plant in a safe shutdown condition from a
 
location other than the control room. This capability is
 
necessary to protect against the possibility of the control
 
room becoming inaccessible. A safe shutdown condition is
 
defined as MODE 3. With the plant in MODE 3, the Reactor
 
Core Isolation Cooling (RCIC) System, the safety/relief
 
valves, and the Residual Heat Removal (RHR) System can be
 
used to remove core decay heat and meet all safety
 
requirements. The long term supply of water for the RCIC
 
System and the ability to operate shutdown cooling from
 
outside the control room allow extended operation in MODE 3.
In the event that the control room becomes inaccessible, the
 
operators can monitor the status of the reactor and the
 
suppression pool and the operation of the RHR and RCIC
 
Systems at the remote shutdown panel and support maintaining
 
the plant in MODE 3. The plant is in MODE 3 following a
 
plant shutdown and can be maintained safely in MODE 3 for an
 
extended period of time.
 
The OPERABILITY of the Remote Shutdown Monitoring System
 
instrumentation Functions ensures that there is sufficient
 
information available on selected plant parameters to
 
support maintaining the plant in MODE 3 should the control
 
room become inaccessible.
 
APPLICABLE The Remote Shutdown Monitoring System is required to provide SAFETY ANALYSES instrumentation at appropriate locations outside the control room with a design capability to support maintaining the
 
plant in a safe condition in MODE 3.
The criteria governing the design and the specific system
 
requirements of the Remote Shutdown Monitoring System are
 
located in UFSAR, Section 7.4.4 (Ref. 1).
 
The Remote Shutdown Monitoring System is considered an
 
important contributor to reducing the risk of accidents; as
 
such, it meets Criterion 4 of 10 CFR 50.36(c)(2)(ii). (continued)
Remote Shutdown Monitoring System B 3.3.3.2
 
LaSalle 1 and 2 B 3.3.3.2-2 Revision 0 BASES  (continued)
 
LCO The Remote Shutdown Monitoring System LCO provides the requirements for the OPERABILITY of the instrumentation
 
necessary to support maintaining the plant in MODE 3 from a
 
location other than the control room. The instrumentation
 
Functions required are listed in the Technical Requirements
 
Manual (Ref. 2).
The instrumentation is that required for:
* Reactor pressure vessel (RPV) pressure control;
* Decay heat removal; and
* RPV inventory control.
The Remote Shutdown Monitoring System is OPERABLE if all
 
instrument channels needed to support the remote shutdown
 
monitoring functions are OPERABLE with readouts displayed in
 
the remote shutdown panel external to the control room. 
 
The Remote Shutdown Monitoring System instruments covered by
 
this LCO do not need to be energized to be considered
 
OPERABLE. This LCO is intended to ensure that the
 
instruments will be OPERABLE if plant conditions require
 
that the Remote Shutdown Monitoring System be placed in
 
operation.
 
APPLICABILITY The Remote Shutdown Monitoring System LCO is applicable in MODES 1 and 2. This is required so that the plant can be
 
maintained in MODE 3 for an extended period of time from a
 
location other than the control room.
This LCO is not applicable in MODES 3, 4, and 5. In these
 
MODES, the plant is already subcritical and in a condition
 
of reduced Reactor Coolant System energy. Under these
 
conditions, considerable time is available to restore
 
necessary instrument Functions if control room instruments
 
become unavailable. Consequently, the LCO does not require
 
OPERABILITY in MODES 3, 4, and 5.
 
(continued)
Remote Shutdown Monitoring System B 3.3.3.2
 
LaSalle 1 and 2 B 3.3.3.2-3 Revision 19 BASES  (continued)
 
ACTIONS The Remote Shutdown Monitoring System is inoperable when each required function is not accomplished by at least one
 
designated Remote Shutdown Monitoring System channel that
 
satisfies the OPERABILITY criteria for the channel's
 
Function. These criteria are outlined in the LCO section of
 
the Bases.
 
A Note has been provided to modify the ACTIONS related to Remote Shutdown Monitoring System Functions. Section 1.3, Completion Times, specifies that once a Condition has been
 
entered, subsequent divisions, subsystems, components, or
 
variables expressed in the Condition, discovered to be
 
inoperable or not within limits, will not result in separate
 
entry into the Condition. Section 1.3 also specifies that
 
Required Actions of the Condition continue to apply for each
 
additional failure, with Completion Times based on initial
 
entry into the Condition. However, the Required Actions for
 
inoperable Remote Shutdown Monitoring System Functions
 
provide appropriate compensatory measures for separate
 
Functions. 
 
As such, a Note has been provided that allows separate
 
Condition entry for each inoperable Remote Shutdown
 
Monitoring System Function.
 
A.1 Condition A addresses the situation where one or more
 
required Functions of the Remote Shutdown Monitoring System
 
is inoperable. This includes any required Function listed
 
in Reference 2.
 
The Required Action is to restore the Function to OPERABLE
 
status within 30 days. The Completion Time is based on
 
operating experience and the low probability of an event
 
that would require evacuation of the control room.
(continued)
Remote Shutdown Monitoring System B 3.3.3.2
 
LaSalle 1 and 2 B 3.3.3.2-4 Revision 0 BASES ACTIONS B.1 (continued)
If the Required Action and associated Completion Time of
 
Condition A are not met, the plant must be brought to a MODE
 
in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within
 
12 hours. The allowed Completion Time is reasonable, based
 
on operating experience, to reach the required MODE from
 
full power conditions in an orderly manner and without
 
challenging plant systems.
 
SURVEILLANCE The Surveillances are modified by a Note to indicate that REQUIREMENTS  when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated
 
Conditions and Required Actions may be delayed for up to 6
 
hours. Upon completion of the Surveillance, or expiration
 
of the 6 hour allowance, the channel must be returned to
 
OPERABLE status or the applicable Condition entered and
 
Required Actions taken. The 6 hour testing allowance is
 
acceptable since it does not significantly reduce the
 
probability of properly monitoring remote shutdown
 
parameters, when necessary.
 
SR  3.3.3.2.1
 
Performance of the CHANNEL CHECK once every 31 days ensures
 
that a gross failure of instrumentation has not occurred. A
 
CHANNEL CHECK is normally a comparison of the parameter
 
indicated on one channel to a similar parameter on other
 
channels. It is based on the assumption that instrument
 
channels monitoring the same parameter should read
 
approximately the same value. Significant deviations
 
between the instrument channels could be an indication of
 
excessive instrument drift in one of the channels or
 
something even more serious. A CHANNEL CHECK will detect
 
gross channel failure; thus, it is key to verifying the
 
instrumentation continues to operate properly between each
 
CHANNEL CALIBRATION.
 
(continued)
Remote Shutdown Monitoring System B 3.3.3.2
 
LaSalle 1 and 2 B 3.3.3.2-5 Revision 0 BASES SURVEILLANCE SR  3.3.3.2.1 (continued)
REQUIREMENTS Agreement criteria are determined by the plant staff based
 
on a combination of the channel instrument uncertainties, including indication and readability. If a channel is
 
outside the criteria, it may be an indication that the
 
sensor or the signal processing equipment has drifted
 
outside its limit. As specified in the Surveillance, a
 
CHANNEL CHECK is only required for those channels that are
 
normally energized.
The Frequency is based upon operating experience that
 
demonstrates channel failure is rare.
 
SR  3.3.3.2.2
 
CHANNEL CALIBRATION is a complete check of the instrument
 
loop and the sensor. The test verifies the channel responds
 
to measured parameter values with the necessary range and
 
accuracy.
 
The 24 month Frequency is based upon operating experience
 
and engineering judgement and is consistent with the
 
refueling cycle.
 
REFERENCES 1. UFSAR, Section 7.4.4.
: 2. Technical Requirements Manual.
 
EOC-RPT Instrumentation B 3.3.4.1
 
LaSalle 1 and 2 B 3.3.4.1-1 Revision 0 B 3.3  INSTRUMENTATION
 
B 3.3.4.1  End of Cycle Recirculation Pump Trip (EOC-RPT) Instrumentation
 
BASES
 
BACKGROUND The EOC-RPT instrumentation initiates a recirculation pump trip (RPT), if operating in fast speed, to reduce the peak
 
reactor pressure and power resulting from turbine trip or
 
generator load rejection transients to provide additional
 
margin to the MCPR Safety Limit (SL).
The need for the additional negative reactivity in excess of
 
that normally inserted on a scram reflects end of cycle
 
reactivity considerations. Flux shapes at the end of cycle
 
are such that the control rods may not be able to ensure
 
that thermal limits are maintained by inserting sufficient
 
negative reactivity during the first few feet of rod travel
 
upon a scram caused by Turbine Control Valve (TCV)-Fast
 
Closure, Trip Oil Pressure-Low, or Turbine Stop Valve (TSV)-Closure. The physical phenomenon involved is that
 
the void reactivity feedback due to a pressurization
 
transient can add positive reactivity at a faster rate than
 
the control rods can add negative reactivity.
 
The EOC-RPT instrumentation as shown in Reference 1 is
 
comprised of sensors that detect initiation of closure of
 
the TSVs, or fast closure of the TCVs, combined with relays
 
and logic circuits, to actuate reactor recirculation pump
 
downshift logic to trip each pump from fast speed (60 Hz).
 
The channels include instrument switches that actuate
 
pre-established setpoints. When the setpoint is exceeded, the switch actuates, which then outputs an EOC-RPT signal to
 
the trip logic to downshift the pumps. When the EOC-RPT
 
breakers (3A, 3B, 4A, and 4B; the fast speed breakers) trip
 
open, the recirculation pumps coast down under their own
 
inertia, breakers 1A and 1B close to start the LFMG, and the
 
low frequency breakers 2A and 2B close automatically on a
 
motor speed interlock to operate the recirculation pumps on
 
low speed (although the recirculation pump start in low
 
speed is not part of the EOC-RPT Instrumentation safety
 
function). The EOC-RPT has two identical trip systems, either of which can actuate an RPT.
(continued)
EOC-RPT Instrumentation B 3.3.4.1
 
LaSalle 1 and 2 B 3.3.4.1-2 Revision 0 BASES BACKGROUND Each EOC-RPT trip system is a two-out-of-two logic for each (continued) Function; thus, either two TSV-Closure or two TCV-Fast Closure, Trip Oil Pressure-Low signals are required for a
 
trip system to actuate. If either trip system actuates, both recirculation pumps, if operating in fast speed, will
 
trip. There are two EOC-RPT breakers in series per
 
recirculation pump. One trip system trips one of the two
 
EOC-RPT breakers for each recirculation pump and the second
 
trip system trips the other EOC-RPT breaker for each
 
recirculation pump.
 
APPLICABLE The TSV-Closure and the TCV-Fast Closure, Trip Oil SAFETY ANALYSES, Pressure-Low Functions are designed to trip the LCO, and recirculation pumps, if operating in fast speed, in the APPLICABILITY event of a turbine trip or generator load rejection to mitigate the neutron flux, heat flux and pressurization
 
transients, and to increase the margin to the MCPR SL. The
 
analytical methods and assumptions used in evaluating the
 
turbine trip and generator load rejection, as well as other
 
safety analyses that assume EOC-RPT, are summarized in
 
References 2, 3, and 4.
To mitigate pressurization transient effects, the EOC-RPT
 
must trip the recirculation pumps, if operating in fast
 
speed, after initiation of initial closure movement of
 
either the TSVs or the TCVs. The combined effects of this
 
trip and a scram reduce fuel bundle power more rapidly than
 
does a scram alone, resulting in an increased margin to the
 
MCPR SL. Alternatively, MCPR limits for an inoperable
 
EOC-RPT as specified in the COLR are sufficient to mitigate
 
pressurization transient effects. The EOC-RPT function is
 
automatically disabled when THERMAL POWER as sensed by
 
turbine first stage pressure is
< 25% RTP.
 
EOC-RPT instrumentation satisfies Criterion 3 of
 
10 CFR 50.36(c)(2)(ii).
 
The OPERABILITY of the EOC-RPT is dependent on the
 
OPERABILITY of the individual instrumentation channel
 
Functions. Each Function must have a required number of
 
OPERABLE channels in each trip system, with their setpoints
 
within the specified Allowable Value of SR 3.3.4.1.2. The
 
actual setpoint is calibrated consistent with applicable 
 
(continued)
EOC-RPT Instrumentation B 3.3.4.1
 
LaSalle 1 and 2 B 3.3.4.1-3 Revision 0 BASES APPLICABLE setpoint methodology assumptions. Channel OPERABILITY also SAFETY ANALYSES, includes the associated EOC-RPT breakers. Each channel LCO, and (including the associated EOC-RPT breakers) must also APPLICABILITY respond within its assumed response time.
 
  (continued)
 
Allowable Values are specified for each EOC-RPT Function
 
specified in the LCO. Nominal trip setpoints are specified
 
in the setpoint calculations. The nominal setpoints are
 
selected to ensure the setpoints do not exceed the Allowable
 
Value between successive CHANNEL CALIBRATIONS. Operation
 
with a trip setpoint less conservative than the nominal trip
 
setpoint, but within its Allowable Value, is acceptable. A
 
channel is inoperable if its actual trip setpoint is not
 
within its required Allowable Value. Trip setpoints are
 
those predetermined values of output at which an action
 
should take place. The setpoints are compared to the actual
 
process parameter (e.g., TCV electrohydraulic control (EHC)
 
pressure), and when the measured output value of the process
 
parameter exceeds the setpoint, the associated device (e.g.,
trip switches) change state. The analytic limits are
 
derived from the limiting values of the process parameters
 
obtained from the safety analysis. The trip setpoints are
 
determined from the analytic limits, corrected for defined
 
process, calibration, and instrument errors. The Allowable
 
Values are then determined, based on the trip setpoint
 
values, by accounting for the calibration based errors.
 
These calibration based errors are limited to reference
 
accuracy, instrument drift, errors associated with
 
measurement and test equipment, and calibration tolerance of
 
loop components. The trip setpoints and Allowable Values
 
determined in this manner provide adequate protection
 
because instrument uncertainties, process effects, calibration tolerances, instrument drift, and severe
 
environment errors (for channels that must function in harsh
 
environments as defined by 10 CFR 50.49) are accounted for
 
and appropriately applied for the instrumentation.
 
The specific Applicable Safety Analysis, LCO, and
 
Applicability discussions are listed below on a Function by
 
Function basis.
 
(continued)
EOC-RPT Instrumentation B 3.3.4.1
 
LaSalle 1 and 2 B 3.3.4.1-4 Revision 0 BASES APPLICABLE Alternately, since this instrumentation protects against a SAFETY ANALYSES, MCPR SL violation with the instrumentation inoperable, LCO, and modifications to the MCPR limits (LCO 3.2.2) may be applied APPLICABILITY to allow this LCO to be met. The MCPR limit for the (continued) condition EOC-RPT inoperable is specified in the COLR.
 
Turbine Stop Valve-Closure
 
Closure of the TSVs and a main turbine trip result in the
 
loss of a heat sink that produces reactor pressure, neutron
 
flux, and heat flux transients that must be limited.
 
Therefore, an RPT is initiated on TSV-Closure, in
 
anticipation of the transients that would result from
 
closure of these valves. EOC-RPT decreases reactor power
 
and aids the reactor scram in ensuring the MCPR SL is not
 
exceeded during the worst case transient.
 
Closure of the TSVs is determined by monitoring the position
 
of each stop valve. There is one valve stem position switch
 
associated with each stop valve, and the signal from each
 
switch is assigned to a separate trip channel. The logic
 
for the TSV-Closure Function is such that two or more TSVs
 
must be closed to produce an EOC-RPT. This Function must be
 
enabled at THERMAL POWER  25% RTP. This is normally accomplished automatically by pressure switches sensing
 
turbine first stage pressure; therefore, opening of the
 
turbine bypass valves may affect the OPERABILITY of this
 
Function. Four channels of TSV-Closure, with two channels
 
in each trip system, are available and required to be
 
OPERABLE to ensure that no single instrument failure will
 
preclude an EOC-RPT from this Function on a valid signal.
 
The TSV-Closure Allowable Value is selected to detect
 
imminent TSV closure.
 
This protection is required, consistent with the safety
 
analysis assumptions, whenever THERMAL POWER is  25% RTP with any recirculating pump in fast speed. Below 25% RTP or
 
with the recirculation in slow speed, the Reactor Vessel
 
Steam Dome Pressure-High and the Average Power Range
 
Monitor (APRM) Fixed Neutron Flux-High Functions of the
 
Reactor Protection System (RPS) are adequate to maintain the
 
necessary safety margins.
 
(continued)
EOC-RPT Instrumentation B 3.3.4.1
 
LaSalle 1 and 2 B 3.3.4.1-5 Revision 0 BASES APPLICABLE TCV-Fast Closure, Trip Oil Pressure-Low SAFETY ANALYSES, LCO, and Fast closure of the TCVs during a generator load rejection APPLICABILITY results in the loss of a heat sink that produces reactor (continued) pressure, neutron flux, and heat flux transients that must be limited. Therefore, an RPT is initiated on TCV-Fast
 
Closure, Trip Oil Pressure-Low in anticipation of the
 
transients that would result from the closure of these
 
valves. The EOC-RPT decreases reactor power and aids the
 
reactor scram in ensuring that the MCPR SL is not exceeded
 
during the worst case transient.
Fast closure of the TCVs is determined by measuring the EHC
 
fluid pressure at each control valve. There is one pressure
 
switch associated with each control valve, and the signal
 
from each switch is assigned to a separate trip channel.
 
The logic for the TCV-Fast Closure, Trip Oil Pressure-Low
 
Function is such that two or more TCVs must be closed (pressure switch trips) to produce an EOC-RPT. This
 
Function must be enabled at THERMAL POWER  25% RTP. This is normally accomplished automatically by pressure switches
 
sensing turbine first stage pressure; therefore, opening of
 
the turbine bypass valves may affect the OPERABILITY of this
 
Function. Four channels of TCV-Fast Closure, Trip Oil
 
Pressure-Low with two channels in each trip system, are
 
available and required to be OPERABLE to ensure that no
 
single instrument failure will preclude an EOC-RPT from this
 
Function on a valid signal. The TCV-Fast Closure, Trip Oil
 
Pressure-Low Allowable Value is selected high enough to
 
detect imminent TCV fast closure.
 
This protection is required consistent with the analysis, whenever the THERMAL POWER is  25% RTP with any recirculating pump in fast speed. Below 25% RTP or with
 
recirculation pumps in slow speed, the Reactor Vessel Steam
 
Dome Pressure-High and the APRM Fixed Neutron Flux-High
 
Functions of the RPS are adequate to maintain the necessary
 
safety margins. The turbine first stage pressure/reactor
 
power relationship for the setpoint of the automatic enable
 
is identical to that described for TSV closure.
 
(continued)
EOC-RPT Instrumentation B 3.3.4.1
 
LaSalle 1 and 2 B 3.3.4.1-6 Revision 0 BASES  (continued)
 
ACTIONS A Note has been provided to modify the ACTIONS related to EOC-RPT instrumentation channels. Section 1.3, Completion
 
Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables
 
expressed in the Condition, discovered to be inoperable or
 
not within limits, will not result in separate entry into
 
the Condition. Section 1.3 also specifies that Required
 
Actions of the Condition continue to apply for each
 
additional failure, with Completion Times based on initial
 
entry into the Condition. However, the Required Actions for
 
inoperable EOC-RPT instrumentation channels provide
 
appropriate compensatory measures for separate inoperable
 
channels. As such, a Note has been provided that allows
 
separate Condition entry for each inoperable EOC-RPT
 
instrumentation channel.
 
A.1 and A.2
 
With one or more required channels inoperable, but with
 
EOC-RPT trip capability maintained (refer to Required
 
Action B.1 and B.2 Bases), the EOC-RPT System is capable of
 
performing the intended function. However, the reliability
 
and redundancy of the EOC-RPT instrumentation is reduced
 
such that a single failure in the remaining trip system
 
could result in the inability of the EOC-RPT System to
 
perform the intended function. Therefore, only a limited
 
time is allowed to restore compliance with the LCO. Because
 
of the diversity of sensors available to provide trip
 
signals, the low probability of extensive numbers of
 
inoperabilities affecting all diverse Functions, and the low
 
probability of an event requiring the initiation of an
 
EOC-RPT, 72 hours is allowed to restore the inoperable
 
channels (Required Action A.1) or apply the EOC-RPT
 
inoperable MCPR limit. Alternately, the inoperable channels
 
may be placed in trip (Required Action A.2) since this would
 
conservatively compensate for the inoperability, restore
 
capability to accommodate a single failure, and allow
 
operation to continue. As noted in Required Action A.2, placing the channel in trip with no further restrictions is
 
not allowed if the inoperable channel is the result of an
 
inoperable breaker, since this may not adequately compensate
 
for the inoperable breaker (e.g., the breaker may be 
 
(continued)
EOC-RPT Instrumentation B 3.3.4.1
 
LaSalle 1 and 2 B 3.3.4.1-7 Revision 0 BASES ACTIONS A.1 and A.2 (continued) inoperable such that it will not open). If it is not
 
desired to place the channel in trip (e.g., as in the case
 
where placing the inoperable channel in trip would result in
 
an RPT), or if the inoperable channel is the result of an
 
inoperable breaker, Condition C must be entered and its
 
Required Actions taken.
 
B.1 and B.2
 
Required Actions B.1 and B.2 are intended to ensure that
 
appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in the
 
Function not maintaining EOC-RPT trip capability. A
 
Function is considered to be maintaining EOC-RPT trip
 
capability when sufficient channels are OPERABLE or in trip, such that the EOC-RPT System will generate a trip signal
 
from the given Function on a valid signal and both
 
recirculation pumps, if operating in fast speed, can be
 
tripped. This requires two channels of the Function, in the
 
same trip system, to each be OPERABLE or in trip, and the
 
associated EOC-RPT breakers to be OPERABLE or in trip.
 
Alternatively, Required Action B.2 requires the MCPR limit
 
for inoperable EOC-RPT, as specified in the COLR, to be
 
applied. This also restores the margin to MCPR assumed in
 
the safety analysis.
 
The 2 hour Completion Time is sufficient for the operator to
 
take corrective action, and takes into account the
 
likelihood of an event requiring actuation of the EOC-RPT
 
instrumentation during this period. It is also consistent
 
with the 2 hour Completion Time provided in LCO 3.2.2, Required Action A.1, since this instrumentation's purpose is
 
to preclude a MCPR violation.
 
C.1 and C.2
 
With any Required Action and associated Completion Time not
 
met, THERMAL POWER must be reduced to
< 25% RTP within 4 hours. Alternately, the associated recirculation pump
 
fast speed breaker may be removed from service since this
 
performs the intended function of the instrumentation. The 
 
(continued)
EOC-RPT Instrumentation B 3.3.4.1
 
LaSalle 1 and 2 B 3.3.4.1-8 Revision 0 BASES ACTIONS C.1 and C.2 (continued) allowed Completion Time of 4 hours is reasonable, based on
 
operating experience, to reduce THERMAL POWER to
< 25% RTP from full power conditions in an orderly manner and without
 
challenging plant systems.
 
SURVEILLANCE The Surveillances are modified by a Note to indicate that REQUIREMENTS when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated
 
Conditions and Required Actions may be delayed for up to
 
6 hours, provided the associated Function maintains EOC-RPT
 
trip capability. Upon completion of the Surveillance, or
 
expiration of the 6 hour allowance, the channel must be
 
returned to OPERABLE status or the applicable Condition
 
entered and Required Actions taken. This Note is based on
 
the reliability analysis (Ref. 5) assumption of the average
 
time required to perform channel surveillance. That
 
analysis demonstrated that the 6 hour testing allowance does
 
not significantly reduce the probability that the
 
recirculation pumps will trip when necessary.
 
SR  3.3.4.1.1
 
A CHANNEL FUNCTIONAL TEST is performed on each required
 
channel to ensure that the channel will perform the intended
 
function. A successful test of the required contact(s) of a
 
channel relay may be performed by the verification of the
 
change of state of a single contact of the relay. This
 
clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a
 
relay. This is acceptable because all of the other required
 
contacts of the relay are verified by other Technical
 
Specifications and non-Technical Specifications tests at
 
least once per refueling interval with applicable
 
extensions. Any setpoint adjustment shall be consistent
 
with the assumptions of the current plant specific setpoint
 
methodology.
 
The Frequency of 92 days is based on reliability analysis (Ref. 5).
(continued)
EOC-RPT Instrumentation B 3.3.4.1
 
LaSalle 1 and 2 B 3.3.4.1-9 Revision 0 BASES SURVEILLANCE SR  3.3.4.1.2 REQUIREMENTS (continued) CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel
 
responds to the measured parameter within the necessary
 
range and accuracy. CHANNEL CALIBRATION leaves the channel
 
adjusted to account for instrument drifts between successive
 
calibrations consistent with the plant specific setpoint
 
methodology.
The Frequency is based upon the assumption of a 24 month
 
calibration interval, in the determination of the magnitude
 
of equipment drift in the setpoint analysis.
 
SR  3.3.4.1.3
 
The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the
 
OPERABILITY of the required trip logic for a specific
 
channel. The system functional test of the pump breakers is
 
included as a part of this test, overlapping the LOGIC
 
SYSTEM FUNCTIONAL TEST, to provide complete testing of the
 
associated safety function. Therefore, if a breaker is
 
incapable of operating, the associated instrument channel
 
would also be inoperable.
 
The 24 month Frequency is based on the need to perform this
 
Surveillance under the conditions that apply during a plant
 
outage and the potential for an unplanned transient if the
 
Surveillance were performed with the reactor at power.
 
Operating experience has shown these components usually pass
 
the Surveillance test when performed at the 24 month
 
Frequency.
 
SR  3.3.4.1.4
 
This SR ensures that an EOC-RPT initiated from the
 
TSV-Closure and TCV-Fast Closure, Trip Oil Pressure-Low
 
Functions will not be inadvertently bypassed when THERMAL
 
POWER is  25% RTP. This involves calibration of the bypass channels. Adequate margins for the instrument setpoint
 
methodologies are incorporated into the actual setpoint.
 
Because main turbine bypass flow can affect this setpoint (continued)
EOC-RPT Instrumentation B 3.3.4.1
 
LaSalle 1 and 2 B 3.3.4.1-10 Revision 0 BASES SURVEILLANCE SR  3.3.4.1.4 (continued)
REQUIREMENTS nonconservatively (THERMAL POWER is derived from first stage
 
pressure), the main turbine bypass valves must remain closed
 
during an in-service calibration at THERMAL POWER  25% RTP, if performing the calibration using actual turbine first
 
stage pressure, to ensure that the calibration remains
 
valid. If any bypass channel's setpoint is nonconservative (i.e., the Functions are bypassed at  25% RTP either due to open main turbine bypass valves or other reasons), the
 
affected TSV-Closure and TCV-Fast Closure, Trip Oil
 
Pressure-Low Functions are considered inoperable.
 
Alternatively, the bypass channel can be placed in the
 
conservative condition (nonbypass). If placed in the
 
nonbypass condition, this SR is met and the channel
 
considered OPERABLE.
 
The Frequency of 24 months is based on engineering judgement
 
and reliability of the components.
 
SR  3.3.4.1.5
 
This SR ensures that the individual channel response times
 
are less than or equal to the maximum values assumed in the
 
accident analysis. The EOC-RPT SYSTEM RESPONSE TIME
 
acceptance criteria are included in Reference 6.
 
EOC-RPT SYSTEM RESPONSE TIME may be verified by actual
 
response time measurements in any series of sequential, over
 
lapping, or total channel measurements. However, the
 
response time of the limit switches for the TSV-Closure
 
Function may be assumed to be the design limit switch
 
response time and therefore, is excluded from the EOC-RPT
 
SYSTEM RESPONSE TIME testing. This is allowed, as
 
documented in Reference 7, since the actual measurement of
 
the limit switch response time is not practicable as this
 
test is done during the refueling outage when the turbine
 
stop valves are fully closed, and thus the limit switch in
 
the circuitry is open. The design limit switch response
 
time is 10 ms.
(continued)
EOC-RPT Instrumentation B 3.3.4.1
 
LaSalle 1 and 2 B 3.3.4.1-11 Revision 0 BASES SURVEILLANCE SR  3.3.4.1.5 (continued)
REQUIREMENTS A Note to the Surveillance states that breaker arc
 
suppression time may be assumed from the most recent
 
performance of SR 3.3.4.1.6. This is allowed since the arc
 
suppression time is short and does not appreciably change, due to the design of the breaker opening device and the fact
 
that the breaker is not routinely cycled. 
 
EOC-RPT SYSTEM RESPONSE TIME tests are conducted on a
 
24 month STAGGERED TEST BASIS. The STAGGERED TEST BASIS is
 
conducted on a function basis such that each test includes
 
at least the logic of one type of channel input, i.e.,
TCV-Fast Closure, Trip Oil Pressure-Low, or TSV-Closure, such that both types of channel inputs are tested at least
 
once per 48 months. Response times cannot be determined at
 
power because operation of final actuated devices is
 
required. Therefore, the 24 month Frequency is consistent
 
with the refueling cycle and is based upon plant operating
 
experience, which shows that random failures of
 
instrumentation components that cause serious response time
 
degradation, but not channel failure, are infrequent
 
occurrences.
 
SR  3.3.4.1.6
 
This SR ensures that the EOC-RPT breaker arc suppression
 
time is provided to the EOC-RPT SYSTEM RESPONSE TIME test.
 
The 60 month Frequency of the testing is based on the
 
difficulty of performing the test and the reliability of the
 
circuit breakers.
 
REFERENCES 1. UFSAR, Figure G.3.3-2.
: 2. UFSAR, Sections 7.6.4, G.3.3.3.8.2, and G.5.1.
: 3. UFSAR, Sections 15.1.2A, 15.2.2A, 15.2.3, and 15.3A.
: 4. UFSAR, Section 7.6.4.2.1.
(continued)
EOC-RPT Instrumentation B 3.3.4.1
 
LaSalle 1 and 2 B 3.3.4.1-12 Revision 0 BASES REFERENCES 5. GENE-770-06-1-A, "Bases for Changes To Surveillance (continued)  Test Intervals And Allowed Out-Of-Service Times For Selected Instrumentation Technical Specifications,"
December 1992.
: 6. Technical Requirements Manual.
: 7. Letter, W.G. Guldemond (NRC) to C. Reed (ComEd), dated January 28, 1987.
 
ATWS-RPT Instrumentation B 3.3.4.2
 
LaSalle 1 and 2 B 3.3.4.2-1 Revision 31 B 3.3  INSTRUMENTATION
 
B 3.3.4.2  Anticipated Transient Without Scram Recirculation Pump Trip
 
          (ATWS-RPT) Instrumentation
 
BASES
 
BACKGROUND The ATWS-RPT System initiates a recirculation pump trip, adding negative reactivity, following events in which a
 
scram does not but should occur, to lessen the effects of an
 
ATWS event. Tripping the recirculation pumps adds negative
 
reactivity from the increase in steam voiding in the core
 
area as core flow decreases. When Reactor Vessel Water
 
Level-Low Low, Level 2 or Reactor Steam Dome Pressure-High
 
setpoint is reached, the recirculation pump motor breakers
 
trip. The ATWS-RPT System (Ref. 1) includes sensors, relays, bypass capability, circuit breakers, and switches that are
 
necessary to cause initiation of a recirculation pump trip.
 
The channels include electronic equipment (e.g., trip units)
 
that compares measured input signals with pre-established
 
setpoints. When the setpoint is exceeded, the channel then
 
outputs an ATWS-RPT signal to the trip logic.
 
The ATWS-RPT consists of two independent trip systems, with
 
two channels of Reactor Steam Dome Pressure-High and two
 
channels of Reactor Vessel Water Level-Low Low, Level 2, in
 
each trip system. Each ATWS-RPT trip system is a
 
one-out-of-two taken twice logic for each Function. Thus, either two Reactor Water Level-Low Low, Level 2 signals or two Reactor Pressure-High signals or Reactor Water Level-Low Low, Level 2 signal and Reactor Pressure-High signal will trip a trip system. The outputs of the channels in a trip
 
system are combined in a logic so that either trip system
 
will trip both recirculation pumps (by tripping the
 
respective fast speed and low frequency motor generator (LFMG) motor breakers).
 
There are two fast speed motor breakers and one LFMG output
 
breaker provided for each of the two recirculation pumps for
 
a total of six breakers. The output of each trip system is
 
provided to one fast speed motor breaker (3A, 3B) and the
 
LFMG output breaker (2A, 2B) for each pump.
 
(continued)
ATWS-RPT Instrumentation B 3.3.4.2
 
LaSalle 1 and 2 B 3.3.4.2-2 Revision 0 BASES  (continued)
 
APPLICABLE The ATWS-RPT is not assumed to mitigate any accident or SAFETY ANALYSES, transient in the safety analysis. The ATWS-RPT initiates an LCO, and RPT to aid in preserving the integrity of the fuel cladding APPLICABILITY following events in which scram does not, but should, occur.
Based on its contribution to the reduction of overall plant
 
risk, however, the instrumentation meets Criterion 4 of
 
10 CFR 50.36(c)(2)(ii).
The OPERABILITY of the ATWS-RPT is dependent on the
 
OPERABILITY of the individual instrumentation channel
 
Functions. Each Function must have a required number of
 
OPERABLE channels in each trip system, with their setpoints
 
within the specified Allowable Value of SR 3.3.4.2.3. The
 
actual setpoint is calibrated consistent with applicable
 
setpoint methodology assumptions. Channel OPERABILITY also
 
includes the associated recirculation pump fast speed and
 
LFMG breakers.
 
Allowable Values are specified for each ATWS-RPT Function
 
specified in the LCO. Nominal trip setpoints are specified
 
in the setpoint calculations. The nominal setpoints are
 
selected to ensure the setpoints do not exceed the Allowable
 
Value between CHANNEL CALIBRATIONS. Operation with a trip
 
setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable. A channel is
 
inoperable if its actual trip setpoint is not within its
 
required Allowable Value. Trip setpoints are those
 
predetermined values of output at which an action should
 
take place. The setpoints are compared to the actual
 
process parameter (e.g., reactor vessel water level), and
 
when the measured output value of the process parameter
 
exceeds the setpoint, the associated device (e.g., trip
 
unit) changes state. The analytic limits are derived from
 
the limiting values of the process parameters obtained from
 
the ATWS analysis. The trip setpoints are determined from
 
the analytic limits, corrected for defined process, calibration, and instrument errors. The Allowable Values
 
are then determined, based on the trip setpoint values, by
 
accounting for the calibration based errors. These
 
calibration based errors are limited to reference accuracy, instrument drift, errors associated with measurement and
 
test equipment, and calibration tolerance of loop
 
components. The trip setpoints and Allowable Values
 
determined in this manner provide adequate protection (continued)
ATWS-RPT Instrumentation B 3.3.4.2
 
LaSalle 1 and 2 B 3.3.4.2-3 Revision 0 BASES APPLICABLE because instrument uncertainties, process effects, SAFETY ANALYSES, calibration tolerances, instrument drift, and severe LCO, and environment errors (for channels that must function in harsh APPLICABILITY environments as defined by 10 CFR 50.49) are accounted for (continued) and appropriately applied for the instrumentation.
 
The individual Functions are required to be OPERABLE in
 
MODE 1 to protect against common mode failures of the
 
Reactor Protection System by providing a diverse trip to
 
mitigate the consequences of a postulated ATWS event. The
 
Reactor Steam Dome Pressure-High and Reactor Vessel Water
 
Level-Low Low, Level 2 Functions are required to be
 
OPERABLE in MODE 1, since the reactor is producing
 
significant power and the recirculation system could be at
 
high flow. During this MODE, the potential exists for
 
pressure increases or low water level, assuming an ATWS
 
event. In MODE 2, the reactor is at low power and the
 
recirculation system is at low flow; thus, the potential is
 
low for a pressure increase or low water level, assuming an
 
ATWS event. Therefore, the ATWS-RPT is not necessary. In
 
MODES 3 and 4, the reactor is shut down with all control
 
rods inserted; thus, an ATWS event is not significant and
 
the possibility of a significant pressure increase or low
 
water level is negligible. In MODE 5, the one-rod-out
 
interlock ensures the reactor remains subcritical; thus, an
 
ATWS event is not significant. In addition, the reactor
 
pressure vessel (RPV) head is not fully tensioned and no
 
pressure transient threat to the reactor coolant pressure
 
boundary (RCPB) exists.
 
The specific Applicable Safety Analyses and LCO discussions
 
are listed below on a Function by Function basis.
: a. Reactor Vessel Water Level-Low Low, Level 2
 
Low RPV water level indicates the capability to cool the
 
fuel may be threatened. Should RPV water level decrease too
 
far, fuel damage could result. Therefore, the ATWS-RPT
 
System is initiated at Level 2 to aid in maintaining level
 
above the top of the active fuel. The reduction of core
 
flow reduces the neutron flux and THERMAL POWER and, therefore, the rate of coolant boiloff.
(continued)
ATWS-RPT Instrumentation B 3.3.4.2
 
LaSalle 1 and 2 B 3.3.4.2-4 Revision 0 BASES APPLICABLE a. Reactor Vessel Water Level-Low Low, Level 2 SAFETY ANALYSES, (continued)
LCO, and APPLICABILITY Reactor vessel water level signals are initiated from four level transmitters that sense the difference between the
 
pressure due to a constant column of water (reference leg)
 
and the pressure due to the actual water level (variable
 
leg) in the vessel.
Four channels of Reactor Vessel Level-Low Low, Level 2, with two channels in each trip system, are available and
 
required to be OPERABLE to ensure that no single instrument
 
failure can preclude an ATWS-RPT from this Function on a
 
valid signal. The Reactor Vessel Water Level-Low Low, Level 2, Allowable Value is chosen so that the system will
 
not initiate after a Level 3 scram with feedwater still
 
available.
: b. Reactor Steam Dome Pressure-High
 
Excessively high RPV pressure may rupture the RCPB. An
 
increase in the RPV pressure during reactor operation
 
compresses the steam voids and results in a positive
 
reactivity insertion. This increases neutron flux and
 
THERMAL POWER, which could potentially result in fuel
 
failure and RPV overpressurization. The Reactor Steam Dome
 
Pressure-High Function initiates an RPT for transients that
 
result in a pressure increase, counteracting the pressure
 
increase by rapidly reducing core power generation. For the
 
overpressurization event, the RPT aids in the mitigation of
 
the ATWS event and, along with the safety/relief valves (S/RVs), limits the peak RPV pressure to less than the ASME
 
Section III Code Service Level C limits (1500 psig).
The Reactor Steam Dome Pressure-High signals are initiated
 
from four pressure transmitters that monitor reactor steam
 
dome pressure. Four channels of Reactor Steam Dome Pressure-High, with two channels in each trip system, are
 
available and required to be OPERABLE to ensure that no
 
single instrument failure can preclude an ATWS-RPT from this
 
Function on a valid signal. The Reactor Steam Dome Pressure-High Allowable Value is chosen to provide an
 
adequate margin to the ASME Section III Code Service Level C
 
allowable Reactor Coolant System pressure.
 
(continued)
ATWS-RPT Instrumentation B 3.3.4.2
 
LaSalle 1 and 2 B 3.3.4.2-5 Revision 0 BASES  (continued)
 
ACTIONS A Note has been provided to modify the ACTIONS related to ATWS-RPT instrumentation channels. Section 1.3, Completion
 
Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables
 
expressed in the Condition, discovered to be inoperable or
 
not within limits, will not result in separate entry into
 
the Condition. Section 1.3 also specifies that Required 
 
Actions of the Condition continue to apply for each
 
additional failure, with Completion Times based on initial
 
entry into the Condition. However, the Required Actions for
 
inoperable ATWS-RPT instrumentation channels provide
 
appropriate compensatory measures for separate inoperable
 
channels. As such, a Note has been provided that allows
 
separate Condition entry for each inoperable ATWS-RPT
 
instrumentation channel.
 
A.1 and A.2
 
With one or more channels inoperable, but with ATWS-RPT trip
 
capability for each Function maintained (refer to Required
 
Action B.1 and C.1 Bases), the ATWS-RPT System is capable of
 
performing the intended function. However, the reliability
 
and redundancy of the ATWS-RPT instrumentation is reduced, such that a single failure in the remaining trip system
 
could result in the inability of the ATWS-RPT System to
 
perform the intended function. Therefore, only a limited
 
time is allowed to restore the inoperable channels to
 
OPERABLE status. Because of the diversity of sensors
 
available to provide trip signals, the low probability of
 
extensive numbers of inoperabilities affecting all diverse
 
Functions, and the low probability of an event requiring the
 
initiation of ATWS-RPT, 14 days is provided to restore the
 
inoperable channel (Required Action A.1). Alternately, the
 
inoperable channel may be placed in trip (Required
 
Action A.2), since this would conservatively compensate for
 
the inoperability, restore capability to accommodate a
 
single failure, and allow operation to continue. As noted, placing the channel in trip with no further restrictions is
 
not allowed if the inoperable channel is the result of an
 
inoperable breaker, since this may not adequately compensate
 
for the inoperable breaker (e.g., the breaker may be
 
inoperable such that it will not open). If it is not
 
(continued)
ATWS-RPT Instrumentation B 3.3.4.2
 
LaSalle 1 and 2 B 3.3.4.2-6 Revision 0 BASES ACTIONS A.1 and A.2 (continued) desirable to place the channel in trip (e.g., as in the case
 
where placing the inoperable channel in trip would result in
 
an RPT), or if the inoperable channel is the result of an
 
inoperable breaker, Condition D must be entered and its
 
Required Actions taken.
 
B.1 Required Action B.1 is intended to ensure that appropriate
 
actions are taken if multiple, inoperable, untripped
 
channels within the same Function result in the Function not
 
maintaining ATWS-RPT trip capability. A Function is
 
considered to be maintaining ATWS-RPT trip capability when
 
sufficient channels are OPERABLE or in trip such that the
 
ATWS-RPT System will generate a trip signal from the given
 
Function on a valid signal, and both recirculation pumps can
 
be tripped. This requires two channels of the Function in
 
the same trip system to each be OPERABLE or in trip, and the
 
corresponding motor breakers associated with ATWS-RPT (one
 
fast speed and one LFMG per pump) to be OPERABLE or in trip.
 
The 72 hour Completion Time is sufficient for the operator
 
to take corrective action (e.g., restoration or tripping of
 
channels) and takes into account the likelihood of an event
 
requiring actuation of the ATWS-RPT instrumentation during
 
this period and the fact that one Function is still
 
maintaining ATWS-RPT trip capability.
 
C.1 Required Action C.1 is intended to ensure that appropriate
 
actions are taken if multiple, inoperable, untripped
 
channels within both Functions result in both Functions not
 
maintaining ATWS-RPT trip capability. The description of a
 
Function maintaining ATWS-RPT trip capability is discussed
 
in the Bases for Required Action B.1, above.
 
The 1 hour Completion Time is sufficient for the operator to
 
take corrective action and takes into account the likelihood
 
of an event requiring actuation of the ATWS-RPT
 
instrumentation during this period.
(continued)
ATWS-RPT Instrumentation B 3.3.4.2
 
LaSalle 1 and 2 B 3.3.4.2-7 Revision 0 BASES ACTIONS D.1 and D.2 (continued)
With any Required Action and associated Completion Time not
 
met, the plant must be brought to a MODE or other specified
 
condition in which the LCO does not apply. To achieve this
 
status, the plant must be brought to at least MODE 2 within
 
6 hours (Required Action D.2). Alternately, the associated
 
recirculation pump may be removed from service since this
 
performs the intended Function of the instrumentation (Required Action D.1). The allowed Completion Time of
 
6 hours is reasonable, based on operating experience, both
 
to reach MODE 2 from full power conditions and to remove a
 
recirculation pump from service in an orderly manner and
 
without challenging plant systems.
 
SURVEILLANCE The Surveillances are modified by a Note to indicate that REQUIREMENTS when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated
 
Conditions and Required Actions may be delayed for up to
 
6 hours provided the associated Function maintains ATWS-RPT
 
trip capability. Upon completion of the Surveillance, or
 
expiration of the 6 hour allowance, the channel must be
 
returned to OPERABLE status or the applicable Condition
 
entered and Required Actions taken. This Note is based on
 
the reliability analysis (Ref. 2) assumption of the average
 
time required to perform channel surveillance. That
 
analysis demonstrated that the 6 hour testing allowance does
 
not significantly reduce the probability that the
 
recirculation pumps will trip when necessary.
 
SR  3.3.4.2.1
 
Performance of the CHANNEL CHECK once every 12 hours ensures
 
that gross failure of instrumentation has not occurred. A
 
CHANNEL CHECK is normally a comparison of the parameter
 
indicated on one channel to a similar parameter on other
 
channels. It is based on the assumption that instrument
 
channels monitoring the same parameter should read
 
approximately the same value. Significant deviations
 
between the instrument channels could be an indication of
 
excessive instrument drift in one of the channels or 
 
(continued)
ATWS-RPT Instrumentation B 3.3.4.2
 
LaSalle 1 and 2 B 3.3.4.2-8 Revision 0 BASES SURVEILLANCE SR  3.3.4.2.1 (continued)
REQUIREMENTS something even more serious. A CHANNEL CHECK will detect
 
gross channel failure; thus, it is key to verifying that the
 
instrumentation continues to operate properly between each
 
CHANNEL CALIBRATION.
 
Agreement criteria are determined by the plant staff based
 
on a combination of the channel instrument uncertainties, including indication and readability. If a channel is
 
outside the criteria, it may be an indication that the
 
instrument has drifted outside its limit.
 
The Frequency is based upon operating experience that
 
demonstrates channel failure is rare. The CHANNEL CHECK
 
supplements less formal, but more frequent, checks of
 
channels during normal operational use of the displays
 
associated with the required channels of this LCO.
 
SR  3.3.4.2.2
 
A CHANNEL FUNCTIONAL TEST is performed on each required
 
channel to ensure that the channel will perform the intended
 
function. A successful test of the required contact(s) of a
 
channel relay may be performed by the verification of the
 
change of state of a single contact of the relay. This
 
clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a
 
relay. This is acceptable because all of the other required
 
contacts of the relay are verified by other Technical
 
Specifications and non-Technical Specifications tests at
 
least once per refueling interval with applicable
 
extensions.
 
Any setpoint adjustment shall be consistent with the
 
assumptions of the current plant specific setpoint
 
methodology.
 
The Frequency of 92 days is based on the reliability
 
analysis of Reference 2.
(continued)
ATWS-RPT Instrumentation B 3.3.4.2
 
LaSalle 1 and 2 B 3.3.4.2-9 Revision 0 BASES SURVEILLANCE SR  3.3.4.2.3 REQUIREMENTS (continued) A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies that the channel
 
responds to the measured parameter within the necessary
 
range and accuracy. CHANNEL CALIBRATION leaves the channel
 
adjusted to account for instrument drifts between successive
 
calibrations consistent with the plant specific setpoint
 
methodology.
The Frequency is based upon the assumption of a 24 month calibration interval in the determination of the magnitude
 
of equipment drift in the setpoint analysis.
 
SR  3.3.4.2.4
 
The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the
 
OPERABILITY of the required trip logic for a specific
 
channel. The system functional test of the pump breakers, included as part of this Surveillance, overlaps the LOGIC
 
SYSTEM FUNCTIONAL TEST to provide complete testing of the
 
assumed safety function. Therefore, if a breaker is
 
incapable of operating, the associated instrument channel(s)
 
would be inoperable.
 
The 24 month Frequency is based on the need to perform this
 
Surveillance under the conditions that apply during a plant
 
outage and the potential for an unplanned transient if the
 
Surveillance were performed with the reactor at power.
 
Operating experience has shown that these components usually
 
pass the Surveillance when performed at the 24 month
 
Frequency.
 
REFERENCES 1. UFSAR, Appendix G.3.1.2.
: 2. GENE-770-06-1-A, "Bases For Changes To Surveillance Test Intervals and Allowed Out-of-Service Times For
 
Selected Instrumentation Technical Specifications,"
December 1992.
 
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-1 Revision 0 B 3.3  INSTRUMENTATION
 
B 3.3.5.1  Emergency Core Cooling System (ECCS) Instrumentation
 
BASES
 
BACKGROUND The purpose of the ECCS instrumentation is to initiate appropriate responses from the systems to ensure that fuel
 
is adequately cooled in the event of a design basis accident
 
or transient.
For most anticipated operational occurrences (AOOs) and
 
Design Basis Accidents (DBAs), a wide range of dependent and
 
independent parameters are monitored.
 
The ECCS instrumentation actuates low pressure core spray (LPCS), low pressure coolant injection (LPCI), high pressure
 
core spray (HPCS), Automatic Depressurization System (ADS),
and the diesel generators (DGs). The equipment involved
 
with each of these systems is described in the Bases for
 
LCO 3.5.1, "ECCS-Operating," or LCO 3.8.1, "AC
 
Sources-Operating."
 
Low Pressure Core Spray System
 
The LPCS System may be initiated by either automatic or
 
manual means. Automatic initiation occurs for conditions of
 
Reactor Vessel Water Level-Low Low Low, Level 1 or Drywell
 
Pressure-High. Reactor vessel water level is monitored by
 
two redundant differential pressure transmitters, each
 
providing input to a trip unit. Drywell pressure is
 
monitored by two pressure switches. The outputs of the four
 
signals (two trip units and two pressure switches) are
 
connected to relays whose contacts are arranged in a
 
one-out-of-two taken twice logic. The logic will provide an
 
initiation signal if both reactor vessel water level
 
channels or both drywell pressure channels trip. In
 
addition, the logic will provide an initiation signal if a
 
certain combination of reactor vessel water level and
 
drywell pressure channels trip. The LPCS initiation signal
 
is a sealed in signal and must be manually reset. The LPCS
 
initiation signal also provides an initiation signal to the
 
Division 1 LPCI initiation logic. The logic can also be (continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-2 Revision 0 BASES BACKGROUND Low Pressure Core Spray System (continued) initiated by use of a manual push button. Upon receipt of
 
an initiation signal, the LPCS pump is automatically started
 
if normal AC power is available; otherwise the pump is
 
started immediately after AC power is available from the DG.
 
The LPCS test line isolation valve, which is also a primary
 
containment isolation valve (PCIV), is closed on a LPCS
 
initiation signal to allow full system flow assumed in the
 
accident analysis and maintains containment isolation in the
 
event LPCS is not operating.
 
The LPCS pump discharge flow is monitored by a flow switch
 
that senses the differential pressure across a flow element
 
in the pump discharge line. When the pump is running and
 
discharge flow is low enough that pump overheating may
 
occur, the minimum flow return line valve is opened. The
 
valve is automatically closed if flow is above the minimum
 
flow setpoint to allow the full system flow assumed in the
 
accident analysis.
 
The LPCS System also monitors the pressure within the
 
injection line and in the reactor vessel to ensure that, before the injection valve opens, the injection line
 
pressure and reactor pressure have fallen to a value below
 
the LPCS System's maximum design pressure. The pressure in
 
the LPCS injection line is monitored by one pressure switch
 
while reactor pressure is monitored by two pressure
 
switches. The injection valve will receive an open
 
permissive signal if the LPCS injection line pressure switch
 
senses low pressure (one-out-of-one logic) and if any one of
 
the reactor pressure switches sense low pressure (one-out-
 
of-two logic). The reactor vessel pressure switches also
 
provide a permissive signal in the Division 1 LPCI injection
 
valve.
 
Low Pressure Coolant Injection Subsystems
 
The LPCI is an operating mode of the Residual Heat Removal (RHR) System, with three LPCI subsystems. The LPCI
 
subsystems may be initiated by automatic or manual means.
 
Automatic initiation occurs for conditions of Reactor Vessel
 
Water Level-Low Low Low, Level 1 or Drywell Pressure-High. 
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-3 Revision 0 BASES BACKGROUND Low Pressure Coolant Injection Subsystems (continued)
Reactor vessel water level is monitored by two redundant
 
differential pressure transmitters per division, each
 
providing input to a trip unit. Drywell pressure is
 
monitored by two pressure switches per division. The
 
outputs of the four Division 2 LPCI (loops B and C) signals (two trip units and two pressure switches) are connected to
 
relays whose contacts are arranged in a one-out-of-two taken
 
twice logic. The logic will provide an initiation signal if
 
both reactor vessel water level channels or both drywell
 
pressure channels trip. In addition, the logic will provide
 
an initiation signal if certain combinations of reactor
 
vessel water level and drywell pressure channels trip. The
 
Division 1 LPCI (loop A) receives its initiation signal from
 
the LPCS logic, which uses a similar one-out-of-two taken
 
twice logic. The two divisions can also be initiated by use
 
of a manual push button (one per division, with the LPCI A
 
manual push button being common with LPCS). Once an
 
initiation signal is received by the LPCI control circuitry, the signal is sealed in until manually reset.
 
Upon receipt of an initiation signal, the LPCI Pump C is
 
automatically started if normal AC power is available;
 
otherwise the pump is started immediately after power is
 
available from the DG while LPCI pumps A and B are
 
automatically started if offsite power is available;
 
otherwise the pumps are started in approximately 5 seconds
 
after AC power from the DG is available. These time delays
 
limit the loading on the standby power sources.
 
Each LPCI subsystem's discharge flow is monitored by a flow
 
switch that senses the differential pressure across a flow
 
element in the pump discharge line. When a pump is running
 
and discharge flow is low enough that pump overheating may
 
occur, the respective minimum flow return line valve is
 
opened. The valve is automatically closed if flow is above
 
the minimum flow setpoint to allow the full system flow
 
assumed in the analyses.
 
The RHR test line suppression pool cooling isolation and
 
suppression pool spray isolation valves (which are also
 
PCIVs) are closed on a LPCI initiation signal to allow full
 
system flow assumed in the accident analysis and maintain
 
containment isolated in the event LPCI is not operating.
 
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-4 Revision 0 BASES BACKGROUND Low Pressure Coolant Injection Subsystems (continued)
The LPCI subsystems monitor the pressure within the
 
associated injection line and in the reactor vessel to
 
ensure that, prior to an injection valve opening, the
 
injection line pressure and reactor pressure have fallen to
 
a value below the LPCI subsystem's maximum design pressure.
 
The pressure within each LPCI injection line is monitored by
 
one pressure switch, while reactor pressure is monitored by
 
two pressure switches, per division. The associated
 
injection valve will receive an open permissive signal if
 
the LPCI injection line pressure switch senses low pressure (one-out-of-one logic) and if any one of the associated
 
reactor pressure switches sense low pressure (one-out-of-two
 
logic, per division). The Division 1 LPCI (loop A) receives
 
its reactor pressure signals from the LPCS logic.
 
High Pressure Core Spray System
 
The HPCS System may be initiated by either automatic or
 
manual means. Automatic initiation occurs for conditions of
 
Reactor Vessel Water Level-Low Low, Level 2 or Drywell
 
Pressure-High. Reactor vessel water level is monitored by
 
four redundant differential pressure transmitters and
 
drywell pressure is monitored by four redundant pressure
 
switches. Each differential pressure transmitter provides
 
input to a trip unit. The outputs of the trip units are
 
connected to relays whose contacts are arranged in a
 
one-out-of-two taken twice logic. Each pressure switch
 
provides input to a relay whose contact is arranged in a
 
one-out-of-two taken twice logic. The logic can also be
 
initiated by use of a manual push button. The HPCS System
 
initiation signal is a sealed in signal and must be manually
 
reset.
 
The HPCS pump discharge flow and pressure are monitored by a
 
differential pressure switch and a pressure switch, respectively. When the pump is running (as indicated by the
 
pressure switch) and discharge flow is low enough that pump
 
overheating may occur, the minimum flow return line valve is
 
opened. The valve is automatically closed if flow is above
 
the minimum flow setpoint to allow full system flow assumed
 
in the accident analyses.
 
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-5 Revision 0 BASES BACKGROUND High Pressure Core Spray System (continued)
The HPCS full flow test line isolation valve to the
 
suppression pool (which is also a PCIV) is closed on a HPCS
 
initiation signal to allow full system flow assumed in the
 
accident analyses and maintain containment isolated in the
 
event HPCS is not operating.
 
The HPCS System provides makeup water to the reactor until
 
the reactor vessel water level reaches the high water level (Level 8) trip, at which time the HPCS injection valve
 
closes. The HPCS pump will continue to run on minimum flow.
 
The logic is two-out-of-two to provide high reliability of
 
the HPCS System. The injection valve automatically reopens
 
if a low low water level signal is subsequently received.
 
Automatic Depressurization System
 
ADS may be initiated by either automatic or manual means.
 
Automatic initiation occurs when signals indicating Reactor
 
Vessel Water Level-Low Low Low, Level 1; Drywell
 
Pressure-High or ADS Drywell Pressure Bypass Timer;
 
confirmed Reactor Vessel Water Level-Low, Level 3; and
 
either LPCS or LPCI Pump Discharge Pressure-High are all
 
present, and the ADS Initiation Timer has timed out. There
 
are two differential pressure transmitters for Reactor
 
Vessel Water Level-Low Low Low, Level 1, two pressure
 
switches for Drywell Pressure-High, and one differential
 
pressure transmitter for confirmed Reactor Vessel Water
 
Level-Low, Level 3 in each of the two ADS trip systems.
 
Each of the transmitters connects to a trip unit, which then
 
drives a relay whose contacts input to the initiation logic.
 
Each pressure switch drives a relay whose contact also
 
inputs to the initiation logic.
 
Each ADS trip system (trip system A and trip system B)
 
includes a time delay between satisfying the initiation
 
logic and the actuation of the ADS valves. The time delay
 
chosen is long enough that the HPCS has time to operate to
 
recover to a level above Level 1, yet not so long that the
 
LPCI and LPCS systems are unable to adequately cool the fuel
 
if the HPCS fails to maintain level. An alarm in the
 
control room is annunciated when either of the timers is
 
running. Resetting the ADS initiation signals resets the
 
ADS Initiation Timers.
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-6 Revision 0 BASES BACKGROUND Automatic Depressurization System (continued)
The ADS also monitors the discharge pressures of the three
 
LPCI pumps and the LPCS pump. Each ADS trip system includes
 
two discharge pressure permissive switches from each of the
 
two low pressure ECCS pumps in the associated Division (i.e., Division 1 ECCS inputs to ADS trip system A and
 
Division 2 ECCS inputs to ADS trip system B). The signals
 
are used as a permissive for ADS actuation, indicating that
 
there is a source of core coolant available once the ADS has
 
depressurized the vessel. Any one of the four low pressure
 
pumps provides sufficient core coolant flow to permit
 
automatic depressurization.
 
The ADS logic in each trip system is arranged in two
 
strings. One string has a contact from each of the
 
following variables:  Reactor Vessel Water Level-Low Low
 
Low, Level 1; Drywell Pressure-High or ADS Drywell Pressure
 
Bypass Timer; Reactor Vessel Water Level-Low, Level 3; ADS
 
Initiation Timer; and two low pressure ECCS Discharge
 
Pressure-High contacts (one from each divisional pump).
 
The other string has a contact from each of the following
 
variables:  Reactor Vessel Water Level-Low Low Low, Level 1; Drywell Pressure-High; ADS Drywell Pressure Bypass
 
Timer; and two low pressure ECCS Discharge Pressure-High
 
contacts (one from each divisional pump). To initiate an
 
ADS trip system, the following applicable contacts must
 
close in the associated string:  Reactor Vessel Water
 
Level-Low Low Low, Level 1; Drywell Pressure-High or ADS
 
Drywell Pressure Bypass Timer; Reactor Vessel Water
 
Level-Low, Level 3 (one string only); ADS Initiation Timer (one string only); and one of the two low pressure ECCS
 
Discharge Pressure-High contacts. 
 
Either ADS trip system A or trip system B will cause all the
 
ADS valves to open. Once the Drywell Pressure-High or ADS
 
initiation signals are present, they are individually sealed
 
in until manually reset.
 
Manual initiation is accomplished by arming and depressing
 
both ADS A trip system strings (Division 1) or both ADS B
 
trip system strings (Division 2) which will cause the ADS
 
valves to open with no time delay. No permissive interlocks (continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-7 Revision 0 BASES BACKGROUND Automatic Depressurization System (continued) are required for the manual initiation. Manual inhibit
 
switches are provided in the control room for ADS; however, their function is not required for ADS OPERABILITY (provided
 
ADS is not inhibited when required to be OPERABLE).
 
Diesel Generators
 
The Division 1, 2, and 3 DGs may be initiated by either
 
automatic or manual means. Automatic initiation occurs for
 
conditions of Reactor Vessel Water Level-Low Low Low, Level 1 or Drywell Pressure-High for DGs 0 and 1A (2A), and
 
Reactor Vessel Water Level-Low Low, Level 2 or Drywell
 
Pressure-High for DG 1B (2B). DG 0 is common to both units
 
and will start on an initiation signal from both units. The
 
other DGs will only start on an initiation signal from the
 
unit ECCS logic. The DGs are also initiated upon loss of
 
voltage signals.  (Refer to Bases for LCO 3.3.8.1, "Loss of
 
Power (LOP) Instrumentation," for a discussion of these
 
signals.)  The DGs receive their initiation signals from the
 
associated Divisions' ECCS logic (i.e., DG 0 receives an
 
initiation signal from Division 1 ECCS (LPCS and LPCI A);
 
DG 1A/2A receives an initiation signal from Division 2 ECCS (LPCI B and LPCI C); and DG 1B/2B receives an initiation
 
signal from Division 3 ECCS (HPCS)). The DGs can also be
 
started manually from the control room and locally in the
 
associated DG room. The DG initiation signal is a sealed in
 
signal and must be manually reset. The DG initiation logic
 
is reset by resetting the associated ECCS initiation logic.
 
Upon receipt of a LOCA initiation signal, each DG is
 
automatically started, is ready to load in approximately
 
13 seconds, and will run in standby conditions (rated
 
voltage and speed, with the DG output breaker open). The
 
DGs will only energize their respective emergency buses if a
 
loss of offsite power occurs.  (Refer to Bases for
 
LCO 3.3.8.1.)
 
APPLICABLE The actions of the ECCS are explicitly assumed in the safety SAFETY ANALYSES, analyses of References 1, 2, and 3. The ECCS is initiated LCO, and to preserve the integrity of the fuel cladding by limiting APPLICABILITY the post LOCA peak cladding temperature to less than the 10 CFR 50.46 limits.
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-8 Revision 0 BASES APPLICABLE ECCS instrumentation satisfies Criterion 3 of
 
SAFETY ANALYSES,  10 CFR 50.36(c)(2)(ii). Certain instrumentation Functions LCO, and are retained for other reasons and are described below in APPLICABILITY the individual Functions discussion.
 
  (continued)
The OPERABILITY of the ECCS instrumentation is dependent
 
upon the OPERABILITY of the individual instrumentation
 
channel Functions specified in Table 3.3.5.1-1. Each
 
Function must have a required number of OPERABLE channels, with their setpoints within the specified Allowable Values, where appropriate. The actual setpoint is calibrated
 
consistent with applicable setpoint methodology assumptions.
 
Each ECCS subsystem must also respond within its assumed
 
response time. Table 3.3.5.1-1, footnote (b), is added to
 
show that certain ECCS instrumentation Functions are also
 
required to be OPERABLE to perform DG initiation. 
 
Allowable Values are specified for each ECCS Function
 
specified in the Table. Nominal trip setpoints are
 
specified in the setpoint calculations. The nominal
 
setpoints are selected to ensure that the setpoints do not
 
exceed the Allowable Value between CHANNEL CALIBRATIONS.
 
Operation with a trip setpoint less conservative than the
 
nominal trip setpoint, but within its Allowable Value, is
 
acceptable. A channel is inoperable if its actual trip
 
setpoint is not within its required Allowable Value. Trip
 
setpoints are those predetermined values of output at which
 
an action should take place. The setpoints are compared to
 
the actual process parameter (e.g., reactor vessel water
 
level), and when the measured output value of the process
 
parameter exceeds the setpoint, the associated device (e.g.,
trip unit) changes state. The analytic limits are derived
 
from the limiting values of the process parameters obtained
 
from the safety analysis. The trip setpoints are determined
 
from the analytic limits, corrected for defined process, calibration, and instrument errors. The Allowable Values
 
are then determined, based on the trip setpoint values, by
 
accounting for the calibration based errors. These
 
calibration based errors are limited to reference accuracy, instrument drift, errors associated with measurement and
 
test equipment, and calibration tolerance of loop
 
components. The trip setpoints and Allowable Values
 
determined in this manner provide adequate protection (continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-9 Revision 0 BASES APPLICABLE because instrument uncertainties, process effects, SAFETY ANALYSES, calibration tolerances, instrument drift, and severe LCO, and environment errors (for channels that must function in APPLICABILITY harsh environments as defined by 10 CFR 50.49) are accounted (continued) for and appropriately applied for the instrumentation.
 
In general, the individual Functions are required to be
 
OPERABLE in the MODES or other specified conditions that may
 
require ECCS (or DG) initiation to mitigate the consequences
 
of a design basis accident or transient. To ensure reliable
 
ECCS and DG function, a combination of Functions is required
 
to provide primary and secondary initiation signals.
 
The specific Applicable Safety Analyses, LCO, and
 
Applicability discussions are listed below on a Function by
 
Function basis.
 
Low Pressure Core Spray and Low Pressure Coolant Injection Systems 1.a, 2.a. Reactor Vessel Water Level-Low Low Low, Level 1
 
Low reactor pressure vessel (RPV) water level indicates that
 
the capability to cool the fuel may be threatened. Should
 
RPV water level decrease too far, fuel damage could result.
 
The low pressure ECCS and associated DGs are initiated at
 
Level 1 to ensure that core spray and flooding functions are
 
available to prevent or minimize fuel damage. The Reactor
 
Vessel Water Level-Low Low Low, Level 1 is one of the
 
Functions assumed to be OPERABLE and capable of initiating
 
the ECCS during the transients analyzed in References 1
 
and 3. In addition, the Reactor Vessel Water Level-Low Low
 
Low, Level 1 Function is directly assumed in the analysis of
 
the recirculation line break (Ref. 2). The core cooling
 
function of the ECCS, along with the scram action of the
 
Reactor Protection System (RPS), ensures that the fuel peak
 
cladding temperature remains below the limits of
 
10 CFR 50.46.
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-10 Revision 6 BASES APPLICABLE 1.a, 2.a. Reactor Vessel Water Level-Low Low Low, Level 1 SAFETY ANALYSES, (continued)
 
LCO, and APPLICABILITY Reactor Vessel Water Level-Low Low Low, Level 1 signals are initiated from four differential pressure transmitters that
 
sense the difference between the pressure due to a constant
 
column of water (reference leg) and the pressure due to the
 
actual water level (variable leg) in the vessel.
 
The Reactor Vessel Water Level-Low Low Low, Level 1
 
Allowable Value is chosen to allow time for the low pressure
 
core flooding systems to activate and provide adequate
 
cooling.
 
Two channels of Reactor Vessel Water Level-Low Low Low, Level 1 Function per associated Division are only required
 
to be OPERABLE when the associated ECCS is required to be
 
OPERABLE for automatic initiation, to ensure that no single instrument failure can preclude the ECCS function.  (Two channels input to LPCS, LPCI A, and the associated Division
 
1 DG, while the other two channels input to LPCI B, LPCI C, and Division 2 DG.) Refer to LCO 3.5.1 and LCO 3.5.2, "ECCS-
 
Shutdown," for Applicability Bases for the low pressure ECCS
 
subsystems.
 
1.b, 2.b. Drywell Pressure-High
 
High pressure in the drywell could indicate a break in the
 
reactor coolant pressure boundary (RCPB). The low pressure
 
ECCS and associated DGs are initiated upon receipt of the
 
Drywell Pressure-High Function in order to minimize the
 
possibility of fuel damage. The core cooling function of
 
the ECCS, along with the scram action of the RPS, ensures
 
that the fuel peak cladding temperature remains below the
 
limits of 10 CFR 50.46.
 
High drywell pressure signals are initiated from four
 
pressure switches that sense drywell pressure. The
 
Allowable Value was selected to be as low as possible and be
 
indicative of a LOCA inside primary containment.
 
The Drywell Pressure-High Function is required to be
 
OPERABLE when the associated ECCS is required to be OPERABLE
 
in conjunction with times when the primary containment is
 
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-11 Revision 0 BASES APPLICABLE 1.b, 2.b. Drywell Pressure-High (continued)
SAFETY ANALYSES, LCO, and required to be OPERABLE. Thus, four channels of the LPCS APPLICABILITY and LPCI Drywell Pressure-High Function are required to be OPERABLE in MODES 1, 2, and 3 to ensure that no single
 
instrument failure can preclude ECCS initiation.  (Two
 
channels input to LPCS, LPCI A, and the Division 1 DG, while
 
the other two channels input to LPCI B, LPCI C, and the
 
Division 2 DG.)  In MODES 4 and 5, the Drywell
 
Pressure-High Function is not required since there is
 
insufficient energy in the reactor to pressurize the primary
 
containment to Drywell Pressure-High setpoint. Refer to
 
LCO 3.5.1 for Applicability Bases for the low pressure ECCS
 
subsystems.
 
1.c, 2.c. LPCI Pump A and Pump B Start-Time Delay Relay
 
The purpose of this time delay is to stagger the start of
 
the two ECCS pumps that are in each of Divisions 1 and 2, thus limiting the starting transients on the 4.16 kV
 
emergency buses. This Function is only necessary when power
 
is being supplied from the standby power sources (DG). On
 
ECCS initiation, the time delay is bypassed if the normal
 
feed breaker to the Class 1E switchgear is closed. The LPCI
 
Pump Start-Time Delay Relays are assumed to be OPERABLE in
 
the accident and transient analyses requiring ECCS
 
initiation. That is, the analysis assumes that the pumps
 
will initiate when required and excess loading will not
 
cause failure of the standby power sources (DG).
 
There are two LPCI Pump Start-Time Delay Relays, one in
 
each of the RHR "A" and RHR "B" pump start logic circuits.
 
While each time delay relay is dedicated to a single pump
 
start logic, a single failure of a LPCI Pump Start-Time
 
Delay Relay could result in the failure of the two low
 
pressure ECCS pumps, powered from the emergency bus, to
 
perform their intended function within the assumed ECCS
 
RESPONSE TIMES (e.g., as in the case where both ECCS pumps
 
on one emergency bus start simultaneously due to an
 
inoperable time delay relay). This still leaves two of the
 
four low pressure ECCS pumps OPERABLE; thus, the single
 
failure criterion is met (i.e., loss of one instrument does
 
not preclude ECCS initiation). The Allowable Value for the
 
LPCI Pump Start-Time Delay Relays is chosen to be short
 
enough so that ECCS operation is not degraded.
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-12 Revision 0 BASES APPLICABLE 1.c, 2.c. LPCI Pump A and Pump B Start-Time Delay Relay SAFETY ANALYSES, (continued)
 
LCO, and APPLICABILITY Each LPCI Pump Start-Time Delay Relay Function is required to be OPERABLE when the associated LPCI subsystem is
 
required to be OPERABLE. Refer to LCO 3.5.1 and LCO 3.5.2
 
for Applicability Bases for the LPCI subsystems.
 
1.d, 1.g, 2.d, 2.f. Reactor Steam Dome Pressure-Low (Injection Permissive) and LPCS and LPCI Injection Line Pressure-Low (Injection Permissive)
 
Low reactor steam dome pressure and injection line pressure
 
signals are used as permissives for the low pressure ECCS
 
subsystems. This ensures that, prior to opening the
 
injection valves of the low pressure ECCS subsystems, the
 
reactor pressure has fallen to a value below these
 
subsystems maximum design pressure. The Reactor Steam Dome
 
Pressure-Low (Injection Permissive) and LPCS and LPCI
 
Injection Line Pressure-Low (Injection Permissive) are two
 
of the Functions assumed to be OPERABLE and capable of
 
permitting initiation of the ECCS during the transients
 
analyzed in References 1 and 3. In addition, the Reactor
 
Steam Dome Pressure-Low (Injection Permissive) and LPCS and
 
LPCI Injection Line Pressure-Low (Injection Permissive)
 
Functions are directly assumed in the analysis of the
 
recirculation line break (Ref. 2). The core cooling
 
function of the ECCS, along with the scram action of the
 
RPS, ensures that the fuel peak cladding temperature remains
 
below the limits of 10 CFR 50.46.
 
The Reactor Steam Dome Pressure-Low (Injection Permissive)
 
signals are initiated from four pressure switches that sense
 
the reactor dome pressure. The LPCS and LPCI Injection Line
 
Pressure-Low (Injection Permissive) signals are initiated
 
from four pressure switches that sense the pressure in the
 
injection line (one switch for each low pressure ECCS
 
injection line). The Allowable Values are low enough to (continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-13 Revision 0 BASES APPLICABLE 1.d, 1.g, 2.d, 2.f. Reactor Steam Dome Pressure-Low SAFETY ANALYSES, (Injection Permissive) and LPCS and LPCI Injection Line LCO, and Pressure-Low (Injection Permissive)
  (continued)
APPLICABILITY prevent overpressurizing the equipment in the low pressure
 
ECCS, but high enough to ensure that the ECCS injection
 
prevents the fuel peak cladding temperature from exceeding
 
the limits of 10 CFR 50.46.
 
Two channels of Reactor Steam Dome Pressure-Low (Injection
 
Permissive) Function per associated Division and one channel
 
of LPCS and LPCI Injection Line Pressure-Low (Injection
 
Permissive) per associated injection line are only required
 
to be OPERABLE when the associated ECCS is required to be
 
OPERABLE to ensure that no single instrument failure can
 
preclude ECCS initiation.  (Two channels of Reactor Vessel
 
Pressure-Low (Injection Permissive) are required for LPCS
 
and LPCI A, while two other channels are required for LPCI B
 
and LPCI C. In addition, one channel of LPCS Injection Line
 
Pressure-Low (Injection Permissive) is required for LPCS, while one channel of LPCI Injection Line Pressure is
 
required for each LPCI subsystem.)  Refer to LCO 3.5.1 and
 
LCO 3.5.2 for Applicability Bases for the low pressure ECCS
 
subsystems.
 
1.e, 1.f, 2.e. LPCS and LPCI Pump Discharge Flow-Low (Bypass)
The minimum flow instruments are provided to protect the
 
associated low pressure ECCS pump from overheating when the
 
pump is operating and the associated injection valve is not
 
sufficiently open. The minimum flow line valve is opened
 
when low flow is sensed, and the valve is automatically
 
closed when the flow rate is adequate to protect the pump.
 
The LPCI and LPCS Pump Discharge Flow-Low (Bypass)
 
Functions are assumed to be OPERABLE and capable of closing
 
the minimum flow valves to ensure that the low pressure ECCS
 
flows assumed during the transients and accidents analyzed
 
in References 1, 2, and 3 are met. The core cooling
 
function of the ECCS, along with the scram action of the
 
RPS, ensures that the fuel peak cladding temperature remains
 
below the limits of 10 CFR 50.46.
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-14 Revision 0 BASES APPLICABLE 1.e, 1.f, 2.e. LPCS and LPCI Pump Discharge Flow-Low SAFETY ANALYSES, (Bypass)
  (continued)
LCO, and APPLICABILITY One flow switch per ECCS pump is used to detect the associated subsystems flow rate. The logic is arranged such
 
that each switch causes its associated minimum flow valve to
 
open when flow is low with the pump running. The logic will
 
close the minimum flow valve once the closure setpoint is
 
exceeded. The LPCI minimum flow valves are time delayed
 
such that the valves will not open for approximately 8
 
seconds after the switches detect low flow. The time delay
 
is provided to limit reactor vessel inventory loss during
 
the startup of the RHR shutdown cooling mode. The Pump
 
Discharge Flow-Low (Bypass) Allowable Values are high
 
enough to ensure that the pump flow rate is sufficient to
 
protect the pump, yet low enough to ensure that the closure
 
of the minimum flow valve is initiated to allow full flow
 
into the core.
Each channel of Pump Discharge Flow-Low (Bypass) Function (one LPCS channel and three LPCI channels) is only required
 
to be OPERABLE when the associated ECCS is required to be
 
OPERABLE, to ensure that no single instrument failure can
 
preclude the ECCS function. Refer to LCO 3.5.1 and
 
LCO 3.5.2 for Applicability Bases for the low pressure ECCS
 
subsystems.
 
1.h, 2.g. Manual Initiation
 
The Manual Initiation push button channels introduce signals
 
into the appropriate ECCS logic to provide manual initiation
 
capability and are redundant to the automatic protective
 
instrumentation. There is one push button for each of the
 
two Divisions of low pressure ECCS (i.e., Division 1 ECCS, LPCS and LPCI A; Division 2 ECCS, LPCI B and LPCI C).
 
The Manual Initiation Function is not assumed in any
 
accident or transient analyses in the UFSAR. However, the
 
Function is retained for overall redundancy and diversity of
 
the low pressure ECCS function as required by the NRC in the
 
plant licensing basis.
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-15 Revision 6 BASES APPLICABLE 1.h, 2.g. Manual Initiation (continued)
SAFETY ANALYSES, LCO, and There is no Allowable Value for this Function since the APPLICABILITY channels are mechanically actuated based solely on the position of the push buttons. Each channel of the Manual
 
Initiation Function (one channel per division) is only
 
required to be OPERABLE when the associated ECCS is required
 
to be OPERABLE for automatic alignment and injection. Refer to LCO 3.5.1 and LCO 3.5.2 for Applicability Bases for the
 
low pressure ECCS subsystems.
 
High Pressure Core Spray System
 
3.a. Reactor Vessel Water Level-Low Low, Level 2
 
Low RPV water level indicates that the capability to cool
 
the fuel may be threatened. Should RPV water level decrease
 
too far, fuel damage could result. Therefore, the HPCS
 
System and associated DG is initiated at Level 2 to maintain
 
level above the top of the active fuel. The Reactor Vessel
 
Water Level-Low Low, Level 2 is one of the Functions
 
assumed to be OPERABLE and capable of initiating HPCS during
 
the transients analyzed in References 1 and 3. The Reactor
 
Vessel Water Level-Low Low, Level 2 Function associated
 
with HPCS is directly assumed in the analysis of the
 
recirculation line break (Ref. 2). The core cooling
 
function of the ECCS, along with the scram action of the
 
RPS, ensures that the fuel peak cladding temperature remains
 
below the limits of 10 CFR 50.46.
 
Reactor Vessel Water Level-Low Low, Level 2 signals are
 
initiated from four differential pressure transmitters that
 
sense the difference between the pressure due to a constant
 
column of water (reference leg) and the pressure due to the
 
actual water level (variable leg) in the vessel. The
 
Reactor Vessel Water Level-Low Low, Level 2 Allowable Value
 
is chosen such that for complete loss of feedwater flow, the
 
Reactor Core Isolation Cooling (RCIC) System flow with HPCS
 
assumed to fail will be sufficient to avoid initiation of
 
low pressure ECCS at Reactor Vessel Water Level-Low Low
 
Low, Level 1.
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-16 Revision 0 BASES APPLICABLE 3.a. Reactor Vessel Water Level-Low Low, Level 2 SAFETY ANALYSES, (continued)
 
LCO, and APPLICABILITY Four channels of Reactor Vessel Water Level-Low Low, Level 2 Function are only required to be OPERABLE when HPCS
 
is required to be OPERABLE to ensure that no single
 
instrument failure can preclude HPCS initiation. Refer to
 
LCO 3.5.1 and LCO 3.5.2 for HPCS Applicability Bases.
 
3.b. Drywell Pressure-High
 
High pressure in the drywell could indicate a break in the
 
RCPB. The HPCS System and associated DG are initiated upon
 
receipt of the Drywell Pressure-High Function in order to
 
minimize the possibility of fuel damage. The core cooling
 
function of the ECCS, along with the scram action of the
 
RPS, ensures that the fuel peak cladding temperature remains
 
below the limits of 10 CFR 50.46.
 
Drywell Pressure-High signals are initiated from four
 
pressure switches that sense drywell pressure. The
 
Allowable Value was selected to be as low as possible and be
 
indicative of a LOCA inside primary containment.
 
The Drywell Pressure-High Function is required to be
 
OPERABLE when HPCS is required to be OPERABLE in conjunction
 
with times when the primary containment is required to be
 
OPERABLE. Thus, four channels of the HPCS Drywell
 
Pressure-High Function are required to be OPERABLE in
 
MODES 1, 2, and 3, to ensure that no single instrument
 
failure can preclude ECCS initiation. In MODES 4 and 5, the
 
Drywell Pressure-High Function is not required since there
 
is insufficient energy in the reactor to pressurize the
 
drywell to the Drywell Pressure-High Functions setpoint.
 
Refer to LCO 3.5.1 for the Applicability Bases for the HPCS
 
System.
 
3.c. Reactor Vessel Water Level-High, Level 8
 
High RPV water level indicates that sufficient cooling water
 
inventory exists in the reactor vessel such that there is no
 
danger to the fuel. Therefore, the Level 8 signal is used
 
to close the HPCS injection valve to prevent overflow into
 
the main steam lines (MSLs). The Reactor Vessel Water
 
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-17 Revision 0 BASES APPLICABLE 3.c. Reactor Vessel Water Level-High, Level 8 (continued)
SAFETY ANALYSES, LCO, and Level-High, Level 8 Function for HPCS isolation is not APPLICABILITY credited in the accident analysis. It is retained since it is a potentially significant contributor to risk.
Reactor Vessel Water Level-High, Level 8 signals for HPCS
 
are initiated from two level transmitters from the narrow
 
range water level measurement instrumentation. The Reactor
 
Vessel Water Level-High, Level 8 Allowable Value is chosen
 
to isolate flow from the HPCS System prior to water
 
overflowing into the MSLs.
 
Two channels of Reactor Vessel Water Level-High, Level 8
 
Function are only required to be OPERABLE when HPCS is
 
required to be OPERABLE to ensure that no single instrument
 
failure can preclude HPCS initiation. Refer to LCO 3.5.1
 
and LCO 3.5.2 for HPCS Applicability Bases.
 
3.d, 3.e. HPCS Pump Discharge Pressure-High (Bypass) and HPCS System Flow Rate-Low (Bypass)
 
The minimum flow instruments are provided to protect the
 
HPCS pump from overheating when the pump is operating and
 
the associated injection valve is not sufficiently open.
 
The minimum flow line valve is opened when low flow and high
 
pump discharge pressure are sensed, and the valve is
 
automatically closed when the flow rate is adequate to
 
protect the pump or the discharge pressure is low (indicating the HPCS pump is not operating). The HPCS
 
System Flow Rate-Low (Bypass) and HPCS Pump Discharge
 
Pressure-High Functions are assumed to be OPERABLE and
 
capable of closing the minimum flow valve to ensure that the
 
ECCS flow assumed during the transients and accidents
 
analyzed in References 1, 2, and 3 are met. The core
 
cooling function of the ECCS, along with the scram action of
 
the RPS, ensures that the fuel peak cladding temperature
 
remains below the limits of 10 CFR 50.46.
 
One flow switch is used to detect the HPCS System's flow
 
rate. The logic is arranged such that the switch causes the
 
minimum flow valve to open, provided the HPCS pump discharge
 
pressure, sensed by another switch, is high enough 
 
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-18 Revision 0 BASES APPLICABLE 3.d, 3.e. HPCS Pump Discharge Pressure-High (Bypass) and SAFETY ANALYSES, HPCS System Flow Rate-Low (Bypass)
  (continued)
LCO, and APPLICABILITY (indicating the pump is operating). The logic will close the minimum flow valve once the closure setpoint is
 
exceeded.  (The valve will also close upon HPCS pump
 
discharge pressure decreasing below the setpoint.)
The HPCS System Flow Rate-Low (Bypass) Allowable Values are
 
high enough to ensure that pump flow rate is sufficient to
 
protect the pump, yet low enough to ensure that the closure
 
of the minimum flow valve is initiated to allow full flow
 
into the core. The HPCS Pump Discharge Pressure-High (Bypass) Allowable Value is set high enough to ensure that
 
the valve will not be open when the pump is not operating.
 
One channel of each Function is required to be OPERABLE when
 
the HPCS is required to be OPERABLE. Refer to LCO 3.5.1 and
 
LCO 3.5.2 for HPCS Applicability Bases.
 
3.f. Manual Initiation
 
The Manual Initiation push button channel introduces a
 
signal into the HPCS logic to provide manual initiation
 
capability and is redundant to the automatic protective
 
instrumentation. There is one push button for the HPCS
 
System.
 
The Manual Initiation Function is not assumed in any
 
accident or transient analyses in the UFSAR. However, the
 
Function is retained for overall redundancy and diversity of
 
the HPCS function as required by the NRC in the plant
 
licensing basis.
 
There is no Allowable Value for this Function since the
 
channel is mechanically actuated based solely on the
 
position of the push button. One channel of the Manual
 
Initiation Function is only required to be OPERABLE when the
 
HPCS System is required to be OPERABLE. Refer to LCO 3.5.1
 
and LCO 3.5.2 for HPCS Applicability Bases.
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-19 Revision 0 BASES APPLICABLE Automatic Depressurization System SAFETY ANALYSES, LCO, and 4.a, 5.a. Reactor Vessel Water Level-Low Low Low, Level 1 APPLICABILITY (continued) Low RPV water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease
 
too far, fuel damage could result. Therefore, ADS receives
 
one of the signals necessary for initiation from this
 
Function. The Reactor Vessel Water Level-Low Low Low, Level 1 is one of the Functions assumed to be OPERABLE and
 
capable of initiating the ADS during the accidents analyzed
 
in Reference 2. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the
 
fuel peak cladding temperature remains below the limits of
 
10 CFR 50.46.
 
Reactor Vessel Water Level-Low Low Low, Level 1 signals are
 
initiated from four differential pressure transmitters that
 
sense the difference between the pressure due to a constant
 
column of water (reference leg) and the pressure due to the
 
actual water level (variable leg) in the vessel. The
 
Reactor Vessel Water Level-Low Low Low, Level 1 Allowable
 
Value is chosen high enough to allow time for the low
 
pressure core spray and injection systems to initiate and
 
provide adequate cooling.
 
Four channels of Reactor Vessel Water Level-Low Low Low, Level 1 Function are only required to be OPERABLE when ADS
 
is required to be OPERABLE to ensure that no single
 
instrument failure can preclude ADS initiation.  (Two
 
channels input to ADS trip system A while the other two
 
channels input to ADS trip system B). Refer to LCO 3.5.1
 
for ADS Applicability Bases.
 
4.b, 5.b. Drywell Pressure-High
 
High pressure in the drywell could indicate a break in the
 
RCPB. Therefore, ADS receives one of the signals necessary
 
for initiation from this Function in order to minimize the
 
possibility of fuel damage. The Drywell Pressure-High is
 
assumed to be OPERABLE and capable of initiating the ADS
 
during the accidents analyzed in Reference 2. The core
 
cooling function of the ECCS, along with the scram action of
 
the RPS, ensures that the fuel peak cladding temperature
 
remains below the limits of 10 CFR 50.46.
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-20 Revision 0 BASES APPLICABLE 4.b, 5.b. Drywell Pressure-High (continued)
SAFETY ANALYSES, LCO, and Drywell Pressure-High signals are initiated from four APPLICABILITY pressure switches that sense drywell pressure. The Allowable Value was selected to be as low as possible and be
 
indicative of a LOCA inside primary containment.
 
Four channels of Drywell Pressure-High Function are only
 
required to be OPERABLE when ADS is required to be OPERABLE
 
to ensure that no single instrument failure can preclude ADS
 
initiation.  (Two channels input to ADS trip system A while
 
the other two channels input to ADS trip system B.)  Refer
 
to LCO 3.5.1 for ADS Applicability Bases.
 
4.c, 5.c. ADS Initiation Timer
 
The purpose of the ADS Initiation Timer is to delay
 
depressurization of the reactor vessel to allow the HPCS
 
System time to maintain reactor vessel water level. Since
 
the rapid depressurization caused by ADS operation is one of
 
the most severe transients on the reactor vessel, its
 
occurrence should be limited. By delaying initiation of the
 
ADS Function, the operator is given the chance to monitor
 
the success or failure of the HPCS System to maintain water
 
level, and then to decide whether or not to allow ADS to
 
initiate, to delay initiation further by recycling the
 
timer, or to inhibit initiation permanently. The ADS
 
Initiation Timer Function is assumed to be OPERABLE for the
 
accident analyses of Reference 2 that require ECCS
 
initiation and assume failure of the HPCS System.
 
There are two ADS Initiation Timer relays, one in each of
 
the two ADS trip systems. The Allowable Value for the ADS
 
Initiation Timer is chosen to be short enough so that there
 
is still time after depressurization for the low pressure
 
ECCS subsystems to provide adequate core cooling.
 
Two channels of the ADS Initiation Timer Function are only
 
required to be OPERABLE when the ADS is required to be
 
OPERABLE to ensure that no single instrument failure can
 
preclude ADS initiation.  (One channel inputs to ADS trip
 
system A while the other channel inputs to ADS trip
 
system B.)  Refer to LCO 3.5.1 for ADS Applicability Bases.
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-21 Revision 0 BASES APPLICABLE 4.d, 5.d. Reactor Vessel Water Level-Low, Level 3 SAFETY ANALYSES, (Confirmatory)
LCO, and APPLICABILITY The Reactor Vessel Water Level-Low, Level 3 Function (continued) (Confirmatory) is used by the ADS only as a confirmatory low water level signal. ADS receives one of the signals
 
necessary for initiation from Reactor Vessel Water
 
Level-Low Low Low, Level 1 signals. In order to prevent
 
spurious initiation of the ADS due to spurious Level 1
 
signals, a Level 3 signal must also be received before ADS
 
initiation commences.
Reactor Vessel Water Level-Low, Level 3 (Confirmatory)
 
signals are initiated from two differential pressure
 
transmitters that sense the difference between the pressure
 
due to a constant column of water (reference leg) and the
 
pressure due to the actual water level (variable leg) in the
 
vessel. The Allowable Value for Reactor Vessel Water
 
Level-Low, Level 3 (Confirmatory)is selected at the RPS
 
Level 3 scram Allowable Value for convenience. Refer to
 
LCO 3.3.1.1, "Reactor Protection System (RPS)
 
Instrumentation," for Bases discussion of this Function.
 
Two channels of Reactor Vessel Water Level-Low, Level 3 (Confirmatory) Function are only required to be OPERABLE
 
when the ADS is required to be OPERABLE to ensure that no
 
single instrument failure can preclude ADS initiation.  (One
 
channel inputs to ADS trip system A while the other channel
 
inputs to ADS trip system B.)  Refer to LCO 3.5.1 for ADS
 
Applicability Bases.
 
4.e, 4.f, 5.e. LPCS and LPCI Pump Discharge Pressure-High
 
The Pump Discharge Pressure-High signals from the LPCS and
 
LPCI pumps (indicating that the associated pump is running)
 
are used as permissives for ADS initiation, indicating that
 
there is a source of low pressure cooling water available
 
once the ADS has depressurized the vessel. Pump Discharge
 
Pressure-High is one of the Functions assumed to be
 
OPERABLE and capable of permitting ADS initiation during the
 
events analyzed in References 2 and 3  with an assumed HPCS
 
failure. For these events, the ADS depressurizes the
 
reactor vessel so that the low pressure ECCS can perform the 
 
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-22 Revision 0 BASES APPLICABLE 4.e, 4.f, 5.e. LPCS and LPCI Pump Discharge Pressure-High SAFETY ANALYSES, (continued)
 
LCO, and APPLICABILITY core cooling functions. This core cooling function of the ECCS, along with the scram action of the RPS, ensures that
 
the fuel peak cladding temperature remains below the limits
 
of 10 CFR 50.46.
Pump discharge pressure signals are initiated from eight
 
pressure switches, two on the discharge side of each of the
 
four low pressure ECCS pumps. In order to generate an ADS
 
permissive in one trip system, it is necessary that only one
 
pump (both channels for the pump) indicate the high
 
discharge pressure condition. The Pump Discharge
 
Pressure-High Allowable Value is less than the pump
 
discharge pressure when the pump is operating in a full flow
 
mode, and high enough to avoid any condition that results in
 
a discharge pressure permissive when the LPCS and LPCI pumps
 
are aligned for injection and the pumps are not running.
 
The actual operating point of this Function is not assumed
 
in any transient or accident analysis.
 
Eight channels of LPCS and LPCI Pump Discharge Pressure-
 
High Function (two LPCS and two LPCI A channels input to ADS
 
trip system A, while two LPCI B and two LPCI C channels
 
input to ADS trip system B) are only required to be OPERABLE
 
when the ADS is required to be OPERABLE to ensure that no
 
single instrument failure can preclude ADS initiation.
 
Refer to LCO 3.5.1 for ADS Applicability Bases.
 
4.g, 5.f. ADS Drywell Pressure Bypass Timer
 
One of the signals required for ADS initiation is Drywell
 
Pressure-High. However, if the event requiring ADS
 
initiation occurs outside the drywell (for example, main
 
steam line break outside primary containment), a high
 
drywell pressure signal may never be present. Therefore, the ADS Drywell Pressure Bypass Timer is used to bypass the
 
Drywell Pressure-High Function after a certain time period
 
has elapsed. The ADS Drywell Pressure Bypass Timer Function
 
instrumentation is retained in the TS because ADS is part of
 
the primary success path for mitigation of a DBA.
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-23 Revision 0 BASES APPLICABLE 4.g, 5.f. ADS Drywell Pressure Bypass Time (continued) SAFETY ANALYSES, LCO, and There are four ADS Drywell Pressure Bypass Timer relays, two APPLICABILITY in each of the two ADS trip systems. The Allowable Value for the ADS Timer is chosen to be short enough that so that
 
there is still time after depressurization for the low
 
pressure ECCS subsystems to provide adequate core cooling.
Four channels of the ADS Drywell Pressure Bypass Timer
 
Function are only required to be OPERABLE when the ADS is
 
required to be OPERABLE to ensure that no single instrument
 
failure can preclude ADS initiation. Refer to LCO 3.5.1 for
 
ADS Applicability Bases.
 
4.h, 5.g. Manual Initiation
 
The Manual Initiation push button channels introduce signals
 
into the ADS logic to provide manual initiation capability
 
and are redundant to the automatic protective
 
instrumentation. There are two push buttons for each ADS
 
trip system (total of four).
 
The Manual Initiation Function is not assumed in any
 
accident or transient analyses in the UFSAR. However, the
 
Function is retained for overall redundancy and diversity of
 
the ADS function as required by the NRC in the plant
 
licensing basis.
 
There is no Allowable Value for this Function since the
 
channel is mechanically actuated based solely on the
 
position of the push buttons. Four channels of the Manual
 
Initiation Function (two channels per ADS trip system) are
 
only required to be OPERABLE when the ADS is required to be
 
OPERABLE. Refer to LCO 3.5.1 for ADS Applicability Bases.
 
ACTIONS A Note has been provided to modify the ACTIONS related to ECCS instrumentation channels. Section 1.3, Completion
 
Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables
 
expressed in the Condition, discovered to be inoperable or
 
not within limits, will not result in separate entry into
 
the Condition. Section 1.3 also specifies that Required
 
Actions of the Condition continue to apply for each (continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-24 Revision 0 BASES ACTIONS additional failure, with Completion Times based on initial (continued) entry into the Condition. However, the Required Actions for inoperable ECCS instrumentation channels provide appropriate
 
compensatory measures for separate inoperable Condition
 
entry for each inoperable ECCS instrumentation channel.
 
A.1 Required Action A.1 directs entry into the appropriate
 
Condition referenced in Table 3.3.5.1-1. The applicable
 
Condition specified in the Table is Function dependent.
 
Each time a channel is discovered to be inoperable, Condition A is entered for that channel and provides for
 
transfer to the appropriate subsequent Condition.
 
B.1, B.2, and B.3
 
Required Actions B.1 and B.2 are intended to ensure that
 
appropriate actions are taken if multiple, inoperable, untripped channels within the same Function (or in some
 
cases, within the same variable) result in redundant
 
automatic initiation capability being lost for the
 
feature(s). Loss of redundant automatic capability for the
 
low pressure ECCS injection feature in both divisions occurs
 
when the initiation capability is available to less than two
 
pumps from any single variable. Required Action B.1
 
features would be those that are initiated by Functions 1.a, l.b, 2.a, and 2.b (i.e., low pressure ECCS and associated
 
DGs). The Required Action B.2 feature would be HPCS System
 
and associated DG. For Required Action B.1, redundant
 
automatic initiation capability is lost if either (a) one or
 
more Function 1.a channels and one or more Function 2.a
 
channels are inoperable and untripped, or (b) one or more
 
Function 1.b channels and one or more Function 2.b channels
 
are inoperable and untripped. For Divisions 1 and 2, since
 
each inoperable channel would have Required Action B.1
 
applied separately (refer to ACTIONS Note), each inoperable
 
channel would only require the affected portion of the
 
associated Division of low pressure ECCS and DG to be
 
declared inoperable. However, since channels in both
 
Divisions are inoperable and untripped, and the Completion
 
Times started concurrently for the channels in both 
 
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-25 Revision 0 BASES ACTIONS B.1, B.2, and B.3 (continued)
Divisions, this results in the affected portions in both
 
Divisions of ECCS and DG being concurrently declared
 
inoperable. For Required Action B.2, redundant automatic
 
initiation capability (i.e., loss of automatic start
 
capability for either Functions 3.a or 3.b) is lost if two
 
Function 3.a or two Function 3.b parallel contacts (channels) are inoperable and untripped in the same trip
 
system. 
 
In this situation (loss of redundant automatic initiation
 
capability), the 24 hour allowance of Required Action B.3 is
 
not appropriate and the feature(s) associated with the
 
inoperable, untripped channels must be declared inoperable
 
within 1 hour. As noted (Note 1 to Required Action B.1 and
 
Required Action B.2), the two Required Actions are only
 
applicable in MODES 1, 2, and 3. In MODES 4 and 5, the
 
specific initiation time of the ECCS is not assumed and the
 
probability of a LOCA is lower. Thus, a total loss of
 
initiation capability for 24 hours (as allowed by Required
 
Action B.3) is allowed during MODES 4 and 5. Notes are also
 
provided (Note 2 to Required Action B.1 and Required
 
Action B.2) to delineate which Required Action is applicable
 
for each Function that requires entry into Condition B if an
 
associated channel is inoperable. This ensures that the
 
proper loss of initiation capability check is performed.
 
The Completion Time is intended to allow the operator time
 
to evaluate and repair any discovered inoperabilities. This
 
Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock."
For Required Action B.1, the Completion Time only begins
 
upon discovery that a redundant feature in both Divisions (e.g., any Division 1 ECCS and Division 2 ECCS) cannot be
 
automatically initiated due to inoperable, untripped
 
channels within the same variable as described in the
 
paragraph above. For Required Action B.2, the Completion
 
Time only begins upon discovery that the HPCS System cannot
 
be automatically initiated due to two inoperable, untripped
 
channels (parallel contacts) for the associated Function in
 
the same trip system. The 1 hour Completion Time from
 
discovery of loss of initiation capability is acceptable
 
because it minimizes risk while allowing time for
 
restoration or tripping of channels.
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-26 Revision 0 BASES ACTIONS B.1, B.2, and B.3 (continued)
Because of the diversity of sensors available to provide
 
initiation signals and the redundancy of the ECCS design, an
 
allowable out of service time of 24 hours has been shown to
 
be acceptable (Ref. 4) to permit restoration of any
 
inoperable channel to OPERABLE status. If the inoperable
 
channel cannot be restored to OPERABLE status within the
 
allowable out of service time, the channel must be placed in
 
the tripped condition per Required Action B.3. Placing the
 
inoperable channel in trip would conservatively compensate
 
for the inoperability, restore capability to accommodate a
 
single failure, and allow operation to continue.
 
Alternately, if it is not desired to place the channel in
 
trip (e.g., as in the case where placing the inoperable
 
channel in trip would result in an initiation), Condition G
 
must be entered and its Required Action taken.
 
C.1 and C.2
 
Required Action C.1 is intended to ensure that appropriate
 
actions are taken if multiple, inoperable channels within
 
the same Function (or in some cases, within the same
 
variable) result in redundant automatic initiation
 
capability being lost for the feature(s). Loss of redundant
 
automatic initiation capability for the low pressure ECCS
 
injection feature in both divisions occurs when the
 
initiation capability is available to less than two pumps
 
from any single variable.
 
Required Action C.1 features would be those that are
 
initiated by Functions 1.c, and 2.c (i.e., low pressure
 
ECCS). For Functions 1.c and 2.c, redundant automatic
 
initiation capability is lost if the Function 1.c and
 
Function 2.c channels are inoperable. Since each inoperable
 
channel would have Required Action C.1 applied separately (refer to ACTIONS Note), each inoperable channel would only
 
require the affected portion of the associated Division to
 
be declared inoperable. However, since channels in both
 
Divisions are inoperable, and the Completion Times started
 
concurrently for the channels in both Divisions, this
 
results in the affected portions in both Divisions being
 
concurrently declared inoperable. For Functions 1.c
 
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-27 Revision 0 BASES ACTIONS C.1 and C.2 (continued) and 2.c, the affected portions of the Division are LPCI A
 
and LPCI B, respectively. In addition, the specific
 
inoperability of these Functions should also be evaluated
 
for impact on the DGs.
 
In this situation (loss of redundant automatic initiation
 
capability), the 24 hour allowance of Required Action C.2 is
 
not appropriate and the feature(s) associated with the
 
inoperable channels must be declared inoperable within
 
1 hour. As noted (Note 1), the Required Action is only
 
applicable in MODES 1, 2, and 3. In MODES 4 and 5, the
 
specific initiation time of the ECCS is not assumed and the
 
probability of a LOCA is lower. Thus, a total loss of
 
automatic initiation capability for 24 hours (as allowed by
 
Required Action C.2) is allowed during MODES 4 and 5.
 
Note 2 states that Required Action C.1 is only applicable
 
for Functions 1.c and 2.c. The Required Action is not
 
applicable to Functions 1.h, 2.g, and 3.f (which also
 
require entry into this Condition if a channel in these
 
Functions is inoperable), since they are the Manual
 
Initiation Functions and are not assumed in any accident or
 
transient analysis. Thus, a total loss of manual initiation
 
capability for 24 hours (as allowed by Required Action C.2)
 
is allowed. Required Action C.1 is also not applicable to
 
Function 3.c (which also requires entry into this Condition
 
if a channel in this Function is inoperable), since the loss
 
of the Function was considered during the development of
 
Reference 4 and considered acceptable for the 24 hours
 
allowed by Required Action C.2.
 
The Completion Time is intended to allow the operator time
 
to evaluate and repair any discovered inoperabilities. This
 
Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock."
For Required Action C.1, the Completion Time only begins
 
upon discovery that the same feature in both Divisions (i.e., any Division 1 ECCS and Division 2 ECCS) cannot be
 
automatically initiated due to inoperable channels within
 
the same variable as described in the paragraph above. The
 
1 hour Completion Time from discovery of loss of initiation
 
capability is acceptable because it minimizes risk while
 
allowing time for restoration of channels.
 
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-28 Revision 0 BASES ACTIONS C.1 and C.2 (continued)
Because of the diversity of sensors available to provide
 
initiation signals and the redundancy of the ECCS design, an
 
allowable out of service time of 24 hours has been shown to
 
be acceptable (Ref. 4) to permit restoration of any
 
inoperable channel to OPERABLE status. If the inoperable
 
channel cannot be restored to OPERABLE status within the
 
allowable out of service time, Condition G must be entered
 
and its Required Action taken. The Required Actions do not
 
allow placing the channel in trip since this action would
 
either cause the initiation or would not necessarily result
 
in a safe state for the channel in all events.
 
D.1, D.2, D.3, and D.4
 
Required Action D.1 is intended to ensure that appropriate
 
actions are taken if multiple, inoperable, channels within
 
the LPCS and LPCI Pump Discharge Flow-Low (Bypass)
 
Functions, the Injection Line Pressure-Low (Injection
 
Permissive), and the Reactor Steam Dome Pressure-Low (Injection Permissive) Functions result in redundant
 
automatic initiation capability being lost for the
 
feature(s). Loss of redundant automatic initiation
 
capability for the low pressure ECCS injection feature in
 
both divisions occurs when the initiation capability is
 
available to less than two pumps from any single variable.
 
For the purposes of this Condition, the injection
 
permissives on Reactor Steam Dome Pressure-Low and
 
Injection Line Pressure-Low are considered the same
 
variable. Similarly, Functions 1.e, 1.f, and 2.e are all
 
minimum flow functions and considered the same variable.
 
For Required Action D.1, the features would be those that
 
are initiated by Functions 1.d, 1.e, 1.f, 1.g, 2.d, 2.e, and 2.f (e.g., low pressure ECCS). Redundant automatic
 
initiation capability is lost if three of the four channels
 
associated with Functions 1.e, 1.f, and 2.e are inoperable.
 
For Function 1.d, redundant automatic initiation capability
 
is lost if two Function 1.d channels are inoperable
 
concurrent with either two inoperable Function 2.d channels
 
or one inoperable Function 2.f channel. For Function 2.d, redundant automatic initiation capability is lost if two
 
Function 2.d channels are inoperable concurrent with two (continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-29 Revision 0 BASES  ACTIONS D.1, D.2, D.3, and D.4 (continued) inoperable 1.d channels or one inoperable 1.g channel. For
 
Function 1.g, redundant automatic initiation capability is
 
lost if two Function 1.g channels are inoperable concurrent
 
with either two inoperable Function 2.d channels or one
 
inoperable Function 2.f channel. For Function 2.f, redundant automatic initiation capability is lost if two
 
Function 2.f channels are inoperable concurrent with two
 
inoperable 1.d channels or one inoperable 1.g channel. Since
 
each inoperable channel would have Required Action D.1
 
applied separately (refer to ACTIONS Note), each inoperable
 
channel would only require the affected low pressure ECCS
 
pump to be declared inoperable. However, since channels for
 
more than one low pressure ECCS pump are inoperable, and the
 
Completion Times started concurrently for the channels of
 
the low pressure ECCS pumps, this results in the affected
 
low pressure ECCS pumps being concurrently declared
 
inoperable.
In this situation (loss of redundant automatic initiation
 
capability), the Completion Times of Required Actions D.3
 
and D.4 are not appropriate and the feature(s) associated
 
with each inoperable channel must be declared inoperable
 
within 1 hour after discovery of loss of initiation
 
capability for feature(s) in both Divisions. As noted (Note 1 to Required Action D.1), Required Action D.1 is only
 
applicable in MODES 1, 2, and 3. In MODES 4 and 5, the
 
specific initiation time of the low pressure ECCS is not
 
assumed and the probability of a LOCA is lower. Thus, a
 
total loss of initiation capability for 7 days for Functions
 
1.e, 1.f, and 2.e (as allowed by Required Action D.4) is
 
allowed during MODES 4 and 5.  (This Condition is not
 
entered when Functions 1.d, 1.g, 2.d or 2.f are inoperable
 
in MODES 4 and 5.)  A Note is also provided (Note 2 to
 
Required Action D.1) to delineate that Required Action D.1
 
is only applicable to low pressure ECCS Functions. Required
 
Action D.1 is not applicable to HPCS Functions 3.d and 3.e
 
since the loss of one channel results in a loss of the
 
Function (one-out-of-one logic). This loss was considered
 
during the development of Reference 4 and considered
 
acceptable for the 7 days allowed by Required Action D.4.
 
Required Action D.2 is intended to ensure that appropriate (continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-30 Revision 0 BASES  ACTIONS D.1, D.2, D.3, and D.4 (continued) actions are taken if multiple, inoperable channels within
 
the Reactor Steam Dome Pressure-Low (Injection Permissive)
 
Function result in automatic initiation capability being
 
lost for the features in one division. For Required Action
 
D.2, the features would be those that are initiated by
 
Functions 1.d and 2.d (e.g., low pressure ECCS). For
 
Functions 1.d and 2.d, automatic initiation capability is
 
lost in one division if two Function 1.d or two Function 2.d
 
channels are inoperable. In this situation, (loss of
 
automatic initiation capability), the 7 day allowance of
 
Required Action D.4 is not appropriate and the features
 
associated with the inoperable channels must be declared
 
inoperable within 24 hours after discovery of loss of
 
initiation capability for features in one division. For
 
Functions 1.g and 2.f, an allowable out of service time of
 
24 hours is provided by Required Action D.3
 
The Completion Time is intended to allow the operator time
 
to evaluate and repair any discovered inoperabilities. This
 
Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock."
For Required Action D.1, the Completion Time only begins
 
upon discovery that three channels of the Pump Discharge
 
Flow-Low (Bypass) Function cannot be automatically
 
initiated due to inoperable channels or upon discovery of a
 
loss of redundant initiation capability for the Reactor
 
Steam Dome Pressure-Low (Injection Permissive) and
 
Injection Line Pressure-Low (Injection Permissive)
 
Functions (as described above). The 1 hour Completion Time
 
from discovery of loss of initiation capability is
 
acceptable because it minimizes risk while allowing time for
 
restoration of channels. For Required Action D.2, the
 
Completion Time only begins upon discovery that two Function
 
1.d or two Function 2.d channels cannot be automatically
 
initiated due to inoperable channels. The 24 hour
 
Completion Time from discovery of loss of initiation
 
capability for features in one division is acceptable
 
because of the redundancy of the ECCS design, as shown in
 
the reliability analysis of Reference 4.
 
If the instrumentation that controls the pump minimum flow
 
valve is inoperable such that the valve will not
 
automatically open, extended pump operation with no
 
injection path available could lead to pump overheating and (continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-31 Revision 0 BASES ACTIONS D.1, D.2, D.3, and D.4 (continued) failure. If there were a failure of the instrumentation
 
such that the valve would not automatically close, a portion
 
of the pump flow could be diverted from the reactor
 
injection path, causing insufficient core cooling. These
 
consequences can be averted by the operator's manual control
 
of the valve, which would be adequate to maintain ECCS pump
 
protection and required flow. Furthermore, other ECCS pumps
 
would be sufficient to complete the assumed safety function
 
if no additional single failure were to occur. If a Reactor
 
Vessel Pressure-Low (Injection Permissive) Function channel
 
is inoperable, another channel exists to ensure the
 
injection valves in the ECCS division can still open. The
 
7 day Completion Time of Required Action D.4 to restore the
 
inoperable channel to OPERABLE status is reasonable based on
 
the remaining capability of the associated ECCS subsystems, the redundancy available in the ECCS design, and the low
 
probability of a DBA occurring during the allowed out of
 
service time. If the inoperable channel cannot be restored
 
to OPERABLE status within the allowable out of service time, Condition G must be entered and its Required Action taken.
 
The Required Actions do not allow placing the channel in
 
trip since this action would not necessarily result in a
 
safe state for the channel in all events.
 
E.1 and E.2
 
Required Action E.1 is intended to ensure that appropriate
 
actions are taken if multiple, inoperable, untripped
 
channels within similar ADS trip system Functions result in
 
automatic initiation capability being lost for the ADS.
 
Automatic initiation capability is lost if either (a) one or
 
more Function 4.a channels and one or more Function 5.a
 
channels are inoperable and untripped, (b) one or more
 
Function 4.b channels and one or more Function 5.b channels
 
are inoperable and untripped, or (c) one Function 4.d
 
channel and one Function 5.d channel are inoperable and
 
untripped.
 
In this situation (loss of automatic initiation capability),
the 96 hour or 8 day allowance, as applicable, of Required
 
Action E.2 is not appropriate, and all ADS valves must be
 
declared inoperable within 1 hour after discovery of loss of
 
ADS initiation capability in both trip systems.
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-32 Revision 0 BASES ACTIONS E.1 and E.2 (continued)
The Completion Time is intended to allow the operator time
 
to evaluate and repair any discovered inoperabilities. This
 
Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock."
For Required Action E.1, the Completion Time only begins
 
upon discovery that the ADS cannot be automatically
 
initiated due to inoperable, untripped channels within
 
similar ADS trip system Functions as described in the
 
paragraph above. The 1 hour Completion Time from discovery
 
of loss of initiation capability is acceptable because it
 
minimizes risk while allowing time for restoration or
 
tripping of channels.
 
Because of the diversity of sensors available to provide
 
initiation signals and the redundancy of the ECCS design, an
 
allowable out of service time of 8 days has been shown to be
 
acceptable (Ref. 4) to permit restoration of any inoperable
 
channel to OPERABLE status if both HPCS and RCIC are
 
OPERABLE. If either HPCS or RCIC is inoperable, the time is
 
shortened to 96 hours. If the status of HPCS or RCIC
 
changes such that the Completion Time changes from 8 days to
 
96 hours, the 96 hours begins upon discovery of HPCS or RCIC
 
inoperability. However, total time for an inoperable, untripped channel cannot exceed 8 days. If the status of
 
HPCS or RCIC changes such that the Completion Time changes
 
from 96 hours to 8 days, the "time zero" for beginning the
 
8 day "clock" begins upon discovery of the inoperable, untripped channel. If the inoperable channel cannot be
 
restored to OPERABLE status within the allowable out of
 
service time, the channel must be placed in the tripped
 
condition per Required Action E.2. Placing the inoperable
 
channel in trip would conservatively compensate for the
 
inoperability, restore capability to accommodate a single
 
failure, and allow operation to continue. Alternately, if
 
it is not desired to place the channel in trip (e.g., as in
 
the case where placing the inoperable channel in trip would
 
result in an initiation), Condition G must be entered and
 
its Required Action taken.
 
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-33 Revision 0 BASES ACTIONS F.1 and F.2 (continued)
Required Action F.1 is intended to ensure that appropriate
 
actions are taken if multiple, inoperable channels within
 
similar ADS trip system Functions result in automatic
 
initiation capability being lost for the ADS. Automatic
 
initiation capability is lost if either (a) one Function 4.c
 
channel and one Function 5.c channel are inoperable, (b) one
 
or more Function 4.e channels and one or more Function 5.e
 
channels are inoperable, (c) one or more Function 4.f
 
channels and one or more Function 5.e channels are
 
inoperable, or (d) one or more Function 4.g channels and one
 
or more Function 5.f channels are inoperable.
 
In this situation (loss of automatic initiation capability),
the 96 hour or 8 day allowance, as applicable, of Required
 
Action F.2 is not appropriate, and all ADS valves must be
 
declared inoperable within 1 hour after discovery of loss of
 
ADS initiation capability in both trip systems. The Note to
 
Required Action F.1 states that Required Action F.1 is only
 
applicable for Functions 4.c, 4.e, 4.f, 4.g, 5.c, 5.e, and 5.f. Required Action F.1 is not applicable to
 
Functions 4.h and 5.g (which also require entry into this
 
Condition if a channel in these Functions is inoperable),
since they are the Manual Initiation Functions and are not
 
assumed in any accident or transient analysis. Thus, a
 
total loss of manual initiation capability for 96 hours or
 
8 days (as allowed by Required Action F.2) is allowed.
 
The Completion Time is intended to allow the operator time
 
to evaluate and repair any discovered inoperabilities. This
 
Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock."
For Required Action F.1, the Completion Time only begins
 
upon discovery that the ADS cannot be automatically
 
initiated due to inoperable channels within similar ADS trip
 
system Functions, as described in the paragraph above. The
 
1 hour Completion Time from discovery of loss of initiation
 
capability is acceptable because it minimizes risk while
 
allowing time for restoration or tripping of channels.
 
Because of the diversity of sensors available to provide
 
initiation signals and the redundancy of the ECCS design, an
 
allowable out of service time of 8 days has been shown to be
 
acceptable (Ref. 4) to permit restoration of any inoperable
 
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-34 Revision 0 BASES ACTIONS F.1 and F.2 (continued) channel to OPERABLE status if both HPCS and RCIC are
 
OPERABLE (Required Action F.2). If either HPCS or RCIC is
 
inoperable, the time is reduced to 96 hours. If the status
 
of HPCS or RCIC changes such that the Completion Time
 
changes from 8 days to 96 hours, the 96 hours begins upon
 
discovery of HPCS or RCIC inoperability. However, total
 
time for an inoperable channel cannot exceed 8 days. If the
 
status of HPCS or RCIC changes such that the Completion Time
 
changes from 96 hours to 8 days, the "time zero" for
 
beginning the 8 day "clock" begins upon discovery of the
 
inoperable channel. If the inoperable channel cannot be
 
restored to OPERABLE status within the allowable out of
 
service time, Condition G must be entered and its Required
 
Action taken. The Required Actions do not allow placing the
 
channel in trip since this action would not necessarily
 
result in a safe state for the channel in all events.
 
G.1 With any Required Action and associated Completion Time not
 
met, the associated feature(s) may be incapable of
 
performing the intended function and the supported
 
feature(s) associated with the inoperable untripped channels
 
must be declared inoperable immediately.
 
SURVEILLANCE As noted at the beginning of the SRs, the SRs for each ECCS REQUIREMENTS instrumentation Function are found in the SRs column of Table 3.3.5.1-1.
The Surveillances are modified by a Note to indicate that
 
when a channel is placed in an inoperable status solely for
 
performance of required Surveillances, entry into associated
 
Conditions and Required Actions may be delayed for up to
 
6 hours as follows:  (a) for Functions 3.c, 3.d, 3.e, and 3.f; and (b) for Functions other than 3.c, 3.d, 3.e, and 3.f provided the associated Function or redundant
 
Function maintains ECCS initiation capability. Upon
 
completion of the Surveillance, or expiration of the 6 hour
 
allowance, the channel must be returned to OPERABLE status
 
or the applicable Condition entered and Required Actions
 
taken. This Note is based on the reliability analysis
 
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-35 Revision 0 BASES SURVEILLANCE (Ref. 4) assumption of the average time required to perform REQUIREMENTS channel Surveillance. That analysis demonstrated that the (continued) 6 hour testing allowance does not significantly reduce the probability that the ECCS will initiate when necessary.
 
SR  3.3.5.1.1
 
Performance of the CHANNEL CHECK once every 12 hours ensures
 
that a gross failure of instrumentation has not occurred. A
 
CHANNEL CHECK is normally a comparison of the parameter
 
indicated on one channel to a similar parameter on other
 
channels. It is based on the assumption that instrument
 
channels monitoring the same parameter should read
 
approximately the same value. Significant deviations
 
between the instrument channels could be an indication of
 
excessive instrument drift in one of the channels or
 
something even more serious. A CHANNEL CHECK will detect
 
gross channel failure; thus, it is key to verifying the
 
instrumentation continues to operate properly between each
 
CHANNEL CALIBRATION.
 
Agreement criteria are determined by the plant staff, based
 
on a combination of the channel instrument uncertainties, including indication and readability. If a channel is
 
outside the criteria, it may be an indication that the
 
instrument has drifted outside its limit.
 
The Frequency is based upon operating experience that
 
demonstrates channel failure is rare. The CHANNEL CHECK
 
supplements less formal, but more frequent, checks of
 
channels during normal operational use of the displays
 
associated with the channels required by the LCO.
 
SR  3.3.5.1.2
 
A CHANNEL FUNCTIONAL TEST is performed on each required
 
channel to ensure that the channel will perform the intended
 
function. A successful test of the required contact(s) of a
 
channel relay may be performed by the verification of the
 
change of state of a single contact of the relay. This (continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-36 Revision 0 BASES SURVEILLANCE SR  3.3.5.1.2 (continued)
REQUIREMENTS clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a
 
relay. This is acceptable because all of the other required
 
contacts of the relay are verified by other Technical
 
Specifications and non-Technical Specifications tests at
 
least once per refueling interval with applicable
 
extensions.
 
Any setpoint adjustment shall be consistent with the
 
assumptions of the current plant specific setpoint
 
methodology.
 
The Frequency of 92 days is based on the reliability
 
analyses of Reference 4.
 
SR  3.3.5.1.3 and SR  3.3.5.1.4
 
A CHANNEL CALIBRATION is a complete check of the instrument
 
loop and the sensor. This test verifies the channel
 
responds to the measured parameter within the necessary
 
range and accuracy. CHANNEL CALIBRATION leaves the channel
 
adjusted to account for instrument drifts between successive
 
calibrations consistent with the plant specific setpoint
 
methodology.
 
The Frequency of SR 3.3.5.1.3 is based upon the assumption
 
of a 92 day calibration interval in the determination of the
 
magnitude of equipment drift in the setpoint analysis. The
 
Frequency of SR 3.3.5.1.4 is based upon the assumption of a
 
24 month calibration interval in the determination of the
 
magnitude of equipment drift in the setpoint analysis.
 
SR  3.3.5.1.5
 
The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the
 
OPERABILITY of the required initiation logic for a specific
 
channel. The system functional testing performed in
 
LCO 3.5.1, LCO 3.5.2, LCO 3.8.1, and LCO 3.8.2 overlaps this
 
Surveillance to provide complete testing of the assumed
 
safety function.
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-37 Revision 0 BASES SURVEILLANCE SR  3.3.5.1.5 (continued)
REQUIREMENTS The 24 month Frequency is based on the need to perform this
 
Surveillance under the conditions that apply during a plant
 
outage and the potential for unplanned transients if the
 
Surveillance were performed with the reactor at power.
 
Operating experience has shown these components usually pass
 
the Surveillance when performed at the 24 month Frequency.
 
SR  3.3.5.1.6
 
This SR ensures that the individual channel response times
 
are less than or equal to the maximum values assumed in the
 
accident analysis. Response time testing acceptance
 
criteria are included in Reference 5.
 
ECCS RESPONSE TIME may be verified by actual response time
 
measurements in any series of sequential, overlapping, or
 
total channel measurements. However, the measurement of
 
instrument loop response times may be excluded if the
 
conditions of Reference 6 are satisfied. If these
 
conditions are satisfied, instrument loop response time may
 
be allocated based on either assumed design instrument loop
 
response time or the manufacturer's stated design instrument
 
loop response time. When the requirements of Reference 6
 
are not satisfied, instrument loop response time must be
 
measured. The instrument loop response times must be added
 
to the remaining equipment response times (e.g., ECCS pump
 
start time) to obtain the ECCS RESPONSE TIME. However, failure to meet the ECCS RESPONSE TIME due to a component
 
other than instrumentation not within limits does not
 
require the associated instrumentation to be declared
 
inoperable; only the affected component (e.g., ECCS pump) is
 
required to be declared inoperable.
 
ECCS RESPONSE TIME tests are conducted on a 24 month
 
STAGGERED TEST BASIS. The 24 month Frequency is consistent
 
with the refueling cycle and is based upon plant operating
 
experience, which shows that random failures of
 
instrumentation components causing serious response time
 
degradation, but not channel failure, are infrequent.
 
(continued)
ECCS Instrumentation B 3.3.5.1
 
LaSalle 1 and 2 B 3.3.5.1-38 Revision 0 BASES  (continued)
 
REFERENCES 1. UFSAR, Section 5.2.
: 2. UFSAR, Section 6.3.
: 3. UFSAR, Chapter 15.
: 4. NEDC-30936-P-A, "BWR Owners' Group Technical Specification Improvement Analyses for ECCS Actuation
 
Instrumentation, Parts 1 and 2," December 1988.
: 5. Technical Requirements Manual.
: 6. NEDO-32291-A, "System Analyses for the Elimination of Selected Response Time Testing Requirements,"
October 1995.
 
RCIC System Instrumentation B 3.3.5.2
 
LaSalle 1 and 2 B 3.3.5.2-1 Revision 0 B 3.3  INSTRUMENTATION
 
B 3.3.5.2  Reactor Core Isolation Cooling (RCIC) System Instrumentation
 
BASES
 
BACKGROUND The purpose of the RCIC System instrumentation is to initiate actions to ensure adequate core cooling when the
 
reactor vessel is isolated from its primary heat sink (the
 
main condenser) and normal coolant makeup flow from the
 
Reactor Feedwater System is insufficient or unavailable, such that RCIC System initiation occurs and maintains
 
sufficient reactor water level precluding initiation of the
 
low pressure Emergency Core Cooling Systems (ECCS) pumps. A
 
more complete discussion of RCIC System operation is
 
provided in the Bases of LCO 3.5.3, "RCIC System."
 
The RCIC System may be initiated by either automatic or
 
manual means. Automatic initiation occurs for conditions of
 
Reactor Vessel Water Level Low-Low, Level 2. The variable
 
is monitored by four differential pressure transmitters that
 
are connected to four trip units. The outputs of the trip
 
units are connected to relays whose contacts are arranged in
 
a one-out-of-two taken twice logic arrangement. The logic
 
can also be initiated by use of a manual push button. Once
 
initiated, the RCIC logic seals in and can be reset by the
 
operator only when the reactor vessel water level signals
 
have cleared.
 
The RCIC test line isolation valve is closed on a RCIC
 
initiation signal to allow full system flow to the reactor
 
vessel.
 
The RCIC System also monitors the water level in the
 
condensate storage tank (CST), since there are two sources
 
of water for RCIC operation. Reactor grade water in the CST
 
is the normal source. Upon receipt of a RCIC initiation
 
signal, the CST suction valve is automatically signaled to
 
open (it is normally in the open position) unless the pump
 
suction from the suppression pool valve is open. If the
 
water level in the CST falls below a preselected level, first the suppression pool suction valve automatically opens
 
and then the CST suction valve automatically closes. Two
 
level switches are used to detect low water level in the
 
CST. Either switch can cause the suppression pool suction
 
valve to open. To prevent losing suction to the pump,  (continued)
RCIC System Instrumentation B 3.3.5.2
 
LaSalle 1 and 2 B 3.3.5.2-2 Revision 0 BASES BACKGROUND the suction valves are interlocked so that one suction path (continued) must be open before the other automatically closes.
 
The RCIC System provides makeup water to the reactor until
 
the reactor vessel water level reaches the high water level (Level 8) trip (two-out-of-two logic), at which time the
 
RCIC turbine steam inlet isolation valve closes (the
 
injection valve also closes due to the closure of the RCIC
 
turbine steam inlet isolation valve). The RCIC System
 
restarts if vessel level again drops to the low level
 
initiation point (Level 2).
 
APPLICABLE The function of the RCIC System, to provide makeup SAFETY ANALYSES, coolant to the reactor, is to respond to transient LCO, and events. The RCIC System is not an Engineered Safety Feature APPLICABILITY System and no credit is taken in the safety analysis for RCIC System operation. Based on its contribution to the
 
reduction of overall plant risk, however, the RCIC System, and therefore its instrumentation, meets Criterion 4 of
 
10 CFR 50.36(c)(2)(ii). Certain instrumentation Functions
 
are retained for other reasons and are described below in
 
the individual Functions discussion.
 
The OPERABILITY of the RCIC System instrumentation is
 
dependent on the OPERABILITY of the individual
 
instrumentation channel Functions specified in
 
Table 3.3.5.2-1. Each Function must have a required number
 
of OPERABLE channels with their setpoints within the
 
specified Allowable Values, where appropriate. The actual
 
setpoint is calibrated consistent with applicable setpoint
 
methodology assumptions.
 
Allowable Values are specified for each RCIC System
 
instrumentation Function specified in the Table. Nominal
 
trip setpoints are specified in the setpoint calculations.
 
The nominal setpoints are selected to ensure that the
 
setpoints do not exceed the Allowable Value between CHANNEL
 
CALIBRATIONS. Operation with a trip setpoint less
 
conservative than the nominal trip setpoint, but within its
 
Allowable Value, is acceptable. A channel is inoperable if
 
its actual trip setpoint is not within its required
 
Allowable Value.
(continued)
RCIC System Instrumentation B 3.3.5.2
 
LaSalle 1 and 2 B 3.3.5.2-3 Revision 0 BASES APPLICABLE Trip setpoints are those predetermined values of output at SAFETY ANALYSES, which an action should take place. The setpoints are LCO, and compared to the actual process parameter (e.g., reactor APPLICABILITY vessel water level), and when the measured output value of (continued) the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The analytic limits (or design limits) are derived from the limiting values of
 
the process parameters obtained from the safety analysis.
 
The trip setpoints are determined from the analytic limits, corrected for defined process, calibration, and instrument
 
errors. The Allowable Values are then determined, based on
 
the trip setpoint values, by accounting for the calibration
 
based errors. These calibration based errors are limited to
 
reference accuracy, instrument drift, errors associated with
 
measurement and test equipment, and calibration tolerance of
 
loop components. The trip setpoints and Allowable Values
 
determined in this manner provide adequate protection
 
because instrument uncertainties, process effects, calibration tolerances, instrument drift, and severe
 
environment errors (for channels that must function in harsh
 
environments as defined by 10 CFR 50.49) are accounted for
 
and appropriately applied for the instrumentation.
 
The individual Functions are required to be OPERABLE in
 
MODE 1, and in MODES 2 and 3 with reactor steam dome
 
pressure > 150 psig, since this is when RCIC is required to
 
be OPERABLE. Refer to LCO 3.5.3 for Applicability Bases for
 
the RCIC System.
 
The specific Applicable Safety Analyses, LCO, and
 
Applicability discussions are listed below on a Function by
 
Function basis.
: 1. Reactor Vessel Water Level-Low Low, Level 2
 
Low reactor pressure vessel (RPV) water level indicates that
 
normal feedwater flow is insufficient to maintain reactor
 
vessel water level and that the capability to cool the fuel
 
may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, the RCIC System is
 
initiated at Level 2 to assist in maintaining water level
 
above the top of the active fuel.
(continued)
RCIC System Instrumentation B 3.3.5.2
 
LaSalle 1 and 2 B 3.3.5.2-4 Revision 0 BASES APPLICABLE 1. Reactor Vessel Water Level-Low Low, Level 2 SAFETY ANALYSES, (continued)
 
LCO, and APPLICABILITY Reactor Vessel Water Level-Low Low, Level 2 signals are initiated from four differential pressure transmitters that
 
sense the difference between the pressure due to a constant
 
column of water (reference leg) and the pressure due to the
 
actual water level (variable leg) in the vessel.
 
The Reactor Vessel Water Level-Low Low, Level 2 Allowable
 
Value is set high enough such that for complete loss of
 
feedwater flow, the RCIC System flow with high pressure core
 
spray assumed to fail will be sufficient to avoid initiation
 
of low pressure ECCS at Level 1.
 
Four channels of Reactor Vessel Water Level-Low Low, Level 2 Function are available and are required to be
 
OPERABLE when RCIC is required to be OPERABLE to ensure that
 
no single instrument failure can preclude RCIC initiation.
 
Refer to LCO 3.5.3 for RCIC Applicability Bases.
: 2. Reactor Vessel Water Level-High, Level 8
 
High RPV water level indicates that sufficient cooling water
 
inventory exists in the reactor vessel such that there is no
 
danger to the fuel. Therefore, the Level 8 signal is used
 
to close the RCIC turbine steam inlet isolation valve to
 
prevent overflow into the main steam lines (MSLs).  (The
 
injection valve also closes due to the closure of the RCIC
 
turbine steam inlet isolation valve.)
 
Reactor Vessel Water Level-High, Level 8 signals for RCIC
 
are initiated from two differential pressure transmitters
 
from the narrow range water level measurement
 
instrumentation, which sense the difference between the
 
pressure due to a constant column of water (reference leg)
 
and the pressure due to the actual water level (variable
 
leg) in the vessel.
 
The Reactor Vessel Water Level-High, Level 8 Allowable
 
Value is high enough to preclude isolating the injection
 
valve of the RCIC during normal operation, yet low enough to
 
trip the RCIC System prior to water overflowing into the
 
MSLs.
(continued)
RCIC System Instrumentation B 3.3.5.2
 
LaSalle 1 and 2 B 3.3.5.2-5 Revision 0 BASES APPLICABLE 2. Reactor Vessel Water Level-High, Level 8 (continued)
SAFETY ANALYSES, LCO, and Two channels of Reactor Vessel Water Level-High, Level 8 APPLICABILITY Function are available and are required to be OPERABLE when RCIC is required to be OPERABLE to ensure that no single
 
instrument failure can preclude RCIC initiation. Refer to
 
LCO 3.5.3 for RCIC Applicability Bases.
: 3. Condensate Storage Tank Level-Low
 
Low level in the CST indicates the unavailability of an
 
adequate supply of makeup water from this normal source.
 
Normally the suction valve between the RCIC pump and the CST
 
is open and, upon receiving a RCIC initiation signal, water
 
for RCIC injection would be taken from the CST. However, if
 
the water level in the CST falls below a preselected level, first the suppression pool suction valve automatically opens
 
and then the CST suction valve automatically closes. This
 
ensures that an adequate supply of makeup water is available
 
to the RCIC pump. To prevent losing suction to the pump, the suction valves are interlocked so that the suppression
 
pool suction valve must be open before the CST suction valve
 
automatically closes.
 
Two level switches are used to detect low water level in the
 
CST. The Condensate Storage Tank Level-Low Function
 
Allowable Value is set high enough to ensure adequate pump
 
suction head while water is being taken from the CST.
 
Two channels of Condensate Storage Tank Level-Low Function
 
are available and are required to be OPERABLE when RCIC is
 
required to be OPERABLE to ensure that no single instrument
 
failure can preclude RCIC swap to suppression pool source.
 
Refer to LCO 3.5.3 for RCIC Applicability Bases.
: 4. Manual Initiation
 
The Manual Initiation push button channel introduces a
 
signal into the RCIC System initiation logic that is
 
redundant to the automatic protective instrumentation and
 
provides manual initiation capability. There is one push
 
button channel for the RCIC System.
(continued)
RCIC System Instrumentation B 3.3.5.2
 
LaSalle 1 and 2 B 3.3.5.2-6 Revision 0 BASES APPLICABLE 4. Manual Initiation (continued)
SAFETY ANALYSES, LCO, and The Manual Initiation Function is not assumed in any APPLICABILITY accident or transient analyses in the UFSAR. However, the Function is retained for overall redundancy and diversity of
 
the RCIC function as required by the NRC in the plant
 
licensing basis.
 
There is no Allowable Value for this Function since the
 
channel is mechanically actuated based solely on the
 
position of the push button. One channel of Manual
 
Initiation is required to be OPERABLE when RCIC is required
 
to be OPERABLE. Refer to LCO 3.5.3 for RCIC Applicability
 
Bases.
ACTIONS A Note has been provided to modify the ACTIONS related to RCIC System instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been
 
entered, subsequent divisions, subsystems, components, or
 
variables expressed in the Condition discovered to be
 
inoperable or not within limits will not result in separate
 
entry into the Condition. Section 1.3 also specifies that
 
Required Actions of the Condition continue to apply for each
 
additional failure, with Completion Times based on initial
 
entry into the Condition. However, the Required Actions for
 
inoperable RCIC System instrumentation channels provide
 
appropriate compensatory measures for separate inoperable
 
channels. As such, a Note has been provided that allows
 
separate Condition entry for each inoperable RCIC System
 
instrumentation channel.
 
A.1 Required Action A.1 directs entry into the appropriate
 
Condition referenced in Table 3.3.5.2-1 in the accompanying
 
LCO. The applicable Condition referenced in the Table is
 
Function dependent. Each time a channel is discovered to be
 
inoperable, Condition A is entered for that channel and
 
provides for transfer to the appropriate subsequent
 
Condition.
(continued)
RCIC System Instrumentation B 3.3.5.2
 
LaSalle 1 and 2 B 3.3.5.2-7 Revision 0 BASES ACTIONS B.1 and B.2 (continued)
Required Action B.1 is intended to ensure that appropriate
 
actions are taken if multiple, inoperable, untripped
 
channels within the same Function result in a complete loss
 
of automatic initiation capability for the RCIC System. In
 
this case, automatic initiation capability is lost if two
 
Function 1 parallel contacts (channels) in the same trip
 
system are inoperable and untripped. In this situation (loss of automatic initiation capability), the 24 hour
 
allowance of Required Action B.2 is not appropriate, and the
 
RCIC System must be declared inoperable within 1 hour after
 
discovery of loss of RCIC initiation capability.
 
The Completion Time is intended to allow the operator time
 
to evaluate and repair any discovered inoperabilities. This
 
Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock."
For Required Action B.1, the Completion Time only begins
 
upon discovery that the RCIC System cannot be automatically
 
initiated due to two inoperable, untripped Reactor Vessel
 
Water Level-Low Low, Level 2 channels (parallel contacts) 
 
in the same trip system. The 1 hour Completion Time from
 
discovery of loss of initiation capability is acceptable
 
because it minimizes risk while allowing time for
 
restoration or tripping of channels.
 
Because of the redundancy of sensors available to provide
 
initiation signals and the fact that the RCIC System is not
 
credited in any accident or transient analysis, an allowable
 
out of service time of 24 hours has been shown to be
 
acceptable (Ref. 1) to permit restoration of any inoperable
 
channel to OPERABLE status. If the inoperable channel
 
cannot be restored to OPERABLE status within the allowable
 
out of service time, the channel must be placed in the
 
tripped condition per Required Action B.2. Placing the
 
inoperable channel in trip would conservatively compensate
 
for the inoperability, restore capability to accommodate a
 
single failure, and allow operation to continue. 
 
Alternately, if it is not desired to place the channel in
 
trip (e.g., as in the case where placing the inoperable
 
channel in trip would result in an initiation), Condition E
 
must be entered and its Required Action taken.
(continued)
RCIC System Instrumentation B 3.3.5.2
 
LaSalle 1 and 2 B 3.3.5.2-8 Revision 0 BASES  ACTIONS C.1 (continued)
A risk based analysis was performed and determined that an
 
allowable out of service time of 24 hours (Ref. 1) is
 
acceptable to permit restoration of any inoperable channel
 
to OPERABLE status (Required Action C.1). A Required Action (similar to Required Action B.1), limiting the allowable out
 
of service time if a loss of automatic RCIC initiation
 
capability exists, is not required. This Condition applies
 
to the Reactor Vessel Water Level-High, Level 8 Function, whose logic is arranged such that any inoperable channel
 
will result in a loss of automatic RCIC initiation (high
 
water level trip) capability. As stated above, this loss of
 
automatic RCIC initiation (high water level trip) capability
 
was analyzed and determined to be acceptable. This
 
Condition also applies to the Manual Initiation Function.
 
Since this Function is not assumed in any accident or
 
transient analysis, a total loss of manual initiation
 
capability (Required Action C.1) for 24 hours is allowed.
 
The Required Action does not allow placing a channel in trip
 
since this action would not necessarily result in the safe
 
state for the channel in all events.
 
D.1, D.2.1, and D.2.2
 
Required Action D.1 is intended to ensure that appropriate
 
actions are taken if multiple inoperable, untripped channels
 
within the same Function result in automatic component
 
initiation (RCIC source swapover) capability being lost for
 
the feature(s). For Required Action D.1, the RCIC System is
 
the only associated feature. In this case, automatic
 
component initiation (RCIC source swapover) capability is
 
lost if two Function 3 channels are inoperable and
 
untripped. In this situation (loss of automatic suction
 
swap), the 24 hour allowance of Required Actions D.2.1
 
and D.2.2 is not appropriate, and the RCIC System must be
 
declared inoperable within 1 hour from discovery of loss of
 
RCIC initiation capability. As noted, Required Action D.1
 
is only applicable if the RCIC pump suction is not aligned
 
to the suppression pool since, if aligned, the Function is
 
already performed.
(continued)
RCIC System Instrumentation B 3.3.5.2
 
LaSalle 1 and 2 B 3.3.5.2-9 Revision 0 BASES ACTIONS D.1, D.2.1, and D.2.2 (continued)
 
The Completion Time is intended to allow the operator time
 
to evaluate and repair any discovered inoperabilities. This
 
Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock."
For Required Action D.1, the Completion Time only begins
 
upon discovery that the RCIC System cannot be automatically
 
aligned to the suppression pool due to two inoperable, untripped channels in the same Function. The 1 hour
 
Completion Time from discovery of loss of initiation
 
capability is acceptable because it minimizes risk while
 
allowing time for restoration or tripping of channels.
 
Because of the redundancy of sensors available to provide
 
initiation signals and the fact that the RCIC System is not
 
assumed in any accident or transient analysis, an allowable
 
out of service time of 24 hours has been shown to be
 
acceptable (Ref. 1) to permit restoration of any inoperable
 
channel to OPERABLE status. If the inoperable channel
 
cannot be restored to OPERABLE status within the allowable
 
out of service time, the channel must be placed in the
 
tripped condition per Required Action D.2.1, which performs
 
the intended function of the channel (shifting the suction
 
source to the suppression pool). Alternatively, Required
 
Action D.2.2 allows the manual alignment of the RCIC suction
 
to the suppression pool, which also performs the intended
 
function. If Required Action D.2.1 or D.2.2 is performed, measures should be taken to ensure that the RCIC System
 
piping remains filled with water. If it is not desired to
 
perform Required Actions D.2.1 and D.2.2 (e.g., as in the
 
case where shifting the suction source could drain down the
 
RCIC suction piping), Condition E must be entered and its
 
Required Action taken.
 
E.1 With any Required Action and associated Completion Time not
 
met, the RCIC System may be incapable of performing the
 
intended function, and the RCIC System must be declared
 
inoperable immediately.
 
(continued)
RCIC System Instrumentation B 3.3.5.2
 
LaSalle 1 and 2 B 3.3.5.2-10 Revision 0 BASES  (continued)
 
SURVEILLANCE As noted in the beginning of the SRs, the SRs for each RCIC REQUIREMENTS System instrumentation Function are found in the SRs column of Table 3.3.5.2-1.
 
The Surveillances are modified by a Note to indicate that
 
when a channel is placed in an inoperable status solely for
 
performance of required Surveillances, entry into associated
 
Conditions and Required Actions may be delayed as follows: 
(a) for up to 6 hours for Functions 2 and 4; and (b) for up
 
to 6 hours for Functions 1 and 3 provided the associated
 
Function maintains RCIC initiation capability. Upon
 
completion of the Surveillance, or expiration of the 6 hour
 
allowance, the channel must be returned to OPERABLE status
 
or the applicable Condition entered and Required Actions
 
taken. This Note is based on the reliability analysis (Ref. 1) assumption of the average time required to perform
 
channel Surveillance. That analysis demonstrated that the
 
6 hour testing allowance does not significantly reduce the
 
probability that the RCIC will initiate when necessary.
 
SR  3.3.5.2.1
 
Performance of the CHANNEL CHECK once every 12 hours ensures
 
that a gross failure of instrumentation has not occurred. A
 
CHANNEL CHECK is normally a comparison of the parameter
 
indicated on one channel to a similar parameter on other
 
channels. It is based on the assumption that instrument
 
channels monitoring the same parameter should read
 
approximately the same value. Significant deviations
 
between the instrument channels could be an indication of
 
excessive instrument drift in one of the channels or
 
something even more serious. A CHANNEL CHECK will detect
 
gross channel failure; thus, it is key to verifying that the
 
instrumentation continues to operate properly between each
 
CHANNEL CALIBRATION.
 
Agreement criteria are determined by the plant staff based
 
on a combination of the channel instrument uncertainties, including indication and readability. If a channel is
 
outside the criteria, it may be an indication that the
 
instrument has drifted outside its limit.
(continued)
RCIC System Instrumentation B 3.3.5.2
 
LaSalle 1 and 2 B 3.3.5.2-11 Revision 0 BASES SURVEILLANCE SR  3.3.5.2.1 (continued)
REQUIREMENTS The Frequency is based upon operating experience that
 
demonstrates channel failure is rare. The CHANNEL CHECK
 
supplements less formal, but more frequent, checks of
 
channels during normal operational use of the displays
 
associated with the channels required by the LCO.
 
SR  3.3.5.2.2
 
A CHANNEL FUNCTIONAL TEST is performed on each required
 
channel to ensure that the channel will perform the intended
 
function. A successful test of the required contact(s) of a
 
channel relay may be performed by the verification of the
 
change of state of a single contact of the relay. This
 
clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a
 
relay. This is acceptable because all of the other required
 
contacts of the relay are verified by other Technical
 
Specifications and non-Technical Specifications tests at
 
least once per refueling interval with applicable
 
extensions. Any setpoint adjustment shall be  consistent
 
with the assumptions of the current plant specific setpoint
 
methodology.
 
The Frequency of 92 days is based on the reliability
 
analysis of Reference 1.
 
SR  3.3.5.2.3
 
CHANNEL CALIBRATION is a complete check of the instrument
 
loop and the sensor. This test verifies the channel
 
responds to the measured parameter with the necessary range
 
and accuracy. CHANNEL CALIBRATION leaves the channel
 
adjusted to account for instrument drifts between successive
 
calibrations consistent with the plant specific setpoint
 
methodology.
 
The Frequency is based on the assumption of a 24 month
 
calibration interval in the determination of the magnitude
 
of equipment drift in the setpoint analysis.
(continued)
RCIC System Instrumentation B 3.3.5.2
 
LaSalle 1 and 2 B 3.3.5.2-12 Revision 0 BASES SURVEILLANCE SR  3.3.5.2.4 REQUIREMENTS (continued) The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific
 
channel. The system functional testing performed in
 
LCO 3.5.3 overlaps this Surveillance to provide complete
 
testing of the safety function.
 
The 24 month Frequency is based on the need to perform this
 
Surveillance under the conditions that apply during a plant
 
outage and the potential for an unplanned transient if the
 
Surveillance were performed with the reactor at power. 
 
Operating experience has shown that these components usually
 
pass the Surveillance when performed at the 24 month
 
Frequency.
 
REFERENCES 1. GENE-770-06-2-A, "Addendum to Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service
 
Times for Selected Instrumentation Technical
 
Specifications," December 1992.
 
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-1 Revision 0 B 3.3  INSTRUMENTATION
 
B 3.3.6.1  Primary Containment Isolation Instrumentation
 
BASES
 
BACKGROUND The primary containment isolation instrumentation automatically initiates closure of appropriate primary
 
containment isolation valves (PCIVs). The function of the
 
PCIVs, in combination with other accident mitigation
 
systems, is to limit fission product release during and
 
following postulated Design Basis Accidents (DBAs). Primary
 
containment isolation within the time limits specified for
 
those isolation valves designed to close automatically
 
ensures that the release of radioactive material to the
 
environment will be consistent with the assumptions used in
 
the analyses for a DBA.
 
The isolation instrumentation includes the sensors, relays, and switches that are necessary to cause initiation of
 
primary containment and reactor coolant pressure boundary (RCPB) isolation. Most channels include electronic
 
equipment (e.g., trip units) that compares measured input
 
signals with pre-established setpoints. When the setpoint
 
is exceeded, the channel output relay actuates, which then
 
outputs a primary containment isolation signal to the
 
isolation logic. Functional diversity is provided by
 
monitoring a wide range of independent parameters. The
 
input parameters to the isolation logic are (a) reactor
 
vessel water level, (b) area and differential temperatures, (c) main steam line (MSL) flow measurement, (d) Standby
 
Liquid Control (SLC) System initiation, (e) condenser vacuum
 
loss, (f) main steam line pressure, (g) reactor core
 
isolation cooling (RCIC) steam line flow and time delay
 
relay, (h) reactor building ventilation exhaust plenum and
 
fuel pool ventilation exhaust radiation, (i) RCIC steam line
 
pressure, (j) RCIC turbine exhaust diaphragm pressure, (k) reactor water cleanup (RWCU) differential flow and time
 
delay relay, (l) reactor vessel pressure, and (m) drywell
 
pressure. Redundant sensor input signals are provided from
 
each such isolation initiation parameter. In addition, manual isolation of the logics is provided.
 
The primary containment isolation instrumentation has inputs
 
to the trip logic from the isolation Functions listed below.
(continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-2 Revision 0 BASES BACKGROUND 1. Main Steam Line Isolation (continued)
Most Main Steam Line Isolation Functions receive inputs from
 
four channels. One channel associated with each Function
 
inputs to one of four trip strings. Two trip strings make
 
up a trip system and both trip systems must actuate to cause
 
isolation of all main steam isolation valves (MSIVs). Any
 
channel will trip the associated trip string. Only one trip
 
string must trip to trip the associated trip system. The
 
trip strings are arranged in one-out-of-two taken twice
 
logic to initiate isolation of all MSIVs. The outputs from
 
the same channels are arranged into two two-out-of-two trip
 
systems to isolate all MSL drain valves. One two-out-of-two
 
trip system is associated with the inboard valves and the
 
other two-out-of-two trip system is associated with the
 
outboard valves.
 
One exception to this arrangement is the Main Steam Line
 
Flow-High Function. This Function uses 16 flow channels, four for each steam line. One channel from each steam line
 
inputs to one of four trip strings. Two trip strings make
 
up each trip system, and both trip systems must trip to
 
cause an MSL isolation. Each trip string has four inputs (one per MSL), any one of which will trip the trip string.
 
The trip strings are arranged in a one-out-of-two taken
 
twice logic. Therefore, this is effectively a
 
one-out-of-eight taken twice logic arrangement to initiate
 
isolation of the MSIVs. Similarly, the 16 flow channels are
 
connected into two two-out-of-two trip systems (effectively, two one-out-of-four twice logic), with one trip system
 
isolating the inboard MSL drain valves and the other two-
 
out-of-two trip system isolating the outboard MSL drain
 
valves.
 
The other exception to this arrangement is the Manual
 
Initiation Function. The MSIV manual isolation logic is
 
similar to the other MSIV isolation logic in that each trip
 
string is associated with a manual isolation pushbutton in a
 
one-out-of-two taken twice logic as described above.
 
However, the MSL drain isolation valves are isolated by a
 
single manual isolation pushbutton; the outboard MSL drain
 
isolation valves isolate from the B channel manual isolation
 
pushbutton and the inboard MSL drain valve isolates from the
 
D channel manual isolation pushbutton. The A and C channel
 
manual isolation pushbuttons only directly affect the manual 
 
(continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-3 Revision 0 BASES BACKGROUND 1. Main Steam Line Isolation (continued) isolation of the MSIVs. The same channel B and D manual
 
isolation pushbuttons are used for the logic of other Group
 
isolation valves.
 
MSL Isolation Functions isolate the Group 1 valves.
: 2. Primary Containment Isolation
 
Most Primary Containment Isolation Functions receive inputs
 
from four channels. The outputs from these channels are
 
arranged into two two-out-of-two trip systems. One trip
 
system initiates isolation of all automatic inboard PCIVs, while the other trip system initiates isolation of all
 
automatic outboard PCIVs. Each trip system closes one of
 
the two valves on each penetration with automatic isolation
 
so that operation of either trip system isolates the
 
penetration. An exception to this arrangement are the
 
Traversing In-core Probe (TIP) System valve/drives. For
 
these valves and drive mechanisms, only one trip system (the
 
inboard valve system) is provided. When the trip system
 
actuates, the drive mechanisms withdraw the TIPs and, when
 
the TIPs are fully withdrawn, the ball valves close. This
 
exception to the arrangement, which has been previously
 
approved by the NRC as part of the issuance of the Operating
 
Licenses, is described in UFSAR Table 6.2-21 (Ref. 1).
 
Reactor Vessel Water Level-Low, Level 3 isolates the Group 7
 
valves. Reactor Vessel Water Level-Low Low, Level 2
 
isolates the Group 2, 3, and 4 valves. Reactor Vessel Water
 
Level-Low Low Low, Level 1 isolates the Group 10 valves.
 
Drywell Pressure-High isolates the Group 2, 4, 7, and 10
 
valves. Reactor Building Ventilation Exhaust Plenum
 
Radiation-High isolates the Group 4 valves. Fuel Pool
 
Ventilation Exhaust Radiation-High isolates the Group 4
 
valves. Manual Initiation Functions isolate the Group 2, 4, 7, and 10 valves.
: 3. Reactor Core Isolation Cooling System Isolation
 
Most Functions receive input from two channels, with each
 
channel in one trip system using one-out-of-one logic. One
 
of the two trip systems is connected to the inboard steam (continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-4 Revision 0 BASES BACKGROUND 3. Reactor Core Isolation Cooling System Isolation (continued)
 
valves and the other trip system is connected to the
 
outboard steam valve on the RCIC penetration so that
 
operation of either trip system isolates the penetration.
 
Two exceptions to this arrangement are the RCIC Steam Supply
 
Pressure-Low and RCIC Turbine Exhaust Diaphragm
 
Pressure-High Functions. These Functions receive input
 
from four steam supply pressure channels and four turbine
 
exhaust diaphragm pressure channels, respectively. The
 
outputs from these channels are connected into two
 
two-out-of-two trip systems, each trip system isolating the
 
inboard or outboard RCIC steam valves. In addition, the
 
RCIC System Isolation Manual Initiation Function has only
 
one channel, which isolates the outboard RCIC steam valve
 
only (provided an automatic initiation signal is present).
 
One additional exception involves the Drywell Pressure-High
 
Function and the RCIC Steam Supply Pressure-Low Functions.
 
The Drywell Pressure-High Function does not provide an
 
isolation to the inboard and outboard RCIC steam valves (Group 8 valves). The logic is arranged such that RCIC
 
Steam Supply Pressure-Low coincident with Drywell
 
Pressure-High isolates the Group 9 valves. The Drywell
 
Pressure-High Function receives inputs from four drywell
 
pressure channels. The outputs from these channels are
 
connected into two one-out-of-two trip systems with
 
coincident RCIC Steam Supply Pressure also connected into
 
the same trip systems arranged in a similar manner (one-out-
 
of-two). One of the two trip systems is connected to the
 
inboard RCIC turbine exhaust vacuum breaker line isolation
 
valve and the other trip system is connected to the outboard
 
RCIC turbine exhaust vacuum breaker line isolation valve (Group 9 valves).
 
RCIC System Isolation Functions isolate the Group 8 and 9
 
valves.
: 4. Reactor Water Cleanup System Isolation
 
Most Functions receive input from two channels with each
 
channel in one trip system using one-out-of-one logic.
 
Functions 4.c, 4.d, 4.e and 4.f (RWCU Heat Exchanger Area
 
Temperature-High, RWCU Heat Exchanger Area Ventilation
 
Differential Temperature-High, RWCU Pump and Valve Area (continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-5 Revision 0 BASES BACKGROUND 4. Reactor Water Cleanup System Isolation (continued)
 
Temperature-High, and RWCU Pump and Valve Area Ventilation
 
Differential Temperature-High, respectively) have one
 
channel in each trip system in each area for a total of four
 
channels per Function, for Functions 4.c and 4.d and a total
 
of six channels per Function for Functions 4.e and 4.f, but
 
the logic is the same (one-out-of-one per area). Each of
 
the two trip systems is connected to one of the two valves
 
on the RWCU penetration so that operation of either trip
 
system isolates the penetration. The exceptions to this
 
arrangement are the Reactor Vessel Water Level-Low Low, Level 2 and the SLC System Initiation Functions. The
 
Reactor Vessel Water Level-Low Low, Level 2 Function
 
receives input from four reactor vessel water level
 
channels. The outputs from the reactor vessel water level
 
channels are connected into two two-out-of-two trip systems, each trip system isolating one of the two RWCU valves. The
 
Standby Liquid Control (SLC) System initiation has two
 
channels, one from each SLC pump start circuit, in a single
 
trip system. The two channels are connected in a one-out-
 
of-two logic. This trip system isolates the RWCU inlet
 
outboard valve.
 
RWCU Isolation Functions isolate the Group 5 valves.
: 5. RHR Shutdown Cooling System Isolation
 
The Shutdown Cooling Isolation Function receives input
 
signals from instrumentation for the Reactor Vessel Water
 
Level-Low, Level 3, Reactor Vessel Pressure-High, and
 
Manual Initiation Functions. The Reactor Vessel Water
 
Level-Low Function receives input from four channels while
 
the Reactor Vessel Pressure-High Function receives input
 
from two channels. The outputs from the Reactor Vessel
 
Water Level-Low channels are connected into two
 
two-out-of-two trip systems. The Reactor Vessel
 
Pressure-High Function is arranged into two one-out-of-one
 
trip systems. The Manual Initiation Function uses two
 
channels, one for each trip system.
(continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-6 Revision 0 BASES BACKGROUND 5. Shutdown Cooling System Isolation (continued)
 
One of the two trip systems is connected to the outboard
 
valve associated with the reactor vessel head spray
 
injection penetration, the shutdown cooling return
 
penetration, and the shutdown cooling suction penetration
 
while the other trip system is connected to the inboard
 
valves on the shutdown cooling suction penetration and the
 
shutdown cooling return check valve bypasses. 
 
The RHR Shutdown Cooling Isolation Functions isolate the
 
Group 6 valves.
 
APPLICABLE The isolation signals generated by the primary containment SAFETY ANALYSES, isolation instrumentation are implicitly assumed in the LCO, and safety analyses of References 2 and 3 to initiate closure of APPLICABILITY valves to limit offsite doses. Refer to LCO 3.6.1.3, "Primary Containment Isolation Valves (PCIVs)," Applicable
 
Safety Analyses Bases, for more detail.
 
Primary containment isolation instrumentation satisfies
 
Criterion 3 of 10 CFR 50.36(c)(2)(ii). Certain
 
instrumentation Functions are retained for other reasons and
 
are described below in the individual Functions discussion.
 
The OPERABILITY of the primary containment instrumentation
 
is dependent on the OPERABILITY of the individual
 
instrumentation channel Functions specified in
 
Table 3.3.6.1-1. Each Function must have a required number
 
of OPERABLE channels, with their setpoints within the
 
specified Allowable Values, where appropriate. The actual
 
setpoint is calibrated consistent with applicable setpoint
 
methodology assumptions. Each channel must also respond
 
within its assumed response time, where appropriate.
 
Allowable Values are specified for each Primary Containment
 
Isolation Function specified in the Table. Nominal trip
 
setpoints are specified in the setpoint calculations. The
 
nominal setpoints are selected to ensure that the setpoints
 
do not exceed the Allowable Value between CHANNEL
 
CALIBRATIONS. Operation with a trip setpoint less
 
conservative than the nominal trip setpoint, but within its
 
Allowable Value, is acceptable. A channel is inoperable if
 
its actual trip setpoint is not within its required (continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-7 Revision 0 BASES APPLICABLE Allowable Value. Trip setpoints are those predetermined SAFETY ANALYSES, values of output at which an action should take place. The LCO, and setpoints are compared to the actual process parameter APPLICABILITY (e.g., reactor vessel water level), and when the measured (continued) output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The
 
analytic limits are derived from the limiting values of the
 
process parameters obtained from the safety analysis. The
 
trip setpoints are determined from the analytic limits, corrected for defined process, calibration, and instrument
 
errors. The Allowable Values are then determined, based on
 
the trip setpoint values, by accounting for the calibration
 
based errors. These calibration based errors are limited to
 
reference accuracy, instrument drift, errors associated with
 
measurement and test equipment, and calibration tolerance of
 
loop components. The trip setpoints and Allowable Values
 
determined in this manner provide adequate protection
 
because instrument uncertainties, process effects, calibration tolerances, instrument drift, and severe
 
environment errors (for channels that must function in harsh
 
environments as defined by 10 CFR 50.49) are accounted for
 
and appropriately applied for the instrumentation.
 
Certain Emergency Core Cooling Systems (ECCS) and RCIC
 
valves (e.g., minimum flow) also serve the dual function of
 
automatic PCIVs. The signals that isolate these valves are
 
also associated with the automatic initiation of the ECCS
 
and RCIC. Some instrumentation and ACTIONS associated with
 
these signals are addressed in LCO 3.3.5.1, "ECCS
 
Instrumentation," and LCO 3.3.5.2, "RCIC System
 
Instrumentation," and are not included in this LCO.
 
In general, the individual Functions are required to be
 
OPERABLE in MODES 1, 2, and 3 consistent with the
 
Applicability for LCO 3.6.1.1, "Primary Containment."
Functions that have different Applicabilities are discussed
 
below in the individual Functions discussion.
 
The specific Applicable Safety Analyses, LCO, and
 
Applicability discussions are listed below on a Function by
 
Function basis.
(continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-8 Revision 0 BASES APPLICABLE 1. Main Steam Line Isolation SAFETY ANALYSES, LCO, and 1.a. Reactor Vessel Water Level-Low Low Low, Level 1 APPLICABILITY (continued) Low reactor pressure vessel (RPV) water level indicates that the capability to cool the fuel may be threatened. Should
 
RPV water level decrease too far, fuel damage could result.
 
Therefore, isolation of the MSIVs and other interfaces with
 
the reactor vessel occurs to prevent offsite dose limits
 
from being exceeded. The Reactor Vessel Water Level-Low
 
Low Low, Level 1 Function is one of the many Functions
 
assumed to be OPERABLE and capable of providing isolation
 
signals. The Reactor Vessel Water Level-Low Low Low, Level 1 Function associated with isolation is assumed in the
 
analysis of the recirculation line break (Ref. 2). The
 
isolation of the MSL on Level 1 supports actions to ensure
 
that offsite dose limits are not exceeded for a DBA.
 
Reactor vessel water level signals are initiated from four
 
differential pressure transmitters that sense the difference
 
between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water
 
level (variable leg) in the vessel. Four channels of
 
Reactor Vessel Water Level-Low Low Low, Level 1 Function
 
are available and are required to be OPERABLE to ensure that
 
no single instrument failure can preclude the isolation
 
function.
 
The Reactor Vessel Water Level-Low Low Low, Level 1
 
Allowable Value is chosen to be the same as the ECCS Level 1
 
Allowable Value (LCO 3.3.5.1) to ensure that the MSLs
 
isolate on a potential loss of coolant accident (LOCA) to
 
prevent offsite doses from exceeding 10 CFR 100 limits.
 
This Function isolates the Group 1 valves.
 
1.b. Main Steam Line Pressure-Low
 
Low MSL pressure indicates that there may be a problem with
 
the turbine pressure regulation, which could result in a low
 
reactor vessel water level condition and the RPV cooling
 
down more than 100
&deg;F/hour if the pressure loss is allowed to continue. The Main Steam Line Pressure-Low Function is
 
directly assumed in the analysis of the pressure regulator
 
failure event (Ref. 4). The closure of the MSIVs ensures (continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-9 Revision 0 BASES APPLICABLE 1.b. Main Steam Line Pressure-Low (continued)
SAFETY ANALYSES, LCO, and that the RPV temperature change limit (100
&deg;F/hour) is not APPLICABILITY reached. In addition, this Function supports actions to ensure that Safety Limit 2.1.1.1 is not exceeded.  (This
 
Function closes the MSIVs prior to pressure decreasing below
 
785 psig, which results in a scram due to MSIV closure, thus
 
reducing reactor power to < 25% RTP.)
 
The MSL low pressure signals are initiated from four
 
pressure switches that are connected downstream of the MSL
 
header prior to each main turbine stop valve. The pressure
 
switches are arranged such that, even though physically
 
separated from each other, each switch is able to detect low
 
MSL pressure. Four channels of Main Steam Line
 
Pressure-Low Function are available and are required to be
 
OPERABLE to ensure that no single instrument failure can
 
preclude the isolation function.
 
The Allowable Value was selected to be high enough to
 
prevent excessive RPV depressurization.
 
The Main Steam Line Pressure-Low Function is only required
 
to be OPERABLE in MODE 1 since this is when the assumed
 
transient can occur (Ref. 4).
 
This Function isolates the Group 1 valves.
 
1.c. Main Steam Line Flow-High
 
Main Steam Line Flow-High is provided to detect a break of
 
the MSL and to initiate closure of the MSIVs. If the steam
 
were allowed to continue flowing out of the break, the
 
reactor would depressurize and the core could uncover. If
 
the RPV water level decreases too far, fuel damage could
 
occur. Therefore, the isolation is initiated on high flow
 
to prevent or minimize core damage. The Main Steam Line
 
Flow-High Function is directly assumed in the analysis of
 
the main steam line break (MSLB) accident (Ref. 5). The
 
isolation action, along with the scram function of the RPS, ensures that the fuel peak cladding temperature remains
 
below the limits of 10 CFR 50.46 and offsite doses do not
 
exceed the 10 CFR 100 limits.
(continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-10 Revision 0 BASES APPLICABLE 1.c. Main Steam Line Flow-High (continued)
SAFETY ANALYSES, LCO, and The MSL flow signals are initiated from 16 differential APPLICABILITY pressure switches that are connected to the four MSLs (the differential pressure switches sense differential pressure
 
across a flow element). The switches are arranged such
 
that, even though physically separated from each other, all
 
four connected to one steam line would be able to detect the
 
high flow. Four channels of Main Steam Line Flow-High
 
Function for each MSL (two channels per trip system) are
 
available and are required to be OPERABLE so that no single
 
instrument failure will preclude detecting a break in any
 
individual MSL.
 
The Allowable Value is chosen to ensure that offsite dose
 
limits are not exceeded due to the break.
 
This Function isolates the Group 1 valves.
 
1.d. Condenser Vacuum-Low
 
The Condenser Vacuum-Low Function is provided to prevent
 
overpressurization of the main condenser in the event of a
 
loss of the main condenser vacuum (Ref. 6). Since the
 
integrity of the condenser is an assumption in offsite dose
 
calculations (Ref. 7), the Condenser Vacuum-Low Function is
 
assumed to be OPERABLE and capable of initiating closure of
 
the MSIVs. The closure of the MSIVs is initiated to prevent
 
the addition of steam that would lead to additional
 
condenser pressurization and possible rupture of the
 
diaphragm installed to protect the turbine exhaust hood, thereby preventing a potential radiation leakage path
 
following an accident.
 
Condenser vacuum pressure signals are derived from four
 
pressure switches that sense the pressure in the condenser.
 
Four channels of Condenser Vacuum-Low Function are
 
available and are required to be OPERABLE to ensure no
 
single instrument failure can preclude the isolation
 
function.
(continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-11 Revision 0 BASES APPLICABLE 1.d. Condenser Vacuum-Low (continued)
SAFETY ANALYSES, LCO, and The Allowable Value is chosen to prevent damage to the APPLICABILITY condenser due to pressurization, thereby ensuring its integrity for offsite dose analysis. As noted (footnote (a)
 
to Table 3.3.6.1-1), the channels are not required to be
 
OPERABLE in MODES 2 and 3, when all turbine stop valves (TSVs) are closed, since the potential for condenser
 
overpressurization is minimized. Switches are provided to
 
manually bypass the channels when all TSVs are closed.
 
This Function isolates the Group 1 valves.
 
1.e  Main Steam Line Tunnel Differential Temperature-High
 
Differential Temperature-High is provided to detect a leak
 
in a main steam line, and provides diversity to the high
 
flow instrumentation. The isolation occurs when a very
 
small leak has occurred. If the small leak is allowed to
 
continue without isolation, offsite dose limits may be
 
reached. However, credit for these instruments is not taken
 
in any transient or accident analysis in the UFSAR, since
 
bounding analyses are performed for large breaks such as
 
MSLBs.
 
Eight thermocouples provide input to the Main Steam Line
 
Tunnel Differential Temperature-High Function. The output
 
of these thermocouples is used to determine the differential
 
temperature. Each channel consists of a differential
 
temperature instrument that receives inputs from
 
thermocouples that are located in the inlet and outlet of
 
the main steam line tunnel for a total of four available
 
channels. Four channels of Main Steam Line Tunnel
 
Differential Temperature-High Function are available and
 
are required to be OPERABLE to ensure that no single
 
instrument failure can preclude the isolation function. 
 
The differential temperature monitoring Allowable Value is
 
chosen to detect a leak equivalent to 100 gpm.
 
These Functions isolate the Group 1 valves.
(continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-12 Revision 0 BASES APPLICABLE 1.f. Manual Initiation SAFETY ANALYSES, LCO, and The Manual Initiation push button channels introduce signals APPLICABILITY into the MSL isolation logic that are redundant to the (continued) automatic protective instrumentation and provide manual isolation capability. There is no specific UFSAR safety
 
analysis that takes credit for this Function. It is
 
retained for overall redundancy and diversity of the
 
isolation function as required by the NRC in the plant
 
licensing basis.
 
There are four push buttons for the logic, with two manual
 
initiation push buttons per trip system. Four channels of
 
Manual Initiation Function are available and are required to
 
be OPERABLE in MODES 1, 2, and 3, since these are the MODES
 
in which the MSL Isolation automatic Functions are required
 
to be OPERABLE. 
 
There is no Allowable Value for this Function since the
 
channels are mechanically actuated based solely on the
 
position of the push buttons.
 
This Function isolates the Group 1 valves.
: 2. Primary Containment Isolation
 
2.a  Reactor Vessel Water Level-Low Low, Level 2
 
Low RPV water level indicates the capability to cool the
 
fuel may be threatened. The valves whose penetrations
 
communicate with the primary containment are isolated to
 
limit the release of fission products. The isolation of the
 
primary containment on Level 2 supports actions to ensure
 
that offsite dose limits of 10 CFR 100 are not exceeded.
 
The Reactor Vessel Water Level-Low Low, Level 2 Function
 
associated with isolation is implicitly assumed in the UFSAR
 
analysis as these leakage paths are assumed to be isolated
 
post LOCA.
 
Reactor Vessel Water Level-Low Low, Level 2 signals are
 
initiated from differential pressure transmitters that sense
 
the difference between the pressure due to a constant column
 
of water (reference leg) and the pressure due to the actual (continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-13 Revision 0 BASES APPLICABLE 2.a  Reactor Vessel Water Level-Low Low, Level 2 SAFETY ANALYSES, (continued)
 
LCO, and APPLICABILITY water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level-Low Low, Level 2 Function are
 
available and are required to be OPERABLE to ensure no
 
single instrument failure can preclude the isolation
 
function.
 
The Reactor Vessel Water Level-Low Low, Level 2 Allowable
 
Value was chosen to be the same as the ECCS Reactor Vessel
 
Water Level-Low Low, Level 2 Allowable Value (LCO 3.3.5.1),
since isolation of these valves is not critical to orderly
 
plant shutdown.
 
This Function isolates the Group 2, 3, and 4 valves.
 
2.b  Drywell Pressure-High
 
High drywell pressure can indicate a break in the RCPB
 
inside the drywell. The isolation of some of the PCIVs on
 
high drywell pressure supports actions to ensure that
 
offsite dose limits of 10 CFR 100 are not exceeded. The
 
Drywell Pressure-High Function associated with isolation of
 
the primary containment is implicitly assumed in the UFSAR
 
accident analysis as these leakage paths are assumed to be
 
isolated post LOCA.
 
High drywell pressure signals are initiated from pressure
 
switches that sense the pressure in the drywell. Four
 
channels of Drywell Pressure-High Function are available
 
and are required to be OPERABLE to ensure that no single
 
instrument failure can preclude the isolation function.
 
The Allowable Value was selected to be the same as the RPS
 
Drywell Pressure-High Allowable Value (LCO 3.3.1.1), since
 
this may be indicative of a LOCA inside primary containment.
 
This Function isolates the Group 2, 4, 7, and 10 valves.
(continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-14 Revision 0 BASES APPLICABLE 2.c. Reactor Building Ventilation Exhaust Plenum SAFETY ANALYSES, Radiation-High LCO, and APPLICABILITY High ventilation exhaust radiation is an indication of (continued) possible gross failure of the fuel cladding. The release may have originated from the primary containment due to a
 
break in the RCPB or refueling floor due to a fuel handling
 
accident. When Reactor Building Ventilation Exhaust
 
Radiation-High is detected, valves whose penetrations
 
communicate with the primary containment atmosphere are
 
isolated to limit the release of fission products.
 
The Reactor Building Ventilation Exhaust Plenum
 
Radiation-High signals are initiated from radiation
 
detectors that are located in the reactor building return
 
air riser above the upper area of the steam tunnel prior to
 
the reactor building ventilation isolation dampers. The
 
signal from each detector is input to an individual monitor
 
whose trip outputs are assigned to an isolation channel. 
 
Four channels of Reactor Building Ventilation Exhaust Plenum
 
Radiation-High Function are available and are required to
 
be OPERABLE to ensure that no single instrument failure can
 
preclude the isolation function.
 
The Allowable Values are chosen to promptly detect gross
 
failure of the fuel cladding and to ensure offsite doses
 
remain below 10 CFR 20 and 10 CFR 100 limits.
 
These Functions isolate the Group 4 valves.
 
2.d. Fuel Pool Ventilation Exhaust Radiation-High
 
High fuel pool ventilation exhaust radiation indicates
 
increased airborne radioactivity levels in secondary
 
containment refuel floor area which could be due to fission
 
gases from the fuel pool resulting from a refueling
 
accident. Since the primary and secondary containments may
 
be in communication, the vent and purge valves for primary
 
containment isolation are also provided with an isolation
 
signal. Therefore, Fuel Pool Ventilation Exhaust
 
Radiation-High Function initiates an isolation to assure
 
timely closure of valves to protect against substantial
 
releases of radioactive materials to the environment. While
 
this Function is identified as initiating the Standby Gas
 
Treatment System for a spent fuel cask drop accident (continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-15 Revision 0 BASES APPLICABLE 2.d. Fuel Pool Ventilation Exhaust Radiation-High SAFETY ANALYSES, (continued)
 
LCO, and APPLICABILITY (Ref. 3), it is not assumed in any limiting accident or transient analysis in the UFSAR because other leakage paths (e.g., MSIVs) are more limiting.
 
The fuel pool ventilation exhaust radiation signals are
 
initiated from radiation detectors located in the reactor
 
building exhaust ducting coming from the refuel floor. The
 
signal from each detector is input to an individual monitor
 
whose trip output is assigned to an isolation channel. Four
 
channels of Fuel Pool Ventilation Exhaust Radiation-High
 
Function are available and are required to be OPERABLE to
 
ensure that no single instrument failure can preclude the
 
isolation function.
 
The Allowable Value is chosen to be the same as the Fuel
 
Pool Ventilation Exhaust Radiation-High Function (LCO
 
3.3.6.2, "Secondary Containment Isolation Instrumentation")
 
to provide a conservative isolation of this potential
 
release path during this abnormal condition of increased
 
airborne radioactivity.
 
This Function isolates the Group 4 valves.
 
2.e. Reactor Vessel Water Level-Low Low Low, Level 1
 
Low RPV water level indicates the capability to cool the
 
fuel may be threatened. Should RPV water level decrease too
 
far, fuel damage could result. Therefore, isolation of the
 
primary containment occurs to prevent offsite dose limits
 
from being exceeded. The Reactor Vessel Water Level-Low
 
Low Low, Level 1 Function is one of the many Functions
 
assumed to be OPERABLE and capable of providing isolation
 
signals. The Reactor Vessel Water Level-Low Low Low, Level 1 Function associated with isolation is implicitly
 
assumed in the UFSAR analysis as these leakage paths are
 
assumed to be isolated post LOCA.
 
Reactor vessel water level signals are initiated from level
 
transmitters that sense the difference between the pressure
 
due to a constant column of water (reference leg) and the
 
pressure due to the actual water level (variable leg) in the
 
vessel. Four channels of Reactor Vessel Water Level-Low (continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-16 Revision 0 BASES APPLICABLE 2.e. Reactor Vessel Water Level-Low Low Low, Level 1 SAFETY ANALYSES, (continued)
 
LCO, and APPLICABILITY Low Low, Level 1 Function are available and are required to be OPERABLE to ensure that no single instrument failure can
 
preclude the isolation function.
 
The Reactor Vessel Water Level-Low Low Low, Level 1
 
Allowable Value is chosen to be the same as the ECCS Reactor
 
Vessel Water Level-Low Low Low, Level 1 Allowable Value (LCO 3.3.5.1) to ensure the valves are isolated to prevent
 
offsite doses from exceeding 10 CFR 100 limits.
 
This Function isolates the Group 10 valves.
 
2.f. Reactor Vessel Water Level-Low, Level 3
 
Low RPV water level indicates the capability to cool the
 
fuel may be threatened. Should RPV water level decrease too
 
far, fuel damage could result. Therefore, the valves whose
 
penetrations communicate with the primary containment are
 
isolated to limit the release of fission products. The
 
isolation of the primary containment on Level 3 supports
 
actions to ensure that offsite dose limits of 10 CFR 100 are
 
not exceeded. The Reactor Vessel Water Level-Low, Level 3
 
Function associated with isolation is implicitly assumed in
 
the UFSAR analysis as these leakage paths are assumed to be
 
isolated post LOCA.
 
Reactor Vessel Water Level-Low, Level 3 signals are
 
initiated from differential pressure transmitters that sense
 
the difference between the pressure due to a constant column
 
of water (reference leg) and the pressure due to the actual
 
water level (variable leg) in the vessel. Four channels of
 
the Reactor Vessel Water Level-Low, Level 3 Function are
 
available and are required to be OPERABLE to ensure that no
 
single instrument failure can preclude the isolation
 
function.
 
The Reactor Vessel Water Level-Low, Level 3 Allowable Value
 
was chosen to be the same as the RPS Reactor Vessel Water
 
Level-Low, Level 3 Allowable Value (LCO 3.3.1.1) since the
 
capability to cool the fuel may be threatened.
 
This Function isolates the Group 7 valves.
(continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-17 Revision 0 BASES APPLICABLE 2.g. Manual Initiation SAFETY ANALYSES, LCO, and The Manual Initiation push button channels introduce signals APPLICABILITY into the primary containment isolation logic that are (continued) redundant to the automatic protective instrumentation and provide manual isolation capability. There is no specific
 
UFSAR safety analysis that takes credit for this Function.
 
It is retained for overall redundancy and diversity of the
 
isolation function as required by the NRC in the plant
 
licensing basis.
 
There are two push buttons for the logic, one manual
 
initiation push button per trip system. Two channels of the
 
Manual Initiation Function are available and are required to
 
be OPERABLE in MODES 1, 2, and 3, since these are the MODES
 
in which the Primary Containment Isolation automatic
 
Functions are required to be OPERABLE.
 
There is no Allowable Value for this Function since the
 
channels are mechanically actuated based solely on the
 
position of the push buttons. 
 
This Function isolates the Group 2, 4, 7, and 10 valves.
: 3. Reactor Core Isolation Cooling System Isolation
 
3.a. RCIC Steam Line Flow-High
 
RCIC Steam Line Flow-High Function is provided to detect a
 
break of the RCIC steam lines and initiates closure of the
 
steam line isolation valves. If the steam is allowed to
 
continue flowing out of the break, the reactor will
 
depressurize and core uncovery can occur. Therefore, the
 
isolation is initiated on high flow to prevent or minimize
 
core damage. The isolation action, along with the scram
 
function of the Reactor Protection System (RPS), ensures
 
that the fuel peak cladding temperature remains below the
 
limits of 10 CFR 50.46. Specific credit for this Function
 
is not assumed in any UFSAR accident analyses since the
 
bounding analysis is performed for large breaks such as
 
recirculation and MSL breaks. However, these instruments
 
prevent the RCIC steam line break from becoming bounding.
(continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-18 Revision 0 BASES APPLICABLE 3.a. RCIC Steam Line Flow-High (continued)
SAFETY ANALYSES, LCO, and The RCIC Steam Line Flow-High signals are initiated from APPLICABILITY two differential pressure switches that are connected to the system steam lines. Two channels of RCIC Steam Line
 
Flow-High Functions are available and are required to be
 
OPERABLE to ensure that no single instrument failure can
 
preclude the isolation function.
 
The Allowable Value is chosen to be low enough to ensure
 
that the trip occurs to prevent fuel damage and maintains
 
the MSLB event as the bounding event.
 
This Function isolates the Group 8 valves.
 
3.b. RCIC Steam Line Flow-Timer
 
The RCIC Steam Line Flow-Timer is provided to prevent false
 
isolations on RCIC Steam Line Flow-High during system
 
startup transients and therefore improves system
 
reliability. This Function is not assumed in any UFSAR
 
transient or accident analyses since the bounding analysis
 
is performed for large breaks such as recirculation and MSL
 
breaks. However, these instruments prevent the RCIC steam
 
line break from being bounding.
 
The RCIC Steam Line Flow-Timer Function delays the RCIC
 
Steam Line Flow-High signals by use of time delay relays.
 
When an RCIC Steam Line Flow-High signal is generated, the
 
time delay relays delay the tripping of the associated RCIC
 
isolation trip system for a short time. Two channels of
 
RCIC Steam Line Flow-Timer Function are available and are
 
required to be OPERABLE to ensure that no single instrument
 
failure can preclude the isolation function.
 
The Allowable Value was chosen to be long enough to prevent
 
false isolations due to system starts but not so long as to
 
impact offsite dose calculations.
 
This Function isolates the Group 8 valves.
(continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-19 Revision 0 BASES APPLICABLE 3.c. RCIC Steam Supply Pressure-Low SAFETY ANALYSES, LCO, and Low RCIC steam supply pressure indicates that the pressure APPLICABILITY of the steam in the RCIC turbine may be too low to continue (continued) operation of the RCIC turbine. This isolation is for equipment protection and is not assumed in any transient or
 
accident analysis in the UFSAR. However, it also provides a
 
diverse signal to indicate a possible system break. These
 
instruments are included in the Technical Specifications (TS) because of the potential for risk due to possible
 
failure of the instruments preventing RCIC initiations.
 
Therefore, they meet Criterion 4 of 10 CFR 50.36(c)(2)(ii).
 
The RCIC Steam Supply Pressure-Low signals are initiated
 
from four pressure switches that are connected to the RCIC
 
steam line. Four channels of RCIC Steam Supply
 
Pressure-Low Function are available and are required to be
 
OPERABLE to ensure that no single instrument failure can
 
preclude the isolation function.
 
The Allowable Value is selected to be high enough to prevent
 
damage to the RCIC turbines.
 
This Function isolates the Group 8 valves. This Function
 
coincident with Drywell Pressure-High also isolates the
 
Group 9 valves.
 
3.d. RCIC Turbine Exhaust Diaphragm Pressure-High
 
High turbine exhaust diaphragm pressure indicates that the
 
pressure may be too high to continue operation of the RCIC
 
turbine. That is, one of two exhaust diaphragms has
 
ruptured and pressure is reaching turbine casing pressure
 
limits. This isolation is for equipment protection and is
 
not assumed in any transient or accident analysis in the
 
UFSAR. These instruments are included in the TS because of
 
the potential for risk due to possible failure of the
 
instruments preventing RCIC initiations. Therefore, they
 
meet Criterion 4 of 10 CFR 50.36(c)(2)(ii).
 
The RCIC Turbine Exhaust Diaphragm Pressure-High signals
 
are initiated from four pressure switches that are connected
 
to the area between the rupture diaphragms on the RCIC
 
turbine exhaust line. Four channels of RCIC Turbine Exhaust (continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-20 Revision 0 BASES APPLICABLE 3.d. RCIC Turbine Exhaust Diaphragm Pressure-High SAFETY ANALYSES, (continued)
 
LCO, and APPLICABILITY Diaphragm Pressure-High Function are available and are required to be OPERABLE to ensure that no single instrument
 
failure can preclude the isolation function.
 
The Allowable Value is selected to be low enough to prevent
 
damage to the RCIC turbine.
 
This Function isolates the Group 8 valves.
 
3.e, 3.f, 3.g, 3.h. Area and Differential Temperature-High
 
Area and Differential Temperatures are provided to detect a
 
leak from the RCIC steam piping. The isolation occurs when
 
a very small leak has occurred and is diverse to the high
 
flow instrumentation. If the small leak is allowed to
 
continue without isolation, offsite dose limits may be
 
reached. These Functions are not assumed in any UFSAR
 
transient or accident analysis, since bounding analyses are
 
performed for large breaks such as recirculation or MSL
 
breaks.
 
Area Temperature-High signals are initiated from
 
thermocouples that are located in the area that is being
 
monitored. Two instruments monitor each area. Four
 
channels for Area Temperature-High Function are available
 
and are required to be OPERABLE to ensure that no single
 
instrument failure can preclude the isolation function.
 
There are two for the RCIC equipment room and two for the
 
RCIC steam line tunnel area.
 
There are 8 thermocouples (four for the RCIC equipment room
 
and four for the RCIC steam line tunnel area) that provide
 
input to the Differential Temperature-High Function. The
 
output of these thermocouples is used to determine the
 
differential temperature. Each channel consists of a
 
differential temperature instrument that receives inputs
 
from thermocouples that are located in the inlet and outlet
 
of the area cooling system for a total of four (two for the
 
RCIC equipment room and two for the RCIC steam line tunnel
 
area) available channels.
(continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-21 Revision 0 BASES APPLICABLE 3.e, 3.f, 3.g, 3.h. Area and Differential Temperature-High SAFETY ANALYSES, (continued)
LCO, and APPLICABILITY The Allowable Values are set low enough to detect a leak equivalent to 25 gpm.
 
This Function isolates the Group 8 valves.
 
3.i. Drywell Pressure-High
 
High drywell pressure can indicate a break in the RCPB. The
 
RCIC isolation of the turbine exhaust is provided to prevent
 
communication with the drywell when high drywell pressure
 
exists. A potential leakage path exists via the turbine
 
exhaust. The isolation is delayed until the system becomes
 
unavailable for injection (i.e., low steam line pressure).
 
The isolation of the RCIC turbine exhaust by Drywell
 
Pressure-High is indirectly assumed in the UFSAR accident
 
analysis because the turbine exhaust leakage path is not
 
assumed to contribute to offsite doses.
 
High drywell pressure signals are initiated from pressure
 
switches that sense the pressure in the drywell. Four
 
channels of RCIC Drywell Pressure-High Function are
 
available and are required to be OPERABLE to ensure that no
 
single instrument failure can preclude the isolation
 
function.
 
The Allowable Value was selected to be the same as the ECCS
 
Drywell Pressure-High Allowable Value (LCO 3.3.5.1), since
 
this is indicative of a LOCA inside primary containment.
 
This Function coincident with RCIC Steam Supply
 
Pressure-Low isolates the Group 9 valves. 
 
3.j. Manual Initiation
 
The Manual Initiation push button channel introduces a
 
signal into the RCIC System isolation logic that is
 
redundant to the automatic protective instrumentation and
 
provides manual isolation capability when a system
 
initiation signal is present. There is no specific UFSAR
 
safety analysis that takes credit for this Function. It is 
 
                                                                  (continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-22 Revision 0 BASES APPLICABLE 3.j. Manual Initiation (continued)
SAFETY ANALYSES, LCO, and retained for overall redundancy and diversity of the APPLICABILITY isolation function as required by the NRC in the plant licensing basis.
 
There is one push button for RCIC. One channel of Manual
 
Initiation Function is available and is required to be
 
OPERABLE in MODES 1, 2, and 3 since these are the MODES in
 
which the RCIC System Isolation automatic Functions are
 
required to be OPERABLE. As noted (footnote (b) to Table
 
3.3.6.1-1), this Function only provides input into one of
 
the two trip systems. 
 
There is no Allowable Value for this Function since the
 
channels are mechanically actuated based solely on the
 
position of the push buttons.
 
This Function, coincident with a Reactor Vessel Water
 
Level-Low Low, Level 2, isolates the outboard Group 8
 
valve. 
: 4. Reactor Water Cleanup System Isolation
 
4.a. Differential Flow-High
 
The high differential flow signal is provided to detect a
 
break in the RWCU System. This will detect leaks in the
 
RWCU System when area or differential temperature would not
 
provide detection (i.e., a cold leg break). Should the
 
reactor coolant continue to flow out of the break, offsite
 
dose limits may be exceeded. Therefore, isolation of the
 
RWCU System is initiated when high differential flow is
 
sensed to prevent exceeding offsite doses. A time delay (Function 4.b, described below) is provided to prevent
 
spurious trips during most RWCU operational transients.
 
This Function is not assumed in any UFSAR transient or
 
accident analysis, since bounding analyses are performed for
 
large breaks such as MSLBs.
 
The high differential flow signals are initiated from one
 
differential pressure transmitter monitoring inlet flow (from the reactor vessel) and two transmitters monitoring
 
system outlet flow to the two available flow paths (normal
 
return to feedwater and discharge flow to either the main (continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-23 Revision 0 BASES APPLICABLE 4.a. Differential Flow-High (continued)
SAFETY ANALYSES, LCO, and condenser or radwaste). The outputs of the transmitters are APPLICABILITY compared (in a summer) and the outputs are sent to two alarm trip units. If the difference between the inlet and outlet
 
flow is too large, each alarm trip unit generates an
 
isolation signal. Two channels of Differential Flow-High
 
Function are available and are required to be OPERABLE to
 
ensure that no single instrument failure (other than the
 
common transmitters and summers) can preclude the isolation
 
function.
 
The Differential Flow-High Allowable Value ensures that the
 
break of the RWCU piping is detected.
 
This Function isolates the Group 5 valves.
 
4.b. Differential Flow-Timer
 
The Differential Flow-Timer is provided to avoid RWCU
 
System isolations due to operational transients (such as
 
pump starts and mode changes). During these transients the
 
inlet and return flows become unbalanced for short time
 
periods and Differential Flow-High will be sensed without
 
an RWCU System break being present. Credit for this
 
Function is not assumed in the UFSAR accident or transient
 
analysis, since bounding analyses are performed for large
 
breaks such as MSLBs.
 
The Differential Flow-Timer Function delays the
 
Differential Flow-High signals by use of time delay relays.
 
When a Differential Flow-High signal is generated, the time
 
delay relays delay the tripping of the associated RWCU
 
isolation trip system for a short time. Two channels of
 
Differential Flow-Timer Function are available and are
 
required to be OPERABLE to ensure that no single instrument
 
failure can preclude the isolation function.
 
The Differential Flow-Timer Allowable Value is selected to
 
ensure that the MSLB outside containment remains the
 
limiting break for UFSAR analysis for offsite dose
 
calculations.
 
This Function isolates the Group 5 valves.
(continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-24 Revision 0 BASES APPLICABLE 4.c, 4.d, 4.e, 4.f, 4.g, 4.h. 4.i, 4.j, Area SAFETY ANALYSES, Differential Temperature-High LCO, and APPLICABILITY Area and Differential Temperature-High is provided to (continued) detect a leak from the RWCU System. The isolation occurs even when very small leaks have occurred and is diverse to
 
the high differential flow instrumentation for the hot
 
portions of the RWCU System. If the small leak continues
 
without isolation, offsite dose limits may be reached.
 
Credit for these instruments is not taken in any transient
 
or accident analysis in the UFSAR, since bounding analyses
 
are performed for large breaks such as MSLBs.
 
Area Temperature-High signals are initiated from
 
temperature elements that are located in the room that is
 
being monitored. There are fourteen thermocouples that
 
provide input to the Area Temperature-High Function (two
 
per area). Fourteen channels are required to be OPERABLE to
 
ensure that no single instrument failure can preclude the
 
isolation function. There are four channels for the RWCU
 
heat exchanger area (two in each heat exchanger room), six
 
channels for the RWCU pump and valve room (two in each of
 
the three rooms), two channels for the holdup pipe area, and
 
two channels for the filter/demineralizer valve room area.
 
There are twenty eight thermocouples that provide input to
 
the Differential Temperature-High Function. The output of
 
these thermocouples is used to determine the differential
 
temperature. Each channel consists of a differential
 
temperature instrument that receives inputs from
 
thermocouples that are located in the inlet and outlet of
 
the area cooling system for a total of fourteen available
 
channels (two per area). Fourteen channels are required to
 
be OPERABLE to ensure that no single instrument failure can
 
preclude the isolation function. There are four channels
 
for the RWCU heat exchanger area, six channels for the RWCU
 
pump and valve room, two channels for the holdup pipe area, and two for the filter/demineralizer valve room area.
 
The Area and Differential Temperature-High Allowable Values
 
are set low enough to detect a leak equivalent to 25 gpm.
 
These Functions isolate the Group 5 valves.
(continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-25 Revision 0 BASES APPLICABLE 4.k. Reactor Vessel Water Level-Low Low, Level 2 SAFETY ANALYSES, LCO, and Low RPV water level indicates the capability to cool the APPLICABILITY fuel may be threatened. Should RPV water level decrease too (continued) far, fuel damage could result. Therefore, isolation of some reactor vessel interfaces occurs to isolate the potential
 
sources of a break. The isolation of the RWCU System on
 
Level 2 supports actions to ensure that fuel peak cladding
 
temperature remains below the limits of 10 CFR 50.46. The
 
Reactor Vessel Water Level-Low Low, Level 2 Function
 
associated with RWCU isolation is not directly assumed in
 
any transient or accident analysis, since bounding analyses
 
are performed for large breaks such as MSLBs.
 
Reactor Vessel Water Level-Low Low, Level 2 signals are
 
initiated from differential pressure transmitters that sense
 
the difference between the pressure due to a constant column
 
of water (reference leg) and the pressure due to the actual
 
water level (variable leg) in the vessel. Four channels of
 
Reactor Vessel Water Level-Low Low, Level 2 Function are
 
available and are required to be OPERABLE to ensure that no
 
single instrument failure can preclude the isolation
 
function.
 
The Reactor Vessel Water Level-Low Low, Level 2 Allowable
 
Value was chosen to be the same as the ECCS Reactor Vessel
 
Water Level-Low Low, Level 2 Allowable Value (LCO 3.3.5.1),
since the capability to cool the fuel may be threatened.
 
This Function isolates the Group 5 valves.
 
4.l. SLC System Initiation
 
The isolation of the RWCU System is required when the SLC
 
System has been initiated to prevent dilution and removal of
 
the boron solution by the RWCU System (Ref. 8). SLC System
 
initiation signals are initiated from the two SLC pump start
 
signals.
 
Two channels (one from each pump) of SLC System Initiation
 
Function are available and are required to be OPERABLE only
 
in MODES 1 and 2, since these are the only MODES where the
 
reactor can be critical, and these MODES are consistent with
 
the Applicability for the SLC System (LCO 3.1.7, "SLC (continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-26 Revision 0 BASES APPLICABLE 4.l. SLC System Initiation (continued)
SAFETY ANALYSES, LCO, and System"). As noted (footnote (b) to Table 3.3.6.1-1), this APPLICABILITY Function only provides input into one of two trip systems.
 
There is no Allowable Value associated with this Function
 
since the channels are mechanically actuated based solely on
 
the position of the SLC System initiation switches.
 
This Function isolates the outboard Group 5 valve.
 
4.m. Manual Initiation
 
The Manual Initiation push button channels introduce signals
 
into the RWCU System isolation logic that are redundant to
 
the automatic protective instrumentation and provide manual
 
isolation capability. There is no specific UFSAR safety
 
analysis that takes credit for this Function. It is
 
retained for overall redundancy and diversity of the
 
isolation function as required by the NRC in the plant
 
licensing basis.
 
There are two push buttons for the logic, one manual
 
initiation push button per trip system. Two channels of the
 
Manual Initiation Function are available and are required to
 
be OPERABLE in MODES 1, 2, and 3 since these are the MODES
 
in which the RWCU System Isolation automatic Functions are
 
required to be OPERABLE.
 
There is no Allowable Value for this Function, since the
 
channels are mechanically actuated based solely on the
 
position of the push buttons.
 
This Function isolates the Group 5 valves.
: 5. RHR Shutdown Cooling System Isolation
 
5.a. Reactor Vessel Water Level-Low, Level 3
 
Low RPV water level indicates the capability to cool the
 
fuel may be threatened. Should RPV water level decrease too
 
far, fuel damage could result. Therefore, isolation of some
 
reactor vessel interfaces occurs to begin isolating the
 
potential sources of a break. The Reactor Vessel Water (continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-27 Revision 0 BASES APPLICABLE 5.a. Reactor Vessel Water Level-Low, Level 3 (continued)
SAFETY ANALYSES, LCO, and Level-Low, Level 3 Function associated with RHR Shutdown APPLICABILITY Cooling System isolation is not directly assumed in any transient or accident analysis, since bounding analyses are
 
performed for large breaks such as MSLBs. The RHR Shutdown
 
Cooling System isolation on Level 3 supports actions to
 
ensure that the RPV water level does not drop below the top
 
of the active fuel during a vessel draindown event caused by
 
a leak (e.g., pipe break or inadvertent valve opening) in
 
the RHR Shutdown Cooling System.
 
Reactor Vessel Water Level-Low, Level 3 signals are
 
initiated from differential pressure transmitters that sense
 
the difference between the pressure due to a constant column
 
of water (reference leg) and the pressure due to the actual
 
water level (variable leg) in the vessel. Four channels (two channels per trip system) of the Reactor Vessel Water
 
Level-Low, Level 3 Function are available and are required
 
to be OPERABLE to ensure that no single instrument failure
 
can preclude the isolation function. As noted (footnote (c)
 
to Table 3.3.6.1-1), only one trip system is required to be
 
OPERABLE in MODES 4 and 5 provided the RHR Shutdown Cooling
 
System integrity is maintained. System integrity is
 
maintained provided the piping is intact and no maintenance
 
is being performed that has the potential for draining the
 
reactor vessel through the system.
 
The Reactor Vessel Water Level-Low, Level 3 Function is
 
only required to be OPERABLE in MODES 3, 4, and 5 to prevent
 
this potential flow path from lowering reactor vessel level
 
to the top of the fuel. In MODES 1 and 2, the Reactor
 
Vessel Pressure-High Function and administrative controls
 
ensure that this flow path remains isolated to prevent
 
unexpected loss of inventory via this flow path.
 
The Reactor Vessel Water Level-Low, Level 3 Allowable Value
 
was chosen to be the same as the RPS Reactor Vessel Water
 
Level-Low, Level 3 Allowable Value (LCO 3.3.1.1) since the
 
capability to cool the fuel may be threatened.
 
This Function isolates the Group 6 valves.
(continued)
 
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-28 Revision 0 BASES APPLICABLE 5.b. Reactor Vessel Pressure-High SAFETY ANALYSES, LCO, and The Shutdown Cooling System Reactor Vessel Pressure-High APPLICABILITY Function is provided to isolate the shutdown cooling portion (continued) of the RHR System. This interlock is provided only for equipment protection to prevent an intersystem LOCA scenario
 
and credit for the interlock is not assumed in the accident
 
or transient analysis in the UFSAR.
 
The Reactor Vessel Pressure-High signals are initiated from
 
two pressure switches. Two channels of Reactor Vessel
 
Pressure-High Function are available and are required to be
 
OPERABLE to ensure that no single instrument failure can
 
preclude the isolation function. 
 
The Allowable Value (corrected for cold water head and
 
reactor vessel flooded) was chosen to be low enough to
 
protect the system equipment from overpressurization.
 
This Function isolates the Group 6 valves.
 
5.c. Manual Initiation
 
The Manual Initiation push button channels introduce signals
 
into the RHR Shutdown Cooling System isolation logic that
 
are redundant to the automatic protective instrumentation
 
and provide manual isolation capability. There is no
 
specific UFSAR safety analysis that takes credit for this
 
Function. It is retained for overall redundancy and
 
diversity of the isolation function as required by the NRC
 
in the plant licensing basis.
 
There is one push button for the logic per trip system. Two
 
channels of the Manual Initiation Function are available and
 
are required to be OPERABLE in MODES 1, 2, and 3 since these
 
are the MODES in which the RHR Shutdown Cooling System
 
Isolation automatic Functions are required to be OPERABLE.
 
While certain automatic Functions are required in MODES 4
 
and 5, the Manual Initiation Function is not required in
 
MODES 4 and 5, since there are other means (i.e., means
 
other than the Manual Initiation push buttons) to manually
 
isolate the RHR Shutdown Cooling System from the control
 
room.  (continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-29 Revision 0 BASES APPLICABLE 5.c. Manual Initiation (continued)
SAFETY ANALYSES, LCO, and There is no Allowable Value for this Function, since the APPLICABILITY channels are mechanically actuated based solely on the position of the push buttons.
 
This Function isolates the Group 6 valves.
 
ACTIONS Note 1 has been provided to modify the ACTIONS related to primary containment isolation instrumentation channels.
 
Section 1.3, Completion Times, specifies that once a
 
Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the
 
Condition discovered to be inoperable or not within limits
 
will not result in separate entry into the Condition.
 
Section 1.3 also specifies that Required Actions of the
 
Condition continue to apply for each additional failure, with Completion Times based on initial entry into the
 
Condition. However, the Required Actions for inoperable
 
primary containment isolation instrumentation channels
 
provide appropriate compensatory measures for separate
 
inoperable channels. As such, a Note has been provided that
 
allows separate Condition entry for each inoperable primary
 
containment isolation instrumentation channel.
 
Note 2 indicates that when automatic isolation capability is
 
lost for Function 1.e, Main Steam Line Tunnel Differential
 
Temperature-High (i.e., when both trip systems are
 
inoperable for Function 1.e) due to required Reactor
 
Building Ventilation System corrective maintenance, filter
 
changes, damper cycling, or for performance of required
 
Surveillances, entry into the associated Conditions and
 
Required Actions may be delayed for up to 4 hours.
 
Similarly, Note 3 indicates that when automatic isolation
 
capability is lost for Function 1.e due to a loss of reactor
 
building ventilation or for performance of SR 3.6.4.1.3 or
 
SR 3.6.4.1.4, entry into the associated Conditions and
 
Required Actions may be delayed for up to 12 hours. Upon
 
completion of the activities or expiration of the time
 
allowance, the channels must be returned to OPERABLE status
 
or the applicable Conditions entered and Required Actions
 
taken. These Notes are necessary so that testing and (continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-30 Revision 0 BASES ACTIONS required Surveillances specified in LCO 3.6.4.1, "Secondary (continued) Containment," LCO 3.6.4.2, "Secondary Containment Isolation Valves (SCIV)," and LCO 3.6.4.3,  "Standby Gas Treatment (SGT) System," can be performed without inducing an
 
isolation of the MSIVs. The 4 hour and 12 hour allowances
 
provide sufficient time to safely perform the testing. The
 
12 hour allowance also provides sufficient time to identify
 
and correct minor reactor building  ventilation system
 
problems. Since the design of the Unit 1 and Unit 2 reactor
 
buildings is such that they share a common area of the
 
refuel floor (i.e., the reactor buildings are not separated
 
on the refuel floor), operation of either unit's ventilation
 
system will affect the other unit's building differential
 
pressure. Performance of testing to verify secondary
 
containment integrity requirements and minor correctable
 
problems could require a dual unit outage (without the
 
Notes).
 
A.1 Because of the diversity of sensors available to provide
 
isolation signals and the redundancy of the isolation
 
design, an allowable out of service time of 12 hours or
 
24 hours, depending on the Function (12 hours for those
 
Functions that have channel components common to RPS
 
instrumentation and 24 hours for those Functions that do not
 
have channel components common to RPS instrumentation), has
 
been shown to be acceptable (Refs. 9 and 10) to permit
 
restoration of any inoperable channel to OPERABLE status.
 
This out of service time is only acceptable provided the
 
associated Function is still maintaining isolation
 
capability (refer to Required Action B.1 Bases). If the
 
inoperable channel cannot be restored to OPERABLE status
 
within the allowable out of service time, the channel must
 
be placed in the tripped condition per Required Action A.1.
 
Placing the inoperable channel in trip would conservatively
 
compensate for the inoperability, restore capability to
 
accommodate a single failure, and allow operation to
 
continue with no further restrictions. Alternately, if it
 
is not desired to place the channel in trip (e.g., as in the
 
case where placing the inoperable channel in trip would
 
result in an isolation), Condition C must be entered and its
 
Required Action taken.
(continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-31 Revision 0 BASES ACTIONS B.1 (continued)
Required Action B.1 is intended to ensure that appropriate
 
actions are taken if multiple, inoperable, untripped
 
channels within the same Function result in redundant
 
automatic isolation capability being lost for the associated
 
penetration flow path(s). The MSIVs portion of the MSL
 
isolation Functions are considered to be maintaining
 
isolation capability when sufficient channels are OPERABLE
 
or in trip such that both trip systems will generate a trip
 
signal from the given Function on a valid signal. The MSL
 
drain valves portion of the MSL isolation Functions and the
 
other isolation Functions are considered to be maintaining
 
isolation capability when sufficient channels are OPERABLE
 
or in trip such that one trip system will generate a trip
 
signal from the given Function on a valid signal. This
 
ensures that one of the two PCIVs in the associated
 
penetration flow path can receive an isolation signal from
 
the given Function. For the MSIVs portion of Functions 1.a, 1.b, 1.d, and 1.e, this would require both trip systems to
 
have one channel OPERABLE or in trip. For the MSL drain
 
valves portion of Functions 1.a, 1.b, 1.d, and 1.e, this
 
would require one trip system to have two channels, each
 
OPERABLE or in trip. For the MSIVs portion of Function 1.c, this would require both trip systems to have one channel, associated with each MSL, OPERABLE or in trip. For the MSL
 
drain valves portion of Function 1.c, this would require one
 
trip system to have two channels, associated with each MSL, each OPERABLE or in trip. For Functions 2.a, 2.b, 2.c, 2.d, 2.e, 2.f, 3.c (for Group 8 valves) 3.d, 4.k, and 5.a, this
 
would require one trip system to have two channels, each
 
OPERABLE or in trip. For Functions 3.a, 3.b, 3.c (for Group
 
9 valves), 3.e, 3.f, 3.g, 3.h, 3.i, 4.a, 4.b, 4.g, 4.h, 4.i, 4.j, 4.l, and 5.b, this would require one trip system to
 
have one channel OPERABLE or in trip. For Functions 4.c, 4.d, 4.e, and 4.f each Function consists of channels that
 
monitor several different areas. Therefore, this would
 
require one channel per area to be OPERABLE or in trip (the
 
channels are not required to be in the same trip system).
 
The Condition does not include the Manual Initiation
 
Functions (Functions 1.f, 2.g, 3.j, 4.m, and 5.c), since
 
they are not assumed in any accident or transient analysis.
 
Thus, a total loss of manual initiation capability for
 
24 hours (as allowed by Required Action A.1) is allowed.
(continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-32 Revision 0 BASES ACTIONS B.1 (continued)
 
The Completion Time is intended to allow the operator time
 
to evaluate and repair any discovered inoperabilities. The
 
Completion Time is acceptable because it minimizes risk
 
while allowing time for restoration or tripping of channels.
 
C.1 Required Action C.1 directs entry into the appropriate
 
Condition referenced in Table 3.3.6.1-1. The applicable
 
Condition specified in Table 3.3.6.1-1 is Function and MODE
 
or other specified condition dependent and may change as the
 
Required Action of a previous Condition is completed. Each
 
time an inoperable channel has not met any Required Action
 
of Condition A or B and the associated Completion Time has
 
expired, Condition C will be entered for that channel and
 
provides for transfer to the appropriate subsequent
 
Condition.
 
D.1, D.2.1, and D.2.2
 
If the channel is not restored to OPERABLE status or placed
 
in trip within the allowed Completion Time, the associated
 
MSLs may be isolated (Required Action D.1), and if allowed (i.e., plant safety analysis allows operation with an MSL
 
isolated), plant operation with the MSL isolated may
 
continue. Isolating the affected MSL accomplishes the
 
safety function of the inoperable channel. This Required
 
Action will generally only be used if a Function 1.c channel
 
is inoperable and untripped. The associated MSL(s) to be
 
isolated are those whose Main Steam Line Flow-High Function
 
channel(s) are inoperable. Alternatively, the plant must be
 
placed in a MODE or other specified condition in which the
 
LCO does not apply. This is done by placing the plant in at
 
least MODE 3 within 12 hours and in MODE 4 within 36 hours (Required Actions D.2.1 and D.2.2). The Completion Times
 
are reasonable, based on operating experience, to reach the
 
required plant conditions from full power conditions in an
 
orderly manner and without challenging plant systems.
(continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-33 Revision 0 BASES ACTIONS E.1 (continued)
If the channel is not restored to OPERABLE status or placed
 
in trip within the allowed Completion Time, the plant must
 
be placed in a MODE or other specified condition in which
 
the LCO does not apply. This is done by placing the plant
 
in at least MODE 2 within 6 hours.
 
The allowed Completion Time of 6 hours is reasonable, based
 
on operating experience, to reach MODE 2 from full power
 
conditions in an orderly manner and without challenging
 
plant systems.
 
F.1 If the channel is not restored to OPERABLE status or placed
 
in trip within the allowed Completion Time, plant operation
 
may continue if the affected penetration flow path(s) is
 
isolated. Isolating the affected penetration flow path(s)
 
accomplishes the safety function of the inoperable channels.
 
For some of the Area and Differential Temperature-High
 
Functions, the affected penetration flow path(s) may be
 
considered isolated by isolating only that portion of the
 
system in the associated room monitored by the inoperable
 
channel. That is, if the RWCU pump room A Area
 
Temperature-High channel is inoperable, the A pump room
 
area can be isolated while allowing continued RWCU operation
 
utilizing the B RWCU pump.
 
Alternatively, if it is not desired to isolate the affected
 
penetration flow path(s) (e.g., as in the case where
 
isolating the penetration flow path(s) could result in a
 
reactor scram), Condition H must be entered and its Required
 
Actions taken.
 
The Completion Time is acceptable because it minimizes risk
 
while allowing sufficient time for plant operations
 
personnel to isolate the affected penetration flow path(s).
(continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-34 Revision 0 BASES ACTIONS G.1 (continued)
If the channel is not restored to OPERABLE status or placed
 
in trip within the allowed Completion Time, plant operations
 
may continue if the affected penetration flow path(s) is
 
isolated. Isolating the affected penetration flow path(s)
 
accomplishes the safety function of the inoperable channels.
 
The 24 hour Completion Time is acceptable due to the fact
 
that these Functions (Manual Initiation) are not assumed in
 
any accident or transient analysis in the UFSAR.
 
Alternately, if it is not desired to isolate the affected
 
penetration flow path(s) (e.g., as in the case where
 
isolating the penetration flow path(s) could result in a
 
reactor scram), Condition H must be entered and its Required
 
Actions taken.
 
H.1 and H.2
 
If the channel is not restored to OPERABLE status or placed
 
in trip, or any Required Action of Condition F or G is not
 
met and the associated Completion Time has expired, the
 
plant must be placed in a MODE or other specified condition
 
in which the LCO does not apply. This is done by placing
 
the plant in at least MODE 3 within 12 hours and in MODE 4
 
within 36 hours. The allowed Completion Times are
 
reasonable, based on operating experience, to reach the
 
required plant conditions from full power conditions in an
 
orderly manner and without challenging plant systems.
 
I.1 and I.2
 
If the channel is not restored to OPERABLE status within the
 
allowed Completion Time, the associated SLC subsystem(s) is
 
declared inoperable or the RWCU System is isolated. Since
 
this Function is required to ensure that the SLC System
 
performs its intended function, sufficient remedial measures
 
are provided by declaring the associated SLC subsystem
 
inoperable or isolating the RWCU System.
 
The Completion Time of 1 hour is acceptable because it
 
minimizes risk while allowing sufficient time for personnel
 
to isolate the RWCU System.
(continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-35 Revision 0 BASES ACTIONS J.1 and J.2 (continued)
If the channel is not restored to OPERABLE status or placed
 
in trip within the allowed Completion Time, the associated
 
penetration flow path should be closed. However, if the
 
shutdown cooling function is needed to provide core cooling, these Required Actions allow the penetration flow path to
 
remain unisolated provided action is immediately initiated
 
to restore the channel to OPERABLE status or to isolate the
 
RHR Shutdown Cooling System (i.e., provide alternate decay
 
heat removal capabilities so the penetration flow path can
 
be isolated). ACTIONS must continue until the channel is
 
restored to OPERABLE status or the RHR Shutdown Cooling
 
System is isolated.
 
SURVEILLANCE As noted at the beginning of the SRs, the SRs for each REQUIREMENTS Primary Containment Isolation Instrumentation Function are found in the SRs column of Table 3.3.6.1-1.
 
The Surveillances are also modified by a Note to indicate
 
that when a channel is placed in an inoperable status solely
 
for performance of required Surveillances, entry into
 
associated Conditions and Required Actions may be delayed
 
for up to 6 hours provided the associated Function maintains
 
isolation capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be
 
returned to OPERABLE status or the applicable Condition
 
entered and Required Actions taken. This Note is based on
 
the reliability analyses (Refs. 9 and 10) assumption of the
 
average time required to perform channel surveillance. That
 
analysis demonstrated that the 6 hour testing allowance does
 
not significantly reduce the probability that the PCIVs will
 
isolate the penetration flow path(s) when necessary.
 
SR  3.3.6.1.1
 
Performance of the CHANNEL CHECK once every 12 hours ensures
 
that a gross failure of instrumentation has not occurred. A
 
CHANNEL CHECK is normally a comparison of the parameter
 
indicated on one channel to a similar parameter on other
 
channels. It is based on the assumption that instrument
 
channels monitoring the same parameter should read (continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-36 Revision 0 BASES SURVEILLANCE SR  3.3.6.1.1 (continued)
REQUIREMENTS approximately the same value. Significant deviations
 
between the instrument channels could be an indication of
 
excessive instrument drift in one of the channels or
 
something even more serious. A CHANNEL CHECK will detect
 
gross channel failure; thus, it is key to verifying the
 
instrumentation continues to operate properly between each
 
CHANNEL CALIBRATION.
 
Agreement criteria are determined by the plant staff, based
 
on a combination of the channel instrument uncertainties, including indication and readability. If a channel is
 
outside the criteria, it may be an indication that the
 
instrument has drifted outside its limit.
 
The Frequency is based on operating experience that
 
demonstrates channel failure is rare. The CHANNEL CHECK
 
supplements less formal, but more frequent, checks of
 
channels during normal operational use of the displays
 
associated with the channels required by the LCO.
 
SR  3.3.6.1.2
 
A CHANNEL FUNCTIONAL TEST is performed on each required
 
channel to ensure that the channel will perform the intended
 
function. A successful test of the required contact(s) of a
 
channel relay may be performed by the verification of the
 
change of state of a single contact of the relay. This
 
clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a
 
relay. This is acceptable because all of the other required
 
contacts of the relay are verified by other Technical
 
Specifications and non-Technical Specifications tests at
 
least once per refueling interval with applicable
 
extensions. Any setpoint adjustment shall be consistent
 
with the assumptions of the current plant specific setpoint
 
methodology.
 
The Frequency of 92 days is based on reliability analyses
 
described in References 9 and 10.
(continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-37 Revision 0 BASES SURVEILLANCE SR  3.3.6.1.3 and SR  3.3.6.1.4 REQUIREMENTS (continued) CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel
 
responds to the measured parameter within the necessary
 
range and accuracy. CHANNEL CALIBRATION leaves the channel
 
adjusted to account for instrument drifts between successive
 
calibrations, consistent with the plant specific setpoint
 
methodology.
 
The Frequencies are based on the assumption of a 92 day or
 
24 month calibration interval, as applicable, in the
 
determination of the magnitude of equipment drift in the
 
setpoint analysis.
 
SR  3.3.6.1.5
 
The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the
 
OPERABILITY of the required isolation logic for a specific
 
channel. The system functional testing performed on PCIVs
 
in LCO 3.6.1.3 overlaps this Surveillance to provide
 
complete testing of the assumed safety function. The
 
24 month Frequency is based on the need to perform this
 
Surveillance under the conditions that apply during a plant
 
outage and the potential for an unplanned transient if the
 
Surveillance were performed with the reactor at power.
 
Operating experience has shown these components usually pass
 
the Surveillance when performed at the 24 month Frequency.
 
SR  3.3.6.1.6
 
This SR ensures that the individual channel response times
 
are less than or equal to the maximum values assumed in the
 
accident analysis. Testing is performed only on channels
 
where the assumed response time does not correspond to the
 
diesel generator (DG) start time. For channels assumed to
 
respond within the DG start time, sufficient margin exists
 
in the 13 second start time when compared to the typical
 
channel response time (milliseconds) so as to assure
 
adequate response without a specific measurement test. The
 
instrument response times must be added to the MSIV closure
 
times to obtain the ISOLATION SYSTEM RESPONSE TIME. 
 
However, failure to meet the ISOLATION SYSTEM RESPONSE TIME (continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-38 Revision 15 BASES SURVEILLANCE SR  3.3.6.1.6 (continued)
REQUIREMENTS due to a MSIV closure time not within limits does not
 
require the associated instrumentation to be declared
 
inoperable; only the MSIV is required to be declared
 
inoperable.
 
ISOLATION SYSTEM RESPONSE TIME acceptance criteria are
 
included in Reference 11.
 
ISOLATION SYSTEM RESPONSE TIME may be verified by actual
 
response time measurements in any series of sequential, overlapping, or total channel measurements. However, the
 
sensor for Function  1.c is allowed to be excluded from specific ISOLATION SYSTEM RESPONSE TIME measurement if the
 
conditions of Reference 12 are satisfied. If these
 
conditions are satisfied, sensor response time may be
 
allocated based on either assumed design sensor response
 
time or the manufacturer's stated design response time. 
 
When the requirements of Reference 12 are not satisfied, sensor response time must be measured. Also, regardless of
 
whether or not the sensor response time is measured, the
 
response time of the remaining portion of the channel, including the trip unit and relay logic, is required to be
 
measured. The sensor and relay/logic components for Functions 1.a and 1.b are assumed to operate at the design response time and therefore, are excluded from specific RPS RESPONSE TIME measurement. This allowance is supported by References 12 and 13, which determined that significant degradation of the channel response time can be detected during performance of other Technical Specification surveillance requirements.
 
ISOLATION SYSTEM RESPONSE TIME tests are conducted on a
 
24 month STAGGERED TEST BASIS. The 24 month test Frequency
 
is consistent with the refueling cycle and is based upon
 
plant operating experience that shows that random failures
 
of instrumentation components causing serious response time
 
degradation, but not channel failure, are infrequent.
 
REFERENCES 1. UFSAR, Table 6.2-21.
: 2. UFSAR, Section 6.2.1.1.
: 3. UFSAR, Chapter 15.
: 4. UFSAR, Section 15.1.3. (continued)
Primary Containment Isolation Instrumentation B 3.3.6.1
 
LaSalle 1 and 2 B 3.3.6.1-39 Revision 15 BASES REFERENCES 5. UFSAR, Section 15.6.4.
 
  (continued) 6. UFSAR, Section 15.2.5
: 7. UFSAR, Section 15.4.9.
: 8. UFSAR, Section 9.3.5.
: 9. NEDC-31677-P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation,"
July 1990.
: 10. NEDC-30851-P-A, Supplement 2, "Technical Specifications Improvement Analysis for BWR Isolation
 
Instrumentation Common to RPS and ECCS
 
Instrumentation," March 1989.
: 11. Technical Requirements Manual.
: 12. NEDO-32291-A, "System Analyses for the Elimination of Selected Response Time Testing Requirements," October
 
1995. 
: 13. NEDO-32291-A Supplement 1, "System Analysis for the Elimination of Selected Response Time Testing Requirements," October 1999.
 
Secondary Containment Isolation Instrumentation B 3.3.6.2
 
LaSalle 1 and 2 B 3.3.6.2-1 Revision 0 B 3.3  INSTRUMENTATION
 
B 3.3.6.2  Secondary Containment Isolation Instrumentation
 
BASES
 
BACKGROUND The secondary containment isolation instrumentation automatically initiates closure of appropriate secondary
 
containment isolation valves (SCIVs) and starts the Standby
 
Gas Treatment (SGT) System. The function of these systems, in combination with other accident mitigation systems, is to
 
limit fission product release during and following
 
postulated Design Basis Accidents (DBAs) (Refs. 1 and 2),
such that offsite radiation exposures are maintained within
 
the requirements of 10 CFR 100 that are part of the NRC
 
staff approved licensing basis. Secondary containment
 
isolation and establishment of vacuum with the SGT System
 
within the assumed time limits ensures that fission products
 
that are released during certain operations that take place
 
inside primary containment or during certain operations when
 
primary containment is not required to be OPERABLE or that
 
take place outside primary containment, are maintained
 
within applicable limits.
 
The isolation instrumentation includes the sensors, relays, and switches that are necessary to cause initiation of
 
secondary containment isolation. Most channels include
 
electronic equipment (e.g., trip units) that compares
 
measured input signals with pre-established setpoints. When
 
the setpoint is exceeded, the channel output relay actuates, which then outputs a secondary containment isolation signal
 
to the isolation logic. Functional diversity is provided by
 
monitoring a wide range of independent parameters. The
 
input parameters to the isolation logic are (a) reactor
 
vessel water level, (b) drywell pressure, (c) reactor
 
building ventilation exhaust plenum radiation, and (d) fuel
 
pool ventilation exhaust radiation. Redundant sensor input
 
signals from each parameter are provided for initiation of
 
isolation parameters. In addition, manual initiation of the
 
logic is provided.
 
For each secondary containment isolation instrumentation
 
Function, the logic receives input from four channels. The
 
output from these channels are arranged into two two-out-of-
 
two trip systems. In addition to the isolation function, the SGT subsystems are initiated. There are two SGT (continued)
Secondary Containment Isolation Instrumentation B 3.3.6.2
 
LaSalle 1 and 2 B 3.3.6.2-2 Revision 0 BASES BACKGROUND subsystems with both subsystems being initiated by each (continued) trip system. Automatically isolated secondary containment penetrations are isolated by two isolation valves. Each
 
trip system initiates isolation of one of two SCIVs so that
 
operation of either trip system isolates the associated
 
penetrations.
 
APPLICABLE The isolation signals generated by the secondary containment SAFETY ANALYSES, isolation instrumentation are implicitly assumed in the LCO, and safety analyses of References 1 and 2 to initiate closure of APPLICABILITY the SCIVs and start the SGT System to limit offsite doses.
 
Refer to LCO 3.6.4.2, "Secondary Containment Isolation
 
Valves (SCIVs)," and LCO 3.6.4.3, "Standby Gas Treatment (SGT) System," Applicable Safety Analyses Bases for more
 
detail of the safety analyses.
 
The secondary containment isolation instrumentation
 
satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). Certain
 
instrumentation Functions are retained for other reasons and
 
are described below in the individual Functions discussion.
 
The OPERABILITY of the secondary containment isolation
 
instrumentation is dependent upon the OPERABILITY of the
 
individual instrumentation channel Functions. Each Function
 
must have the required number of OPERABLE channels with
 
their setpoints set within the specified Allowable Values, as shown in Table 3.3.6.2-1. The actual setpoint is
 
calibrated consistent with applicable setpoint methodology
 
assumptions. 
 
Allowable Values are specified for each Function specified
 
in the Table. Nominal trip setpoints are specified in
 
setpoint calculations. The nominal setpoints are selected
 
to ensure that the setpoints do not exceed the Allowable
 
Values between CHANNEL CALIBRATIONS. Operation with a trip
 
setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable. A channel is
 
inoperable if its actual trip setpoint is not within its
 
required Allowable Value.
 
Trip setpoints are those predetermined values of output at
 
which an action should take place. The setpoints are
 
compared to the actual process parameter (e.g., reactor (continued)
Secondary Containment Isolation Instrumentation B 3.3.6.2
 
LaSalle 1 and 2 B 3.3.6.2-3 Revision 0 BASES APPLICABLE vessel water level), and when the measured output value of SAFETY ANALYSES, the process parameter exceeds the setpoint, the associated LCO, and device (e.g., trip unit) changes state. The analytic limits APPLICABILITY are derived from the limiting values of the process (continued) parameters obtained from the safety analysis. The trip setpoints are determined from the analytic limits, corrected
 
for defined process, calibration, and instrument errors. 
 
The Allowable Values are then determined, based on the trip
 
setpoint values, by accounting for the calibration based
 
errors. These calibration based errors are limited to
 
reference accuracy, instrument drift, errors associated with
 
measurement and test equipment, and calibration tolerance of
 
loop components. The trip setpoints and Allowable Values
 
determined in this manner provide adequate protection
 
because instrument uncertainties, process effects, calibration tolerances, instrument drift, and severe
 
environment errors (for channels that must function in harsh
 
environments as defined by 10 CFR 50.49) are accounted for
 
and appropriately applied for the instrumentation.
 
In general, the individual Functions are required to be
 
OPERABLE in the MODES or other specified conditions when
 
SCIVs and the SGT System are required.
 
The specific Applicable Safety Analyses, LCO, and
 
Applicability discussions are listed below on a Function by
 
Function basis.
: 1. Reactor Vessel Water Level-Low Low, Level 2
 
Low reactor pressure vessel (RPV) water level indicates that
 
the capability to cool the fuel may be threatened. Should
 
RPV water level decrease too far, fuel damage could result.
 
An isolation of the secondary containment and actuation of
 
the SGT System are initiated in order to minimize the
 
potential of an offsite dose release. The Reactor Vessel
 
Water Level-Low Low, Level 2 Function is one of the
 
Functions assumed to be OPERABLE and capable of providing
 
isolation and initiation signals. The isolation and
 
initiation of systems on Reactor Vessel Water Level-Low
 
Low, Level 2 support actions to ensure that any offsite
 
releases are within the limits calculated in the safety
 
analysis (Ref. 1).
(continued)
Secondary Containment Isolation Instrumentation B 3.3.6.2
 
LaSalle 1 and 2 B 3.3.6.2-4 Revision 0 BASES APPLICABLE 1. Reactor Vessel Water Level-Low Low, Level 2 SAFETY ANALYSES, (continued)
 
LCO, and APPLICABILITY Reactor Vessel Water Level-Low Low, Level 2 signals are initiated from differential pressure transmitters that sense
 
the difference between the pressure due to a constant column
 
of water (reference leg) and the pressure due to the actual
 
water level (variable leg) in the vessel. Four channels of
 
Reactor Vessel Water Level-Low Low, Level 2 Function are
 
available and are required to be OPERABLE to ensure that no
 
single instrument failure can preclude the isolation
 
function.
 
The Reactor Vessel Water Level-Low Low, Level 2 Allowable
 
Value was chosen to be the same as the High Pressure Core
 
Spray (HPCS)/Reactor Core Isolation Cooling (RCIC) Reactor
 
Vessel Water Level-Low Low, Level 2 Allowable Value (LCO 3.3.5.1, "Emergency Core Cooling System (ECCS)
 
Instrumentation," and LCO 3.3.5.2, "Reactor Core Isolation
 
Cooling (RCIC) System Instrumentation"), since this could
 
indicate the capability to cool the fuel is being
 
threatened.
 
The Reactor Vessel Water Level-Low Low, Level 2 Function is
 
required to be OPERABLE in MODES 1, 2, and 3 where
 
considerable energy exists in the Reactor Coolant System (RCS); thus, there is a probability of pipe breaks resulting
 
in significant releases of radioactive steam and gas. In
 
MODES 4 and 5, the probability and consequences of these
 
events are low due to the RCS pressure and temperature
 
limitations of these MODES; thus, this Function is not
 
required. In addition, the Function is also required to be
 
OPERABLE during operations with a potential for draining the
 
reactor vessel (OPDRVs) to ensure that offsite dose limits
 
are not exceeded if core damage occurs.
: 2. Drywell Pressure-High
 
High drywell pressure can indicate a break in the reactor
 
coolant pressure boundary (RCPB). An isolation of the
 
secondary containment and actuation of the SGT System are
 
initiated in order to minimize the potential of an offsite
 
dose release. The isolation and initiation of systems on
 
Drywell Pressure-High supports actions to ensure that any
 
offsite releases are within the limits calculated in the (continued)
Secondary Containment Isolation Instrumentation B 3.3.6.2
 
LaSalle 1 and 2 B 3.3.6.2-5 Revision 0 BASES APPLICABLE 2. Drywell Pressure-High (continued)
SAFETY ANALYSES, LCO, and safety analysis. However, the Drywell Pressure-High APPLICABILITY Function associated with isolation is not assumed in any UFSAR accident or transient analysis. It is retained for
 
the overall redundancy and diversity of the secondary
 
containment isolation instrumentation as required by the NRC
 
approved licensing basis.
 
High drywell pressure signals are initiated from pressure
 
switches that sense the pressure in the drywell. Four
 
channels of Drywell Pressure-High Function are available
 
and are required to be OPERABLE to ensure that no single
 
instrument failure can preclude the isolation function.
 
The Allowable Value was chosen to be the same as the RPS
 
Drywell Pressure-High Function Allowable Value (LCO 3.3.1.1) since this is indicative of a loss of coolant
 
accident.
 
The Drywell Pressure-High Function is required to be
 
OPERABLE in MODES 1, 2, and 3 where considerable energy
 
exists in the RCS; thus, there is a probability of pipe
 
breaks resulting in significant releases of radioactive
 
steam and gas. This Function is not required in MODES 4
 
and 5 because the probability and consequences of these
 
events are low due to the RCS pressure and temperature
 
limitations of these MODES.
 
3, 4. Reactor Building Ventilation Exhaust Plenum and Fuel Pool Ventilation Exhaust Radiation-High
 
High secondary containment exhaust radiation is an
 
indication of possible gross failure of the fuel cladding. 
 
The release may have originated from the primary containment
 
due to a break in the RCPB or the refueling floor due to a
 
fuel handling accident. When Exhaust Radiation-High is
 
detected, secondary containment isolation and actuation of
 
the SGT System are initiated to limit the release of fission
 
products as assumed in the UFSAR safety analyses (Refs. 1
 
and 2).  (continued)
Secondary Containment Isolation Instrumentation B 3.3.6.2
 
LaSalle 1 and 2 B 3.3.6.2-6 Revision 0 BASES APPLICABLE 3, 4. Reactor Building Ventilation Exhaust Plenum and Fuel SAFETY ANALYSES, Pool Ventilation Exhaust Radiation-High (continued)
LCO, and APPLICABILITY Reactor Building Ventilation Exhaust Plenum Radiation-High signals are initiated from radiation detectors that are
 
located in the reactor building return air riser above the
 
upper area of the steam tunnel prior to the reactor building
 
ventilation isolation dampers. Fuel Pool Ventilation
 
Exhaust Radiation-High signals are initiated from radiation
 
detectors that are located in the reactor building exhaust
 
ducting coming from the refuel floor. The signal from each
 
detector is input to an individual monitor whose trip
 
outputs are assigned to an isolation channel. Four channels
 
of Reactor Building Ventilation Exhaust Plenum
 
Radiation-High Function and four channels of Fuel Pool
 
Ventilation Exhaust Radiation-High Function are available
 
and are required to be OPERABLE to ensure that no single
 
instrument failure can preclude the isolation function.
 
The Allowable Values are chosen to promptly detect gross
 
failure of the fuel cladding.
 
The Reactor Building Ventilation Exhaust Plenum and Fuel
 
Pool Ventilation Exhaust Radiation-High Functions are
 
required to be OPERABLE in MODES 1, 2, and 3 where
 
considerable energy exists; thus, there is a probability of
 
pipe breaks resulting in significant releases of radioactive
 
steam and gas. In MODES 4 and 5, the probability and
 
consequences of these events are low due to the RCS pressure
 
and temperature limitations of these MODES; thus, these
 
Functions are not required. In addition, the Functions are
 
required to be OPERABLE during CORE ALTERATIONS, OPDRVs, and
 
movement of irradiated fuel assemblies in the secondary
 
containment because the capability of detecting radiation
 
releases due to fuel failures (due to fuel uncovery or
 
dropped fuel assemblies) must be provided to ensure that
 
offsite dose limits are not exceeded.
: 5. Manual Initiation
 
The Manual Initiation push button channels introduce signals
 
into the secondary containment isolation logic that are
 
redundant to the automatic protective instrumentation
 
channels, and provide manual isolation capability. There is (continued)
Secondary Containment Isolation Instrumentation B 3.3.6.2
 
LaSalle 1 and 2 B 3.3.6.2-7 Revision 0 BASES APPLICABLE 5. Manual Initiation (continued)
SAFETY ANALYSES, LCO, and no specific UFSAR safety analysis that takes credit for this APPLICABILITY Function. It is retained for the overall redundancy and diversity of the secondary containment isolation
 
instrumentation as required by the NRC approved licensing
 
basis.
 
There is one manual initiation push button for the logic per
 
trip system. Two channels of the Manual Initiation Function
 
are available and are required to be OPERABLE in MODES 1, 2, and 3 and during CORE ALTERATIONS, OPDRVs, and movement of
 
irradiated fuel assemblies in the secondary containment, since these are the MODES and other specified conditions in
 
which the Secondary Containment Isolation automatic
 
Functions are required to be OPERABLE. There is no
 
Allowable Value for this Function since the channels are
 
mechanically actuated based solely on the position of the
 
push buttons.
 
ACTIONS A Note has been provided to modify the ACTIONS related to secondary containment isolation instrumentation channels. 
 
Section 1.3, Completion Times, specifies that once a
 
Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the
 
Condition discovered to be inoperable or not within limits
 
will not result in separate entry into the Condition. 
 
Section 1.3 also specifies that Required Actions of the
 
Condition continue to apply for each additional failure, with Completion Times based on initial entry into the
 
Condition. However, the Required Actions for inoperable
 
secondary containment isolation instrumentation channels
 
provide appropriate compensatory measures for separate
 
inoperable channels. As such, a Note has been provided that
 
allows separate Condition entry for each inoperable
 
secondary containment isolation instrumentation channel.
 
A.1 Because of the diversity of sensors available to provide
 
isolation signals and the redundancy of the isolation
 
design, an allowable out of service time of 12 hours or
 
24 hours, depending on the Function (12 hours for those (continued)
Secondary Containment Isolation Instrumentation B 3.3.6.2
 
LaSalle 1 and 2 B 3.3.6.2-8 Revision 0 BASES ACTIONS A.1 (continued)
 
Functions that have channel components common to RPS
 
instrumentation and 24 hours for those Functions that do not
 
have channel components common to RPS instrumentation), has
 
been shown to be acceptable (Refs. 3 and 4) to permit
 
restoration of any inoperable channel to OPERABLE status. 
 
This out of service time is only acceptable provided the
 
associated Function is still maintaining isolation
 
capability (refer to Required Action B.1 Bases). If the
 
inoperable channel cannot be restored to OPERABLE status
 
within the allowable out of service time, the channel must
 
be placed in the tripped condition per Required Action A.1.
 
Placing the inoperable channel in trip would conservatively
 
compensate for the inoperability, restore capability to
 
accommodate a single failure, and allow operation to
 
continue. Alternately, if it is not desired to place the
 
channel in trip (e.g., as in the case where placing the
 
inoperable channel in trip would result in an isolation),
Condition C must be entered and its Required Actions taken.
 
B.1 Required Action B.1 is intended to ensure that appropriate
 
actions are taken if multiple, inoperable, untripped
 
channels within the same Function result in a complete loss
 
of automatic isolation capability for the associated
 
penetration flow path(s) or a complete loss of automatic
 
initiation capability for the SGT System. A Function is
 
considered to be maintaining isolation capability when
 
sufficient channels are OPERABLE or in trip, such that one
 
trip system will generate a trip signal from the given
 
Function on a valid signal. This ensures that one of the
 
two SCIVs in the associated penetration flow path and the
 
SGT subsystems can be initiated on an isolation signal from
 
the given Function. For the Functions with two
 
two-out-of-two logic trip systems (Functions 1, 2, 3, and 4), this would require one trip system to have two
 
channels, each OPERABLE or in trip. The Condition does not
 
include the Manual Initiation Function (Function 5), since
 
it is not assumed in any accident or transient analysis. 
 
Thus, a total loss of manual initiation capability for
 
24 hours (as allowed by Required Action A.1) is allowed.
(continued)
Secondary Containment Isolation Instrumentation B 3.3.6.2
 
LaSalle 1 and 2 B 3.3.6.2-9 Revision 6 BASES ACTIONS B.1 (continued)
The Completion Time is intended to allow the operator time
 
to evaluate and repair any discovered inoperabilities. The
 
1 hour Completion Time is acceptable because it minimizes
 
risk while allowing time for restoration or tripping of
 
channels.
 
C.1.1, C.1.2, C.2.1, and C.2.2
 
If any Required Action and associated Completion Time are
 
not met, the ability to isolate the secondary containment
 
and start the SGT System cannot be ensured. Therefore, further actions must be performed to ensure the ability to
 
maintain the secondary containment function. Isolating the
 
associated penetration flow path(s) and starting the
 
associated SGT subsystem(s) (Required Actions C.1.1
 
and C.2.1) performs the intended function of the
 
instrumentation and allows operations to continue. The
 
method used to place the SGT subsystem(s) in operation must
 
provide for automatically reinitiating the subsystem(s) upon
 
restoration of power following a loss of power to the SGT
 
subsystem(s).
 
Alternatively, declaring the associated SCIV(s) or SGT
 
subsystem(s) inoperable (Required Actions C.1.2 and C.2.2)
 
is also acceptable since the Required Actions of the
 
respective LCOs (LCO 3.6.4.2 and LCO 3.6.4.3) provide
 
appropriate actions for the inoperable components.
 
Although each Secondary Containment Isolation Instrumentation trip system is capable of initiating both SGT subsystems, for the purpose of Required Actions C.2.1 and C.2.2, only one SGT subsystem is "associated" with each trip system. The unit SGT subsystem is associated with the trip system whose SGT initiation logic is powered by the unit Division 2 DC electrical power subsystem. The opposite unit SGT subsystem is associated with the trip system whose SGT initiation logic is powered by the opposite unit Division 2 DC electrical power subsystem. Associating the SGT subsystems in this manner ensures that appropriate actions are taken to address a loss of the ability to accommodate a single failure or a loss of the required radioactivity release control function.
(continued)
Secondary Containment Isolation Instrumentation B 3.3.6.2
 
LaSalle 1 and 2 B 3.3.6.2-10 Revision 6 BASES  ACTIONS  C.1.1, C.1.2, C.2.1, and C.2.2 (continued)
 
One hour is sufficient for plant operations personnel to
 
establish required plant conditions or to declare the
 
associated components inoperable without challenging plant
 
systems.
SURVEILLANCE As noted at the beginning of the SRs, the SRs for each REQUIREMENTS Secondary Containment Isolation instrumentation Function are located in the SRs column of Table 3.3.6.2-1.
 
The Surveillances are also modified by a Note to indicate
 
that when a channel is placed in an inoperable status solely
 
for performance of required Surveillances, entry into
 
associated Conditions and Required Actions may be delayed
 
for up to 6 hours, provided the associated Function
 
maintains isolation capability. Upon completion of the
 
Surveillance, or expiration of the 6 hour allowance, the
 
channel must be returned to OPERABLE status or the
 
applicable Condition entered and Required Action(s) taken.
 
This Note is based on the reliability analysis (Refs. 3
 
and 4) assumption of the average time required to perform
 
channel surveillance. That analysis demonstrated that the
 
6 hour testing allowance does not significantly reduce the
 
probability that the SCIVs will isolate the associated
 
penetration flow paths and the SGT System will initiate when
 
necessary.
 
SR  3.3.6.2.1
 
Performance of the CHANNEL CHECK once every 12 hours ensures
 
that a gross failure of instrumentation has not occurred. A
 
CHANNEL CHECK is normally a comparison of the indicated
 
parameter for one instrument channel to a similar parameter
 
on other channels. It is based on the assumption that
 
instrument channels monitoring the same parameter should
 
read approximately the same value. Significant deviations
 
between the instrument channels could be an indication of
 
excessive instrument drift in one of the channels or
 
something even more serious. A CHANNEL CHECK will detect
 
gross channel failure; thus, it is key to verifying the
 
instrumentation continues to operate properly between each
 
CHANNEL CALIBRATION.
(continued)
Secondary Containment Isolation Instrumentation B 3.3.6.2
 
LaSalle 1 and 2 B 3.3.6.2-11 Revision 6 BASES SURVEILLANCE SR  3.3.6.2.1 (continued)
REQUIREMENTS Agreement criteria are determined by the plant staff, based
 
on a combination of the channel instrument uncertainties, including indication and readability. If a channel is
 
outside the criteria, it may be an indication that the
 
instrument has drifted outside its limit.
 
The Frequency is based on operating experience that
 
demonstrates channel failure is rare. The CHANNEL CHECK
 
supplements less formal, but more frequent, checks of
 
channels during normal operational use of the displays
 
associated with the channels required by the LCO.
 
SR  3.3.6.2.2 A CHANNEL FUNCTIONAL TEST is performed on each required
 
channel to ensure that the channel will perform the intended
 
function. A successful test of the required contact(s) of a
 
channel relay may be performed by the verification of the
 
change of state of a single contact of the relay. This
 
clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a
 
relay. This is acceptable because all of the other required
 
contacts of the relay are verified by other Technical
 
Specifications and non-Technical Specifications tests at
 
least once per refueling interval with applicable
 
extensions. Any setpoint adjustment shall be consistent
 
with the assumptions of the current plant specific setpoint
 
methodology.
 
The Frequency of 92 days is based upon the reliability
 
analysis of References 3 and 4.
 
SR  3.3.6.2.3
 
CHANNEL CALIBRATION is a complete check of the instrument
 
loop and the sensor. This test verifies the channel
 
responds to the measured parameter within the necessary
 
range and accuracy. CHANNEL CALIBRATION leaves the channel
 
adjusted to account for instrument drifts between successive
 
calibrations consistent with the plant specific setpoint
 
methodology.
(continued)
Secondary Containment Isolation Instrumentation B 3.3.6.2
 
LaSalle 1 and 2 B 3.3.6.2-12 Revision 6 BASES SURVEILLANCE SR  3.3.6.2.3 (continued)
REQUIREMENTS The Frequency is based upon the assumption of a 24 month
 
calibration interval in the determination of the magnitude
 
of equipment drift in the setpoint analysis.
 
SR  3.3.6.2.4
 
The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the
 
OPERABILITY of the required isolation logic for a specific
 
channel. The system functional testing, performed on SCIVs
 
and the SGT System in LCO 3.6.4.2 and LCO 3.6.4.3, 
 
respectively, overlaps this Surveillance to provide complete
 
testing of the assumed safety function.
 
The 24 month Frequency is based on the need to perform this
 
Surveillance under the conditions that apply during a plant
 
outage and the potential for an unplanned transient if the
 
Surveillance were performed with the reactor at power. 
 
Operating experience has shown these components usually pass
 
the Surveillance when performed at the 24 month Frequency.
 
REFERENCES 1. UFSAR, Section 15.6.5.
: 2. UFSAR, Section 15.7.4.
: 3. NEDC-31677-P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation,"
July 1990.
: 4. NEDC-30851-P-A Supplement 2, "Technical Specifications Improvement Analysis for BWR Isolation
 
Instrumentations Common to RPS and ECCS
 
Instrumentation," March 1989.
 
CRAF System Instrumentation B 3.3.7.1
 
LaSalle 1 and 2 B 3.3.7.1-1 Revision 0 B 3.3  INSTRUMENTATION
 
B 3.3.7.1  Control Room Area Filtration (CRAF) System Instrumentation
 
BASES
 
BACKGROUND The CRAF System is designed to provide a radiologically controlled environment to ensure the habitability of the
 
control room for the safety of control room operators under
 
all plant conditions. Two independent CRAF subsystems are
 
each capable of fulfilling the stated safety function. The
 
instrumentation and controls for the CRAF System
 
automatically initiate action to isolate and pressurize the
 
control room area to minimize the consequences of
 
radioactive material in the control room area environment.
 
In the event of a Control Room Air Intake Radiation-High
 
signal, the CRAF System is automatically placed in the
 
pressurization mode. In this mode the normal outside air
 
supply to the system is closed and is diverted to the
 
emergency makeup filter train where it passes through a
 
charcoal filter and is delivered to the suction of the
 
control room return air fan and the suction of the auxiliary
 
electric equipment room supply fan. Recirculated control
 
room air is combined with the emergency makeup filter train
 
air and delivered to the control room area via the supply
 
fan. The addition of outside air through the emergency
 
filter train will keep the control room area slightly
 
pressurized with respect to surrounding areas. A
 
description of the CRAF System is provided in the Bases for
 
LCO 3.7.4, "Control Room Area Filtration (CRAF) System."
 
The CRAF System (Ref. 1) instrumentation has 4 trip systems, two for each of the air intakes: two trip systems initiate
 
one CRAF subsystem, while the other trip systems initiate
 
the other CRAF subsystem. For each CRAF subsystem, the
 
associated two trip systems are arranged in a one-out-of-two
 
logic (i.e., either trip system can actuate the CRAF
 
subsystem). Each trip system receives input from two
 
Control Room Air Intake Radiation-High channels. The
 
Control Room Air Intake Radiation-High channels are
 
arranged in a two-out-of-two logic for each trip system. 
 
The channels include electronic equipment (e.g., trip units)
(continued)
CRAF System Instrumentation B 3.3.7.1
 
LaSalle 1 and 2 B 3.3.7.1-2 Revision 0 BASES BACKGROUND that compares measured input signals with pre-established (continued) setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs a CRAF System
 
initiation signal to the initiation logic.
 
APPLICABLE The ability of the CRAF System to maintain the habitability SAFETY ANALYSES of the control room area is explicitly assumed for certain accidents as discussed in the UFSAR safety analyses (Refs. 2
 
and 3). CRAF System operation ensures that the radiation
 
exposure of control room personnel, through the duration of
 
any one of the postulated accidents, does not exceed the
 
limits set by GDC 19 of 10 CFR 50, Appendix A.
 
CRAF System instrumentation satisfies Criterion 3 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO High radiation at the intake ducts of the control room outside air intakes is an indication of possible gross
 
failure of the fuel cladding. The release may have
 
originated from the primary containment due to a break in
 
the RCPB or the refueling floor due to a fuel handling
 
accident. When control room air intake high radiation is
 
detected, the associated CRAF subsystem is automatically
 
initiated in the pressurization mode since this radiation
 
release could result in radiation exposure to control room
 
personnel.
 
The Control Room Air Intake Radiation-High Function
 
consists of eight independent monitors, with four monitors
 
associated with one CRAF subsystem and the other four
 
monitors associated with the other CRAF subsystem. Each of
 
the four monitors associated with a CRAF subsystem are
 
arranged in two trip systems, with each trip system
 
containing two radiation monitors. Eight channels of the
 
Control Room Air Intake Radiation-High Function are
 
available and required to be OPERABLE to ensure no single
 
instrument failure can preclude CRAF System initiation. The
 
Allowable Value was selected to ensure protection of the
 
control room personnel.
(continued)
CRAF System Instrumentation B 3.3.7.1
 
LaSalle 1 and 2 B 3.3.7.1-3 Revision 0 BASES LCO Each channel must have its setpoint set within the specified (continued) Allowable Value of SR 3.3.7.1.3. The actual setpoint is calibrated consistent with applicable setpoint methodology
 
assumptions. Nominal trip setpoints are specified in the
 
setpoint calculations. These nominal setpoints are selected
 
to ensure that the setpoints do not exceed the Allowable
 
Value between successive CHANNEL CALIBRATIONS. Operation
 
with a trip setpoint that is less conservative than the
 
nominal trip setpoint, but within its Allowable Value, is
 
acceptable. A channel is inoperable if its actual trip
 
setpoint is not within its required Allowable Value.
 
Trip setpoints are those predetermined values of output at
 
which an action should take place. The setpoints are
 
compared to the actual process parameter (e.g., control room
 
air intake radiation), and when the measured output value of
 
the process parameter exceeds the setpoint, the associated
 
device (e.g., trip unit) changes state. The analytic limits
 
are derived from the limiting values of the process
 
parameters obtained from the safety analysis. The trip
 
setpoints are determined from the analytic limits, corrected
 
for defined process, calibration, and instrument errors. 
 
The Allowable Values are then determined, based on the trip
 
setpoint values, by accounting for the calibration based
 
errors. These calibration based errors are limited to
 
reference accuracy, instrument drift, errors associated with
 
measurement and test equipment, and calibration tolerance of
 
loop components. The trip setpoints and Allowable Values
 
determined in this manner provide adequate protection
 
because instrument uncertainties, process effects, calibration tolerances, instrument drift, and severe
 
environment errors (for channels that must function in harsh
 
environments as defined by 10 CFR 50.49) are accounted for
 
and appropriately applied for the instrumentation.
 
APPLICABILITY The Control Room Air Intake Radiation-High Function is required to be OPERABLE in MODES 1, 2, and 3, and during
 
CORE ALTERATIONS, OPDRVs, and movement of irradiated fuel in
 
the secondary containment to ensure that control room
 
personnel are protected during a LOCA, fuel handling event, or a vessel draindown event. During MODES 4 and 5, when
 
these specified conditions are not in progress (e.g., CORE
 
ALTERATIONS), the probability of a LOCA or fuel damage is
 
low; thus, the Function is not required.
(continued)
 
CRAF System Instrumentation B 3.3.7.1
 
LaSalle 1 and 2 B 3.3.7.1-4 Revision 0 BASES  (continued)
 
ACTIONS A Note has been provided to modify the ACTIONS related to CRAF System instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been
 
entered, subsequent divisions, subsystems, components, or
 
variables expressed in the Condition discovered to be
 
inoperable or not within limits will not result in separate
 
entry into the Condition. Section 1.3 also specifies that
 
Required Actions of the Condition continue to apply for each
 
additional failure, with Completion Times based on initial
 
entry into the Condition. However, the Required Actions for
 
inoperable CRAF System instrumentation channels provide
 
appropriate compensatory measures for separate inoperable
 
channels. As such, a Note has been provided that allows
 
separate Condition entry for each inoperable CRAF System
 
instrumentation channel.
 
A.1 and A.2
 
Because of the redundancy of sensors available to provide
 
initiation signals and the redundancy of the CRAF System
 
design, an allowable out of service time of 6 hours is
 
provided to permit restoration of any inoperable channel to
 
OPERABLE status. However, this out of service time is only
 
acceptable provided the Function is still maintaining CRAF
 
subsystem initiation capability. A Function is considered
 
to be maintaining CRAF subsystem initiation capability when
 
sufficient channels are OPERABLE or in trip, such that at
 
least one trip system will generate an initiation signal on
 
a valid signal. This would require one trip system to have
 
two channels, each OPERABLE or in trip. In this situation (loss of CRAF subsystem initiation capability), the 6 hour
 
allowance of Required Action A.2 is not appropriate. If the
 
Function is not maintaining CRAF subsystem initiation
 
capability, the CRAF subsystem must be declared inoperable
 
within 1 hour of discovery of loss of CRAF subsystem
 
initiation capability. 
 
This Completion Time also allows for an exception to the
 
normal "time zero" for beginning the allowed outage time "clock."  For Required Action A.1, the Completion Time only
 
begins upon discovery that the CRAF subsystem cannot be
 
automatically initiated due to inoperable, untripped Control (continued)
CRAF System Instrumentation B 3.3.7.1
 
LaSalle 1 and 2 B 3.3.7.1-5 Revision 0 BASES ACTIONS A.1 and A.2 (continued)
 
Room Air Intake Radiation-High channels in both trip systems
 
in any air intake. The 1 hour Completion Time is acceptable
 
because it minimizes risk while allowing time for restoring
 
or tripping of channels. If it is not desired to declare
 
the CRAF subsystem inoperable, Condition B may be entered
 
and Required Action B.1 taken.
 
If the inoperable channel cannot be restored to OPERABLE
 
status within the allowable out of service time, the channel
 
must be placed in the tripped condition, per Required
 
Action A.2. Placing the inoperable channel in trip performs
 
the intended function of the channel. Alternately, if it is
 
the second channel and it is not desired to place the
 
channel in trip (e.g., as in the case where it is not
 
desired to start the subsystem), Condition B must be entered
 
and its Required Actions taken.
 
The 6 hour Completion Time is based on the consideration
 
that this Function provides the primary signal to start the
 
CRAF subsystem, thus ensuring that the design basis of the
 
CRAF subsystem is met.
 
B.1 and B.2
 
With any Required Action and associated Completion Time not
 
met, the associated CRAF subsystem must be placed in the
 
pressurization mode of operation (Required Action B.1) to
 
ensure that control room personnel will be protected in the
 
event of a Design Basis Accident. The method used to place
 
the CRAF subsystem in operation must provide for
 
automatically reinitiating the subsystem upon restoration of
 
power following a loss of power to the CRAF subsystem(s). 
 
Alternately, if it is not desired to start the subsystem, the CRAF subsystem associated with inoperable, untripped
 
channels must be declared inoperable within 1 hour.
 
The 1 hour Completion Time is intended to allow the operator
 
time to place the CRAF subsystem in operation. The 1 hour
 
Completion Time is acceptable because it minimizes risk
 
while allowing time for restoration or tripping of channels, or for placing the associated CRAF subsystem in operation.
(continued)
CRAF System Instrumentation B 3.3.7.1
 
LaSalle 1 and 2 B 3.3.7.1-6 Revision 0 BASES  (continued)
 
SURVEILLANCE The Surveillances are modified by a Note to indicate REQUIREMENTS that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into
 
associated Conditions and Required Actions may be delayed
 
for up to 6 hours, provided the associated Function
 
maintains CRAF subsystem initiation capability. Upon
 
completion of the surveillance, or expiration of the 6 hour
 
allowance, the channel must be returned to OPERABLE status
 
or the applicable Condition entered and Required Actions
 
taken. This Note is based on the reliability analysis (Refs. 4 and 5) assumption of the average time required to
 
perform channel surveillance. That analysis demonstrated
 
that the 6 hour testing allowance does not significantly
 
reduce the probability that the CRAF System will initiate
 
when necessary.
 
SR  3.3.7.1.1
 
Performance of the CHANNEL CHECK once every 12 hours ensures
 
that a gross failure of instrumentation has not occurred. A
 
CHANNEL CHECK is normally a comparison of the indicated
 
parameter for one instrument channel to a similar parameter
 
on other channels. It is based on the assumption that
 
instrument channels monitoring the same parameter should
 
read approximately the same value. Significant deviations
 
between the instrument channels could be an indication of
 
excessive instrument drift in one of the channels or
 
something even more serious. A CHANNEL CHECK will detect
 
gross channel failure; thus, it is key to verifying the
 
instrumentation continues to operate properly between each
 
CHANNEL CALIBRATION.
 
Agreement criteria are determined by the plant staff based
 
on a combination of the channel instrument uncertainties, including indication and readability. If a channel is
 
outside the criteria, it may be an indication that the
 
instrument has drifted outside its limit.
 
The Frequency is based upon operating experience that
 
demonstrates channel failure is rare. The CHANNEL CHECK
 
supplements less formal, but more frequent, checks of
 
channel status during normal operational use of the displays
 
associated with channels required by the LCO.
(continued)
CRAF System Instrumentation B 3.3.7.1
 
LaSalle 1 and 2 B 3.3.7.1-7 Revision 0 BASES SURVEILLANCE SR  3.3.7.1.2 REQUIREMENTS (continued) A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended
 
function. A successful test of the required contact(s) of a
 
channel relay may be performed by the verification of the
 
change of state of a single contact of the relay. This
 
clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a
 
relay. This is acceptable because all of the other required
 
contacts of the relay are verified by other Technical
 
Specifications and non-Technical Specifications tests at
 
least once per refueling interval with applicable
 
extensions. Any setpoint adjustment shall be consistent
 
with the assumptions of the current plant specific setpoint
 
methodology.
 
The Frequency of 92 days is based on the reliability
 
analyses of References 4 and 5.
 
SR  3.3.7.1.3
 
A CHANNEL CALIBRATION is a complete check of the instrument
 
loop and the sensor. This test verifies the channel
 
responds to the measured parameter within the necessary
 
range and accuracy. CHANNEL CALIBRATION leaves the channel
 
adjusted to account for instrument drifts between successive
 
calibrations consistent with the plant specific setpoint
 
methodology.
 
The Frequency is based on the assumption of a 24 month
 
calibration interval in the determination of the magnitude
 
of equipment drift in the setpoint analysis.
 
SR  3.3.7.1.4
 
The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the
 
OPERABILITY of the required initiation logic for a specific
 
channel. The system functional testing performed in
 
LCO 3.7.4, "Control Room Area Filtration (CRAF) System,"
overlaps this Surveillance to provide complete testing of
 
the assumed safety function.
 
(continued)
CRAF System Instrumentation B 3.3.7.1
 
LaSalle 1 and 2 B 3.3.7.1-8 Revision 0 BASES SURVEILLANCE SR  3.3.7.1.4 (continued)
REQUIREMENTS While the Surveillance can be performed with the reactor at
 
power, operating experience has shown these components
 
usually pass the Surveillance when performed at the 24 month
 
Frequency, which is based on the refueling cycle. 
 
Therefore, the Frequency was concluded to be acceptable from
 
a reliability standpoint.
 
REFERENCES 1. UFSAR, Sections 7.3.4 and 9.4.1.
: 2. UFSAR, Section 6.4.
: 3. UFSAR, Chapter 15.
: 4. GENE-770-06-1A, "Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for
 
Selected Instrumentation Technical Specifications,"
December 1992.
: 5. NEDC-31677P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation,"
July 1990.
 
LOP Instrumentation B 3.3.8.1
 
LaSalle 1 and 2 B 3.3.8.1-1 Revision 0 B 3.3  INSTRUMENTATION
 
B 3.3.8.1  Loss of Power (LOP) Instrumentation
 
BASES
 
BACKGROUND Successful operation of the required safety functions of the Emergency Core Cooling Systems (ECCS) is dependent upon the
 
availability of adequate power sources for energizing the
 
various components such as pump motors, motor operated
 
valves, and the associated control components. The LOP
 
instrumentation monitors the 4.16 kV emergency buses. 
 
Offsite power is the preferred source of power for the
 
4.16 kV emergency buses. If the monitors determine that
 
insufficient voltage is available, the buses are
 
disconnected from the offsite power sources and connected to
 
the onsite diesel generator (DG) power sources.
 
Each 4.16 kV emergency bus has its own independent LOP
 
instrumentation and associated trip logic. The voltage for
 
the Division 1, 2, and 3 buses is monitored at two levels, which can be considered as two different undervoltage
 
functions:  loss of voltage and degraded voltage.
 
For Division 1 and 2, each loss of voltage and degraded
 
voltage function is monitored by two instruments per bus
 
whose output trip contacts are arranged in a two-out-of-two
 
logic configuration per bus (Ref. 1). The loss of voltage
 
signal is generated when a loss of voltage occurs for a
 
specific time interval. Lower voltage conditions will
 
result in decreased trip times for the inverse time
 
undervoltage relays. The degraded voltage signal is
 
generated when a degraded voltage occurs for a specified
 
time interval; the time interval is dependent upon whether a
 
loss of coolant accident signal is present. The relays
 
utilized are inverse time delay voltage relays or
 
instantaneous voltage relays with a time delay.
 
For Division 3, the degraded voltage function logic is the
 
same as for Divisions 1 and 2, but the Division 3 loss of
 
voltage function logic is different. The Division 3 DG will
 
auto-start if either one of the two bus undervoltage relays (with a time delay) actuates and the DG output breaker will
 
automatically close with the same undervoltage permissive
 
provided that the Division 3 bus main feeder breaker is open
 
and the DG speed and voltage permissives are met. The
 
Division 3 bus main feed breaker trip logic includes two
 
(continued)
LOP Instrumentation B 3.3.8.1
 
LaSalle 1 and 2 B 3.3.8.1-2 Revision 0 BASES BACKGROUND trip systems. Each trip system consists of an undervoltage (continued) relay on the 4.16 kV bus (with a time delay) and an undervoltage relay on the system auxiliary transformer (SAT)
 
side of the main feed breaker to the 4.16 kV bus (with no
 
time delay) arranged in a two-out-of-two logic. The trip
 
setting of the SAT undervoltage relay is maintained such
 
that it trips prior to the bus undervoltage relay. Either
 
trip system will open (trip) the main feed breaker to the
 
bus.
 
A loss of voltage signal or degraded voltage signal results
 
in the start of the associated DG, the trip of the normal
 
and alternate offsite power supply breakers to the
 
associated 4.16 kV emergency bus, and (for Divisions 1 and 2
 
only) the shedding of the appropriate 4.16 kV bus loads.
 
APPLICABLE The LOP instrumentation is required for the Engineered SAFETY ANALYSES, Safety Features to function in any accident with a loss of LCO, and offsite power. The required channels of LOP instrumentation APPLICABILITY ensure that the ECCS and other assumed systems powered from the DGs provide plant protection in the event of any of the
 
analyzed accidents in References 2, 3, and 4 in which a loss
 
of offsite power is assumed. The initiation of the DGs on
 
loss of offsite power, and subsequent initiation of the 
 
ECCS, ensure that the fuel peak cladding temperature remains
 
below the limits of 10 CFR 50.46.
 
Accident analyses credit the loading of at least two of the
 
DGs based on the loss of offsite power coincident with a
 
loss of coolant accident (LOCA). The diesel starting and
 
loading times have been included in the delay time
 
associated with each safety system component requiring DG
 
supplied power following a loss of offsite power.
 
The LOP instrumentation satisfies Criterion 3 of
 
10 CFR 50.36(c)(2)(ii).
 
The OPERABILITY of the LOP instrumentation is dependent upon
 
the OPERABILITY of the individual instrumentation channel
 
Functions specified in Table 3.3.8.1-1. Each Function must
 
have a required number of OPERABLE channels per 4.16 kV
 
emergency bus, with their setpoints within the specified
 
Allowable Values. The actual setpoint is calibrated
 
consistent with applicable setpoint methodology assumptions.
(continued)
LOP Instrumentation B 3.3.8.1
 
LaSalle 1 and 2 B 3.3.8.1-3 Revision 0 BASES APPLICABLE The Allowable Values are specified for each Function in the SAFETY ANALYSES, Table. Nominal trip setpoints are specified in the setpoint LCO, and calculations. The nominal setpoints are selected to ensure APPLICABILITY that the setpoint does not exceed the Allowable Value (continued) between CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within the Allowable Value, is acceptable. A channel is
 
inoperable if its actual trip setpoint is not within its
 
required Allowable Value. Trip setpoints are those
 
predetermined values of output at which an action should
 
take place. The setpoints are compared to the actual
 
process parameter (e.g., degraded voltage), and when the
 
measured output value of the process parameter exceeds the
 
setpoint, the associated device (e.g., trip unit) changes
 
state. The analytic limits are derived from the limiting
 
values of the process parameters obtained from the safety
 
analysis. The trip setpoints are determined from the
 
analytic limits, corrected for defined process, calibration, and instrument errors. The Allowable Values are then
 
determined, based on the trip setpoint values, by accounting
 
for the calibration based errors. These calibration based
 
errors are limited to reference accuracy, instrument drift, errors associated with measurement and test equipment, and
 
calibration tolerance of loop components. The trip
 
setpoints and Allowable Values determined in this manner
 
provide adequate protection because instrument
 
uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for
 
channels that must function in harsh environments as defined
 
by 10 CFR 50.49) are accounted for and appropriately applied
 
for the instrumentation.
 
The specific Applicable Safety Analyses, LCO, and
 
Applicability discussions are listed below on a Function by
 
Function basis.
 
4.16 kV Emergency Bus Undervoltage
 
1.a, 1.b, 2.a, 2.b. 4.16 kV Emergency Bus Undervoltage (Loss of Voltage)
 
Loss of voltage on a 4.16 kV emergency bus indicates that
 
offsite power may be completely lost to the respective
 
emergency bus and is unable to supply sufficient power for
 
proper operation of the applicable equipment. Therefore,  (continued)
LOP Instrumentation B 3.3.8.1
 
LaSalle 1 and 2 B 3.3.8.1-4 Revision 0 BASES APPLICABLE 4.16 kV Emergency Bus Undervoltage SAFETY ANALYSES, LCO, and 1.a, 1.b, 2.a, 2.b. 4.16 kV Emergency Bus Undervoltage APPLICABILITY (Loss of Voltage)
  (continued) the power supply to the bus is transferred from the offsite
 
power supply to DG power. This transfer is initiated when
 
the voltage on the bus drops below the relay settings with a
 
short time delay. The transfer occurs prior to the bus
 
voltage dropping below the minimum Loss of Voltage Function
 
Allowable Value but after the voltage drops below the
 
maximum Loss of Voltage Function Allowable Value (loss of
 
voltage with a short time delay). The short time delay
 
prevents inadvertent relay actuations due to momentary
 
voltage dips. For Divisions 1 and 2, the time delay varies
 
inversely with decreasing voltage. For Division 3, the time
 
delay is a fixed value. The time delay values are bounded
 
by the upper and lower Allowable Values, as applicable. 
 
This ensures that adequate power will be available to the
 
required equipment.
 
The Bus Undervoltage Allowable Values are low enough to
 
prevent inadvertent power supply transfer since they are
 
below the minimum expected voltage during normal and
 
emergency operation, but high enough to ensure power is
 
available to the required equipment. The Time Delay
 
Allowable Values are long enough to provide time for the
 
offsite power supply to recover to normal voltages, but
 
short enough to ensure that power is available to the
 
required equipment.
 
Two channels of each 4.16 kV Emergency Bus Undervoltage (Loss of Voltage) Function per associated emergency bus are
 
required to be OPERABLE when the associated DG is required
 
to be OPERABLE to ensure that no single instrument failure
 
can preclude the DG function. For the Division 1 and 2
 
4.16 kV emergency buses, the Loss of Voltage Functions are
: 1) 4.16 kV Basis and 2) Time Delay. For the Division 3
 
4.16 kV emergency bus, the Loss of Voltage Functions are: 1)
 
4.16 kV Basis and 2) Time Delay. Refer to LCO 3.8.1, "AC
 
Sources-Operating," and LCO 3.8.2, "AC Sources-Shutdown,"
for Applicability Bases for the DGs.
(continued)
LOP Instrumentation B 3.3.8.1
 
LaSalle 1 and 2 B 3.3.8.1-5 Revision 13 BASES APPLICABLE 1.c, 1.d, 1.e, 2.c, 2.d, 2.e. 4.16 kV Emergency Bus SAFETY ANALYSES, Undervoltage (Degraded Voltage)
LCO, and APPLICABILITY A reduced voltage condition on a 4.16 kV emergency bus (continued) indicates that while offsite power may not be completely lost to the respective emergency bus, power may be
 
insufficient for starting large motors without risking
 
damage to the motors that could disable the ECCS function. 
 
Therefore, power supply to the bus is transferred from
 
offsite power to onsite DG power when the voltage on the bus
 
drops below the Degraded Voltage Function Allowable Values (degraded voltage with a time delay). This ensures that
 
adequate power will be available to the required equipment.
 
The Bus Undervoltage Allowable Values are low enough to
 
prevent inadvertent power supply transfer, but high enough
 
to ensure that sufficient power is available to the required
 
equipment. The Time Delay Allowable Values are long enough
 
to provide time for the offsite power supply to recover to
 
normal voltages, but short enough to ensure that sufficient
 
power is available to the required equipment.
 
Two channels of each 4.16 kV Emergency Bus Undervoltage (Degraded Voltage) Function per associated emergency bus are
 
required to be OPERABLE when the associated DG is required
 
to be OPERABLE to ensure that no single instrument failure
 
can preclude the DG function. The Degraded Voltage
 
Functions are: 1) 4.16 kV Basis; 2) Time Delay, No LOCA; and
: 3) Time Delay, LOCA.
 
The Degraded Voltage Time Delay, LOCA, Function is dependent on whether a LOCA signal is present at the time of the
 
degraded voltage condition. The LOCA signal for Division 1
 
and 2 buses is generated by either the Reactor Vessel Water
 
Level - Low Low Low, Level 1, or Drywell Pressure - High, ECCS Instrumentation. The LOCA signal for Division 3 is
 
  (continued)
LOP Instrumentation B 3.3.8.1
 
LaSalle 1 and 2 B 3.3.8.1-6 Revision 9 BASES APPLICABLE 1.c, 1.d, 1.e, 2.c, 2.d, 2.e. 4.16 kV Emergency Bus SAFETY ANALYSES, Undervoltage (Degraded Voltage) (continued)
LCO, and APPLICABILITY generated by either the Reactor Vessel Water Level - Low Low, Level 2 or Drywell Pressure - High ECCS Instrumentation. The required OPERABILITY of this instrumentation is identified on Table 3.3.5.1-1, "Emergency Core Cooling System Instrumentation."  Two footnotes have been provided for the Degraded Voltage Time Delay, LOCA, Function to modify its OPERABILITY consistent with the OPERABILITY requirements of the ECCS Instrumentation that generate the associated LOCA signal. Per footnote (a), the Degraded Voltage Time Delay, LOCA, Function is required to be OPERABLE in MODES 4 and 5 when the associated ECCS is required to be OPERABLE for automatic initiation.
Additionally, footnote (b) states the Degraded Voltage Time Delay, LOCA, Function is not required to be OPERABLE when the reactor vessel is defueled. These footnotes are acceptable because the Degraded Voltage Time Delay, No LOCA, Function provides adequate protection to ensure that other required systems powered from the DG(s) function as designed in any non-LOCA accident in which a loss of offsite power is assumed.
ACTIONS A Note has been provided to modify the ACTIONS related to LOP instrumentation channels. Section 1.3, Completion
 
Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables
 
expressed in the Condition discovered to be inoperable or
 
not within limits will not result in separate entry into the
 
Condition. Section 1.3 also specifies that Required Actions
 
of the Condition continue to apply for each additional
 
failure, with Completion Times based on initial entry into
 
the Condition. However, the Required Actions for inoperable
 
LOP instrumentation channels provide appropriate 
 
compensatory measures for separate inoperable channels. As
 
such, a Note has been provided that allows separate
 
Condition entry for each inoperable LOP instrumentation
 
channel.
 
  (continued)
LOP Instrumentation B 3.3.8.1
 
LaSalle 1 and 2 B 3.3.8.1-7 Revision 9 BASES ACTIONS A.1 (continued)
With one or more channels of a Function inoperable, the
 
Function may not be capable of performing the intended
 
function. Therefore, only 1 hour is allowed to restore the
 
inoperable channel to OPERABLE status. If the inoperable
 
channel cannot be restored to OPERABLE status within the
 
allowable out of service time, the channel must be placed in
 
the tripped condition per Required Action A.1. Placing the
 
inoperable channel in trip would conservatively compensate
 
for the inoperability, restore capability to accommodate a
 
single failure, and allow operation to continue. 
 
Alternately, if it is not desired to place the channel in
 
trip (e.g., as in the case where placing the channel in trip
 
would result in a DG initiation), Condition B must be
 
entered and its Required Action taken.
 
The Completion Time is intended to allow the operator time
 
to evaluate and repair any discovered inoperabilities. The
 
1 hour Completion Time is acceptable because it minimizes
 
risk while allowing time for restoration or tripping of
 
channels.
 
B.1 If any Required Action and associated Completion Time is not
 
met, the associated Function may not be capable of
 
performing the intended function. Therefore, the associated
 
DG(s) are declared inoperable immediately. This requires
 
entry into applicable Conditions and Required Actions of
 
LCO 3.8.1 and LCO 3.8.2, which provide appropriate actions
 
for the inoperable DG(s).
 
SURVEILLANCE As noted at the beginning of the SRs, the SRs for each LOP REQUIREMENTS Instrumentation Function are located in the SRs column of Table 3.3.8.1-1.
(continued)
LOP Instrumentation B 3.3.8.1
 
LaSalle 1 and 2 B 3.3.8.1-8 Revision 9 BASES SURVEILLANCE The Surveillances are modified by a Note to indicate that REQUIREMENTS when a channel is placed in an inoperable status solely for (continued) performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to
 
2 hours provided the associated Function maintains LOP
 
initiation capability. LOP initiation capability is
 
maintained provided the associated Function can perform the
 
load shed and control scheme for two of the three 4.16 kV
 
emergency buses. Upon completion of the Surveillance, or
 
expiration of the 2 hour allowance, the channel must be
 
returned to OPERABLE status or the applicable Condition
 
entered and Required Actions taken.
 
SR  3.3.8.1.1 and SR  3.3.8.1.3
 
A CHANNEL FUNCTIONAL TEST is performed on each required
 
channel to ensure that the channel will perform the intended
 
function. A successful test of the required contact(s) of a
 
channel relay may be performed by the verification of the
 
change of state of a single contact of the relay. This
 
clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a
 
relay. This is acceptable because all of the other required
 
contacts of the relay are verified by other Technical
 
Specifications and non-Technical Specifications tests at
 
least once per refueling interval with applicable
 
extensions. Any setpoint adjustment shall be consistent
 
with the assumptions of the current plant specific setpoint
 
methodology.
 
The Frequencies of 18 months and 24 months are based on
 
plant operating experience with regard to channel
 
OPERABILITY and drift that demonstrates that failure of more
 
than one channel of a given Function in any 18 month or 24
 
month interval, as applicable, is rare.
 
SR  3.3.8.1.2 and SR  3.3.8.1.4
 
A CHANNEL CALIBRATION is a complete check of the instrument
 
loop and the sensor. This test verifies the channel
 
responds to the measured parameter within the necessary (continued)
LOP Instrumentation B 3.3.8.1
 
LaSalle 1 and 2 B 3.3.8.1-9 Revision 9 BASES SURVEILLANCE SR  3.3.8.1.2 and SR  3.3.8.1.4 (continued)
REQUIREMENTS range and accuracy. CHANNEL CALIBRATION leaves the channel
 
adjusted to account for instrument drifts between successive
 
calibrations consistent with the plant specific setpoint
 
methodology.
 
The Frequency is based on the assumption of an 18 month or
 
24 month calibration interval, as applicable, in the
 
determination of the magnitude of equipment drift in the
 
setpoint analysis.
 
SR  3.3.8.1.5
 
The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the
 
OPERABILITY of the required actuation logic for a specific
 
channel. The system functional testing performed in
 
LCO 3.8.1 and LCO 3.8.2 overlaps this Surveillance to
 
provide complete testing of the assumed safety functions. 
 
The 24 month Frequency is based on the need to perform this
 
Surveillance under the conditions that apply during a plant
 
outage and the potential for an unplanned transient if the
 
Surveillance were performed with the reactor at power. 
 
Operating experience has shown these components usually pass
 
the Surveillance when performed at the 24 month Frequency.
 
REFERENCES 1. UFSAR, Section 8.2.3.3.
: 2. UFSAR, Section 5.2.
: 3. UFSAR, Section 6.3.
: 4. UFSAR, Chapter 15.
 
RPS Electric Power Monitoring B 3.3.8.2
 
LaSalle 1 and 2 B 3.3.8.2-1 Revision 0 B 3.3  INSTRUMENTATION
 
B 3.3.8.2  Reactor Protection System (RPS) Electric Power Monitoring
 
BASES
 
BACKGROUND The RPS Electric Power Monitoring System is provided to isolate the RPS bus from the motor generator (MG) set or the
 
alternate power supply in the event of overvoltage, undervoltage, or underfrequency. This system protects the
 
loads connected to the RPS bus against unacceptable voltage
 
and frequency conditions (Ref. 1) and forms an important
 
part of the primary success path for the essential safety
 
circuits. Some of the essential equipment powered from the
 
RPS buses includes the RPS logic, scram solenoids, and
 
various valve isolation logic.
 
The RPS Electric Power Monitoring assembly will detect any
 
abnormal high or low voltage or low frequency condition in
 
the outputs of the two MG sets or the alternate power supply
 
and will de-energize its respective RPS bus, thereby causing
 
all safety functions normally powered by this bus to
 
de-energize.
 
In the event of failure of an RPS Electric Power Monitoring
 
System (e.g., both inseries electric power monitoring
 
assemblies), the RPS loads may experience significant
 
effects from the unregulated power supply. Deviation from
 
the nominal conditions can potentially cause damage to the
 
scram and MSIV trip solenoids and other Class 1E devices.
 
In the event of a low voltage condition, for an extended
 
period of time, the scram and MSIV trip solenoids can
 
chatter and potentially lose their pneumatic control
 
capability, resulting in a loss of primary scram and MSIV
 
closure action.
 
In the event of an overvoltage condition, the RPS and
 
isolation logic relays and scram solenoids, as well as the
 
main steam isolation valve trip solenoids, may experience a
 
voltage higher than their design voltage. If the
 
overvoltage condition persists for an extended time period, it may cause equipment degradation and the loss of plant
 
safety function.
(continued)
RPS Electric Power Monitoring B 3.3.8.2
 
LaSalle 1 and 2 B 3.3.8.2-2 Revision 0 BASES BACKGROUND Two redundant Class 1E circuit breakers are connected in (continued) series between each RPS bus and its MG set, and between each RPS bus and the alternate power supply. Each of these
 
circuit breakers has an associated independent set of
 
Class 1E overvoltage, undervoltage, and underfrequency
 
sensing logic. Together, a circuit breaker and its sensing
 
logic constitute an electric power monitoring assembly. If
 
the output of the inservice MG set or alternate power supply
 
exceeds the predetermined limits of overvoltage, undervoltage, or underfrequency, a trip coil driven by this
 
logic circuitry opens the circuit breaker, which removes the
 
associated power supply from service.
 
APPLICABLE RPS Electric Power Monitoring is necessary to meet the SAFETY ANALYSES assumptions of the safety analyses by ensuring that the equipment powered from the RPS buses can perform its
 
intended function. RPS Electric Power Monitoring provides
 
protection to the RPS and other systems that receive power
 
from the RPS buses, by disconnecting the RPS bus from the
 
power supply under specified conditions that could damage
 
the RPS bus powered equipment.
 
RPS Electric Power Monitoring satisfies Criterion 3 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO The OPERABILITY of each RPS electric power monitoring assembly is dependent upon the OPERABILITY of the
 
overvoltage, undervoltage, and underfrequency logic, as well
 
as the OPERABILITY of the associated circuit breaker. Two
 
electric power monitoring assemblies are required to be
 
OPERABLE for each inservice power supply. This provides
 
redundant protection against any abnormal voltage or
 
frequency conditions to ensure that no single RPS electric
 
power monitoring assembly failure can preclude the function
 
of RPS bus powered components. Each of the inservice
 
electric power monitoring assembly trip logic setpoints is
 
required to be within the specific Allowable Value. The
 
actual setpoint is calibrated consistent with applicable
 
setpoint methodology assumptions.
(continued)
RPS Electric Power Monitoring B 3.3.8.2
 
LaSalle 1 and 2 B 3.3.8.2-3 Revision 0 BASES LCO Allowable Values are specified for each RPS electric power (continued) monitoring assembly trip logic (refer to SR 3.3.8.2.2).
Nominal trip setpoints are specified in the setpoint
 
calculations. The nominal setpoints are selected to ensure
 
that the setpoints do not exceed the Allowable Value between
 
CHANNEL CALIBRATIONS. Operation with a trip setpoint less
 
conservative than the nominal trip setpoint, but within its
 
Allowable Value, is acceptable. A channel is inoperable if
 
its actual trip setpoint is not within its required
 
Allowable Value. Trip setpoints are those predetermined
 
values of output at which an action should take place. The
 
setpoints are compared to the actual process parameter (e.g., overvoltage), and when the measured output value of
 
the process parameter exceeds the setpoint, the associated
 
device (e.g., trip coil) changes state. The analytic limits
 
are derived from the limiting values of the process
 
parameters obtained from the safety analysis. The trip
 
setpoints are determined from the analytic limits, corrected
 
for defined process, calibration, and instrument errors. 
 
The Allowable Values are then determined, based on the trip
 
setpoint values, by accounting for the calibration based
 
errors. These calibration based errors are limited to
 
reference accuracy, instrument drift, errors associated with
 
measurement and test equipment, and calibration tolerance of
 
loop components. The trip setpoints and Allowable Values
 
determined in this manner provide adequate protection
 
because instrument uncertainties, process effects, calibration tolerances, instrument drift, and severe
 
environment errors (for channels that must function in harsh
 
environments as defined by 10 CFR 50.49) are accounted for
 
and appropriately applied for the instrumentation.
 
The Allowable Values for the instrument settings are based
 
on the RPS providing  57 Hz and 120 V
+/- 10%. The most limiting voltage requirement and associated line losses
 
determine the settings of the electric power monitoring
 
instrument channels. The settings are calculated based on
 
the loads on the buses and RPS MG set or alternate power
 
supply being 120 VAC and 60 Hz.
(continued)
 
RPS Electric Power Monitoring B 3.3.8.2
 
LaSalle 1 and 2 B 3.3.8.2-4 Revision 0 BASES  (continued)
 
APPLICABILITY The operation of the RPS electric power monitoring assemblies is essential to disconnect the RPS bus powered
 
components from the inservice MG set or alternate power
 
supply during abnormal voltage or frequency conditions. 
 
Since the degradation of a nonclass 1E source supplying
 
power to the RPS bus can occur as a result of any random
 
single failure, the OPERABILITY of the RPS electric power
 
monitoring assemblies is required when the RPS bus powered
 
components are required to be OPERABLE. This results in the
 
RPS Electric Power Monitoring System OPERABILITY being
 
required in MODES 1, 2, and 3, MODES 4 and 5, with residual
 
heat removal (RHR) shutdown cooling isolation valves open, MODE 5 with any control rod withdrawn from a core cell
 
containing one or more fuel assemblies, during movement of
 
irradiated fuel assemblies in the secondary containment, during CORE ALTERATIONS, and during operations with a
 
potential for draining the reactor vessel (OPDRVs).
 
ACTIONS A.1
 
If one RPS electric power monitoring assembly for an
 
inservice power supply (MG set or alternate) is inoperable, or one RPS electric power monitoring assembly on each
 
inservice power supply is inoperable, the OPERABLE assembly
 
will still provide protection to the RPS bus powered
 
components under degraded voltage or frequency conditions. 
 
However, the reliability and redundancy of the RPS Electric
 
Power Monitoring System are reduced and only a limited time
 
(72 hours) is allowed to restore the inoperable assembly(s)
 
to OPERABLE status. If the inoperable assembly(s) cannot be
 
restored to OPERABLE status, the associated power supply
 
must be removed from service (Required Action A.1). This
 
places the RPS bus in a safe condition. An alternate power
 
supply with OPERABLE power monitoring assemblies may then be
 
used to power the RPS bus.
 
The 72 hour Completion Time takes into account the remaining
 
OPERABLE electric power monitoring assembly and the low
 
probability of an event requiring RPS Electric Power
 
Monitoring protection occurring during this period. It
 
allows time for plant operations personnel to take
 
corrective actions or to place the plant in the required
 
condition in an orderly manner and without challenging plant
 
systems.  (continued)
RPS Electric Power Monitoring B 3.3.8.2
 
LaSalle 1 and 2 B 3.3.8.2-5 Revision 32 BASES ACTIONS A.1 (continued)
Alternatively, if it is not desired to remove the power
 
supply(s) from service (e.g., as in the case where removing
 
the power supply(s) from service would result in a scram or
 
isolation), Condition C, D, E, or F as applicable, must be
 
entered and its Required Actions taken.
 
B.1 If both power monitoring assemblies for an inservice power
 
supply (MG set or alternate) are inoperable, or both power
 
monitoring assemblies in each inservice power supply are
 
inoperable, the system protective function is lost. In this
 
condition, 1 hour is allowed to restore one assembly to
 
OPERABLE status for each inservice power supply. If one
 
inoperable assembly for each inservice power supply cannot
 
be restored to OPERABLE status, the associated power
 
supplies must be removed from service within 1 hour (Required Action B.1). An alternate power supply with
 
OPERABLE assemblies may then be used to power one RPS bus. 
 
The 1 hour Completion Time is sufficient for the plant
 
operations personnel to take corrective actions and is
 
acceptable because it minimizes risk while allowing time for
 
restoration or removal from service of the electric power
 
monitoring assemblies.
 
Alternately, if it is not desired to remove the power
 
supply(s) from service (e.g., as in the case where removing
 
the power supply(s) from service would result in a scram or
 
isolation), Condition C, D, E, or F as applicable, must be
 
entered and its Required Actions taken.
 
C.1 If any Required Action and associated Completion Time of
 
Condition A or B are not met in MODE 1, 2, or 3, the plant must be brought to a MODE in which overall plant risk is minimized. The plant shutdown is accomplished by placing the plant in MODE 3 within 12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 2) and because the time spent in MODE 3 to (continued)
RPS Electric Power Monitoring B 3.3.8.2
 
LaSalle 1 and 2 B 3.3.8.2-6 Revision 32 BASES ACTIONS C.1 (continued)
 
perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner
 
and without challenging plant systems.
 
D.1 and D.2
 
If any Required Action and associated Completion Time of
 
Condition A or B are not met in MODE 4 or 5 with RHR SDC
 
isolation valves open, action must be immediately initiated
 
to either restore one electric power monitoring assembly to
 
OPERABLE status for the inservice power source supplying the
 
required instrumentation powered from the RPS bus (Required
 
Action D.1) or to isolate the RHR SDC System (Required
 
Action D.2). Required Action D.1 is provided because the
 
RHR SDC System may be needed to provide core cooling. All
 
actions must continue until the applicable Required Actions
 
are completed.
 
E.1 If any Required Action and associated Completion Time of
 
Condition A or B are not met in MODE 5 with any control rod
 
withdrawn from a core cell containing one or more fuel
 
assemblies, the operator must immediately initiate action to
 
fully insert all insertable control rods in core cells
 
containing one or more fuel assemblies (Required
 
Action E.1). This Required Action results in the least
 
reactive condition for the reactor core and ensures that the
 
safety function of the RPS (e.g., scram of control rods) is
 
not required.
 
F.1.1, F.1.2, F.2.1, and F.2.2
 
If any Required Action and associated Completion Time of
 
Condition A or B are not met during movement of irradiated
 
fuel assemblies in the secondary containment, during CORE
 
ALTERATIONS, or during OPDRVs, the ability to isolate the (continued)
RPS Electric Power Monitoring B 3.3.8.2
 
LaSalle 1 and 2 B 3.3.8.2-7 Revision 0 BASES ACTIONS F.1.1, F.1.2, F.2.1, and F.2.2 (continued)
 
secondary containment and start the Standby Gas Treatment (SGT) System cannot be ensured. Therefore, actions must be
 
immediately performed to ensure the ability to maintain the
 
secondary containment and SGT System functions. Isolating
 
the affected penetration flow path(s) and starting the
 
associated SGT subsystem(s) (Required Actions F.1.1 and
 
F.2.1) performs the intended function of the instrumentation
 
the RPS electric power monitoring assemblies is protecting, and allows operations to continue.
 
Alternatively, immediately declaring the associated
 
secondary containment isolation valve(s) or SGT subsystem(s)
 
inoperable (Required Action F.1.2 and F.2.2) is also
 
acceptable since the Required Actions of the respective LCOs (LCO 3.6.4.2 and LCO 3.6.4.3) provide appropriate actions
 
for the inoperable components.
 
SURVEILLANCE SR  3.3.8.2.1 REQUIREMENTS A CHANNEL FUNCTIONAL TEST is performed on each overvoltage, undervoltage, and underfrequency channel to ensure that the
 
channel will perform the intended function. A successful
 
test of the required contact(s) of a channel relay may be
 
performed by the verification of the change of state of a
 
single contact of the relay. This clarifies what is an
 
acceptable CHANNEL FUNCTIONAL TEST of a relay. This is
 
acceptable because all of the other required contacts of the
 
relay are verified by other Technical Specifications and
 
non-Technical Specifications tests at least once per
 
refueling interval with applicable extensions. Any setpoint
 
adjustment shall be consistent with the assumptions of the
 
current plant specific setpoint methodology.
 
As noted in the Surveillance, the CHANNEL FUNCTIONAL TEST is
 
only required to be performed while the plant is in a
 
condition in which the loss of the RPS bus will not
 
jeopardize steady state power operation (the design of the
 
system is such that the power source must be removed from
 
service to conduct the Surveillance). The 24 hours is
 
intended to indicate an outage of sufficient duration to (continued)
RPS Electric Power Monitoring B 3.3.8.2
 
LaSalle 1 and 2 B 3.3.8.2-8 Revision 32 BASES SURVEILLANCE SR  3.3.8.2.1 (continued)
REQUIREMENTS allow for scheduling and proper performance of the
 
Surveillance. The 184 day Frequency and the Note in the
 
Surveillance are based on guidance provided in Generic
 
Letter 91-09 (Ref. 3).
 
SR  3.3.8.2.2
 
CHANNEL CALIBRATION is a complete check of the instrument
 
loop and the sensor. This test verifies that the channel
 
responds to the measured parameter within the necessary
 
range and accuracy. CHANNEL CALIBRATION leaves the channel
 
adjusted to account for instrument drifts between successive
 
calibrations consistent with the plant specific setpoint
 
methodology. 
 
The Frequency is based upon the assumption of an 24 month
 
calibration interval in the determination of the magnitude
 
of equipment drift in the setpoint analysis.
 
SR  3.3.8.2.3
 
Performance of a system functional test demonstrates that, with a required system actuation (simulated or actual)
 
signal, the logic of the system will automatically trip open
 
the associated power monitoring assembly circuit breaker. 
 
The system functional test shall include actuation of the
 
protective relays, tripping logic, and output circuit
 
breakers. Only one signal per power monitoring assembly is
 
required to be tested. This Surveillance overlaps with the
 
CHANNEL CALIBRATION to provide complete testing of the
 
safety function. The system functional test of the Class 1E
 
circuit breakers is included as part of this test to provide
 
complete testing of the safety function. If the breakers
 
are incapable of operating, the associated electric power
 
monitoring assembly would be inoperable.
 
The 24 month Frequency is based on the need to perform this
 
Surveillance under the conditions that apply during a plant
 
outage and the potential for an unplanned transient if the (continued)
RPS Electric Power Monitoring B 3.3.8.2
 
LaSalle 1 and 2 B 3.3.8.2-9 Revision 32 BASES SURVEILLANCE SR  3.3.8.2.3 (continued)
REQUIREMENTS Surveillance were performed with the reactor at power. 
 
Operating experience has shown that these components usually
 
pass the Surveillance when performed at the 24 month
 
Frequency.
 
REFERENCES 1. UFSAR, Section 8.3.1.1.3.
: 2. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants," December 2002.
: 3. NRC Generic Letter 91-09, "Modification of Surveillance Interval for the Electric Protective
 
Assemblies in Power Supplies for the Reactor
 
Protection System."
Recirculation Loops Operating B 3.4.1 LaSalle 1 and 2 B 3.4.1-1 Revision 0 B 3.4  REACTOR COOLANT SYSTEM (RCS)
 
B 3.4.1  Recirculation Loops Operating
 
BASES
 
BACKGROUND The Reactor Recirculation System is designed to provide a forced coolant flow through the core to remove heat from the
 
fuel. The forced coolant flow removes heat at a faster rate
 
from the fuel than would be possible with just natural
 
circulation. The forced flow, therefore, allows operation
 
at significantly higher power than would otherwise be
 
possible. The recirculation system also controls reactivity
 
over a wide span of reactor power by varying the
 
recirculation flow rate to control the void content of the
 
moderator. The Reactor Recirculation System consists of two
 
recirculation pump loops external to the reactor vessel. 
 
These loops provide the piping path for the driving flow of
 
water to the reactor vessel jet pumps. Each external loop
 
contains a two speed motor driven recirculation pump, a flow
 
control valve, associated piping, jet pumps, valves, and
 
instrumentation. The recirculation loops are part of the
 
reactor coolant pressure boundary and are located inside the
 
drywell structure. The jet pumps are reactor vessel
 
internals.
The recirculated coolant consists of saturated water from
 
the steam separators and dryers that has been subcooled by
 
incoming feedwater. This water passes down the annulus
 
between the reactor vessel wall and the core shroud. A
 
portion of the coolant flows from the vessel, through the
 
two external recirculation loops, and becomes the driving
 
flow for the jet pumps. Each of the two external
 
recirculation loops discharges high pressure flow into an
 
external manifold, from which individual recirculation inlet
 
lines are routed to the jet pump risers within the reactor
 
vessel. The remaining portion of the coolant mixture in the
 
annulus becomes the suction flow for the jet pumps. This
 
flow enters the jet pump at suction inlets and is
 
accelerated by the driving flow. The drive flow and suction
 
flow are mixed in the jet pump throat section and result in
 
partial pressure recovery. The total flow then passes
 
through the jet pump diffuser section into the area below
 
the core (lower plenum), gaining sufficient head in the
 
process to drive the required flow upward through the core.
(continued)
Recirculation Loops Operating B 3.4.1 LaSalle 1 and 2 B 3.4.1-2 Revision 23 BASES BACKGROUND The subcooled water enters the bottom of the fuel channels (continued) and contacts the fuel cladding, where heat is transferred to the coolant. As it rises, the coolant begins to boil, creating steam voids within the fuel channel that continue
 
until the coolant exits the core. Because of reduced
 
moderation, the steam voiding introduces negative reactivity
 
that must be compensated for to maintain or to increase
 
reactor power. The recirculation flow control allows
 
operators to increase recirculation flow and sweep some of
 
the voids from the fuel channel, overcoming the negative
 
reactivity void effect. Thus, the reason for having
 
variable recirculation flow is to compensate for reactivity
 
effects of boiling over a wide range of power generation (i.e., approximately 65 to 100% RTP) without having to move
 
control rods and disturb desirable flux patterns.
Each recirculation loop is manually started from the control
 
room. The recirculation flow control valves provide
 
regulation of individual recirculation loop drive flows. 
 
The flow in each loop can be manually or automatically
 
controlled.
 
APPLICABLE The operation of the Reactor Recirculation System is SAFETY ANALYSES an initial condition assumed in the design basis loss of coolant accident (LOCA) (Ref. 1). During a LOCA caused by a
 
recirculation loop pipe break, the intact loop is assumed to
 
provide coolant flow during the first few seconds of the
 
accident. The initial core flow decrease is rapid because
 
the recirculation pump in the broken loop ceases to pump
 
reactor coolant to the vessel almost immediately. The pump
 
in the intact loop coasts down relatively slowly. This pump
 
coastdown governs the core flow response for the next
 
several seconds until the jet pump suction is uncovered (Ref. 2). The analyses assume that both loops are operating
 
at the same flow prior to the accident. However, the LOCA
 
analysis was reviewed for the case with a flow mismatch
 
between the two loops, with the pipe break assumed to be in
 
the loop with the higher flow. While the flow coastdown and
 
core response are potentially more severe in this assumed
 
case (since the intact loop starts at a lower flow rate and
 
the core response is the same as if both loops were
 
operating at a lower flow rate), a small mismatch has been
 
determined to be acceptable based on engineering judgement.
(continued)
Recirculation Loops Operating B 3.4.1 LaSalle 1 and 2 B 3.4.1-3 Revision 23 BASES APPLICABLE The recirculation system is also assumed to have sufficient SAFETY ANALYSES flow coastdown characteristics to maintain fuel thermal (continued) margins during abnormal operational transients (Ref. 2), which are analyzed in Chapter 15 of the UFSAR.
 
A plant specific LOCA analysis has been performed assuming
 
only one operating recirculation loop. This analysis has
 
demonstrated that, in the event of a LOCA caused by a pipe
 
break in the operating recirculation loop, the Emergency
 
Core Cooling System response will provide adequate core
 
cooling, provided the APLHGR and LHGR requirements are
 
modified accordingly (Ref. 3).
 
The transient analyses in Chapter 15 of the UFSAR have also
 
been performed for single recirculation loop operation (Ref. 3) and demonstrate sufficient flow coastdown
 
characteristics to maintain fuel thermal margins during the
 
abnormal operational transients analyzed provided the MCPR
 
requirements are modified. During single recirculation loop
 
operation, modification to the Reactor Protection System
 
average power range monitor (APRM) and the Rod Block Monitor (RBM) Allowable Values is also required to account for the
 
different relationships between recirculation drive flow and
 
reactor core flow. The APLHGR, LHGR, and MCPR limits for
 
single loop operation are specified in the COLR. The APRM
 
Flow Biased Simulated Thermal Power-Upscale Allowable Value
 
is in LCO 3.3.1.1, "Reactor Protection System (RPS)
 
Instrumentation."  The Rod Block Monitor-Upscale Allowable
 
Value is specified in the COLR. 
 
Recirculation loops operating satisfies Criterion 2 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO Two recirculation loops are normally required to be in operation with their flows matched within the limits
 
specified in SR 3.4.1.1 to ensure that during a LOCA caused
 
by a break of the piping of one recirculation loop the
 
assumptions of the LOCA analysis are satisfied. With the
 
limits specified in SR 3.4.1.1 not met, the recirculation
 
loop with the lower flow must be considered not in
 
operation. With only one recirculation loop in operation, (continued)
 
Recirculation Loops Operating B 3.4.1 LaSalle 1 and 2 B 3.4.1-4 Revision 23 BASES LCO modifications to the required APLHGR limits (LCO 3.2.1, (continued) "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)"),
MCPR limits (LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)"), LHGR limits (LCO 3.2.3, "LINEAR HEAT GENERATION
 
RATE (LHGR)"), APRM Flow Biased Simulated Thermal Power-
 
Upscale Allowable Value (LCO 3.3.1.1), and the Rod Block
 
Monitor-Upscale Allowable Value (LCO 3.3.2.1) must be applied
 
to allow continued operation consistent with the assumptions
 
of Reference 3.
 
APPLICABILITY In MODES 1 and 2, requirements for operation of the Reactor Recirculation System are necessary since there is
 
considerable energy in the reactor core and the limiting
 
design basis transients and accidents are assumed to occur.
In MODES 3, 4, and 5, the consequences of an accident are
 
reduced and the coastdown characteristics of the
 
recirculation loops are not important.
 
ACTIONS A.1
 
With no recirculation loops in operation, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to MODE 3 within 12 hours. In this condition, the recirculation loops are not required to be operating because of the reduced severity of design basis accidents and minimal dependence on the recirculation loop coastdown characteristics. The allowed Completion Time of 12 hours is reasonable, based on operating experience to reach MODE 3 from the full power condition in an orderly manner and without challenging plant systems.
 
B.1 and C.1
 
With both recirculation loops operating but the flows not
 
matched, the flows must be matched within 2 hours. If
 
matched flows are not restored, the recirculation loop with
 
lower flow must be declared "not in operation," as required
 
by Required Action B.1. This Required Action does not require tripping the recirculation pump in the lowest flow
 
loop when the mismatch between total jet pump flows of the 
 
(continued)
 
Recirculation Loops Operating B 3.4.1 LaSalle 1 and 2 B 3.4.1-5 Revision 23 BASES ACTIONS B.1 and C.1 (continued)
 
two loops is greater than the required limits. However, in
 
cases where large flow mismatches occur, low flow or reverse
 
flow can occur in the low flow loop jet pumps, causing
 
vibration of the jet pumps. If zero or reverse flow is
 
detected, the condition should be alleviated by changing
 
flow control valve position to re-establish forward flow or
 
by tripping the pump.
 
With the requirements of the LCO not met for reasons other
 
than Conditions A or B (e.g., one loop is "not in operation"), compliance with the LCO must be restored within
 
24 hours. A recirculation loop is considered not in
 
operation when the pump in that loop is idle or when the
 
mismatch between total jet pump flows of the two loops is
 
greater than required limits for greater than 2 hours (i.e.,
Required Action B.1 has been taken). Should a LOCA occur with one recirculation loop not in operation, the core flow
 
coastdown and resultant core response may not be bounded by
 
the LOCA analyses. Therefore, only a limited time is
 
allowed to restore the inoperable loop to operating status.
 
Alternatively, if the single loop requirements of the LCO
 
are applied to the APLHGR, LHGR, and MCPR operating limits
 
and RPS and RBM Allowable Values, operation with only one
 
recirculation loop would satisfy the requirements of the LCO
 
and the initial conditions of the accident sequence.
 
The 2 hour and 24 hour Completion Times are based on the low
 
probability of an accident occurring during this time
 
period, on a reasonable time to complete the Required
 
Action, and on frequent core monitoring by operators
 
allowing abrupt changes in core flow conditions to be
 
quickly detected.
 
D.1  If the Required Action and associated Completion Time of
 
Condition C is not met, the unit is required to be brought to a MODE in which the LCO does not apply. To achieve this
 
status, the plant must be brought to MODE 3 within 12 hours.
 
In this condition, the recirculation loops are not required (continued)
Recirculation Loops Operating B 3.4.1 LaSalle 1 and 2 B 3.4.1-6 Revision 23 BASES ACTIONS D.1 (continued) to be operating because of the reduced severity of DBAs and minimal dependence on the recirculation loop coastdown
 
characteristics. The allowed Completion Time of 12 hours is
 
reasonable, based on operating experience, to reach MODE 3
 
from full power conditions in an orderly manner and without
 
challenging plant systems.
 
SURVEILLANCE SR  3.4.1.1 REQUIREMENTS This SR ensures the recirculation loop flows are within the
 
allowable limits for mismatch. At low core flow (i.e.,
< 70% of rated core flow), the APLHGR, LHGR, and MCPR
 
requirements provide larger margins to the fuel cladding
 
integrity Safety Limit such that the potential adverse
 
effect of early boiling transition during a LOCA is reduced.
 
A larger flow mismatch can therefore be allowed when core
 
flow is < 70% of rated core flow. The recirculation loop
 
jet pump flow, as used in this Surveillance, is the
 
summation of the flows from all of the jet pumps associated
 
with a single recirculation loop.
 
The mismatch is measured in terms of percent of rated core
 
flow. If the flow mismatch exceeds the specified limits, the loop with the lower flow is considered not in operation.
 
This SR is not required when both loops are not in operation
 
since the mismatch limits are meaningless during single loop
 
or natural circulation operation. The Surveillance must be
 
performed within 24 hours after both loops are in operation.
 
The 24 hour Frequency is consistent with the Frequency for
 
jet pump OPERABILITY verification and has been shown by
 
operating experience to be adequate to detect off normal jet
 
pump loop flows in a timely manner.
 
REFERENCES 1. UFSAR, Sections 6.3 and 15.6.5.
: 2. UFSAR, Appendix G.3.1.2.
: 3. UFSAR, Section 6.B.
 
FCVs B 3.4.2 LaSalle 1 and 2 B 3.4.2-1 Revision 0 B 3.4  REACTOR COOLANT SYSTEM (RCS)
 
B 3.4.2  Flow Control Valves (FCVs)
 
BASES
 
BACKGROUND The Reactor Recirculation System is described in the Background section of the Bases for LCO 3.4.1, "Recirculation Loops Operating," which discusses the
 
operating characteristics of the system and how this affects
 
the design basis transient and accident analyses. The FCVs
 
are part of the Reactor Recirculation System.
The Recirculation Flow Control System consists of the
 
electronic and hydraulic components necessary for the
 
positioning of the two hydraulically actuated FCVs. The
 
recirculation loop flow rate can be rapidly changed within
 
the expected flow range, in response to rapid changes in
 
system demand. Limits on the system response are required
 
to minimize the impact on core flow response during certain
 
accidents and transients. Solid state control logic will
 
generate an FCV "motion inhibit" signal in response to any
 
one of several hydraulic power unit or analog control
 
circuit failure signals. The "motion inhibit" signal causes
 
hydraulic power unit shutdown and hydraulic isolation such
 
that the FCVs fail "as is."
APPLICABLE The FCV stroke rate is limited to  11% per second in SAFETY ANALYSES the opening and closing directions on a control signal failure of maximum demand. This stroke rate is an
 
assumption of the analysis of the recirculation flow control
 
failures on decreasing and increasing flow (Refs. 1 and 2).
 
During a LOCA caused by a recirculation loop pipe break, the
 
intact loop is assumed to provide coolant flow during the
 
first few seconds of the accident. The initial core flow
 
decrease is rapid because the recirculation pump in the
 
broken loop ceases to pump almost immediately since it has
 
lost suction. The pump in the intact loop coasts down
 
relatively slowly. This pump coastdown governs the core
 
flow response for the next several seconds (Ref. 3), because
 
the FCV is assumed to fail "as is" due to a motion inhibit
 
as a result of a high drywell pressure interlock. In
 
addition, the closure of a recirculation FCV concurrent with
 
a loss of coolant accident (LOCA) was analyzed during (continued)
 
FCVs B 3.4.2 LaSalle 1 and 2 B 3.4.2-2 Revision 0 BASES APPLICABLE initial licensing and found to be acceptable for a maximum SAFETY ANALYSES closure rate of 11% of stroke per second, since this event (continued) involves multiple failures.
 
Flow control valves satisfy Criterion 2 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO An FCV in each operating recirculation loop must be OPERABLE to ensure that the assumptions of the design basis transient
 
and accident analyses are satisfied.
 
APPLICABILITY In MODES 1 and 2, the FCVs are required to be OPERABLE, since during these conditions there is considerable energy
 
in the reactor core, and the limiting design basis
 
transients and accidents are assumed to occur. In MODES 3, 4, and 5, the consequences of a transient or accident are
 
reduced and OPERABILITY of the flow control valves is not
 
important.
 
ACTIONS A Note has been provided to modify the ACTIONS related to FCVs. Section 1.3, Completion Times, specifies once a
 
Condition has been entered, subsequent divisions, subsystems, components or variables expressed in the
 
Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition.
 
Section 1.3 also specifies Required Actions of the Condition
 
continue to apply for each additional failure, with
 
Completion Times based on initial entry into the Condition.
 
However, the Required Actions for inoperable FCVs provide
 
appropriate compensatory measures for separate inoperable
 
FCVs. As such, a Note has been provided that allows
 
separate Condition entry for each inoperable FCV.
 
A.1 With one or two required FCVs inoperable, the assumptions of
 
the design basis transient and accident analyses may not be
 
met and the inoperable FCV must be returned to OPERABLE
 
status or hydraulically locked within 4 hours.
 
Opening an FCV faster than the limit could result in a more
 
severe flow runout transient. Closing an FCV faster than 
 
(continued)
FCVs B 3.4.2 LaSalle 1 and 2 B 3.4.2-3 Revision 0 BASES ACTIONS A.1 (continued) the limit could result in a more severe coolant flow
 
decrease transient. Both conditions could result in
 
violation of the Safety Limit MCPR. The FCVs are designed
 
to lockup (high drywell pressure interlock) under LOCA
 
conditions. When the FCVs "lock-up", the recirculation flow
 
coastdown is adequate and the resulting calculated clad
 
temperatures are acceptable. In addition, it has been
 
calculated with the FCVs closing at the specified limit, the
 
resulting calculated clad temperatures will also be
 
acceptable. Closing an FCV faster than the limit assumed in
 
the LOCA analysis (Ref. 3) could affect the recirculation
 
flow coastdown, resulting in higher peak clad temperatures.
 
Therefore, if an FCV is inoperable, deactivating the valve
 
will essentially lock the valve in position, which will
 
prohibit the FCV from adversely affecting the DBA and
 
transient analyses. Continued operation is allowed in this
 
Condition.
 
The 4 hour Completion Time is a reasonable time period to
 
complete the Required Action, while limiting the time of
 
operation with an inoperable FCV.
 
B.1 If the FCVs are not deactivated ("locked up") within the
 
associated Completion Time, the unit must be brought to a
 
MODE in which the LCO does not apply. To achieve this
 
status, the unit must be brought to at least MODE 3 within
 
12 hours. This brings the unit to a condition where the
 
flow coastdown characteristics of the recirculation loop are
 
not important. The allowed Completion Time of 12 hours is
 
reasonable, based on operating experience, to reach MODE 3
 
from full power conditions in an orderly manner and without
 
challenging unit systems.
 
SURVEILLANCE SR  3.4.2.1 REQUIREMENTS Hydraulic power unit pilot operated 4-way valves located
 
between the servo valves and the common "open" and "close" lines are required to close in the event of a loss of
 
hydraulic pressure. When closed, these valves inhibit FCV
 
motion by blocking hydraulic pressure from the servo valve
 
(continued)
FCVs B 3.4.2 LaSalle 1 and 2 B 3.4.2-4 Revision 0 BASES SURVEILLANCE SR  3.4.2.1 (continued)
REQUIREMENTS to the common open and close lines as well as to the
 
alternate subloop. This Surveillance verifies FCV lockup on
 
a loss of hydraulic pressure.
 
The 24 month Frequency is based on the need to perform this
 
Surveillance under the conditions that apply during a plant
 
outage and the potential for an unplanned transient if the
 
Surveillance were performed with the reactor at power.
 
Operating experience has shown these components usually pass
 
the SR when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a
 
reliability standpoint.
 
SR  3.4.2.2
 
This SR ensures the overall average rate of FCV movement at
 
all positions is maintained within the analyzed limits.
 
The 24 month Frequency is based on the need to perform this
 
Surveillance under the conditions that apply during a plant
 
outage and the potential for an unplanned transient if the
 
Surveillance were performed with the reactor at power.
 
Operating experience has shown these components usually pass
 
the SR when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a
 
reliability standpoint.
 
REFERENCES 1. UFSAR, Section 15.3.2.
: 2. UFSAR, Section 15.4.5.
: 3. UFSAR, Appendix G.
 
Jet Pumps B 3.4.3 LaSalle 1 and 2 B 3.4.3-1 Revision 0 B 3.4  REACTOR COOLANT SYSTEM (RCS)
 
B 3.4.3  Jet Pumps
 
BASES
 
BACKGROUND The Reactor Recirculation System is described in the Background section of the Bases for LCO 3.4.1, "Recirculation Loops Operating," which discusses the
 
operating characteristics of the system and how these
 
characteristics affect the Design Basis Accident (DBA)
 
analyses.
The jet pumps are part of the Reactor Recirculation System
 
and are designed to provide forced circulation through the
 
core to remove heat from the fuel. The jet pumps are
 
located in the annular region between the core shroud and
 
the vessel inner wall. Because the jet pump suction
 
elevation is at two thirds core height, the vessel can be
 
reflooded and coolant level maintained at two thirds core
 
height even with the complete break of the recirculation
 
loop pipe that is located below the jet pump suction
 
elevation.
 
Each reactor coolant recirculation loop contains 10 jet
 
pumps. Recirculated coolant passes down the annulus between
 
the reactor vessel wall and the core shroud. A portion of
 
the coolant flows from the vessel, through the two external
 
recirculation loops, and becomes the driving flow for the
 
jet pumps. Each of the two external recirculation loops
 
discharges high pressure flow into an external manifold from
 
which individual recirculation inlet lines are routed to the
 
jet pump risers within the reactor vessel. The remaining
 
portion of the coolant mixture in the annulus becomes the
 
suction flow for the jet pumps. This flow enters the jet
 
pump at suction inlets and is accelerated by the drive flow.
 
The drive flow and suction flow are mixed in the jet pump
 
throat section. The total flow then passes through the jet
 
pump diffuser section into the area below the core (lower
 
plenum), gaining sufficient head in the process to drive the
 
required flow upward through the core.
 
APPLICABLE Jet pump OPERABILITY is an explicit assumption in the design SAFETY ANALYSES basis loss of coolant accident (LOCA) analysis evaluated in Reference 1.
(continued)
Jet Pumps B 3.4.3 LaSalle 1 and 2 B 3.4.3-2 Revision 0 BASES APPLICABLE The capability of reflooding the core to two-thirds core SAFETY ANALYSES height is dependent upon the structural integrity of the jet (continued) pumps. If the structural system, including the beam holding a jet pump in place, fails, jet pump displacement and
 
performance degradation could occur, resulting in an
 
increased flow area through the jet pump and a lower core
 
flooding elevation. This could adversely affect the water
 
level in the core during the reflood phase of a LOCA as well
 
as the assumed blowdown flow during a LOCA.
Jet pumps satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).
 
LCO The structural failure of any of the jet pumps could cause significant degradation in the ability of the jet pumps to
 
allow reflooding to two thirds core height during a LOCA.
 
OPERABILITY of all jet pumps is required to ensure that
 
operation of the Reactor Recirculation System will be
 
consistent with the assumptions used in the licensing basis
 
analysis (Ref. 1).
 
APPLICABILITY In MODES 1 and 2, the jet pumps are required to be OPERABLE since there is a large amount of energy in the reactor core
 
and since the limiting DBAs are assumed to occur in these
 
MODES. This is consistent with the requirements for
 
operation of the Reactor Recirculation System (LCO 3.4.1).
In MODES 3, 4, and 5, the Reactor Recirculation System is
 
not required to be in operation, and when not in operation
 
sufficient flow is not available to evaluate jet pump
 
OPERABILITY.
 
ACTIONS A.1 An inoperable jet pump can increase the blowdown area and
 
reduce the capability to reflood during a design basis LOCA.
 
If one or more of the jet pumps are inoperable, the plant
 
must be brought to a MODE in which the LCO does not apply.
 
To achieve this status, the plant must be brought to MODE 3
 
within 12 hours. The allowed Completion Time of 12 hours is
 
reasonable, based on operating experience, to reach MODE 3
 
from full power conditions in an orderly manner and without
 
challenging plant systems.
(continued)
Jet Pumps B 3.4.3 LaSalle 1 and 2 B 3.4.3-3 Revision 0 BASES  (continued)
 
SURVEILLANCE SR  3.4.3.1 REQUIREMENTS This SR is designed to detect significant degradation in jet
 
pump performance that precedes jet pump failure (Ref. 2).
 
This SR is required to be performed only when the loop has
 
forced recirculation flow since surveillance checks and
 
measurements can only be performed during jet pump
 
operation. The jet pump failure of concern is a complete
 
mixer displacement due to jet pump beam failure. Jet pump
 
plugging is also of concern since it adds flow resistance to
 
the recirculation loop. Significant degradation is
 
indicated if any two of the three specified criteria confirm
 
unacceptable deviations from established patterns or
 
relationships. The allowable deviations from the
 
established patterns have been developed based on the
 
variations experienced at plants during normal operation and
 
with jet pump assembly failures (Refs. 2 and 3). Since
 
refueling activities (fuel assembly replacement or shuffle, as well as any modifications to fuel support orifice size or
 
core plate bypass flow) can affect the relationship between
 
core flow, jet pump flow, and recirculation loop flow, these
 
relationships may need to be re-established each cycle.
 
Similarly, initial entry into extended single loop operation
 
may also require establishment of these relationships.
 
During the initial weeks of operation under such conditions, while baselining new "established patterns", engineering
 
judgement of the daily Surveillance results is used to
 
detect significant abnormalities which could indicate a jet
 
pump failure. In addition, during two recirculation loop
 
operation, the jet pump SR should be performed with balanced
 
recirculation loop drive flows (drive flow mismatch less
 
than 5%) to ensure an accurate indication of jet pump
 
performance.
 
The recirculation flow control valve (FCV) operating
 
characteristics (loop flow characteristics versus FCV
 
position) are determined by the flow resistance from the
 
loop suction through the jet pump nozzles. A change in the
 
relationship may indicate a flow restriction, loss in pump
 
hydraulic performance, leak, or new flow path between the
 
recirculation pump discharge and jet pump nozzle. For this
 
criterion, the loop flow versus FCV position relationship
 
must be verified. When both recirculation loops are
 
operating, the established FCV position should include the (continued)
Jet Pumps B 3.4.3 LaSalle 1 and 2 B 3.4.3-4 Revision 0 BASES SURVEILLANCE SR  3.4.3.1 (continued)
REQUIREMENTS loop flow characteristics for two recirculation loop
 
operation. When only one recirculation loop is operating, the established FCV position should include the loop flow
 
characteristics for single loop operation.
 
Total calculated core flow can be determined from either the
 
established THERMAL POWER-core flow relationship or the core
 
plate differential pressure-core flow relationship. Once
 
this relationship has been established, increased or reduced
 
indicated total core flow from the calculated total core
 
flow may be an indication of failures in one or several jet
 
pumps. When determining calculated total core flow in
 
single recirculation loop operation using the core plate
 
differential pressure-core flow relationship, the calculated
 
total core flow value should be derived using the
 
established core plate differential pressure - core flow
 
relationship for two recirculation loop operation.
 
Individual jet pumps in a recirculation loop typically do
 
not have the same flow. The unequal flow is due to the
 
drive flow manifold, which does not distribute flow equally
 
to all risers. The jet pump diffuser to lower 
 
plenum differential pressure pattern or relationship of one
 
jet pump to the loop average is repeatable. An appreciable
 
change in this relationship is an indication that increased (or reduced) resistance has occurred in one of the jet
 
pumps. 
 
The deviations from normal are considered indicative of a
 
potential problem in the recirculation drive flow or jet
 
pump system (Ref. 2). Normal flow ranges and established
 
jet pump differential pressure patterns are established by
 
plotting historical data as discussed in Reference 2.
 
The 24 hour Frequency has been shown by operating experience
 
to be adequate to verify jet pump OPERABILITY and is
 
consistent with the Frequency for recirculation loop
 
OPERABILITY verification.
 
This SR is modified by two Notes. Note 1 allows this
 
Surveillance not to be performed until 4 hours after the
 
associated recirculation loop is in operation, since these (continued)
Jet Pumps B 3.4.3 LaSalle 1 and 2 B 3.4.3-5 Revision 0 BASES SURVEILLANCE SR  3.4.3.1 (continued)
REQUIREMENTS checks can only be performed during jet pump operation. The
 
4 hours is an acceptable time to establish conditions
 
appropriate for data collection and evaluation. 
 
Note 2 allows this SR not to be performed until 24 hours
 
after THERMAL POWER exceeds 25% RTP. During low flow
 
conditions, jet pump noise approaches the threshold response
 
of the associated flow instrumentation and precludes the
 
collection of repeatable and meaningful data. The 24 hours
 
is an acceptable time to establish conditions appropriate to
 
perform this SR.
 
REFERENCES 1. UFSAR, Section 6.3 and Appendices G.2.2.2 and G.3.2.2.3.
: 2. GE Service Information Letter No. 330.
: 3. NUREG/CR-3052, "Closeout of IE Bulletin 80-07: BWR Jet Pump Assembly Failure," November 1984.
 
S/RVs B 3.4.4 LaSalle 1 and 2 B 3.4.4-1 Revision 0 B 3.4  REACTOR COOLANT SYSTEM (RCS)
 
B 3.4.4  Safety/Relief Valves (S/RVs)
 
BASES
 
BACKGROUND The American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (Ref. 1) requires the Reactor
 
Pressure Vessel be protected from overpressure during upset
 
conditions by self actuated safety valves. As part of the
 
nuclear pressure relief system, the size and number of
 
safety/relief valves (S/RVs) are selected such that peak
 
pressure in the nuclear system will not exceed the ASME Code
 
limits for the reactor coolant pressure boundary (RCPB).
The S/RVs are located on the main steam lines between the
 
reactor vessel and the first isolation valve within the
 
drywell. Each S/RV discharges steam through a discharge
 
line to a point below the minimum water level in the
 
suppression pool.
 
The S/RVs can actuate by either of two modes:  the safety
 
mode or the relief mode (however, for the purpose of this
 
LCO, only the safety mode is required). In the safety mode (or spring mode of operation), the direct action of the
 
steam pressure in the main steam lines will act against a
 
spring loaded disk that will pop open when the valve inlet
 
pressure exceeds the spring force. In the relief mode (or
 
power actuated mode of operation), a pneumatic
 
piston/cylinder and mechanical linkage assembly are used to
 
open the valve by overcoming the spring force, even with the
 
valve inlet pressure equal to 0 psig. The pneumatic
 
operator is arranged so that its malfunction will not
 
prevent the valve disk from lifting if steam inlet pressure
 
reaches the spring lift set pressures. In the relief mode, valves may be opened manually or automatically at the
 
selected preset pressure. Seven of the S/RVs that provide
 
the safety and relief function are part of the Automatic
 
Depressurization System specified in LCO 3.5.1, "ECCS-Operating."  The instrumentation associated with the
 
relief valve function for the ADS function is discussed in
 
LCO 3.3.5.1, "Emergency Core Cooling Systems (ECCS)
 
Instrumentation." 
(continued)
S/RVs B 3.4.4 LaSalle 1 and 2 B 3.4.4-2 Revision 4 BASES  (continued)
 
APPLICABLE The overpressure protection system must accommodate the SAFETY ANALYSES most severe pressure transient. Evaluations have determined that the most severe transient is the closure of all main
 
steam isolation valves (MSIVs) followed by reactor scram on
 
high neutron flux (i.e., failure of the direct scram
 
associated with MSIV position) (Ref. 2). For the purpose of
 
the analyses, 12 of the S/RVs are assumed to operate in the safety mode. The analysis results demonstrate that the
 
design S/RV capacity is capable of maintaining reactor
 
pressure below the ASME Code limit of 110% of vessel design
 
pressure (110% x 1250 psig = 1375 psig). This LCO helps to
 
ensure that the acceptance limit of 1375 psig is met during
 
the design basis event.
From an overpressure standpoint, the design basis events are
 
bounded by the MSIV closure with flux scram event described
 
above. For other pressurization events, such as a turbine
 
trip or generator load rejection with Main Turbine Bypass
 
System failure, the S/RVs are assumed to function. The
 
opening of the valves during the pressurization event
 
mitigates the increase in reactor vessel pressure, which
 
affects the MINIMUM CRITICAL POWER RATIO (MCPR) during these
 
events. The number of S/RVs required to mitigate these
 
events is bounded by the number required to be OPERABLE by
 
the LCO. 
 
S/RVs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).
 
LCO The safety function of 12 S/RVs is required to be OPERABLE.
The requirements of this LCO are applicable only to the capability of the S/RVs to mechanically open to relieve
 
excess pressure when the lift setpoint is exceeded (safety
 
mode). In Reference 2, an evaluation was performed to
 
establish the parametric relationship between the peak
 
vessel pressure and the number of OPERABLE S/RVs. The
 
results show that with a minimum of 12 S/RVs in the safety mode OPERABLE, the ASME Code limit of 1375 psig is not
 
exceeded.
(continued)
S/RVs B 3.4.4 LaSalle 1 and 2 B 3.4.4-3 Revision 0 BASES LCO The S/RV safety setpoints are established to ensure the ASME (continued) Code limit on peak reactor pressure is satisfied. The ASME Code specifications require the lowest safety valve be set
 
at or below vessel design pressure (1250 psig) and the
 
highest safety valve be set so the total accumulated
 
pressure does not exceed 110% of the design pressure for
 
overpressurization conditions. The transient evaluations in
 
Reference 3 involving the safety mode are based on these
 
setpoints, but also include the additional uncertainties of
 
+/- 3% of the nominal setpoint to account for potential setpoint drift to provide an added degree of conservatism.
Operation with fewer valves OPERABLE than specified, or with
 
setpoints outside the ASME limits, could result in a more
 
severe reactor response to a transient than predicted, possibly resulting in the ASME Code limit on reactor
 
pressure being exceeded.
 
The S/RVs are required to be OPERABLE to limit peak pressure
 
in the main steam lines and maintain reactor pressure within
 
acceptable limits during events that cause rapid
 
pressurization, so that MCPR is not exceeded.
 
APPLICABILITY In MODES 1, 2, and 3, the specified number of S/RVs must be OPERABLE since there may be considerable energy in the
 
reactor core and the limiting design basis transients are
 
assumed to occur. The S/RVs may be required to provide
 
pressure relief to limit peak reactor pressure.
In MODE 4, decay heat is low enough for the RHR System to
 
provide adequate cooling, and reactor pressure is low enough
 
that the overpressure limit is unlikely to be approached by
 
assumed operational transients or accidents. In MODE 5, the
 
reactor vessel head is unbolted or removed and the reactor
 
is at atmospheric pressure. The S/RV function is not needed
 
during these conditions.
 
ACTIONS A.1 and A.2 With less than the minimum number of required S/RVs
 
OPERABLE, a transient may result in the violation of the
 
ASME Code limit on reactor pressure. If one or more
 
required S/RVs are inoperable, the plant must be brought to (continued)
S/RVs B 3.4.4 LaSalle 1 and 2 B 3.4.4-4 Revision 31 BASES ACTIONS A.1 and A.2 (continued) a MODE in which the LCO does not apply. To achieve this
 
status, the plant must be brought to at least MODE 3 within
 
12 hours and to MODE 4 within 36 hours. The allowed
 
Completion Times are reasonable, based on operating
 
experience, to reach the required plant conditions from full
 
power conditions in an orderly manner and without
 
challenging plant systems.
 
SURVEILLANCE SR  3.4.4.1 REQUIREMENTS This Surveillance demonstrates that the required S/RVs will
 
open at the pressures assumed in the safety analysis of
 
Reference 2. The demonstration of the S/RV safety function
 
lift settings must be performed during shutdown, since this
 
is a bench test, and in accordance with the Inservice
 
Testing Program. The lift setting pressure shall correspond
 
to ambient conditions of the valves at nominal operating
 
temperatures and pressures. The S/RV setpoint is +/- 3% for
 
OPERABILITY; however, the valves are reset to +/- 1% during
 
the Surveillance to allow for drift. Additionally, during
 
the performance of this Surveillance, the S/RV will be
 
manually actuated by providing air to the valve actuator to
 
verify the performance of the valve actuator, lever and
 
pivot mechanism to open the valve. A Note is provided to
 
allow up to two of the required 12 S/RVs to be physically
 
replaced with S/RVs with lower setpoints. This provides
 
operational flexibility which maintains the assumptions in
 
the overpressure protection analysis.
The Frequency is specified in the Inservice Testing Program
 
which requires the valves be subjected to a bench test
 
during refueling outages. The Frequency is acceptable based
 
on industry standards and operating history.
 
REFERENCES 1. ASME, Boiler and Pressure Vessel Code, Section III.
: 2. UFSAR, Section 5.2.2.1.3.
: 3. UFSAR, Chapter 15.
: 4. ASME Code for Operation and Maintenance of Nuclear Power Plants (OM Code).
 
RCS Operational LEAKAGE B 3.4.5 LaSalle 1 and 2 B 3.4.5-1 Revision 0 B 3.4  REACTOR COOLANT SYSTEM (RCS)
 
B 3.4.5  RCS Operational LEAKAGE
 
BASES
 
BACKGROUND The RCS includes systems and components that contain or transport the coolant to or from the reactor core. The
 
pressure containing components of the RCS and the portions
 
of connecting systems out to and including the isolation
 
valves define the reactor coolant pressure boundary (RCPB).
 
The joints of the RCPB components are welded or bolted.
During plant life, the joint and valve interfaces can
 
produce varying amounts of reactor coolant LEAKAGE, through
 
either normal operational wear or mechanical deterioration.
 
Limits on RCS operational LEAKAGE are required to ensure
 
appropriate action is taken before the integrity of the RCPB
 
is impaired. This LCO specifies the types and limits of
 
LEAKAGE. This protects the RCS pressure boundary described
 
in 10 CFR 50.2, 10 CFR 50.55a(c), and GDC 55 of 10 CFR 50, Appendix A (Refs. 1, 2, and 3).
 
The safety significance of leaks from the RCPB varies widely
 
depending on the source, rate, and duration. Therefore, detection of LEAKAGE in the drywell is necessary. Methods
 
for quickly separating the identified LEAKAGE from the
 
unidentified LEAKAGE are necessary to provide the operators
 
quantitative information to permit them to take corrective
 
action should a leak occur detrimental to the safety of the
 
facility or the public.
 
A limited amount of leakage inside the drywell is expected
 
from auxiliary systems that cannot be made 100% leaktight.
 
Leakage from these systems should be detected and isolated
 
from the drywell atmosphere, if possible, so as not to mask
 
RCS operational LEAKAGE detection.
 
This LCO deals with protection of the RCPB from degradation
 
and the core from inadequate cooling, in addition to
 
preventing the accident analyses radiation release
 
assumptions from being exceeded. The consequences of
 
violating this LCO include the possibility of a loss of
 
coolant accident.
 
(continued)
RCS Operational LEAKAGE B 3.4.5 LaSalle 1 and 2 B 3.4.5-2 Revision 0 BASES  (continued)
 
APPLICABLE The allowable RCS operational LEAKAGE limits are based on SAFETY ANALYSES the predicted and experimentally observed behavior of pipe cracks. The normally expected background LEAKAGE due to
 
equipment design and the detection capability of the
 
instrumentation for determining system LEAKAGE were also
 
considered. The evidence from experiments suggests, for
 
LEAKAGE even greater than the specified unidentified LEAKAGE
 
limits, the probability is small that the imperfection or
 
crack associated with such LEAKAGE would grow rapidly.
The unidentified LEAKAGE flow limit allows time for
 
corrective action before the RCPB could be significantly
 
compromised. The 5 gpm limit is a small fraction of the
 
calculated flow from a critical crack in the primary system
 
piping. Crack behavior from experimental programs (Refs. 4
 
and 5) shows leak rates of hundreds of gallons per minute
 
will precede crack instability (Ref. 6).
 
The low limit on increase in unidentified LEAKAGE assumes a
 
failure mechanism of intergranular stress corrosion cracking (IGSCC) that produces tight cracks. This flow increase
 
limit is capable of providing an early warning of such
 
deterioration.
 
No applicable safety analysis assumes the total LEAKAGE
 
limit. The total LEAKAGE limit considers RCS inventory
 
makeup capability and drywell sump capacity.
 
RCS operational LEAKAGE satisfies Criterion 2 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO RCS operational LEAKAGE shall be limited to:
: a. Pressure Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, being
 
indicative of material degradation. LEAKAGE of this
 
type is unacceptable as the leak itself could cause
 
further deterioration, resulting in higher LEAKAGE.
 
Violation of this LCO could result in continued
 
degradation of the RCPB. LEAKAGE past seals and
 
gaskets is not pressure boundary LEAKAGE.
(continued)
RCS Operational LEAKAGE B 3.4.5 LaSalle 1 and 2 B 3.4.5-3 Revision 0 BASES LCO b. Unidentified LEAKAGE (continued)
Five gpm of unidentified LEAKAGE is allowed as a
 
reasonable minimum detectable amount that the drywell
 
atmosphere monitoring, drywell sump flow monitoring, and drywell air cooler condensate flow rate monitoring
 
equipment can detect within a reasonable time period.
 
Violation of this LCO could result in continued
 
degradation of the RCPB.
: c. Total LEAKAGE The total LEAKAGE limit is based on a reasonable
 
minimum detectable amount. The limit also accounts
 
for LEAKAGE from known sources (identified LEAKAGE).
 
Violation of this LCO indicates an unexpected amount
 
of LEAKAGE and, therefore, could indicate new or
 
additional degradation in an RCPB component or system.
: d. Unidentified LEAKAGE Increase An unidentified LEAKAGE increase of
> 2 gpm within the previous 24 hour period indicates a potential flaw in
 
the RCPB and must be quickly evaluated to determine
 
the source and extent of the LEAKAGE. The increase is
 
measured relative to the steady state value; temporary
 
changes in LEAKAGE rate as a result of transient
 
conditions (e.g., startup) are not considered. As
 
such, the 2 gpm increase limit is only applicable in
 
MODE 1 when operating pressures and temperatures are
 
established. Violation of this LCO could result in
 
continued degradation of the RCPB.
 
APPLICABILITY In MODES 1, 2, and 3, the RCS operational LEAKAGE LCO applies because the potential for RCPB LEAKAGE is greatest
 
when the reactor is pressurized.
In MODES 4 and 5, RCS operational LEAKAGE limits are not
 
required since the reactor is not pressurized and stresses
 
in the RCPB materials and potential for LEAKAGE are reduced.
(continued)
RCS Operational LEAKAGE B 3.4.5 LaSalle 1 and 2 B 3.4.5-4 Revision 0 BASES  (continued)
 
ACTIONS A.1 With RCS unidentified or total LEAKAGE greater than the
 
limits, actions must be taken to reduce the leak. Because
 
the LEAKAGE limits are conservatively below the LEAKAGE that
 
would constitute a critical crack size, 4 hours is allowed
 
to reduce the LEAKAGE rates before the reactor must be shut
 
down. If an unidentified LEAKAGE has been identified and
 
quantified, it may be reclassified and considered as
 
identified LEAKAGE. However, the total LEAKAGE limit would
 
remain unchanged.
 
B.1 and B.2
 
An unidentified LEAKAGE increase of > 2 gpm within a 24 hour
 
period is an indication of a potential flaw in the RCPB and
 
must be quickly evaluated. Although the increase does not
 
necessarily violate the absolute unidentified LEAKAGE limit, certain susceptible components must be determined not to be
 
the source of the LEAKAGE increase within the required
 
Completion Time. For an unidentified LEAKAGE increase
 
greater than required limits, an alternative to reducing
 
LEAKAGE increase to within limits (i.e., reducing the
 
leakage rate such that the current rate is less than the "2
 
gpm increase in the previous 24 hours" limit; either by
 
isolating the source or other possible methods) is to verify
 
the source of the unidentified leakage increase is not
 
material susceptible to IGSCC.
 
The 4 hour Completion Time is needed to properly reduce the
 
LEAKAGE increase or verify the source before the reactor
 
must be shut down.
 
C.1 and C.2
 
If any Required Action and associated Completion Time of
 
Condition A or B is not met or if pressure boundary LEAKAGE
 
exists, the plant must be brought to a MODE in which the LCO
 
does not apply. To achieve this status, the plant must be
 
brought to MODE 3 within 12 hours and to MODE 4 within
 
36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant
 
conditions from full power conditions in an orderly manner
 
and without challenging plant systems.
(continued)
RCS Operational LEAKAGE B 3.4.5 LaSalle 1 and 2 B 3.4.5-5 Revision 0 BASES  (continued)
 
SURVEILLANCE SR  3.4.5.1 REQUIREMENTS The RCS LEAKAGE is monitored by a variety of instruments
 
designed to provide alarms when LEAKAGE is indicated and to
 
quantify the various types of LEAKAGE. Leakage detection
 
instrumentation is discussed in more detail in the Bases for
 
LCO 3.4.7, "RCS Leakage Detection Instrumentation."  Sump
 
level and flow rate are typically monitored to determine
 
actual LEAKAGE rates. However, any method may be used to
 
quantify LEAKAGE provided the method has suitable
 
sensitivity to satisfy the requirements of LCO 3.4.5. In
 
conjunction with alarms and other administrative controls, a
 
12 hour Frequency for this Surveillance is appropriate for
 
identifying changes in LEAKAGE and for tracking required
 
trends (Ref. 7).
 
REFERENCES 1. 10 CFR 50.2.
: 2. 10 CFR 50.55a(c).
: 3. 10 CFR 50, Appendix A, GDC 55.
: 4. GEAP-5620, "Failure Behavior in ASTM A106 B Pipes Containing Axial Through-Wall Flaws," April 1968.
: 5. NUREG-75/067, "Investigation and Evaluation of Cracking in Austenitic Stainless Steel Piping of
 
Boiling Water Reactor Plants," October 1975.
: 6. UFSAR, Section 5.2.5.5.2.
: 7. Generic Letter 88-01, Supplement 1, February 1992.
 
RCS PIV Leakage B 3.4.6 LaSalle 1 and 2 B 3.4.6-1 Revision 0 B 3.4  REACTOR COOLANT SYSTEM (RCS)
 
B 3.4.6  RCS Pressure Isolation Valve (PIV) Leakage
 
BASES
 
BACKGROUND The function of RCS PIVs is to separate the high pressure RCS from an attached low pressure system. This protects the
 
RCS pressure boundary described in 10 CFR 50.2, 10 CFR 50.55a(c), and GDC 55 of 10 CFR 50, Appendix A (Refs. 1, 2, and 3). PIVs are designed to meet the
 
requirements of Reference 4. During their lives, these
 
valves can produce varying amounts of reactor coolant
 
leakage through either normal operational wear or mechanical
 
deterioration.
The RCS PIV LCO allows RCS high pressure operation when
 
leakage through these valves exists in amounts that do not
 
compromise safety. The PIV leakage limit applies to each
 
individual valve. Leakage through these valves is not
 
included in any allowable LEAKAGE specified in LCO 3.4.5, "RCS Operational LEAKAGE."
 
Although this Specification provides a limit on allowable
 
PIV leakage rate, its main purpose is to prevent
 
overpressure failure of the low pressure portions of
 
connecting systems. The leakage limit is an indication that
 
the PIVs between the RCS and the connecting systems are
 
degraded or degrading. PIV leakage could lead to
 
overpressure of the low pressure piping or components.
 
Failure consequences could be a loss of coolant accident (LOCA) outside of containment, an unanalyzed accident which
 
could degrade the ability for low pressure injection.
 
A study (Ref. 5) evaluated various PIV configurations to
 
determine the probability of intersystem LOCAs. This study
 
concluded that periodic leakage testing of the PIVs can
 
substantially reduce intersystem LOCA probability.
 
PIVs are provided to isolate the RCS from the following
 
connected systems:
: a. Residual Heat Removal (RHR) System;
: b. Low Pressure Core Spray System; (continued)
RCS PIV Leakage B 3.4.6 LaSalle 1 and 2 B 3.4.6-2 Revision 0 BASES BACKGROUND c. High Pressure Core Spray System; and
 
  (continued) d. Reactor Core Isolation Cooling System.
 
The PIVs are listed in the Technical Requirements Manual (Ref. 6).
 
APPLICABLE Reference 5 evaluated various PIV configurations, leakage SAFETY ANALYSES testing of the valves, and operational changes to determine the effect on the probability of intersystem LOCAs. This
 
study concluded that periodic leakage testing of the PIVs
 
can substantially reduce the probability of an intersystem
 
LOCA. PIV leakage is not considered in any Design Basis Accident
 
analyses. This Specification provides for monitoring the
 
condition of the reactor coolant pressure boundary (RCPB) to
 
detect PIV degradation that has the potential to cause a
 
LOCA outside of containment. 
 
RCS PIV leakage satisfies Criterion 2 of 
 
10 CFR 50.36(c)(2)(ii).
 
LCO RCS PIV leakage is leakage into closed systems connected to the RCS. Isolation valve leakage is usually on the order of
 
drops per minute. Leakage that increases significantly
 
suggests that something is operationally wrong and
 
corrective action must be taken. Violation of this LCO
 
could result in continued degradation of a PIV, which could
 
lead to overpressurization of a low pressure system and the
 
loss of the integrity of a fission product barrier.
The LCO PIV leakage limit is 0.5 gpm per nominal inch of
 
valve size with a maximum limit of 5 gpm (Ref. 4).
Reference 7 permits leakage testing at a lower pressure
 
differential than between the specified maximum RCS pressure
 
and the normal pressure of the connected system during RCS
 
operation (the maximum pressure differential). The observed
 
rate may be adjusted to the maximum pressure differential by
 
assuming leakage is directly proportional to the pressure
 
differential to the one-half power.
 
(continued)
RCS PIV Leakage B 3.4.6 LaSalle 1 and 2 B 3.4.6-3 Revision 0 BASES  (continued)
 
APPLICABILITY In MODES 1, 2, and 3, this LCO applies because the PIV leakage potential is greatest when the RCS is pressurized. 
 
In MODE 3, valves in the RHR flowpath are not required to
 
meet the requirements of this LCO when in, or during
 
transition to or from, the RHR shutdown cooling mode of
 
operation.
In MODES 4 and 5, leakage limits are not provided because
 
the lower reactor coolant pressure results in a reduced
 
potential for leakage and for a LOCA outside the
 
containment. Accordingly, the potential for the
 
consequences of reactor coolant leakage is far lower during
 
these MODES.
 
ACTIONS The ACTIONS are modified by two Notes. Note 1 has been provided to modify the ACTIONS related to RCS PIV flow
 
paths. Section 1.3, Completion Times, specifies once a
 
Condition has been entered, subsequent divisions, subsystems, components or variables expressed in the
 
Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition.
 
Section 1.3 also specifies Required Actions of the Condition
 
continue to apply for each additional failure, with
 
Completion Times based on initial entry into the Condition.
 
However, the Required Actions for the Condition of RCS PIV
 
leakage limits exceeded provide appropriate compensatory
 
measures for separate, affected RCS PIV flow paths. As
 
such, a Note has been provided that allows separate
 
Condition entry for each affected RCS PIV flow path. Note 2
 
requires an evaluation of affected systems if a PIV is
 
inoperable. The leakage may have affected system
 
OPERABILITY, or isolation of a leaking flow path with an
 
alternate valve may have degraded the ability of the
 
interconnected system to perform its safety function. As a
 
result, the applicable Conditions and Required Actions for
 
systems made inoperable by PIVs must be entered. This
 
ensures appropriate remedial actions are taken, if
 
necessary, for the affected systems.
 
A.1 and A.2
 
If leakage from one or more RCS PIVs is not within limit, the flow path must be isolated by at least one closed (continued)
RCS PIV Leakage B 3.4.6 LaSalle 1 and 2 B 3.4.6-4 Revision 0 BASES ACTIONS A.1 and A.2 (continued) manual, de-activated automatic, or check valve within
 
4 hours. Required Action A.1 and Required Action A.2 are
 
modified by a Note stating that the valves used for
 
isolation must meet the same leakage requirements as the
 
PIVs and must be on the RCPB or the high pressure portion of
 
the system.
Four hours provides time to reduce leakage in excess of the
 
allowable limit and to isolate the flow path if leakage
 
cannot be reduced while corrective actions to reseat the
 
leaking PIVs are taken. The 4 hours allows time for these
 
actions and restricts the time of operation with leaking
 
valves.
 
Required Action A.2 specifies that the double isolation
 
barrier of two valves be restored by closing another valve
 
qualified for isolation or restoring one leaking PIV. The
 
72 hour Completion Time after exceeding the limit considers
 
the time required to complete the Required Action, the low
 
probability of a second valve failing during this time
 
period, and the low probability of a pressure boundary
 
rupture of the low pressure ECCS piping when overpressurized
 
to reactor pressure (Ref. 7).
 
B.1 and B.2
 
If leakage cannot be reduced or the system isolated, the
 
plant must be brought to a MODE in which the LCO does not
 
apply. To achieve this status, the plant must be brought to
 
MODE 3 within 12 hours and to MODE 4 within 36 hours. This
 
action may reduce the leakage and also reduces the potential
 
for a LOCA outside the containment. The Completion Times
 
are reasonable, based on operating experience, to achieve
 
the required plant conditions from full power conditions in
 
an orderly manner and without challenging plant systems.
 
SURVEILLANCE SR  3.4.6.1 REQUIREMENTS Performance of leakage testing on each RCS PIV is required
 
to verify that leakage is below the specified limit and to
 
identify each leaking valve. The leakage limit of 0.5 gpm (continued)
RCS PIV Leakage B 3.4.6 LaSalle 1 and 2 B 3.4.6-5 Revision 31 BASES SURVEILLANCE SR  3.4.6.1 (continued)
REQUIREMENTS per inch of nominal valve diameter up to 5 gpm maximum
 
applies to each valve. Leakage testing requires a stable
 
pressure condition. As stated in the LCO section of the
 
Bases, the test pressure may be at a lower pressure than the
 
maximum pressure differential (at the maximum pressure of
 
1050 psig) provided the observed leakage rate is adjusted in
 
accordance with Reference 4. For the two PIVs tested in
 
series, the leakage requirement applies to each valve
 
individually and not to the combined leakage across both
 
valves (i.e., the leakage acceptance criteria is the
 
criteria for one valve to account for the condition where
 
all of the leakage is through one valve). If the PIVs are
 
not individually leakage tested, one valve may have failed
 
completely and not be detected if the other valve in series
 
meets the leakage requirement. In this situation, the
 
protection provided by redundant valves would be lost.
 
The Frequency required by the Inservice Testing Program is
 
within the ASME OM Code Frequency requirement and is based on the need to perform this Surveillance under the
 
conditions that apply during an outage and the potential for
 
an unplanned transient if the Surveillance were performed
 
with the reactor at power.
 
This SR is modified by a Note that states the leakage
 
Surveillance is only required to be performed in MODES 1
 
and 2. Entry into MODE 3 is permitted for leakage testing
 
at high differential pressures with stable conditions not
 
possible in the lower MODES.
 
REFERENCES 1. 10 CFR 50.2.
: 2. 10 CFR 50.55a(c).
: 3. 10 CFR 50, Appendix A, GDC 55.
: 4. ASME Code for Operation and Maintenance of Nuclear Power Plants (OM Code). 
: 5. NUREG-0677, "The Probability of Intersystem LOCA:
Impact Due to Leak Testing and Operational Changes,"
May 1980.
(continued)
RCS PIV Leakage B 3.4.6 LaSalle 1 and 2 B 3.4.6-6 Revision 0 BASES REFERENCES 6. Technical Requirements Manual.
 
  (continued) 7. NEDC-31339, "BWR Owners Group Assessment of Emergency Core Cooling System Pressurization in Boiling Water
 
Reactors," November 1986.
 
RCS Leakage Detection Instrumentation B 3.4.7 LaSalle 1 and 2 B 3.4.7-1 Revision 22 B 3.4  REACTOR COOLANT SYSTEM (RCS)
 
B 3.4.7  RCS Leakage Detection Instrumentation
 
BASES
 
BACKGROUND GDC 30 of 10 CFR 50, Appendix A (Ref. 1), requires means for detecting and, to the extent practical, identifying the
 
location of the source of RCS LEAKAGE. Regulatory Guide 1.45 (Ref. 2) describes acceptable methods for selecting leakage
 
detection systems.
Limits on LEAKAGE from the reactor coolant pressure boundary (RCPB) are required so that appropriate action can be taken
 
before the integrity of the RCPB is impaired (Ref. 2). 
 
Leakage detection systems for the RCS are provided to alert
 
the operators when leakage rates above normal background
 
levels are detected and also to supply quantitative
 
measurement of rates. The Bases for LCO 3.4.5, "RCS
 
Operational LEAKAGE," discuss the limits on RCS LEAKAGE rates.
 
Systems for separating the LEAKAGE of an identified source
 
from an unidentified source are necessary to provide prompt
 
and quantitative information to the operators to permit them
 
to take immediate corrective action.
 
LEAKAGE from the RCPB inside the drywell is detected by at
 
least one of three independently monitored variables, such as
 
drywell air cooler condensate flow rate, sump flow rate, and
 
drywell gaseous and particulate radioactivity levels. The
 
primary means of quantifying LEAKAGE in the drywell is the
 
drywell floor drain sump flow monitoring system.
 
The drywell floor drain sump flow monitoring system monitors
 
the LEAKAGE collected in the floor drain sump. This
 
unidentified LEAKAGE consists of LEAKAGE from control rod
 
drives, valve flanges or packings, floor drains, the closed
 
cooling water subsystems, and drywell air cooling unit
 
condensate drains, and any LEAKAGE not collected in the
 
drywell equipment drain sump. The drywell floor drain sump
 
has a weir level transmitter that supplies floor drain sump
 
fill-up rate flow indication in the main control room. The drywell floor drain sump flow monitoring system contains an additional method of measuring drywell floor drain sump flow through the use of a magnetic flow meter. The flow meter is installed on the piping that runs parallel to the sump pump piping. When in use, the magnetic flow meter measures a (continued)
RCS Leakage Detection Instrumentation B 3.4.7 LaSalle 1 and 2 B 3.4.7-2 Revision 22 BASES BACKGROUND continuous flow in the line and will display a flow rate in    (continued) the control room.
The floor drain sump has level switches that start and stop the sump pumps when required. The sump pump which is selected Lead starts on a high level in the sump. The other
 
pump starts, and a control room alarm is annunciated, if the
 
sump level reaches the high-high level. The pumps stop when
 
low level is reached in the sump. A timer starts each time
 
the first sump pump starts. A second timer starts when the
 
pump is stopped. If the pump takes longer than a given time
 
to pump down the sump, or if the pump starts too soon after
 
the previous pumpdown, an alarm is sounded in the control
 
room indicating a higher than normal sump fill-up rate. 
 
A flow monitor in the discharge line of the drywell floor drain sump pumps provides flow input to a flow totalizer, which is indicated in the control room. The magnetic flow meter indication also provides an input to the flow totalizer. The totalizer inputs can be swapped using hand switches located in the Auxiliary Electric Equipment Room and the Reactor Building. Both monitors cannot be used simultaneously. The flow totalizer can be used to quantify the amount of inputs.
The drywell air monitoring systems continuously monitor the
 
drywell atmosphere for airborne particulate and gaseous
 
radioactivity. A sudden increase of radioactivity, which
 
may be attributed to RCPB steam or reactor water LEAKAGE, is
 
annunciated in the control room. The drywell atmosphere
 
particulate and gaseous radioactivity monitoring systems are
 
not capable of quantifying leakage rates, but are sensitive
 
enough to indicate increased LEAKAGE rates of 1 gpm within
 
1 hour. Larger changes in LEAKAGE rates are detected in
 
proportionally shorter times (Ref. 3).
 
Condensate from the drywell coolers is routed to the drywell
 
floor drain sump and is monitored by a flow transmitter that
 
provides indication and alarms in the control room. This
 
drywell air cooler condensate flow rate monitoring system
 
serves as an added indicator, but not quantifier, of RCS
 
unidentified LEAKAGE.
 
APPLICABLE A threat of significant compromise to the RCPB exists if the SAFETY ANALYSES barrier contains a crack that is large enough to propagate  (continued)
RCS Leakage Detection Instrumentation B 3.4.7 LaSalle 1 and 2 B 3.4.7-3 Revision 22 BASES APPLICABLE rapidly. LEAKAGE rate limits are set low enough to detect SAFETY ANALYSES the LEAKAGE emitted from a single crack in the RCPB (Refs. 4 (continued) and 5). Each of the leakage detection systems inside the drywell is designed with the capability of detecting LEAKAGE
 
less than the established LEAKAGE rate limits and providing
 
appropriate alarm of excess LEAKAGE in the control room. A
 
control room alarm allows the operators to evaluate the
 
significance of the indicated LEAKAGE and, if necessary, shut down the reactor for further investigation and
 
corrective action. The allowed LEAKAGE rates are well below
 
the rates predicted for critical crack sizes (Ref. 6).
 
Therefore, these actions provide adequate response before a
 
significant break in the RCPB can occur.
RCS leakage detection instrumentation satisfies Criterion 1
 
of 10 CFR 50.36(c)(2)(ii).
 
LCO The drywell floor drain sump flow monitoring system is required to quantify the unidentified LEAKAGE from the RCS.
 
Thus, for the system to be considered OPERABLE, the floor
 
drain sump fillup rate monitor or the magnetic flow meter portion of the system must be OPERABLE. The other
 
monitoring systems provide early alarms to the operators so
 
closer examination of other detection systems will be made
 
to determine the extent of any corrective action that may be
 
required. With the leakage detection systems inoperable, monitoring for LEAKAGE in the RCPB is degraded.
 
APPLICABILITY In MODES 1, 2, and 3, leakage detection systems are required to be OPERABLE to support LCO 3.4.5. This Applicability is
 
consistent with that for LCO 3.4.5.
 
ACTIONS A.1 With the drywell floor drain sump flow monitoring system
 
inoperable, no other form of sampling can provide the
 
equivalent information to quantify leakage. However, the
 
drywell atmospheric activity monitor and the drywell air
 
cooler condensate flow rate monitor will provide indications
 
of changes in leakage.
 
  (continued)
RCS Leakage Detection Instrumentation B 3.4.7 LaSalle 1 and 2 B 3.4.7-4 Revision 22 BASES ACTIONS With the drywell floor drain sump flow monitoring system (continued) inoperable, but with RCS unidentified and total LEAKAGE being determined every 12 hours (SR 3.4.5.1), operation may
 
continue for 30 days. The 30 day Completion Time of
 
Required Action A.1 is acceptable, based on operating
 
experience, considering the multiple forms of leakage
 
detection that are still available.
B.1  With both gaseous and particulate drywell atmospheric
 
monitoring channels inoperable (i.e., the required drywell
 
atmospheric monitoring system), grab samples of the drywell
 
atmosphere shall be taken and analyzed to provide periodic
 
leakage information. Provided a sample is obtained and
 
analyzed every 12 hours, the plant may continue operation
 
since at least one other form of drywell leakage detection (i.e., air cooler condensate flow rate monitor) is
 
available.
 
The 12 hour interval provides periodic information that is
 
adequate to detect LEAKAGE. 
 
C.1 With the required drywell air cooler condensate flow rate
 
monitoring system inoperable, SR 3.4.7.1 is performed every
 
8 hours to provide periodic information of activity in the
 
drywell at a more frequent interval than the routine
 
Frequency of SR 3.4.7.1. The 8 hour interval provides
 
periodic information that is adequate to detect LEAKAGE and
 
recognizes that other forms of leakage detection are
 
available. However, this Required Action is modified by a
 
Note that allows this action to be not applicable if the
 
required drywell atmospheric monitoring system is
 
inoperable. Consistent with SR 3.0.1, Surveillances are not
 
required to be performed on inoperable equipment.
 
D.1 and D.2
 
With both the gaseous and particulate drywell atmospheric
 
monitor channels and the drywell air cooler condensate flow
 
rate monitor inoperable, the only means of detecting LEAKAGE
 
is the drywell floor drain sump flow monitor. This (continued)
RCS Leakage Detection Instrumentation B 3.4.7 LaSalle 1 and 2 B 3.4.7-5 Revision 19 BASES ACTIONS D.1 and D.2 (continued)
Condition does not provide the required diverse means of
 
leakage detection. The Required Action is to restore either
 
of the inoperable monitors to OPERABLE status within 30 days
 
to regain the intended leakage detection diversity. The
 
30 day Completion Time ensures that the plant will not be
 
operated in a degraded configuration for a lengthy time
 
period. E.1 and E.2
 
If any Required Action of Condition A, B, C, or D cannot be
 
met within the associated Completion Time, the plant must be
 
brought to a MODE in which the LCO does not apply. To
 
achieve this status, the plant must be brought to at least
 
MODE 3 within 12 hours and to MODE 4 within 36 hours. The
 
allowed Completion Times are reasonable, based on operating
 
experience, to reach the required plant conditions in an
 
orderly manner and without challenging plant systems.
 
F.1 With all required monitors inoperable, no required automatic
 
means of monitoring LEAKAGE are available, and immediate
 
plant shutdown in accordance with LCO 3.0.3 is required.
 
SURVEILLANCE The Surveillances are modified by a Note to indicate that REQUIREMENTS when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated
 
Conditions and Required Actions may be delayed for up to 6
 
hours, provided the other required instrumentation (the
 
drywell sump flow monitoring system, drywell atmospheric
 
monitoring channel, or the drywell air cooler condensate
 
flow monitoring system, as applicable) is OPERABLE. Upon (continued)
RCS Leakage Detection Instrumentation B 3.4.7 LaSalle 1 and 2 B 3.4.7-6 Revision 0 BASES SURVEILLANCE completion of the Surveillance, or expiration of the 6 hour REQUIREMENTS allowance, the channel must be returned to OPERABLE status (continued) or the applicable Condition entered and Required Actions taken. The 6 hour testing allowance is acceptable since it
 
does not significantly reduce the probability of properly
 
monitoring RCS leakage.
 
SR  3.4.7.1
 
This SR requires the performance of a CHANNEL CHECK of the
 
required drywell atmospheric monitoring system. The check
 
gives reasonable confidence that the channel is operating
 
properly. The Frequency of 12 hours is based on instrument
 
reliability and is reasonable for detecting off normal
 
conditions.
 
SR  3.4.7.2
 
This SR requires the performance of a CHANNEL FUNCTIONAL
 
TEST of the required RCS leakage detection instrumentation.
 
The test ensures that the monitors can perform their
 
function in the desired manner. The test also verifies the
 
alarm function and relative accuracy of the instrument
 
string. A successful test of the required contact(s) of a
 
channel relay may be performed by the verification of the
 
change of state of a single contact of the relay. This
 
clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a
 
relay. This is acceptable because all of the other required
 
contacts of the relay are verified by other Technical
 
Specifications and non-Technical Specifications tests at
 
least once per refueling interval with applicable
 
extensions. The Frequency of 31 days considers instrument
 
reliability, and operating experience has shown it proper
 
for detecting degradation.
 
SR  3.4.7.3
 
This SR requires the performance of a CHANNEL CALIBRATION of
 
the required RCS leakage detection instrumentation channels.
 
The calibration verifies the accuracy of the instrument
 
string, including the instruments located inside the (continued)
RCS Leakage Detection Instrumentation B 3.4.7 LaSalle 1 and 2 B 3.4.7-7 Revision 0 BASES SURVEILLANCE SR  3.4.7.3 (continued)
REQUIREMENTS drywell. The Frequency of 24 months is a typical refueling
 
cycle and considers channel reliability. Operating
 
experience has proven this Frequency is acceptable.
 
REFERENCES 1. 10 CFR 50, Appendix A, GDC 30.
: 2. Regulatory Guide 1.45, May 1973.
: 3. UFSAR, Section 5.2.5.1.1.
: 4. GEAP-5620, "Failure Behavior in ASTM A106B Pipes Containing Axial Through-Wall Flaws," April 1968.
: 5. NUREG-75/067, "Investigation and Evaluation of Cracking in Austenitic Stainless Steel Piping of
 
Boiling Water Reactor Plants," October 1975.
: 6. UFSAR, Section 5.2.5.5.2.
 
RCS Specific Activity B 3.4.8 LaSalle 1 and 2 B 3.4.8-1 Revision 0 B 3.4  REACTOR COOLANT SYSTEM (RCS)
 
B 3.4.8  RCS Specific Activity
 
BASES
 
BACKGROUND During circulation, the reactor coolant acquires radioactive materials due to release of fission products from fuel leaks
 
into the coolant and activation of corrosion products in the
 
reactor coolant. These radioactive materials in the coolant
 
can plate out in the RCS, and, at times, an accumulation
 
will break away to spike the normal level of radioactivity.
 
The release of coolant during a Design Basis Accident (DBA)
 
could send radioactive materials into the environment.
Limits on the maximum allowable level of radioactivity in
 
the reactor coolant are established to ensure, in the event
 
of a release of any radioactive material to the environment
 
during a DBA, radiation doses are maintained within the
 
limits of 10 CFR 100 (Ref. 1).
 
This LCO contains iodine specific activity limits. The
 
iodine isotopic activities per gram of reactor coolant are
 
expressed in terms of a DOSE EQUIVALENT I-131. The
 
allowable levels are intended to limit the 2 hour radiation
 
dose to an individual at the site boundary to a small
 
fraction of the 10 CFR 100 limit.
 
APPLICABLE Analytical methods and assumptions involving radioactive SAFETY ANALYSES material in the primary coolant are presented in the UFSAR (Ref. 2). The specific activity in the reactor coolant (the
 
source term) is an initial condition for evaluation of the
 
consequences of an accident due to a main steam line break (MSLB) outside containment. No fuel damage is postulated in
 
the MSLB accident, and the release of radioactive material
 
to the environment is assumed to end when the main steam
 
isolation valves (MSIVs) close completely.
This MSLB release forms the basis for determining offsite
 
doses (Ref. 2). The limits on the specific activity of the
 
primary coolant ensure that the 2 hour thyroid and whole 
 
body doses at the site boundary, resulting from an MSLB (continued)
RCS Specific Activity B 3.4.8 LaSalle 1 and 2 B 3.4.8-2 Revision 0 BASES APPLICABLE outside containment during steady state operation, will not SAFETY ANALYSES exceed 10% of the dose guidelines of 10 CFR 100.
 
  (continued)
The limit on specific activity is a value from a parametric
 
evaluation of typical site locations. This limit is
 
conservative because the evaluation considered more
 
restrictive parameters than for a specific site, such as the
 
location of the site boundary and the meteorological
 
conditions of the site.
 
RCS specific activity satisfies Criterion 2 of 
 
10 CFR 50.36(c)(2)(ii).
 
LCO The specific iodine activity is limited to  0.2 &#xb5;Ci/gm DOSE EQUIVALENT I-131. This limit ensures the source term
 
assumed in the safety analysis for the MSLB is not exceeded, so any release of radioactivity to the environment during an
 
MSLB is less than a small fraction of the 10 CFR 100 limits.
 
APPLICABILITY In MODE 1, and MODES 2 and 3 with any main steam line not isolated, limits on the primary coolant radioactivity are
 
applicable since there is an escape path for release of
 
radioactive material from the primary coolant to the
 
environment in the event of an MSLB outside of primary
 
containment.
In MODES 2 and 3 with the main steam lines isolated, such
 
limits do not apply since an escape path does not exist. In
 
MODES 4 and 5, no limits are required since the reactor is
 
not pressurized and the potential for leakage is reduced.
 
ACTIONS A.1 and A.2 When the reactor coolant specific activity exceeds the LCO
 
DOSE EQUIVALENT I-131 limit, but is  4.0 &#xb5;Ci/gm, samples must be analyzed for DOSE EQUIVALENT I-131 at least once
 
every 4 hours. In addition, the specific activity must be
 
restored to the LCO limit within 48 hours. The Completion 
 
Time of once every 4 hours is based on the time needed to
 
take and analyze a sample. The 48 hour Completion Time to (continued)
RCS Specific Activity B 3.4.8 LaSalle 1 and 2 B 3.4.8-3 Revision 19 BASES ACTIONS A.1 and A.2 (continued) restore the activity level provides a reasonable time for
 
temporary coolant activity increases (iodine spikes or crud
 
bursts) to be cleaned up with the normal processing systems.
 
A Note permits the use of the provisions of LCO 3.0.4.c.
This allowance permits entry into the applicable MODE(S) while relying on the ACTIONS. This allowance is acceptable due to the significant conservatism incorporated into the
 
specific activity limit, the low probability of an event
 
which is limiting due to exceeding this limit, and the
 
ability to restore transient specific activity excursions
 
while the plant remains at, or proceeds to power operation.
B.1, B.2.1, B.2.2.1, and B.2.2.2
 
If the DOSE EQUIVALENT I-131 cannot be restored to  0.2 &#xb5;Ci/gm within 48 hours, or if at any time it is
> 4.0 &#xb5;Ci/gm, it must be determined at least every 4 hours and all the main steam lines must be isolated within 12 hours.
 
Isolating the main steam lines precludes the possibility of
 
releasing radioactive material to the environment in an
 
amount that is more than a small fraction of the
 
requirements of 10 CFR 100 during a postulated MSLB
 
accident.
 
Alternately, the plant can be brought to MODE 3 within
 
12 hours and to MODE 4 within 36 hours. This option is
 
provided for those instances when isolation of main steam
 
lines is not desired (e.g., due to the decay heat loads).
 
In MODE 4, the requirements of the LCO are no longer
 
applicable.
 
The Completion Time of once every 4 hours is the time needed
 
to take and analyze a sample. The 12 hour Completion Time
 
is reasonable, based on operating experience, to isolate the
 
main steam lines in an orderly manner and without
 
challenging plant systems. Also, the allowed Completion
 
Times for Required Actions B.2.2.1 and B.2.2.2 for bringing
 
the plant to MODES 3 and 4 are reasonable, based on (continued)
RCS Specific Activity B 3.4.8 LaSalle 1 and 2 B 3.4.8-4 Revision 0 BASES ACTIONS B.1, B.2.1, B.2.2.1, and B.2.2.2 (continued) operating experience, to reach the required plant conditions
 
from full power conditions in an orderly manner and without
 
challenging plant systems.
 
SURVEILLANCE SR  3.4.8.1 REQUIREMENTS This Surveillance is performed to ensure iodine remains
 
within limit during normal operation. The 7 day Frequency
 
is adequate to trend changes in the iodine activity level.
 
This SR is modified by a Note that requires this
 
Surveillance to be performed only in MODE 1 because the
 
level of fission products generated in other MODES is much
 
less.
REFERENCES 1. 10 CFR 100.11.
: 2. UFSAR, Section 15.6.4.5.
 
RHR Shutdown Cooling System-Hot Shutdown B 3.4.9 LaSalle 1 and 2 B 3.4.9-1 Revision 0 B 3.4  REACTOR COOLANT SYSTEM (RCS)
 
B 3.4.9  Residual Heat Removal (RHR) Shutdown Cooling System-Hot Shutdown
 
BASES
 
BACKGROUND Irradiated fuel in the shutdown reactor core generates heat during the decay of fission products and increases the
 
temperature of the reactor coolant. This decay heat must be
 
removed to reduce the temperature of the reactor coolant to 200&deg;F in preparation for performing Refueling or Cold Shutdown maintenance operations, or the decay heat must be
 
removed for maintaining the reactor in the Hot Shutdown
 
condition.
The two redundant, manually controlled shutdown cooling
 
subsystems of the RHR System provide decay heat removal. 
 
Each loop consists of a motor driven pump, a heat exchanger, and associated piping and valves. Both loops have a common
 
suction from the same recirculation loop. Each pump
 
discharges the reactor coolant, after circulation through
 
the respective heat exchanger, to the reactor via the
 
associated recirculation loop. The RHR heat exchangers
 
transfer heat to the Residual Heat Removal Service Water
 
System (LCO 3.7.1, "Residual Heat Removal Service Water (RHRSW) System").
 
APPLICABLE Decay heat removal by the RHR System in the shutdown cooling SAFETY ANALYSES mode is not required for mitigation of any event or accident evaluated in the safety analyses. Decay heat removal is, however, an important safety function that must be
 
accomplished or core damage could result.
The RHR Shutdown Cooling System meets Criterion 4 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO Two RHR shutdown cooling subsystems are required to be OPERABLE, and, when no recirculation pump is in operation, one shutdown cooling subsystem must be in operation. An
 
OPERABLE RHR shutdown cooling subsystem consists of one
 
OPERABLE RHR pump, one heat exchanger, and the associated
 
piping and valves. Each shutdown cooling subsystem is
 
considered OPERABLE if it can be manually aligned (remote or (continued)
RHR Shutdown Cooling System-Hot Shutdown B 3.4.9    LaSalle 1 and 2 B 3.4.9-2 Revision 0 BASES LCO local) in the shutdown cooling mode for removal of decay (continued) heat. In MODE 3, one RHR shutdown cooling subsystem can provide the required cooling, but two subsystems are
 
required to be OPERABLE to provide redundancy. Operation of
 
one subsystem can maintain or reduce the reactor coolant
 
temperature as required. To ensure adequate core flow to
 
allow for accurate average reactor coolant temperature
 
monitoring, nearly continuous operation is required.
Note 1 permits both RHR shutdown cooling subsystems and
 
recirculation pumps to not be in operation for a period of
 
2 hours in an 8 hour period. Note 2 allows one RHR shutdown
 
cooling subsystem to be inoperable for up to 2 hours for
 
performance of surveillance tests. These tests may be on
 
the affected RHR System or on some other plant system or
 
component that necessitates placing the RHR System in an
 
inoperable status during the performance. This is permitted
 
because the core heat generation can be low enough and the
 
heatup rate slow enough to allow some changes to the RHR
 
subsystems or other operations requiring RHR flow
 
interruption and loss of redundancy.
 
APPLICABILITY In MODE 3 with reactor vessel pressure below the RHR cut in permissive pressure (i.e., the actual pressure at which
 
the interlock resets) the RHR Shutdown Cooling System must
 
be OPERABLE and one RHR shutdown cooling subsystem shall be
 
operated in the shutdown cooling mode to remove decay heat
 
to reduce or maintain coolant temperature. With an RHR
 
shutdown cooling subsystem not in operation, a recirculation
 
pump is required to be in operation.
In MODES 1 and 2, and in MODE 3 with reactor vessel pressure
 
greater than or equal to the RHR cut-in permissive pressure, this LCO is not applicable. Operation of the RHR System in
 
the shutdown cooling mode is not allowed above this pressure
 
because the RCS pressure may exceed the design pressure of
 
the shutdown cooling piping. Decay heat removal at reactor
 
pressures greater than or equal to the RHR cut-in permissive
 
pressure is typically accomplished by condensing the steam
 
in the main condenser. Additionally, in MODE 2, the
 
OPERABILITY requirements for the Emergency Core Cooling
 
Systems (ECCS) (LCO 3.5.1, "ECCS-Operating") do not allow
 
placing the RHR shutdown cooling subsystem into operation.
 
(continued)
RHR Shutdown Cooling System-Hot Shutdown B 3.4.9    LaSalle 1 and 2 B 3.4.9-3 Revision 19 BASES APPLICABILITY The requirements for decay heat removal in MODES 4 and 5 are (continued) discussed in LCO 3.4.10, "Residual Heat Removal (RHR)
Shutdown Cooling System-Cold Shutdown"; LCO 3.9.8, "Residual Heat Removal (RHR)-High Water Level"; and
 
LCO 3.9.9, "Residual Heat Removal (RHR)-Low Water Level."
ACTIONS A Note has been provided to modify the ACTIONS related to RHR shutdown cooling subsystems. Section 1.3, Completion
 
Times, specifies once a Condition has been entered, subsequent divisions, subsystems, components or variables
 
expressed in the Condition, discovered to be inoperable or
 
not within limits, will not result in separate entry into
 
the Condition. Section 1.3 also specifies Required Actions
 
of the Condition continue to apply for each additional
 
failure, with Completion Times based on initial entry into
 
the Condition. However, the Required Actions for inoperable
 
shutdown cooling subsystems provide appropriate compensatory
 
measures for separate inoperable shutdown cooling
 
subsystems. As such, a Note has been provided that allows
 
separate Condition entry for each inoperable RHR shutdown
 
cooling subsystem.
 
A.1, A.2, and A.3
 
With one RHR shutdown cooling subsystem inoperable for decay
 
heat removal, except as permitted by LCO Note 2, the
 
inoperable subsystem must be restored to OPERABLE status
 
without delay. In this condition, the remaining OPERABLE
 
subsystem can provide the necessary decay heat removal. The
 
overall reliability is reduced, however, because a single
 
failure in the OPERABLE subsystem could result in reduced
 
RHR shutdown cooling capability. Therefore an alternate
 
method of decay heat removal must be provided.
(continued)
RHR Shutdown Cooling System-Hot Shutdown B 3.4.9    LaSalle 1 and 2 B 3.4.9-4 Revision 0 BASES ACTIONS A.1, A.2, and A.3 (continued)
With both RHR shutdown cooling subsystems inoperable, an
 
alternate method of decay heat removal must be provided in
 
addition to that provided for the initial RHR shutdown
 
cooling subsystem inoperability. This re-establishes backup
 
decay heat removal capabilities, similar to the requirements
 
of the LCO. The 1 hour Completion Time is based on the
 
decay heat removal function and the probability of a loss of
 
the available decay heat removal capabilities.
 
The required cooling capacity of the alternate method should
 
be ensured by verifying (by calculation or demonstration)
 
its capability to maintain or reduce temperature. Decay
 
heat removal by ambient losses can be considered as, or
 
contributing to, the alternate method capability. Alternate
 
methods that can be used include (but are not limited to)
 
the Condensate/Feed and Main Steam Systems or the Reactor
 
Water Cleanup System (by itself or using feed and bleed in
 
combination with the Control Rod Drive System or
 
Condensate/Feed System), and a combination of an ECCS pump
 
and S/RVs.
 
However, due to the potentially reduced reliability of the
 
alternate methods of decay heat removal, it is also required
 
to reduce the reactor coolant temperature to the point where
 
MODE 4 is entered.
 
B.1, B.2, and B.3
 
With no RHR shutdown cooling subsystem and no recirculation
 
pump in operation, except as is permitted by LCO Note 1, reactor coolant circulation by the RHR shutdown cooling
 
subsystem or one recirculation pump must be restored without
 
delay.
 
Until RHR or recirculation pump operation is re-established, an alternate method of reactor coolant circulation must be
 
placed into service. This will provide the necessary
 
circulation for monitoring coolant temperature. The 1 hour
 
Completion Time is based on the coolant circulation function
 
and is modified such that the 1 hour is applicable (continued)
RHR Shutdown Cooling System-Hot Shutdown B 3.4.9    LaSalle 1 and 2 B 3.4.9-5 Revision 0 BASES ACTIONS B.1, B.2, and B.3 (continued) separately for each occurrence involving a loss of coolant
 
circulation. Furthermore, verification of the functioning
 
of the alternate method must be reconfirmed every 12 hours
 
thereafter. This will provide assurance of continued
 
temperature monitoring capability.
During the period when the reactor coolant is being
 
circulated by an alternate method (other than by the
 
required RHR shutdown cooling subsystem or recirculation
 
pump), the reactor coolant temperature and pressure must be
 
periodically monitored to ensure proper function of the
 
alternate method. The once per hour Completion Time is
 
deemed appropriate.
 
SURVEILLANCE SR  3.4.9.1 REQUIREMENTS This Surveillance verifies that one RHR shutdown cooling
 
subsystem or recirculation pump is in operation and
 
circulating reactor coolant. The required flow rate is
 
determined by the flow rate necessary to provide sufficient
 
decay heat removal capability. The Frequency of 12 hours is
 
sufficient in view of other visual and audible indications 
 
available to the operator for monitoring the RHR subsystem
 
in the control room.
 
This Surveillance is modified by a Note allowing sufficient
 
time to align the RHR System for shutdown cooling operation
 
after clearing the pressure interlock that isolates the
 
system, or for placing a recirculation pump in operation.
 
The Note takes exception to the requirements of the
 
Surveillance being met (i.e., forced coolant circulation is
 
not required for this initial 2 hour period), which also
 
allows entry into the Applicability of this Specification in
 
accordance with SR 3.0.4 since the Surveillance will not be "not met" at the time of entry into the Applicability.
 
REFERENCES None.
 
RHR Shutdown Cooling System-Cold Shutdown B 3.4.10 LaSalle 1 and 2 B 3.4.10-1 Revision 0 B 3.4  REACTOR COOLANT SYSTEM (RCS)
 
B 3.4.10  Residual Heat Removal (RHR) Shutdown Cooling System-Cold Shutdown
 
BASES
 
BACKGROUND Irradiated fuel in the shutdown reactor core generates heat during the decay of fission products and increases the
 
temperature of the reactor coolant. This decay heat must be
 
removed to maintain the temperature of the reactor coolant
 
at  200&deg;F in preparation for performing refueling maintenance operations, or the decay heat must be removed
 
for maintaining the reactor in the Cold Shutdown condition.
The two redundant, manually controlled shutdown cooling
 
subsystems of the RHR System provide decay heat removal. 
 
Each loop consists of a motor driven pump, a heat exchanger, and associated piping and valves. Both loops have a common
 
suction from the same recirculation loop. Each pump
 
discharges the reactor coolant, after circulation through
 
the respective heat exchanger, to the reactor via separate
 
feedwater lines or to the reactor via the associated
 
recirculation loop. The RHR heat exchangers transfer heat
 
to the Residual Heat Removal Service Water (RHRSW) System.
 
APPLICABLE Decay heat removal by the RHR System in the shutdown cooling SAFETY ANALYSES mode is not required for mitigation of any event or accident evaluated in the safety analyses. Decay heat removal is, however, an important safety function that must be
 
accomplished or core damage could result.
The RHR Shutdown Cooling System meets Criterion 4 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO Two RHR shutdown cooling subsystems are required to be OPERABLE, and, when no recirculation pump is in operation, one RHR shutdown cooling subsystem must be in operation. An
 
OPERABLE RHR shutdown cooling subsystem consists of one
 
OPERABLE RHR pump, one heat exchanger, the necessary
 
portions of the RHRSW System and Ultimate Heat Sink capable
 
of providing cooling to the heat exchanger, and the
 
associated piping and valves. Each shutdown cooling (continued)
RHR Shutdown Cooling System-Cold Shutdown B 3.4.10 LaSalle 1 and 2 B 3.4.10-2 Revision 6 BASES LCO subsystem is considered OPERABLE if it can be manually (continued) aligned (remote or local) in the shutdown cooling mode for removal of decay heat. In MODE 4, one RHR shutdown cooling
 
subsystem can provide the required cooling, but two
 
subsystems are required to be OPERABLE to provide
 
redundancy. Operation of one subsystem can maintain and
 
reduce the reactor coolant temperature as required. To
 
ensure adequate core flow to allow for accurate average
 
reactor coolant temperature monitoring, nearly continuous
 
operation is required.
Note 1 allows both RHR shutdown cooling subsystems to be
 
inoperable during hydrostatic testing. This is allowed since the RHR Shutdown Cooling System is not designed to
 
operate at the Reactor Coolant System pressures achieved
 
during hydrostatic testing. This is acceptable since
 
adequate reactor coolant circulation will be achieved by
 
operation of a reactor recirculation pump and since systems
 
are available to control reactor coolant temperature. 
 
Note 2 permits both RHR shutdown cooling subsystems and
 
recirculation pumps to not be in operation for a period of
 
2 hours in an 8 hour period. Note 3 allows one RHR shutdown
 
cooling subsystem to be inoperable for up to 2 hours for
 
performance of surveillance tests. These tests may be on
 
the affected RHR System or on some other plant system or
 
component that necessitates placing the RHR System in an
 
inoperable status during the performance. This is permitted
 
because the core heat generation can be low enough and the
 
heatup rate slow enough to allow some changes to the RHR
 
subsystems or other operations requiring RHR flow
 
interruption and loss of redundancy.
 
APPLICABILITY In MODE 4, the RHR Shutdown Cooling System must be OPERABLE and one RHR shutdown cooling subsystem shall be operated in
 
the shutdown cooling mode to remove decay heat to maintain
 
coolant temperature below 200
&deg;F. With an RHR shutdown cooling subsystem not in operation, a recirculation pump is
 
required to be in operation.
In MODES 1 and 2, and in MODE 3 with reactor vessel pressure
 
greater than or equal to the RHR cut-in permissive pressure, this LCO is not applicable. Operation of the RHR System in
 
the shutdown cooling mode is not allowed above this (continued)
RHR Shutdown Cooling System-Cold Shutdown B 3.4.10 LaSalle 1 and 2 B 3.4.10-3 Revision 13 BASES APPLICABILITY pressure because the RCS pressure may exceed the design (continued) pressure of the shutdown cooling piping. Decay heat removal at reactor pressures greater than or equal to the RHR cut-in
 
permissive pressure is typically accomplished by condensing
 
the steam in the main condenser. Additionally, in MODE 2
 
below this pressure, the OPERABILITY requirements for the
 
Emergency Core Cooling Systems (ECCS) (LCO 3.5.1, "ECCS-Operating") do not allow placing the RHR shutdown
 
cooling subsystem into operation.
The requirements for decay heat removal in MODE 3 below the
 
cut-in permissive pressure and in MODE 5 are discussed in
 
LCO 3.4.9, "Residual Heat Removal (RHR) Shutdown Cooling
 
System-Hot Shutdown"; LCO 3.9.8, "Residual Heat Removal (RHR)-High Water Level"; and LCO 3.9.9, "Residual Heat
 
Removal (RHR)-Low Water Level."
ACTIONS A Note has been provided to modify the ACTIONS related to RHR shutdown cooling subsystems. Section 1.3, Completion
 
Times,  specifies once a Condition has been entered, subsequent divisions, subsystems, components or variables
 
expressed in the Condition, discovered to be inoperable or
 
not within limits, will not result in separate entry into
 
the Condition. Section 1.3 also specifies Required Actions
 
of the Condition continue to apply for each additional
 
failure, with Completion Times based on initial entry into
 
the Condition. However, the Required Actions for inoperable
 
shutdown cooling subsystems provide appropriate compensatory measures for separate inoperable shutdown cooling
 
subsystems. As such, a Note has been provided that allows
 
separate Condition entry for each inoperable RHR shutdown
 
cooling subsystem.
 
A.1 With one of the two RHR shutdown cooling subsystems
 
inoperable, except as permitted by LCO Notes 1 and 3, the
 
remaining subsystem is capable of providing the required
 
decay heat removal. However, the overall reliability is
 
reduced. Therefore, an alternate method of decay heat
 
removal must be provided. With both RHR shutdown cooling
 
subsystems inoperable, an alternate method of decay heat (continued)
RHR Shutdown Cooling System-Cold Shutdown B 3.4.10 LaSalle 1 and 2 B 3.4.10-4 Revision 0 BASES ACTIONS A.1 (continued) removal must be provided in addition to that provided for
 
the initial RHR shutdown cooling subsystem inoperability.
 
This re-establishes backup decay heat removal capabilities, similar to the requirements of the LCO. The 1 hour
 
Completion Time is based on the decay heat removal function
 
and the probability of a loss of the available decay heat
 
removal capabilities. Furthermore, verification of the
 
functional availability of these alternate method(s) must be
 
reconfirmed every 24 hours thereafter. This will provide
 
assurance of continued heat removal capability.
 
The required cooling capacity of the alternate method should
 
be ensured by verifying (by calculation or demonstration)
 
its capability to maintain or reduce temperature. Decay
 
heat removal by ambient losses can be considered as, or
 
contributing to, the alternate method capability. Alternate
 
methods that can be used include (but are not limited to)
 
the Condensate/Feed and Main Steam Systems, the Reactor
 
Water Cleanup System (by itself or using feed and bleed in
 
combination with the Control Rod Drive System or
 
Condensate/Feed System) and a combination of an ECCS pump
 
and S/RVs.
 
B.1 and B.2
 
With no RHR shutdown cooling subsystem and no recirculation
 
pump in operation, except as is permitted by LCO Notes 1
 
and 2, and until RHR or recirculation pump operation is
 
re-established, an alternate method of reactor coolant
 
circulation must be placed into service. This will provide
 
the necessary circulation for monitoring coolant
 
temperature. The 1 hour Completion Time is based on the
 
coolant circulation function and is modified such that the
 
1 hour is applicable separately for each occurrence
 
involving a loss of coolant circulation. Furthermore, verification of the functioning of the alternate method must
 
be reconfirmed every 12 hours thereafter. This will provide
 
assurance of continued temperature monitoring capability.
 
(continued)
RHR Shutdown Cooling System-Cold Shutdown B 3.4.10 LaSalle 1 and 2 B 3.4.10-5 Revision 0 BASES ACTIONS B.1 and B.2 (continued)
During the period when the reactor coolant is being
 
circulated by an alternate method (other than by the
 
required RHR shutdown cooling subsystem or recirculation
 
pump), the reactor coolant temperature and pressure must be
 
periodically monitored to ensure proper function of the
 
alternate method. The once per hour Completion Time is
 
deemed appropriate.
 
SURVEILLANCE SR  3.4.10.1 REQUIREMENTS This Surveillance verifies that one RHR shutdown cooling
 
subsystem or recirculation pump is in operation and
 
circulating reactor coolant. The required flow rate is
 
determined by the flow rate necessary to provide sufficient
 
decay heat removal capability. The Frequency of 12 hours is
 
sufficient in view of other visual and audible indications
 
available to the operator for monitoring the RHR subsystem
 
in the control room.
 
REFERENCES None.
 
RCS P/T Limits B 3.4.11 LaSalle 1 and 2 B 3.4.11-1 Revision 16 B 3.4  REACTOR COOLANT SYSTEM (RCS)
 
B 3.4.11  RCS Pressure and Temperature (P/T) Limits
 
BASES
 
BACKGROUND All components of the RCS are designed to withstand effects of cyclic loads due to system pressure and temperature
 
changes. These loads are introduced by startup (heatup) and
 
shutdown (cooldown) operations, power transients, and
 
reactor trips. This LCO limits the pressure and temperature
 
changes during RCS heatup and cooldown, within the design
 
assumptions and the stress limits for cyclic operation.
The Specification contains P/T limit curves for heatup, cooldown, inservice leak and hydrostatic testing, and
 
criticality and also limits the maximum rate of change of
 
reactor coolant temperature. The P/T limit curves are
 
applicable for 20 effective full power years.
 
Each P/T limit curve defines an acceptable region for normal
 
operation. The usual use of the curves is operational
 
guidance during heatup or cooldown maneuvering, when
 
pressure and temperature indications are monitored and
 
compared to the applicable curve to determine that operation
 
is within the allowable region.
 
The LCO establishes operating limits that provide a margin
 
to brittle failure of the reactor vessel and piping of the
 
reactor coolant pressure boundary (RCPB). The vessel is the
 
component most subject to brittle failure. Therefore, the
 
LCO limits apply mainly to the vessel.
 
10 CFR 50, Appendix G (Ref. 1), requires the establishment
 
of P/T limits for material fracture toughness requirements
 
of the RCPB materials. Reference 1 requires an adequate
 
margin to brittle failure during normal operation, anticipated operational occurrences, and system hydrostatic
 
tests. It mandates the use of the American Society of
 
Mechanical Engineers (ASME) Code, Section III, Appendix G (Ref. 2).
 
The actual shift in the RT NDT of the vessel material will be established periodically by removing and evaluating the
 
irradiated reactor vessel material specimens, in accordance
 
with ASTM E 185 (Ref. 3) and 10 CFR 50, Appendix H  (continued)
RCS P/T Limits B 3.4.11    LaSalle 1 and 2 B 3.4.11-2 Revision 16 BASES BACKGROUND (Ref. 4). The operating P/T limit curves will be adjusted, (continued) as necessary, based on the evaluation findings and the recommendations of Reference 5.
 
The P/T limit curves are composite curves established by
 
superimposing limits derived from stress analyses of those
 
portions of the reactor vessel and head that are the most
 
restrictive. At any specific pressure, temperature, and
 
temperature rate of change, one location within the reactor
 
vessel will dictate the most restrictive limit. Across the
 
span of the P/T limit curves, different locations are more
 
restrictive, and, thus, the curves are composites of the
 
most restrictive regions.
 
The non-nuclear heatup and cooldown curve applies during
 
heatups with non-nuclear heat (e.g., recirculation pump
 
heat) and during cooldowns when the reactor is not critical (e.g., following a scram). The curve provides the minimum
 
reactor vessel metal temperatures based on the most limiting
 
vessel stress.
 
The P/T criticality limits include the Reference 1
 
requirement that they be at least 40
&deg;F above the non-critical heatup curve or the cooldown curve and not
 
lower than the minimum permissible temperature for the
 
inservice leak and hydrostatic testing.
 
The consequence of violating the LCO limits is that the RCS
 
has been operated under conditions that can result in
 
brittle failure of the RCPB, possibly leading to a
 
nonisolable leak or loss of coolant accident. In the event
 
these limits are exceeded, an evaluation must be performed
 
to determine the effect on the structural integrity of the
 
RCPB components. The ASME Code, Section XI, Appendix E (Ref. 6), provides a recommended methodology for evaluating
 
an operating event that causes an excursion outside the
 
limits.
APPLICABLE The P/T limits are not derived from Design Basis Accident SAFETY ANALYSES (DBA) analyses. They are prescribed during normal operation to avoid encountering pressure, temperature, and temperature
 
rate of change conditions that might cause undetected flaws
 
to propagate and cause nonductile failure of the RCPB, a
 
condition that is unanalyzed. Reference 5 establishes the methodology for determining the P/T limits. Since the (continued)
RCS P/T Limits B 3.4.11    LaSalle 1 and 2 B 3.4.11-3 Revision 0 BASES APPLICABLE P/T limits are not derived from any DBA, there are no SAFETY ANALYSES acceptance limits related to the P/T limits. Rather, the (continued) P/T limits are acceptance limits themselves since they preclude operation in an unanalyzed condition.
RCS P/T limits satisfy Criterion 2 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO The elements of this LCO are:
: a. RCS pressure and temperature are within the limits specified in Figures 3.4.11-1, 3.4.11-2, 3.4.11-3, 3.4.11-4, 3.4.11-5, and 3.4.11-6 heatup and cooldown
 
rates are  100&deg;F in any 1 hour period during RCS heatup, cooldown, and inservice leak and hydrostatic
 
testing, and the RCS temperature change during system
 
leakage and hydrostatic testing is  20&deg;F in any 1 hour period when the RCS temperature and pressure are not
 
within the limits of Figure 3.4.11-2 and 3.4.11-5 as
 
applicable;
: b. The temperature difference between the reactor vessel bottom head coolant and the reactor pressure vessel (RPV) coolant is  145&deg;F during recirculation pump startup in MODES 1, 2, 3, and 4;
: c. The temperature difference between the reactor coolant in the respective recirculation loop and in the
 
reactor vessel is  50&deg;F during recirculation pump startup in MODES 1, 2, 3, and 4;
: d. RCS pressure and temperature are within the applicable criticality limits specified in Figures 3.4.11-3 and
 
3.4.11-6, prior to achieving criticality; and
: e. The reactor vessel flange and the head flange temperatures are  72&deg;F for Unit 1 and  86&deg;F for Unit 2 when tensioning the reactor vessel head bolting
 
studs and when the reactor head is tensioned.
 
These limits define allowable operating regions and permit a
 
large number of operating cycles while also providing a wide
 
margin to nonductile failure.
(continued)
RCS P/T Limits B 3.4.11    LaSalle 1 and 2 B 3.4.11-4 Revision 0 BASES LCO The rate of change of temperature limits control the (continued) thermal gradient through the vessel wall and are used as inputs for calculating the heatup, cooldown, and inservice
 
leak and hydrostatic testing P/T limit curves. Thus, the
 
LCO for the rate of change of temperature restricts stresses
 
caused by thermal gradients and also ensures the validity of
 
the P/T limit curves.
Violation of the limits places the reactor vessel outside of
 
the bounds of the stress analyses and can increase stresses
 
in other RCS components. The consequences depend on several
 
factors, as follows:
: a. The severity of the departure from the allowable operating pressure temperature regime or the severity
 
of the rate of change of temperature;
: b. The length of time the limits were violated (longer violations allow the temperature gradient in the thick
 
vessel walls to become more pronounced); and
: c. The existence, size, and orientation of flaws in the vessel material.
 
APPLICABILITY The potential for violating a P/T limit exists at all times.
For example, P/T limit violations could result from ambient
 
temperature conditions that result in the reactor vessel
 
metal temperature being less than the minimum allowed
 
temperature for boltup. Therefore, this LCO is applicable
 
even when fuel is not loaded in the core.
 
ACTIONS A.1 and A.2 Operation outside the P/T limits while in MODE 1, 2, or 3
 
must be corrected so that the RCPB is returned to a
 
condition that has been verified by stress analyses.
 
The 30 minute Completion Time reflects the urgency of
 
restoring the parameters to within the analyzed range. Most
 
violations will not be severe, and the activity can be
 
accomplished in this time in a controlled manner.
(continued)
RCS P/T Limits B 3.4.11    LaSalle 1 and 2 B 3.4.11-5 Revision 0 BASES ACTIONS A.1 and A.2 (continued)
Besides restoring operation within limits, an engineering
 
evaluation is required to determine if RCS operation can
 
continue. The evaluation must verify the RCPB integrity
 
remains acceptable and must be completed if continued
 
operation is desired. Several methods may be used, including comparison with pre-analyzed transients in the
 
stress analyses, new analyses, or inspection of the
 
components. ASME Code, Section XI, Appendix E (Ref. 6), may
 
be used to support the evaluation. However, its use is
 
restricted to evaluation of the vessel beltline.
 
The 72 hour Completion Time is reasonable to accomplish the
 
evaluation of a mild violation. More severe violations may
 
require special, event specific stress analyses or
 
inspections. A favorable evaluation must be completed if
 
continued operation is desired.
 
Condition A is modified by a Note requiring Required
 
Action A.2 be completed whenever the Condition is entered. 
 
The Note emphasizes the need to perform the evaluation of
 
the effects of the excursion outside the allowable limits. 
 
Restoration alone per Required Action A.1 is insufficient
 
because higher than analyzed stresses may have occurred and
 
may have affected the RCPB integrity.
 
B.1 and B.2
 
If a Required Action and associated Completion Time of
 
Condition A are not met, the plant must be brought to a
 
lower MODE because either the RCS remained in an
 
unacceptable P/T region for an extended period of increased
 
stress, or a sufficiently severe event caused entry into an
 
unacceptable region. Either possibility indicates a need
 
for more careful examination of the event, best accomplished
 
with the RCS at reduced pressure and temperature. With the
 
reduced pressure and temperature conditions, the possibility
 
of propagation of undetected flaws is decreased.
 
Pressure and temperature are reduced by bringing the plant
 
to at least MODE 3 within 12 hours and to MODE 4 within
 
36 hours. The allowed Completion Times are reasonable,  (continued)
RCS P/T Limits B 3.4.11    LaSalle 1 and 2 B 3.4.11-6 Revision 0 BASES ACTIONS B.1 and B.2 (continued) based on operating experience, to reach the required plant
 
conditions from full power conditions in an orderly manner
 
and without challenging plant systems.
 
C.1 and C.2
 
Operation outside the P/T limits in other than MODES 1, 2, and 3 (including defueled conditions) must be corrected so
 
that the RCPB is returned to a condition that has been
 
verified by stress analyses. The Required Action must be
 
initiated without delay and continued until the limits are
 
restored.
 
Besides restoring the P/T limit parameters to within limits, an engineering evaluation is required to determine if RCS
 
operation is allowed. This evaluation must verify that the
 
RCPB integrity is acceptable and must be completed before
 
approaching criticality or heating up to > 200
&deg;F. Several methods may be used, including comparison with pre-analyzed
 
transients, new analyses, or inspection of the components. 
 
ASME Section XI, Appendix E (Ref. 6), may be used to support
 
the evaluation; however, its use is restricted to evaluation
 
of the beltline. 
 
Condition C is modified by a Note requiring Required Action
 
C.2 be completed whenever the Condition is entered. The
 
Note emphasizes the need to perform the evaluation of the
 
effects of the excursion outside the allowable limits. 
 
Restoration alone per Required Action C.1 is insufficient
 
because higher than analyzed stresses may have occurred and
 
may have affected the RCPB integrity.
 
SURVEILLANCE SR  3.4.11.1 REQUIREMENTS Verification that operation is within limits is required
 
every 30 minutes when RCS pressure and temperature
 
conditions are undergoing planned changes. This Frequency
 
is considered reasonable in view of the control room
 
indication available to monitor RCS status. Also, since
 
temperature rate of change limits are specified in hourly
 
increments, 30 minutes permits assessment and correction of (continued)
RCS P/T Limits B 3.4.11    LaSalle 1 and 2 B 3.4.11-7 Revision 0 BASES SURVEILLANCE SR  3.4.11.1 (continued)
REQUIREMENTS minor deviations. The limits of Figures 3.4.11-1, 3.4.11-2, 3.4.11-3, 3.4.11-4, 3.4.11-5, and 3.4.11-6 are met when
 
operation is to the right of the applicable curve.
 
Surveillance for heatup, cooldown, or inservice leak and
 
hydrostatic testing may be discontinued when the criteria
 
given in the relevant plant procedure for ending the
 
activity are satisfied.
 
This SR has been modified by a Note that requires this
 
Surveillance to be performed only during system heatup and
 
cooldown operations and inservice leak and hydrostatic
 
testing.
 
SR  3.4.11.2
 
A separate limit is used when the reactor is approaching
 
criticality. Consequently, the RCS pressure and temperature
 
must be verified within the appropriate limits before
 
withdrawing control rods that will make the reactor
 
critical. The limits of Figures 3.4.11-3 and 3.4.11-6 are
 
met when operation is to the right of the applicable curve.
 
Performing the Surveillance within 15 minutes before control
 
rod withdrawal for the purpose of achieving criticality
 
provides adequate assurance that the limits will not be
 
exceeded between the time of the Surveillance and the time
 
of the control rod withdrawal.
 
SR  3.4.11.3 and SR  3.4.11.4
 
Differential temperatures within the applicable limits
 
ensure that thermal stresses resulting from the startup of
 
an idle recirculation pump will not exceed design
 
allowances. In addition, compliance with these limits
 
ensures that the assumptions of the analysis for the startup
 
of an idle recirculation loop (Ref. 8) are satisfied.
(continued)
RCS P/T Limits B 3.4.11    LaSalle 1 and 2 B 3.4.11-8 Revision 0 BASES SURVEILLANCE SR  3.4.11.3 and SR  3.4.11.4 (continued)
REQUIREMENTS Performing the Surveillance within 15 minutes before
 
starting the idle recirculation pump provides adequate
 
assurance that the limits will not be exceeded between the
 
time of the Surveillance and the time of the idle pump
 
start.
 
An acceptable means of demonstrating compliance with the
 
temperature differential requirement in SR 3.4.11.3 is to
 
compare temperatures of the reactor pressure vessel steam
 
space coolant and the bottom head drain line coolant.
 
An acceptable means of demonstrating compliance with the
 
temperature differential requirement in SR 3.4.11.4 is to
 
compare the temperatures of the operating recirculation loop
 
and the idle loop.
 
SR 3.4.11.3 and SR 3.4.11.4 have been modified by a Note
 
that requires the Surveillance to be met only in MODES 1, 2, 3, and 4 during a recirculation pump startup since this is
 
when the stresses occur. In MODE 5, the overall stress on
 
limiting components is lower; therefore, T limits are not required.
 
SR  3.4.11.5, SR  3.4.11.6, and SR  3.4.11.7
 
Limits on the reactor vessel flange and head flange
 
temperatures are generally bounded by the other P/T limits
 
during system heatup and cooldown. However, operations
 
approaching MODE 4 from MODE 5 and in MODE 4 with RCS
 
temperature less than or equal to certain specified values
 
require assurance that these temperatures meet the LCO
 
limits.
 
The flange temperatures must be verified to be above the
 
limits within 30 minutes before and every 30 minutes
 
thereafter while tensioning the vessel head bolting studs to
 
ensure that once the head is tensioned the limits are
 
satisfied. When in MODE 4 with RCS temperature  77&deg;F for Unit 1 and  91&deg;F for Unit 2, 30 minute checks of the flange temperatures are required because of the reduced margin to
 
the limits. When in MODE 4 with RCS temperature  92&deg;F for  (continued)
RCS P/T Limits B 3.4.11    LaSalle 1 and 2 B 3.4.11-9 Revision 16 BASES                                                                               
 
SURVEILLANCE SR  3.4.11.5, SR  3.4.11.6, and SR  3.4.11.7 (continued)
REQUIREMENTS Unit 1 and  106&deg;F for Unit 2, monitoring of the flange temperature is required every 12 hours to ensure the
 
temperatures are within the specified limits.
 
The 30 minute Frequency reflects the urgency of maintaining
 
the temperatures within limits, and also limits the time
 
that the temperature limits could be exceeded. The 12 hour
 
Frequency is reasonable based on the rate of temperature
 
change possible at these temperatures.
 
SR 3.4.11.5 is modified by a Note that requires the
 
Surveillance to be performed only when tensioning the
 
reactor vessel head bolting studs. SR 3.4.11.6 is modified
 
by a Note that requires the Surveillance to be initiated
 
30 minutes after RCS temperature  77&deg;F for Unit 1 and  91&deg;F for Unit 2 in MODE 4, SR 3.4.11.7 is modified by a Note that requires the Surveillance to be initiated 12 hours
 
after RCS temperature  92&deg;F for Unit 1 and  106&deg;F for Unit 2 in MODE 4. The Notes contained in these SRs are
 
necessary to specify when the reactor vessel flange and head
 
flange temperatures are required to be verified to be within
 
the specified limits.
 
REFERENCES 1. 10 CFR 50, Appendix G.
: 2. ASME, Boiler and Pressure Vessel Code, Section III, Appendix G.
: 3. ASTM E 185.
: 4. 10 CFR 50, Appendix H.
: 5. Regulatory Guide 1.99, Revision 2, May 1988.
: 6. ASME, Boiler and Pressure Vessel Code, Section XI, Appendix E.
: 7. UFSAR, Section 15.4.4.
 
Reactor Steam Dome Pressure B 3.4.12 LaSalle 1 and 2 B 3.4.12-1 Revision 0 B 3.4  REACTOR COOLANT SYSTEM (RCS)
 
B 3.4.12  Reactor Steam Dome Pressure
 
BASES
 
BACKGROUND The reactor steam dome pressure is an assumed value in the determination of compliance with reactor pressure vessel
 
overpressure protection criteria and is also an assumed
 
initial condition of Design Basis Accidents (DBAs) and
 
transients.
 
APPLICABLE The reactor steam dome pressure of  1020 psig is an SAFETY ANALYSES initial condition of the vessel overpressure protection analysis of Reference 1. This analysis assumes an initial
 
maximum reactor steam dome pressure and evaluates the
 
response of the pressure relief system, primarily the
 
safety/relief valves, during the limiting pressurization
 
transient. The determination of compliance with the
 
overpressure criteria is dependent on the initial reactor
 
steam dome pressure; therefore, the limit on this pressure
 
ensures that the assumptions of the overpressure protection
 
analysis are conserved. Reference 2 also assumes an initial
 
reactor steam dome pressure for the analysis of DBAs and
 
transients used to determine the limits for fuel cladding
 
integrity MCPR (see Bases for LCO 3.2.2, "MINIMUM CRITICAL
 
POWER RATIO (MCPR)") and 1% cladding plastic strain (see
 
Bases for LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION
 
RATE (APLHGR)" and LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)"). The nominal reactor operating pressure is
 
approximately 1005 psig. Transient analyses typically use
 
the nominal or a design dome pressure as input to the
 
analysis. Small deviations (5 to 10 psi) from the nominal
 
pressure are not expected to change most of the transient
 
analyses results. However, sensitivity studies for fast
 
pressurization events (main turbine generator load rejection
 
without bypass, turbine trip without bypass, and feedwater
 
controller failure) indicate that the delta-CPR may increase
 
for lower initial pressures. Therefore, the fast
 
pressurization events have considered a bounding initial
 
pressure based on a typical operating range to assure a
 
conservative delta-CPR and operating limit.
Reactor steam dome pressure satisfies the requirements of
 
Criterion 2 of 10 CFR 50.36(c)(2)(ii).
 
(continued)
Reactor Steam Dome Pressure B 3.4.12    LaSalle 1 and 2 B 3.4.12-2 Revision 0 BASES  (continued)
 
LCO The specified reactor steam dome pressure limit of  1020 psig ensures the plant is operated within the assumptions of the reactor overpressure analysis. Operation
 
above the limit may result in a transient response more
 
severe than analyzed.
 
APPLICABILITY In MODES 1 and 2, the reactor steam dome pressure is required to be less than or equal to the limit. In these
 
MODES, the reactor may be generating significant steam, and
 
events that may challenge the overpressure limits are
 
possible.
In MODES 3, 4, and 5, the limit is not applicable because
 
the reactor is shut down. In these MODES, the reactor
 
pressure is well below the required limit, and no
 
anticipated events will challenge the overpressure limits.
 
ACTIONS A.1 With the reactor steam dome pressure greater than the limit, prompt action should be taken to reduce pressure to below
 
the limit and return the reactor to operation within the
 
bounds of the analyses. The 15 minute Completion Time is
 
reasonable considering the importance of maintaining the
 
pressure within limits. This Completion Time also ensures
 
that the probability of an accident while pressure is
 
greater than the limit is minimal. 
 
B.1 If the reactor steam dome pressure cannot be restored to
 
within the limit within the associated Completion Time, the
 
plant must be brought to a MODE in which the LCO does not
 
apply. To achieve this status, the plant must be brought to
 
at least MODE 3 within 12 hours. The allowed Completion
 
Time of 12 hours is reasonable, based on operating
 
experience, to reach MODE 3 from full power conditions in an
 
orderly manner and without challenging plant systems.
 
(continued)
Reactor Steam Dome Pressure B 3.4.12    LaSalle 1 and 2 B 3.4.12-3 Revision 0 BASES  (continued)
 
SURVEILLANCE SR  3.4.12.1 REQUIREMENTS Verification that reactor steam dome pressure is  1020 psig ensures that the initial condition of the vessel
 
overpressure protection analysis is met. Operating
 
experience has shown the 12 hour Frequency to be sufficient
 
for identifying trends and verifying operation within safety
 
analyses assumptions.
 
REFERENCES 1. UFSAR, Section 5.2.2.2.1.
: 2. UFSAR, Chapter 15.
 
ECCS-Operating B 3.5.1 LaSalle 1 and 2 B 3.5.1-1 Revision 0 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM
 
B 3.5.1  ECCS-Operating
 
BASES
 
BACKGROUND The ECCS is designed, in conjunction with the primary and secondary containment, to limit the release of radioactive
 
materials to the environment following a loss of coolant
 
accident (LOCA). The ECCS uses two independent methods (flooding and spraying) to cool the core during a LOCA. The
 
ECCS network is composed of the High Pressure Core Spray (HPCS) System, the Low Pressure Core Spray (LPCS) System, and the low pressure coolant injection (LPCI) mode of the
 
Residual Heat Removal (RHR) System. The ECCS also consists
 
of the Automatic Depressurization System (ADS). The
 
suppression pool provides the required source of water for
 
the ECCS.
 
On receipt of an initiation signal, ECCS pumps automatically
 
start; the system aligns, and the pumps inject water, taken
 
from the suppression pool, into the Reactor Coolant System (RCS) as RCS pressure is overcome by the discharge pressure
 
of the ECCS pumps. Although the system is initiated, ADS
 
action is delayed, allowing the operator to interrupt the
 
timed sequence if the system is not needed. The HPCS pump
 
discharge pressure almost immediately exceeds that of the
 
RCS, and the pump injects coolant into the spray sparger
 
above the core. If the break is small, HPCS will maintain
 
coolant inventory, as well as vessel level, while the RCS is
 
still pressurized. If HPCS fails, it is backed up by ADS in
 
combination with LPCI and LPCS. In this event, the ADS
 
timed sequence would be allowed to time out and open the
 
selected safety/relief valves (S/RVs), depressurizing the
 
RCS and allowing the LPCI and LPCS to overcome RCS pressure
 
and inject coolant into the vessel. If the break is large, RCS pressure initially drops rapidly, and the LPCI and LPCS
 
systems cool the core.
 
Water from the break returns to the suppression pool where
 
it is used again and again. Water in the suppression pool
 
is circulated through a heat exchanger cooled by the
 
Residual Heat Removal Service Water (RHRSW) System.
 
Depending on the location and size of the break, portions of (continued)
ECCS-Operating B 3.5.1 LaSalle 1 and 2 B 3.5.1-2 Revision 0 BASES BACKGROUND the ECCS may be ineffective; however, the overall design is (continued) effective in cooling the core regardless of the size or location of the piping break. 
 
All ECCS subsystems are designed to ensure that no single
 
active component failure will prevent automatic initiation
 
and successful operation of the minimum required ECCS
 
subsystems.
 
The LPCS System (Ref. 1) consists of a motor driven pump, a
 
spray sparger above the core, piping, and valves to transfer
 
water from the suppression pool to the sparger. The LPCS
 
System is designed to provide cooling to the reactor core
 
when the reactor pressure is low. Upon receipt of an
 
initiation signal, the LPCS pump is automatically started
 
when AC power is available. When the RPV pressure drops
 
sufficiently, LPCS flow to the RPV begins. A full flow test
 
line is provided to route water to the suppression pool to
 
allow testing of the LPCS System without spraying water into
 
the RPV.
 
LPCI is an independent operating mode of the RHR System.
 
There are three LPCI subsystems. Each LPCI subsystem (Ref. 2) consists of a motor driven pump, piping, and valves
 
to transfer water from the suppression pool to the core.
 
Each LPCI subsystem has its own suction and discharge piping
 
and separate vessel nozzle that connects with the core
 
shroud through internal piping. The LPCI subsystems are
 
designed to provide core cooling at low RPV pressure. Upon
 
receipt of an initiation signal, each LPCI pump is
 
automatically started.  (If AC power is supplied by the
 
diesel generators, C pump starts immediately when AC power
 
is available and A and B pumps approximately 5 seconds after
 
AC power is available). When the RPV pressure drops
 
sufficiently, LPCI flow to the RPV begins. RHR System
 
valves in the LPCI flow path are automatically positioned to
 
ensure the proper flow path for water from the suppression
 
pool to inject into the core. A full flow test line is
 
provided to route water to the suppression pool to allow
 
testing of each LPCI pump without injecting water into the
 
RPV.
 
The HPCS System (Ref. 3) consists of a single motor driven
 
pump, a spray sparger above the core, and piping and valves (continued)
ECCS-Operating B 3.5.1 LaSalle 1 and 2 B 3.5.1-3 Revision 6 BASES BACKGROUND to transfer water from the suppression pool to the sparger. 
  (continued) The HPCS System is designed to provide core cooling over a wide range of RPV pressures (0 psid to 1200 psid, vessel to
 
suction source). Upon receipt of an initiation signal, the
 
HPCS pump automatically starts (when AC power is available)
 
and valves in the flow path begin to open. Since the HPCS
 
System is designed to operate over the full range of
 
expected RPV pressures, HPCS flow begins as soon as the
 
necessary valves are open. A full flow test line is
 
provided to route water to the suppression pool to allow
 
testing of the HPCS System during normal operation without
 
spraying water into the RPV.
 
The ECCS pumps are provided with minimum flow bypass lines, which discharge to the suppression pool. The valves in
 
these lines automatically open to prevent pump damage due to
 
overheating when other discharge line valves are closed or
 
RPV pressure is greater than the LPCS or LPCI pump discharge
 
pressures following system initiation. To ensure rapid
 
delivery of water to the RPV and to minimize water hammer
 
effects, the ECCS discharge line "keep fill" systems are
 
designed to maintain all pump discharge lines filled with
 
water.
 
The ADS (Ref. 4) consists of 7 of the 13 S/RVs. It is designed to provide depressurization of the primary system
 
during a small break LOCA if HPCS fails or is unable to
 
maintain required water level in the RPV. ADS operation
 
reduces the RPV pressure to within the operating pressure
 
range of the low pressure ECCS subsystems (LPCS and LPCI),
so that these subsystems can provide core cooling.
 
The Drywell Pneumatic System discharges from the air
 
receiver (or nitrogen receiver when the primary containment
 
is inerted) and after filtration is divided into two supply
 
headers, one of which supplies all the ADS accumulators with
 
approximately 175 psig air (or nitrogen). There is a check
 
valve between each ADS accumulator and the supply. Drywell
 
Pneumatic System low header pressure and high ADS pressure
 
are alarmed in the control room.
 
The accumulators for the ADS valves are normally maintained
 
by the Drywell Pneumatic System compressors. There are two
 
full-capacity compressors which cycle as needed to maintain (continued)
ECCS-Operating B 3.5.1 LaSalle 1 and 2 B 3.5.1-4 Revision 0 BASES BACKGROUND pressure in the drywell pneumatic receiver tank. Nitrogen (continued) bottle banks provide a backup source to maintain the ADS accumulators charged following isolation of the normal
 
pneumatic supply. Each ADS accumulator is provided with a
 
pressure switch to detect low pressure (< 150 psig). These
 
pressure switches are provided with alarms in the control
 
room. A control room alarm is also annunciated for low
 
pressure in the ADS nitrogen bottle banks supply headers.
 
APPLICABLE The ECCS performance is evaluated for the entire spectrum of SAFETY ANALYSES break sizes for a postulated LOCA. The accidents for which ECCS operation is required are presented in References 5, 6, and 7. The required analyses and assumptions are defined in
 
10 CFR 50 (Ref. 8), and the results of these analyses are
 
described in Reference 9.
 
This LCO helps to ensure that the following acceptance
 
criteria for the ECCS, established by 10 CFR 50.46 (Ref. 10), will be met following a LOCA assuming the worst
 
case single active component failure in the ECCS:
: a. Maximum fuel element cladding temperature is  2200&deg;F; 
: b. Maximum cladding oxidation is  0.17 times the total cladding thickness before oxidation;
: c. Maximum hydrogen generation from zirconium water reaction is  0.01 times the hypothetical amount that would be generated if all of the metal in the cladding
 
surrounding the fuel, excluding the cladding
 
surrounding the plenum volume, were to react; 
: d. The core is maintained in a coolable geometry; and
: e. Adequate long term cooling capability is maintained.
 
The limiting single failures are discussed in Reference 11.
 
For the LOCA evaluation model which covers the entire
 
spectrum of break sizes (large breaks to small breaks),
failure of the HPCS ECCS subsystem in Division 3 due to
 
failure of its associated diesel generator is, in general, the most severe failure. The remaining OPERABLE ECCS
 
subsystems, which include one spray subsystem, provide the (continued)
ECCS-Operating B 3.5.1 LaSalle 1 and 2 B 3.5.1-5 Revision 0 BASES APPLICABLE capability to adequately cool the core, under near-term and SAFETY ANALYSES long-term conditions, and prevent excessive fuel damage.
  (continued) For all LOCA analyses, only six ADS valves are assumed to function. An additional analysis has been performed which
 
assumes five ADS valves function, however in this analysis
 
all low pressure and high pressure ECCS subsystems are also
 
assumed to be available.
 
The ECCS satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).
 
LCO Each ECCS injection/spray subsystem and six ADS valves are required to be OPERABLE. The ECCS injection/spray
 
subsystems are defined as the three LPCI subsystems, the
 
LPCS System, and the HPCS System. The low pressure ECCS
 
injection/spray subsystems are defined as the LPCS System
 
and the three LPCI subsystems.
 
With less than the required number of ECCS subsystems
 
OPERABLE during a limiting design basis LOCA concurrent with
 
the worst case single failure, the limits specified in
 
10 CFR 50.46 (Ref. 10) could potentially be exceeded. All
 
ECCS subsystems must therefore be OPERABLE to satisfy the
 
single failure criterion required by 10 CFR 50.46 (Ref. 10).
 
As noted, LPCI subsystems may be considered OPERABLE during
 
alignment and operation for decay heat removal when below
 
the actual RHR cut in permissive pressure in MODE 3, if
 
capable of being manually realigned (remote or local) to the
 
LPCI mode and not otherwise inoperable. Alignment and
 
operation for decay heat removal includes: a) when the
 
system is realigned to or from the RHR shutdown cooling mode
 
and; b) when the system is in the RHR shutdown cooling mode, whether or not the RHR pump is operating. This allowance is
 
necessary since the RHR System may be required to operate in
 
the shutdown cooling mode to remove decay heat and sensible
 
heat from the reactor. At these low pressures and decay
 
heat levels, a reduced complement of ECCS subsystems should
 
provide the required core cooling, thereby allowing
 
operation of RHR shutdown cooling when necessary.
 
APPLICABILITY All ECCS subsystems are required to be OPERABLE during MODES 1, 2, and 3 when there is considerable energy in the
 
reactor core and core cooling would be required to prevent
 
fuel damage in the event of a break in the primary system  (continued)
ECCS-Operating B 3.5.1 LaSalle 1 and 2 B 3.5.1-6 Revision 19 BASES APPLICABILITY piping. In MODES 2 and 3, the ADS function is not required (continued) when pressure is  150 psig because the low pressure ECCS subsystems (LPCS and LPCI) are capable of providing flow
 
into the RPV below this pressure. ECCS requirements for
 
MODES 4 and 5 are specified in LCO 3.5.2, "ECCS-Shutdown.
 
ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable HPCS subsystem. There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable HPCS subsystem and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.
A.1 If any one low pressure ECCS injection/spray subsystem is
 
inoperable, the inoperable subsystem must be restored to
 
OPERABLE status within 7 days. In this Condition, the
 
remaining OPERABLE subsystems provide adequate core cooling
 
during a LOCA. However, overall ECCS reliability is reduced
 
because a single failure in one of the remaining OPERABLE
 
subsystems concurrent with a LOCA may result in the ECCS not
 
being able to perform its intended safety function. The
 
7 day Completion Time is based on a reliability study (Ref. 12) that evaluated the impact on ECCS availability by
 
assuming that various components and subsystems were taken
 
out of service. The results were used to calculate the
 
average availability of ECCS equipment needed to mitigate
 
the consequences of a LOCA as a function of allowed outage
 
times (i.e., Completion Times).
 
B.1 and B.2
 
If the HPCS System is inoperable, and the RCIC System is
 
immediately verified to be OPERABLE (when RCIC is required
 
to be OPERABLE), the HPCS System must be restored to
 
OPERABLE status within 14 days. In this Condition, adequate
 
core cooling is ensured by the OPERABILITY of the redundant
 
and diverse low pressure ECCS injection/spray subsystems in
 
conjunction with the ADS. Also, the RCIC System will  (continued)
ECCS-Operating B 3.5.1 LaSalle 1 and 2 B 3.5.1-7 Revision 19 BASES ACTIONS B.1 and B.2 (continued)
 
automatically provide makeup water at most reactor operating
 
pressures. Immediate verification of RCIC OPERABILITY is
 
therefore required when HPCS is inoperable and RCIC is
 
required to be OPERABLE. This may be performed by an
 
administrative check, by examining logs or other
 
information, to determine if RCIC is out of service for
 
maintenance or other reasons. It is not necessary to
 
perform the Surveillances needed to demonstrate the
 
OPERABILITY of the RCIC System. However, if the OPERABILITY
 
of the RCIC System cannot be immediately verified and RCIC
 
is required to be OPERABLE, Condition E must be entered. If
 
a single active component fails concurrent with a design
 
basis LOCA, there is a potential, depending on the specific
 
failure, that the minimum required ECCS equipment will not
 
be available. A 14 day Completion Time is based on the
 
results of a reliability study (Ref. 12) and has been found
 
to be acceptable through operating experience.
 
C.1 With two ECCS injection subsystems inoperable or one ECCS
 
injection and the low pressure ECCS spray subsystem (LPCS)
 
inoperable, at least one ECCS injection/spray subsystem must
 
be restored to OPERABLE status within 72 hours. In this
 
Condition, the remaining OPERABLE subsystems provide
 
adequate core cooling during a LOCA. However, overall ECCS
 
reliability is reduced in this Condition because a single
 
failure in one of the remaining OPERABLE subsystems
 
concurrent with a design basis LOCA may result in the ECCS
 
not being able to perform its intended safety function. 
 
Since the ECCS availability is reduced relative to
 
Condition A, a more restrictive Completion Time is imposed.
 
The 72 hour Completion Time is based on a reliability study, as provided in Reference 12.
 
  (continued)
ECCS-Operating B 3.5.1 LaSalle 1 and 2 B 3.5.1-8 Revision 32 BASES ACTIONS (continued) D.1 and D.2
 
With the ADS accumulator backup compressed gas system bottle
 
pressure less than the specified limit, bottle pressure must
 
be restored within 72 hours, or the associated ADS valves
 
must be declared inoperable. In this condition, the
 
remaining Drywell Pneumatic System and ADS accumulators are
 
sufficient to ensure ADS valve operation. However, overall
 
ECCS reliability is reduced in this condition because with
 
insufficient bottle bank pressure, the capability of ADS
 
valves to operate for long periods of time following an
 
accident (without the Drywell Pneumatic System) is reduced.
 
Each ADS valve is equipped with an individual accumulator of
 
sufficient capacity to operate the valves in the event of a
 
loss of air supply. The 72 hour Completion Time is based on
 
a reliability study, as provided in Reference 12.
 
E.1    If any Required Action and associated Completion Time of
 
Condition A, B, or C are not met, the plant must be brought
 
to a MODE in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least
 
MODE 3 within 12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 15) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without
 
challenging plant systems.
 
F.1 The LCO requires six ADS valves to be OPERABLE to provide
 
the ADS function. Reference 11 contains the results of an
 
evaluation of the effect of one required ADS valve being out
 
of service. Per this evaluation, operation of only five ADS
 
valves will provide the required depressurization. However, overall reliability of the ADS is reduced because a single
 
failure in the OPERABLE ADS valves could result in a (continued)
ECCS-Operating B 3.5.1 LaSalle 1 and 2 B 3.5.1-9 Revision 32 BASES ACTIONS (continued) reduction in depressurization capability. Therefore, operation is only allowed for a limited time. The 14 day
 
Completion Time is based on a reliability study (Ref. 12)
 
and has been found to be acceptable through operating
 
experience.
 
G.1 If any Required Action and associated Completion Time of
 
Condition F is not met, the plant must be brought to a MODE in which overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within
 
12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 15) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short.
However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
 
H.1 and H.2 If two or more ADS valves are inoperable, there is a reduction in the depressurization capability. The plant must be brought to a condition in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and reactor steam dome pressure reduced to  150 psig within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
 
I.1    When multiple ECCS subsystems are inoperable, as stated in
 
Condition I, the plant is in a condition outside of the design basis. Therefore, LCO 3.0.3 must be entered
 
immediately.
(continued)
ECCS-Operating B 3.5.1 LaSalle 1 and 2 B 3.5.1-10 Revision 32 BASES  (continued)
 
SURVEILLANCE SR  3.5.1.1 REQUIREMENTS The flow path piping has the potential to develop voids and
 
pockets of entrained air. Maintaining the pump discharge
 
lines of the HPCS System, LPCS System, and LPCI subsystems
 
full of water ensures that the systems will perform
 
properly, injecting their full capacity into the RCS upon
 
demand. This will also prevent a water hammer following an
 
ECCS initiation signal. One acceptable method of ensuring
 
the lines are full is to vent at the high points. The
 
31 day Frequency is based on operating experience, on the
 
procedural controls governing system operation, and on the
 
gradual nature of void buildup in the ECCS piping.
 
SR  3.5.1.2
 
Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths provides
 
assurance that the proper flow paths will exist for ECCS
 
operation. This SR does not apply to valves that are
 
locked, sealed, or otherwise secured in position since these 
 
valves were verified to be in the correct position prior to
 
locking, sealing, or securing. A valve that receives an
 
initiation signal is allowed to be in a nonaccident position
 
provided the valve will automatically reposition in the
 
proper stroke time. This SR does not require any testing or
 
valve manipulation; rather, it involves verification that
 
those valves potentially capable of being mispositioned are
 
in the correct position. This SR does not apply to valves
 
that cannot be inadvertently misaligned, such as check
 
valves.
 
The 31 day Frequency of this SR was derived from the
 
Inservice Testing Program requirements for performing valve
 
testing at least once every 92 days. The Frequency of
 
31 days is further justified because the valves are operated
 
under procedural control and because improper valve
 
alignment would only affect a single subsystem. This
 
Frequency has been shown to be acceptable through operating
 
experience.
 
SR  3.5.1.3
 
Verification every 31 days that ADS accumulator supply
 
header pressure is  150 psig assures adequate pneumatic pressure for reliable ADS operation. The accumulator on
 
each ADS valve provides pneumatic pressure for valve  (continued)
ECCS-Operating B 3.5.1 LaSalle 1 and 2 B 3.5.1-11 Revision 32 BASES SURVEILLANCE SR  3.5.1.3 (continued)
REQUIREMENTS actuation. The ADS valve accumulators are sized to provide 
 
two cycles of the ADS valves upon loss of the nitrogen
 
supply (Ref. 13). The ECCS safety analysis assumes only one
 
actuation to achieve the depressurization required for
 
operation of the low pressure ECCS. The accumulator supply
 
header pressure verification may be accomplished by
 
monitoring control room alarms. The 31 day Frequency takes
 
into consideration alarms for low pneumatic pressure.
 
SR  3.5.1.4
 
Verification every 31 days that ADS accumulator backup
 
compressed gas system bottle pressure is  500 psig assures availability of an adequate backup pneumatic supply to the
 
ADS accumulators following a loss of the drywell pneumatic 
 
supply. The 31 day frequency is adequate because each ADS
 
bottle bank is monitored by a low pressure alarm. Also, unless the normal drywell pneumatic supply is lost, the only
 
expected losses from the bottles are due to leakage, which
 
is minimal.
 
SR  3.5.1.5
 
The performance requirements of the ECCS pumps are determined through application of the 10 CFR 50, Appendix K, criteria (Ref. 8). This periodic Surveillance is performed (in accordance with the ASME OM Code requirements for the
 
ECCS pumps) to verify that the ECCS pumps will develop the
 
flow rates required by the respective analyses. The ECCS
 
pump flow rates ensure that adequate core cooling is
 
provided to satisfy the acceptance criteria of 10 CFR 50.46 (Ref. 10).
 
The pump flow rates are verified against a test line
 
pressure that was determined during preoperational testing
 
to be equivalent to the RPV pressure expected during a LOCA.
 
Under these conditions, the total system pump outlet
 
pressure is adequate to overcome the elevation head pressure
 
between the pump suction and the vessel discharge, the
 
piping friction losses, and RPV pressure present during
 
LOCAs. The Frequency for this Surveillance is in accordance
 
with the Inservice Testing Program requirements.
 
(continued)
ECCS-Operating B 3.5.1 LaSalle 1 and 2 B 3.5.1-12 Revision 32 BASES SURVEILLANCE SR  3.5.1.6 REQUIREMENTS (continued) The ECCS subsystems are required to actuate automatically to perform their design functions. This Surveillance verifies
 
that, with a required system initiation signal (actual or
 
simulated), the automatic initiation logic of HPCS, LPCS, and LPCI will cause the systems or subsystems to operate as
 
designed, including actuation of the system throughout its
 
emergency operating sequence, automatic pump startup, and
 
actuation of all automatic valves to their required
 
position. This Surveillance also ensures that the HPCS
 
System injection valve will automatically reopen on an RPV
 
low water level (Level 2) signal received subsequent to an
 
RPV high water level (Level 8) injection valve closure
 
signal. The LOGIC SYSTEM FUNCTIONAL TEST performed in
 
LCO 3.3.5.1 overlaps this Surveillance to provide complete
 
testing of the assumed safety function.
 
The 24 month Frequency is based on the need to perform this
 
Surveillance under the conditions that apply during a plant
 
outage and the potential for an unplanned transient if the
 
Surveillance were performed with the reactor at power.
 
Operating experience has shown that these components usually
 
pass the SR when performed at the 24 month Frequency, which 
 
is based on the refueling cycle. Therefore, the Frequency
 
was concluded to be acceptable from a reliability
 
standpoint.
 
This SR is modified by a Note that excludes vessel
 
injection/spray during the Surveillance. Since all active
 
components are testable and full flow can be demonstrated by
 
recirculation through the test line, coolant injection into
 
the RPV is not required during the Surveillance.
 
SR  3.5.1.7
 
The ADS designated S/RVs are required to actuate
 
automatically upon receipt of specific initiation signals.
 
A system functional test is performed to demonstrate that
 
the mechanical portions of the ADS function (i.e.,
solenoids) operate as designed when initiated either by an
 
(continued)
ECCS-Operating B 3.5.1 LaSalle 1 and 2 B 3.5.1-13 Revision 32 BASES SURVEILLANCE SR  3.5.1.7 (continued)
REQUIREMENTS actual or simulated initiation signal, causing proper
 
actuation of all the required components. SR 3.5.1.8 and
 
the LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1
 
overlap this Surveillance to provide complete testing of the
 
assumed safety function.
 
The 24 month Frequency is based on the need to perform this
 
Surveillance under the conditions that apply during a plant
 
outage and the potential for an unplanned transient if the
 
Surveillance were performed with the reactor at power. 
 
Operating experience has shown that these components usually
 
pass the SR when performed at the 24 month Frequency, which
 
is based on the refueling cycle. Therefore, the Frequency
 
was concluded to be acceptable from a reliability
 
standpoint.
 
This SR is modified by a Note that excludes valve actuation
 
since the valves are individually tested in accordance with
 
SR 3.5.1.8. This also prevents an RPV pressure blowdown.
 
SR  3.5.1.8
 
A manual actuation of each required ADS actuator is
 
performed to verify that the valve, actuator, and solenoids
 
are functioning properly. SR 3.4.4.1, SR 3.5.1.7 and the
 
LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1
 
overlap this Surveillance to provide complete testing of the
 
assumed safety function.
 
The Frequency of 24 months is based on the need to perform
 
this Surveillance under the conditions that apply just prior
 
to or during a startup from a plant outage. Operating
 
experience has shown that these components usually pass the
 
SR when performed at the 24 month Frequency, which is based
 
on the refueling cycle. Therefore, the Frequency was
 
concluded to be acceptable from a reliability standpoint.
 
This SR is modified by a Note that excludes the valve
 
actuation since valve OPERABILITY is demonstrated for ADS
 
valves by successful operation of a sample of S/RVs. The
 
sample population of S/RVs tested each refueling outage to
 
satisfy SR 3.4.4.1 are stroked in the relief mode during "as
 
(continued)
ECCS-Operating B 3.5.1 LaSalle 1 and 2 B 3.5.1-14 Revision 32 BASES SURVEILLANCE SR  3.5.1.8 (continued)
REQUIREMENTS found" testing to verify proper operation of the ADS valve.
 
The successful performance of the test sample of S/RVs
 
provides reasonable assurance that all ADS valves will
 
perform in a similar fashion. Additionally, after the S/RVs
 
are replaced, the relief mode actuator of the newly
 
installed S/RVs are uncoupled from the S/RV stem and cycled
 
to ensure that no damage has occurred during transportation
 
and installation. This verifies that each replaced S/RV
 
will properly perform its intended safety function.
 
REFERENCES 1. UFSAR, Section 6.3.2.2.3.
: 2. UFSAR, Section 6.3.2.2.4.
: 3. UFSAR, Section 6.3.2.2.1.
: 4. UFSAR, Section 6.3.2.2.2.
: 5. UFSAR, Section 15.2.8.
: 6. UFSAR, Section 15.6.4.
: 7. UFSAR, Section 15.6.5.
: 8. 10 CFR 50, Appendix K.
: 9. UFSAR, Section 6.3.3.
: 10. 10 CFR 50.46.
: 11. UFSAR, Section 6.3.3.3.
: 12. Memorandum from R.L. Baer (NRC) to V. Stello, Jr. (NRC), "Recommended Interim Revisions to LCO's for
 
ECCS Components," December 1, 1975.
: 13. UFSAR, Section 7.3.1.2.
: 14. ASME Code for Operation and Maintenance of Nuclear Power Plants (OM Code).
: 15. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants," December 2002.
 
ECCS-Shutdown B 3.5.2 LaSalle 1 and 2 B 3.5.2-1 Revision 0 B 3.5  EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM
 
B 3.5.2  ECCS-Shutdown
 
BASES
 
BACKGROUND A description of the High Pressure Core Spray (HPCS) System, Low Pressure Core Spray (LPCS) System, and low pressure
 
coolant injection (LPCI) mode of the Residual Heat Removal (RHR) System is provided in the Bases for LCO 3.5.1, "ECCS-Operating."
APPLICABLE The ECCS performance is evaluated for the entire spectrum of SAFETY ANALYSES  break sizes for a postulated loss of coolant accident (LOCA). The long term cooling analysis following a design
 
basis LOCA (Ref. 1) demonstrates that only one ECCS
 
injection/spray subsystem is required, post LOCA, to
 
maintain adequate reactor vessel water level in the event of
 
an inadvertent vessel draindown. It is reasonable to
 
assume, based on engineering judgment, that while in MODES 4
 
and 5, one ECCS injection/spray subsystem can maintain
 
adequate reactor vessel water level. To provide redundancy, a minimum of two ECCS injection/spray subsystems are
 
required to be OPERABLE in MODES 4 and 5.
 
The ECCS satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).
 
LCO Two ECCS injection/spray subsystems are required to be OPERABLE. The ECCS injection/spray subsystems are defined
 
as the three LPCI subsystems, the LPCS System, and the HPCS
 
System. The LPCS System and each LPCI subsystem consist of
 
one motor driven pump, piping, and valves to transfer water
 
from the suppression pool to the RPV. The HPCS System
 
consists of one motor driven pump, piping, and valves to
 
transfer water from the suppression pool to the RPV. The
 
necessary portions of the Diesel Generator Cooling Water
 
System are also required to provide appropriate cooling to
 
each required ECCS injection/spray subsystem
 
As noted, one LPCI subsystem (A or B) may be considered
 
OPERABLE during alignment and operation for decay heat
 
removal, if capable of being manually realigned (remote or (continued)
ECCS-Shutdown B 3.5.2 LaSalle 1 and 2 B 3.5.2-2 Revision 0 BASES LCO local) to the LPCI mode and is not otherwise inoperable. 
  (continued) Alignment and operation for decay heat removal includes: a) when the system is realigned to or from the RHR shutdown
 
cooling mode and; b) when the system is in the RHR shutdown
 
cooling mode, whether or not the RHR pump is operating. 
 
This allowance is necessary since the RHR System may be
 
required to operate in the shutdown cooling mode to remove
 
decay heat and sensible heat from the reactor. Because of
 
low pressure and low temperature conditions in MODES 4
 
and 5, sufficient time will be available to manually align
 
and initiate LPCI subsystem operation to provide core
 
cooling prior to postulated fuel uncovery.
 
APPLICABILITY OPERABILITY of the ECCS injection/spray subsystems is required in MODES 4 and 5 to ensure adequate coolant
 
inventory and sufficient heat removal capability for the
 
irradiated fuel in the core in case of an inadvertent
 
draindown of the vessel. Requirements for ECCS OPERABILITY
 
during MODES 1, 2, and 3 are discussed in the Applicability
 
section of the Bases for LCO 3.5.1. ECCS subsystems are not
 
required to be OPERABLE during MODE 5 with the spent fuel
 
storage pool gates removed and the water level maintained at 22 ft above the RPV flange. This provides sufficient coolant inventory to allow operator action to terminate the
 
inventory loss prior to fuel uncovery in case of an
 
inadvertent draindown.
 
The Automatic Depressurization System is not required to be
 
OPERABLE during MODES 4 and 5 because the RPV pressure is
 
< 150 psig, and the LPCS, HPCS, and LPCI subsystems can
 
provide core cooling without any depressurization of the
 
primary system.
 
ACTIONS A.1 and B.1
 
If any one required ECCS injection/spray subsystem is
 
inoperable, the required inoperable ECCS injection/spray
 
subsystem must be restored to OPERABLE status within
 
4 hours. In this Condition, the remaining OPERABLE
 
subsystem can provide sufficient RPV flooding capability to
 
recover from an inadvertent vessel draindown. However, overall system reliability is reduced because a single
 
failure in the remaining OPERABLE subsystem concurrent with
 
(continued)
ECCS-Shutdown B 3.5.2 LaSalle 1 and 2 B 3.5.2-3 Revision 0 BASES ACTIONS A.1 and B.1 (continued) a vessel draindown could result in the ECCS not being able
 
to perform its intended function. The 4 hour Completion
 
Time for restoring the required ECCS injection/spray
 
subsystem to OPERABLE status is based on engineering
 
judgment that considered the availability of one subsystem
 
and the low probability of a vessel draindown event.
 
With the inoperable subsystem not restored to OPERABLE
 
status within the required Completion Time, action must be
 
initiated immediately to suspend operations with a potential
 
for draining the reactor vessel (OPDRVs) to minimize the
 
probability of a vessel draindown and the subsequent
 
potential for fission product release. Actions must
 
continue until OPDRVs are suspended.
 
C.1, C.2, D.1, D.2, and D.3
 
If both of the required ECCS injection/spray subsystems are
 
inoperable, all coolant inventory makeup capability may be
 
unavailable. Therefore, actions must be initiated
 
immediately to suspend OPDRVs in order to minimize the
 
probability of a vessel draindown and the subsequent
 
potential for fission product release. Actions must
 
continue until OPDRVs are suspended. One ECCS
 
injection/spray subsystem must also be restored to OPERABLE
 
status within 4 hours. The 4 hour Completion Time to
 
restore at least one required ECCS injection/spray subsystem
 
to OPERABLE status ensures that prompt action will be taken
 
to provide the required cooling capacity or to initiate
 
actions to place the plant in a condition that minimizes any
 
potential fission product release to the environment.
 
If at least one required ECCS injection/spray subsystem is
 
not restored to OPERABLE status within the 4 hour Completion
 
Time, additional actions are required to minimize any
 
potential fission product release to the environment. This
 
includes ensuring secondary containment is OPERABLE; one
 
standby gas treatment subsystem is OPERABLE; and secondary
 
containment isolation capability is available in each
 
secondary containment penetration flow path not isolated
 
that is assumed to be isolated to mitigate radioactivity (continued)
ECCS-Shutdown B 3.5.2 LaSalle 1 and 2 B 3.5.2-4 Revision 0 BASES ACTIONS C.1, C.2, D.1, D.2, and D.3 (continued) releases (i.e., one secondary containment isolation valve
 
and associated instrumentation are OPERABLE or other
 
acceptable administrative controls to assure isolation
 
capability. The administrative controls consist of
 
stationing a dedicated operator, who is in continuous
 
communication with the control room at the controls of the
 
isolation device. In this way, the penetration can be
 
rapidly isolated when a need for secondary containment
 
isolation is indicated.)  This may be performed by an
 
administrative check, by examining logs or other
 
information, to determine if the components are out of
 
service for maintenance or other reasons. It is not
 
necessary to perform the Surveillances needed to demonstrate
 
OPERABILITY of the components. If, however, any required
 
component is inoperable, then it must be restored to
 
OPERABLE status. In this case, the Surveillances may need
 
to be performed to restore the component to OPERABLE status.
 
Actions must continue until all required components are
 
OPERABLE.
 
SURVEILLANCE SR  3.5.2.1 and SR  3.5.2.2 REQUIREMENTS The minimum water level of -12 ft 7 in (referenced to a
 
plant elevation of 699 ft 11 in) required for the
 
suppression pool, equivalent to a contained water volume of
 
70,000 ft 3 , is periodically verified to ensure that the suppression pool will provide adequate net positive suction
 
head (NPSH) for the ECCS pumps, recirculation volume, and
 
vortex prevention. With the suppression pool water level
 
less than the required limit, all ECCS injection/spray
 
subsystems are inoperable.
 
The 12 hour Frequency of these SRs was developed considering
 
operating experience related to suppression pool water level
 
variations and instrument drift during the applicable MODES.
 
Furthermore, the 12 hour Frequency is considered adequate in
 
view of other indications in the control room to alert the
 
operator to an abnormal suppression pool water level
 
condition.
(continued)
ECCS-Shutdown B 3.5.2 LaSalle 1 and 2 B 3.5.2-5 Revision 0 BASES SURVEILLANCE SR  3.5.2.3, SR  3.5.2.5, and SR  3.5.2.6 REQUIREMENTS (continued) The Bases provided for SR 3.5.1.1, SR 3.5.1.4, and SR 3.5.1.5 are applicable to SR 3.5.2.3, SR 3.5.2.5, and
 
SR 3.5.2.6, respectively.
 
SR  3.5.2.4
 
Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths provides
 
assurance that the proper flow paths will exist for ECCS
 
operation. This SR does not apply to valves that are
 
locked, sealed, or otherwise secured in position since these
 
valves were verified to be in the correct position prior to
 
locking, sealing, or securing. A valve that receives an
 
initiation signal is allowed to be in a nonaccident position
 
provided the valve will automatically reposition in the
 
proper stroke time. This SR does not require any testing or
 
valve manipulation; rather, it involves verification that
 
those valves capable of potentially being mispositioned are
 
in the correct position. This SR does not apply to valves
 
that cannot be inadvertently misaligned, such as check
 
valves. The 31 day Frequency is appropriate because the
 
valves are operated under procedural control and the
 
probability of their being mispositioned during this time
 
period is low.
 
REFERENCES 1. UFSAR, Section 6.3.3.2.
 
RCIC System B 3.5.3 LaSalle 1 and 2 B 3.5.3-1 Revision 13 B 3.5  EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM
 
B 3.5.3  RCIC System
 
BASES
 
BACKGROUND The RCIC System is not part of the ECCS; however, the RCIC System is included with the ECCS section because of their
 
similar functions.
The RCIC System is designed to operate either automatically
 
or manually following reactor pressure vessel (RPV)
 
isolation accompanied by a loss of coolant flow from the
 
feedwater system to provide adequate core cooling and
 
control of RPV water level. Under these conditions, the
 
High Pressure Core Spray (HPCS) and RCIC systems perform
 
similar functions. The RCIC System design requirements
 
ensure that the criteria of Reference 1 are satisfied.
 
The RCIC System (Ref. 2) consists of a steam driven turbine
 
pump unit, piping and valves to provide steam to the
 
turbine, as well as piping and valves to transfer water
 
from the suction source to the core via the head spray
 
nozzle. A 1" H 2 purge line is connected from the injection line to the reactor head vent to prevent hydrogen buildup (Ref. 4). The purge line contains an orifice to minimize
 
RCIC flow bypassing the RPV and ensures that sufficient
 
injection flow is delivered to the RPV.
 
Suction piping is provided from the condensate storage tank (CST) and the suppression pool. Pump suction is normally
 
aligned to the CST to minimize injection of suppression pool
 
water into the RPV. However, if the CST water supply is low
 
an automatic transfer to the suppression pool water source
 
ensures a water supply for continuous operation of the RCIC
 
System. The steam supply to the turbine is piped from main
 
steam line B, upstream of the inboard main steam line
 
isolation valve.
 
The RCIC System is designed to provide core cooling for a
 
wide range of reactor pressures, 135 psig to 1185 psig.
 
Upon receipt of an initiation signal, the RCIC turbine
 
accelerates to a specified speed. As the RCIC flow
 
increases, the turbine control valve is automatically
 
adjusted to maintain design flow. Exhaust steam from the
 
RCIC turbine is discharged to the suppression pool. A full (continued)
RCIC System B 3.5.3 LaSalle 1 and 2 B 3.5.3-2 Revision 10 BASES
 
BACKGROUND flow test line is provided to route water to the CST or the (continued) suppression pool to allow testing of the RCIC System during normal operation without injecting water into the RPV.
 
The RCIC pump is provided with a minimum flow bypass line, which discharges to the suppression pool. The valve in this
 
line automatically opens to prevent pump damage due to
 
overheating when other discharge line valves are closed. To
 
ensure rapid delivery of water to the RPV and to minimize
 
water hammer effects, the RCIC System discharge line "keep
 
fill" system is designed to maintain the pump discharge line
 
filled with water.
 
APPLICABLE The function of the RCIC System is to respond to transient SAFETY ANALYSES events by providing makeup coolant to the reactor. The RCIC System is not an Engineered Safety Feature System and no
 
credit is taken in the safety analyses for RCIC System
 
operation. Based on its contribution to the reduction of
 
overall plant risk, the system satisfies Criterion 4 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO The OPERABILITY of the RCIC System provides adequate core cooling such that actuation of any of the ECCS subsystems is
 
not required in the event of RPV isolation accompanied by a
 
loss of feedwater flow. The RCIC System has sufficient
 
capacity to maintain RPV inventory during an isolation
 
event.
APPLICABILITY The RCIC System is required to be OPERABLE in MODE 1, and MODES 2 and 3 with reactor steam dome pressure
> 150 psig since RCIC is the primary non-ECCS water source for core
 
cooling when the reactor is isolated and pressurized. In
 
MODES 2 and 3 with reactor steam dome pressure  150 psig, and in MODES 4 and 5, RCIC is not required to be OPERABLE
 
since the ECCS injection/spray subsystems can provide
 
sufficient flow to the vessel.
(continued)
RCIC System B 3.5.3 LaSalle 1 and 2 B 3.5.3-3 Revision 19 BASES  (continued)
 
ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable RCIC system. There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable RCIC system and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCOO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.
 
A.1 and A.2 If the RCIC System is inoperable during MODE 1, or MODES 2
 
or 3 with reactor steam dome pressure
> 150 psig, and the HPCS System is immediately verified to be OPERABLE, the RCIC
 
System must be restored to OPERABLE status within 14 days.
 
In this Condition, loss of the RCIC System will not affect
 
the overall plant capability to provide makeup inventory at
 
high RPV pressure since the HPCS System is the only high
 
pressure system assumed to function during a loss of coolant
 
accident (LOCA). OPERABILITY of the HPCS is therefore
 
immediately verified when the RCIC System is inoperable.
 
This may be performed as an administrative check, by
 
examining logs or other information, to determine if the
 
HPCS is out of service for maintenance or other reasons.
 
Verification does not require performing the Surveillances
 
needed to demonstrate the OPERABILITY of the HPCS System.
 
If the OPERABILITY of the HPCS System cannot be immediately
 
verified, however, Condition B must be entered. For
 
transients and certain abnormal events with no LOCA, RCIC (as opposed to HPCS) is the preferred source of makeup
 
coolant because of its relatively small capacity, which
 
allows easier control of RPV water level. Therefore, a
 
limited time is allowed to restore the inoperable RCIC to
 
OPERABLE status.
 
The 14 day Completion Time is based on a reliability study (Ref. 3) that evaluated the impact on ECCS availability, assuming that various components and subsystems were taken
 
out of service. The results were used to calculate the
 
average availability of ECCS equipment needed to mitigate
 
the consequences of a LOCA as a function of allowed outage
 
times (AOTs). Because of the similar functions of the HPCS
 
and RCIC, the AOTs (i.e., Completion Times) determined for
 
the HPCS are also applied to RCIC.
 
(continued)
RCIC System B 3.5.3 LaSalle 1 and 2 B 3.5.3-4 Revision 19 BASES ACTIONS (continued) B.1 and B.2 If the RCIC System cannot be restored to OPERABLE status
 
within the associated Completion Time, or if the HPCS System
 
is simultaneously inoperable, the plant must be brought to a
 
condition in which the LCO does not apply. To achieve this
 
status, the plant must be brought to at least MODE 3 within
 
12 hours and reactor steam dome pressure reduced to 150 psig within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the
 
required plant conditions from full power conditions in an
 
orderly manner and without challenging plant systems.
 
SURVEILLANCE SR  3.5.3.1 REQUIREMENTS The flow path piping has the potential to develop voids and
 
pockets of entrained air. Maintaining the pump discharge
 
line of the RCIC System full of water ensures that the
 
system will perform properly, injecting its full capacity
 
into the Reactor Coolant System upon demand. This will also
 
prevent a water hammer following an initiation signal. One
 
acceptable method of ensuring the line is full is to vent at
 
the high points. The 31 day Frequency is based on the
 
gradual nature of void buildup in the RCIC piping, the
 
procedural controls governing system operation, and
 
operating experience.
SR  3.5.3.2
 
Verifying the correct alignment for manual, power operated, and automatic valves (including the RCIC pump flow
 
controller) in the RCIC flow path provides assurance that
 
the proper flow path will exist for RCIC operation. This SR
 
does not apply to valves that are locked, sealed, or
 
otherwise secured in position since these were verified to
 
be in the correct position prior to locking, sealing, or
 
securing. A valve that receives an initiation signal is
 
allowed to be in a nonaccident position provided the valve
 
will automatically reposition in the proper stroke time.
 
This SR does not require any testing or valve manipulation;
 
rather, it involves verification that those valves capable
 
of potentially being mispositioned are in the correct
 
position. This SR does not apply to valves that cannot be
 
inadvertently misaligned, such as check valves. For the
 
RCIC System, this SR also includes the steam flow path for  (continued)
RCIC System B 3.5.3 LaSalle 1 and 2 B 3.5.3-5 Revision 19 BASES SURVEILLANCE SR  3.5.3.2 (continued)
REQUIREMENTS the turbine and the flow controller position.
 
The 31 day Frequency of this SR was derived from the
 
Inservice Testing Program requirements for performing valve 
 
testing at least every 92 days. The Frequency of 31 days is
 
further justified because the valves are operated under
 
procedural control and because improper valve position would
 
affect only the RCIC System. This Frequency has been shown
 
to be acceptable through operating experience.
 
SR 3.5.3.3 and SR 3.5.3.4
 
The RCIC pump flow rates ensure that the system can maintain reactor coolant inventory during pressurized conditions with
 
the RPV isolated. The flow tests for the RCIC System are
 
performed at two different pressure ranges such that system
 
capability to provide rated flow against a test line
 
pressure corresponding to reactor pressure is tested both at
 
the higher and lower operating ranges of the system. The
 
required system head should overcome the RPV pressure and
 
associated discharge line losses. Adequate reactor steam
 
pressure must be available to perform these tests.
 
Additionally, adequate steam flow must be passing through
 
the main turbine or turbine bypass valves to continue to
 
control reactor pressure when the RCIC System diverts steam
 
flow. Therefore, sufficient time is allowed after adequate
 
pressure and flow are achieved to perform these SRs.
 
Reactor steam pressure must be  920 psig to perform SR 3.5.3.3 and  135 psig to perform SR 3.5.3.4. Adequate steam flow is represented by at least one turbine bypass
 
valve opened 50%. Reactor startup is allowed prior to
 
performing the low pressure Surveillance because the reactor
 
pressure is low and the time to satisfactorily perform the
 
Surveillance is short. The reactor pressure is allowed to
 
be increased to normal operating pressure since it is
 
assumed that the low pressure test has been satisfactorily
 
completed and there is no indication or reason to believe
 
that RCIC is inoperable. Therefore, these SRs are modified
 
by Notes that state the Surveillances are not required to be
 
performed until 12 hours after the reactor steam pressure
 
and flow are adequate to perform the test. The 12 hours
 
allowed for the flow tests after the required pressure and
 
flow are reached are sufficient to achieve stable conditions
 
for testing and provides a reasonable time to complete the
 
SRs. (continued)
RCIC System B 3.5.3 LaSalle 1 and 2 B 3.5.3-6 Revision 10 BASES
 
SURVEILLANCE SR 3.5.3.3 and SR 3.5.3.4 (continued)
REQUIREMENTS A 92 day Frequency for SR 3.5.3.3 is consistent with the
 
Inservice Testing Program requirements. The 24 month
 
Frequency for SR 3.5.3.4 is based on the need to perform
 
this Surveillance under the conditions that apply during
 
startup from a plant outage. Operating experience has shown
 
that these components usually pass the SR when performed at
 
the 24 month Frequency, which is based on the refueling
 
cycle. Therefore, the Frequency was concluded to be
 
acceptable from a reliability standpoint.
 
SR  3.5.3.5
 
The RCIC System is required to actuate automatically to perform its design function. This Surveillance verifies
 
that with a required system initiation signal (actual or
 
simulated) the automatic initiation logic of RCIC will cause
 
the system to operate as designed, i.e., actuation of the
 
system throughout its emergency operating sequence, which
 
includes automatic pump startup and actuation of all
 
automatic valves to their required positions. This
 
Surveillance also ensures that the RCIC System will
 
automatically restart on an actual or simulated RPV low
 
water level (Level 2) signal received subsequent to an
 
actual or simulated RPV high water level (Level 8) shutdown
 
signal, and that the suction is automatically transferred
 
from the CST to the suppression pool. The LOGIC SYSTEM
 
FUNCTIONAL TEST performed in LCO 3.3.5.2 overlaps this
 
Surveillance to provide complete testing of the assumed
 
design function.
While this Surveillance can be performed with the reactor at
 
power, operating experience has shown that these components
 
usually pass the SR when performed at the 24 month
 
Frequency, which is based on the refueling cycle.
 
Therefore, the Frequency was concluded to be acceptable from
 
a reliability standpoint.
 
This SR is modified by a Note that excludes vessel injection
 
during the Surveillance. Since all active components are
 
testable and full flow can be demonstrated by recirculation
 
through the test line, coolant injection into the RPV is not
 
required during the Surveillance.
 
(continued)
RCIC System B 3.5.3 LaSalle 1 and 2 B 3.5.3-7 Revision 10 BASES  (continued)
 
REFERENCES 1. 10 CFR 50, Appendix A, GDC 33.
: 2. UFSAR, Section 5.4.6.2.
: 3. Memorandum from R.L. Baer (NRC) to V. Stello, Jr. (NRC), "Recommended Interim Revisions to LCO's for
 
ECCS Components," December 1, 1975.
: 4. GE Service Information Letter (SIL) No. 643, "Potential for Radiolytic Gas Detonation," June 14, 2002. 
 
Primary Containment B 3.6.1.1
 
LaSalle 1 and 2 B 3.6.1.1-1 Revision 0 B 3.6  CONTAINMENT SYSTEMS
 
B 3.6.1.1  Primary Containment
 
BASES
 
BACKGROUND The function of the primary containment is to isolate and contain fission products released from the Reactor Primary
 
System following a design basis Loss of Coolant Accident (LOCA) and to confine the postulated release of radioactive
 
material to within limits. The primary containment consists
 
of a steel lined, reinforced concrete vessel, which
 
surrounds the Reactor Primary System and provides an
 
essentially leak tight barrier against an uncontrolled
 
release of radioactive material to the environment.
 
Additionally, this structure provides shielding from the
 
fission products that may be present in the primary
 
containment atmosphere following accident conditions.
The isolation devices for the penetrations in the primary
 
containment boundary are a part of the primary containment
 
leak tight barrier. To maintain this leak tight barrier:
: a. All penetrations required to be closed during accident conditions are either:
: 1. capable of being closed by an OPERABLE automatic containment isolation system, or
: 2. closed by manual valves, blind flanges, or de-activated automatic valves secured in their
 
closed positions, except as provided in
 
LCO 3.6.1.3, "Primary Containment Isolation
 
Valves (PCIVs)";
: b. Primary containment air locks are OPERABLE, except as provided in LCO 3.6.1.2, "Primary Containment Air
 
Locks"; 
: c. All equipment hatches are closed and sealed; and
: d. The sealing mechanism associated with each primary containment penetration (e.g., welds, bellows, or
 
0-rings) is OPERABLE.
(continued)
Primary Containment B 3.6.1.1 LaSalle 1 and 2 B 3.6.1.1-2 Revision 0 BASES BACKGROUND This Specification ensures that the performance of the (continued) primary containment, in the event of a Design Basis Accident (DBA), meets the assumptions used in the safety analyses of
 
References 1 and 2. SR 3.6.1.1.1 leakage rate requirements
 
are in conformance with 10 CFR 50, Appendix J (Ref. 3),
Option B, as modified by approved exemptions.
 
APPLICABLE The safety design basis for the primary containment is that SAFETY ANALYSES it must withstand the pressures and temperatures of the limiting DBA without exceeding the design leakage rate.
The DBA that postulates the maximum release of radioactive
 
material within primary containment is a LOCA. In the
 
analysis of this accident, it is assumed that primary
 
containment is OPERABLE such that release of fission
 
products to the environment is controlled by the rate of
 
primary containment leakage.
 
Analytical methods and assumptions involving the primary
 
containment are presented in References 1 and 2. The safety
 
analyses assume a nonmechanistic fission product release
 
following a DBA, which forms the basis for determination of
 
offsite doses. The fission product release is, in turn, based on an assumed leakage rate from the primary
 
containment. OPERABILITY of the primary containment ensures
 
that the leakage rate assumed in the safety analyses is not
 
exceeded.
 
The maximum allowable leakage rate for the primary
 
containment (L a) is 0.635% by weight of the containment air per 24 hours at the design basis LOCA maximum peak
 
containment pressure (P a) of 39.9 psig (Ref. 4).
 
Primary containment satisfies Criterion 3 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO Primary containment OPERABILITY is maintained by limiting leakage to  1.0 L a , except prior to the first startup after performing a required Primary Containment Leakage Rate
 
Testing Program leakage test. At this time, the applicable
 
leakage limits must be met. In addition, the leakage from
 
the drywell to the suppression chamber must be limited to
 
ensure the primary containment pressure does not exceed (continued)
Primary Containment B 3.6.1.1 LaSalle 1 and 2 B 3.6.1.1-3 Revision 32 BASES LCO design limits. Compliance with this LCO will ensure a (continued) primary containment configuration, including equipment hatches, that is structurally sound and that will limit
 
leakage to those leakage rates assumed in the safety
 
analysis. Individual leakage rates specified for the
 
primary containment air locks are addressed in LCO 3.6.1.2.
 
APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4
 
and 5, the probability and consequences of these events are
 
reduced due to the pressure and temperature limitations of
 
these MODES. Therefore, primary containment is not required
 
to be OPERABLE in MODES 4 and 5 to prevent leakage of
 
radioactive material from primary containment.
 
ACTIONS A.1 In the event that primary containment is inoperable, primary
 
containment must be restored to OPERABLE status within
 
1 hour. The 1 hour Completion Time provides a period of
 
time to correct the problem that is commensurate with the
 
importance of maintaining primary containment OPERABILITY
 
during MODES 1, 2, and 3. This time period also ensures
 
that the probability of an accident (requiring primary
 
containment OPERABILITY) occurring during periods where
 
primary containment is inoperable is minimal.
 
B.1 If primary containment cannot be restored to OPERABLE status
 
within the associated Completion Time, the plant must be
 
brought to a MODE in which overall plant risk is minimized.
To achieve this status, the plant must be brought to at
 
least MODE 3 within 12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 5), because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner
 
and without challenging plant systems.
 
(continued)
Primary Containment B 3.6.1.1 LaSalle 1 and 2 B 3.6.1.1-4 Revision 32 BASES  (continued)
 
SURVEILLANCE SR  3.6.1.1.1 REQUIREMENTS Maintaining the primary containment OPERABLE requires
 
compliance with the visual examinations and leakage rate
 
test requirements of the Primary Containment Leakage Rate
 
Testing Program. Failure to meet air lock leakage testing
 
limit (SR 3.6.1.2.1), or main steam isolation valve leakage
 
limit (SR 3.6.1.3.10) does not necessarily result in a
 
failure of this SR. The impact of the failure to meet these
 
SRs must be evaluated against the Type A, B, and C
 
acceptance criteria of the Primary Containment Leakage Rate
 
Testing Program.
 
As left leakage prior to the first startup after performing
 
a required Primary Containment Leakage Rate Testing Program
 
leakage test is required to be
< 0.6 L a for combined Type B and C leakage, and  0.75 L a for overall Type A leakage. At all other times between required leakage rate tests, the
 
acceptance criteria is based on an overall Type A leakage
 
limit of  1.0 L a. At  1.0 L a the offsite dose consequences are bounded by the assumptions of the safety
 
analysis. The Frequency is required by the Primary
 
Containment Leakage Rate Testing Program. 
 
SR  3.6.1.1.2
 
The structural integrity of the primary containment is
 
ensured by the successful completion of the Inservice
 
Inspection Program for Post Tensioning Tendons and by
 
associated visual inspections of the steel liner and
 
penetrations for evidence of deterioration or breach of
 
integrity. This ensures that the structural integrity of
 
the primary containment will be maintained in accordance
 
with the provisions of the Inservice Inspection Program for
 
Post Tensioning Tendons. Testing and Frequency are
 
consistent with the recommendations of 10 CFR 50.55a (Ref. 6), except that the Unit 1 and 2 primary containments shall be treated as twin containments even though the
 
Initial Structural Integrity tests were not within two years
 
of each other. (continued)
Primary Containment B 3.6.1.1 LaSalle 1 and 2 B 3.6.1.1-5 Revision 2 BASES SURVEILLANCE SR  3.6.1.1.3 REQUIREMENTS (continued) Maintaining the pressure suppression function of the primary containment requires limiting the leakage from the drywell
 
to the suppression chamber. Thus, if an event were to occur
 
that pressurized the drywell, the steam would be directed
 
through the downcomers into the suppression pool. This SR
 
measures drywell-to-suppression chamber differential
 
pressure during a 1 hour period to ensure that the leakage
 
paths that would bypass the suppression pool are within
 
allowable limits.
Satisfactory performance of this SR can be achieved by
 
establishing a known differential pressure ( 1.5 psid) between the drywell and the suppression chamber and
 
verifying that the measured bypass leakage is  10% of the acceptable k/A design value of 0.030 ft
: 2. The leakage test is performed every 120 months. The Frequency was developed considering it is prudent that this Surveillance be performed during a unit outage and also in view of the
 
fact that component failures that might have affected this
 
test are identified by other primary containment SRs. One test failure increases the test Frequency to 48 months. Two consecutive test failures, however, would indicate unexpected primary containment degradation, in this event, increasing the Frequency to once every 24 months is required until the situation is remedied as evidenced by passing two consecutive tests.
SR  3.6.1.1.4 Maintaining the pressure suppression function of the primary containment requires limiting the leakage form the drywell to the suppression chamber. Thus, if an event were to occur that pressurizes the drywell, the steam would be directed through the downcomers into the suppression pool. This SR measures the individual drywell to suppression chamber vacuum relief valve bypass leakage to ensure that the leakage paths that would bypass the suppression pool are within allowable limits.
Satisfactory performance of this SR can be achieved by establishing a known differential pressure (>
1.5 psid) between the drywell side and the suppression chamber side of the drywell to suppression chamber vacuum relief valve and verifying that the measured bypass leakage is <
1.2% of the acceptable k/A design value of 0.030 ft
: 2. The leakage test is performed every 24 months. The 24 month Frequency was (continued)
 
Primary Containment B 3.6.1.1 LaSalle 1 and 2 B 3.6.1.1-6 Revision 32 BASES SURVEILLANCE SR  3.6.1.1.4 (continued)
REQUIREMENTS developed considering it is prudent that this Surveillance
 
be performed during a unit outage.
The SR is modified by a Note stating that performance of SR
 
3.6.1.1.3 satisfies this Surveillance Requirement. This is
 
acceptable since drywell to suppression chamber vacuum
 
relief valve leakage is included in the measurement of the
 
drywell to suppression chamber bypass leakage required by SR
 
3.6.1.1.3.
 
SR  3.6.1.1.5 Maintaining the pressure suppression function of the primary
 
containment requires limiting the leakage form the drywell
 
to the suppression chamber. Thus, if an event were to occur
 
that pressurizes the drywell, the steam would be directed
 
through the downcomers into the suppression pool. This SR
 
determines the total drywell to suppresssion chamber vacuum
 
relief valve bypass leakage to ensure that the leakage paths
 
that would bypass the suppression pool are within allowable
 
limits. Satisfactory performance of this SR can be achieved by
 
summing the individual drywell to suppression chamber vacuum
 
relief valve bypass leakage form SR 3.6.1.1.4 and verifying
 
that the measured bypass leakage is <
3.0% of the acceptable k/A design value of 0.030 ft
: 2. The acceptable bypass leakage of this Surveillance is performed every 24 months.
The 24 month Frequency was developed considering it si
 
prudent that this Surveillance be performed during a unit
 
outage. The SR is modified by a Note stating that performance of SR
 
3.6.1.1.3 satisfies this Surveillance Requirement. This is
 
acceptable since drywell to suppression chamber vacuum
 
relief valve leakage is included in the measurement of the
 
drywell to suppression chamber bypass leakage required by SR
 
3.6.1.1.3.
 
(continued)
 
Primary Containment B 3.6.1.1 LaSalle 1 and 2 B 3.6.1.1-7 Revision 32 BASES  (continued)
 
REFERENCES 1. UFSAR, Section 6.2.
: 2. UFSAR, Section 15.6.5.
: 3. 10 CFR 50, Appendix J, Option B.
: 4. UFSAR, Section 6.2.6.1.
: 5. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants," December 2002.
: 6. 10 CFR 50.55a.
 
Primary Containment Air Lock B 3.6.1.2
 
LaSalle 1 and 2 B 3.6.1.2-1 Revision 0 B 3.6  CONTAINMENT SYSTEMS
 
B 3.6.1.2  Primary Containment Air Lock
 
BASES
 
BACKGROUND A double-door primary containment air lock has been built into the primary containment to provide personnel access to
 
the primary containment and to provide primary containment
 
isolation during the process of personnel entry and exit. 
 
The air lock is designed to withstand the same loads, temperatures, and peak design internal and external
 
pressures as the primary containment (Ref. 1). As part of
 
the primary containment, the air lock limits the release of
 
radioactive material to the environment during normal unit
 
operation and through a range of transients and accidents up
 
to and including postulated Design Basis Accidents (DBAs).
 
Each air lock door has been designed and tested to certify
 
its ability to withstand pressure in excess of the maximum
 
expected pressure following a DBA in primary containment. 
 
Each of the doors has double, compressible seals and local
 
leak rate testing capability to ensure pressure integrity. 
 
To effect a leak tight seal, the air lock design uses
 
pressure sealed doors (i.e., an increase in primary
 
containment internal pressure results in an increased
 
sealing on each door.).
 
The air lock is nominally a right circular cylinder, 10 ft 
 
in diameter, with doors at each end that are interlocked to
 
prevent simultaneous opening. The air lock is provided with
 
limit switches on both doors that provide remote indication
 
of door position via an alarm in the control room that
 
indicates when an air lock door is open. During periods
 
when primary containment is not required to be OPERABLE, the
 
air lock interlock mechanism may be disabled, allowing both
 
doors of the air lock to remain open for extended periods
 
when frequent primary containment entry is necessary. Under
 
some conditions, as allowed by this LCO, the primary
 
containment may be accessed through the air lock when the
 
door interlock mechanism has failed, by manually performing
 
the interlock function.
 
The primary containment air lock forms part of the primary
 
containment pressure boundary. As such, air lock integrity
 
and leak tightness are essential for maintaining primary (continued)
Primary Containment Air Lock B 3.6.1.2
 
LaSalle 1 and 2 B 3.6.1.2-2 Revision 0 BASES BACKGROUND containment leakage rate to within limits in the event of a (continued) DBA. Not maintaining air lock integrity or leak tightness may result in a leakage rate in excess of that assumed in
 
the safety analysis.
 
APPLICABLE The DBA that postulates the maximum release of radioactive SAFETY ANALYSES material within primary containment is a LOCA. In the analysis of this accident, it is assumed that primary
 
containment is OPERABLE, such that release of fission
 
products to the environment is controlled by the rate of
 
primary containment leakage. The primary containment is
 
designed with a maximum allowable leakage rate (L a) of 0.635% by weight of the containment air mass per 24 hours at
 
the Design Basis LOCA maximum peak containment pressure (P a) of 39.9 psig (Ref. 2). This allowable leakage rate forms
 
the basis for the acceptance criteria imposed on the SRs
 
associated with the air lock.
Primary containment air lock OPERABILITY is also required to
 
minimize the amount of fission product gases that may escape
 
primary containment through the air lock and contaminate and
 
pressurize the secondary containment.
 
Primary containment air lock satisfies Criterion 3 of the
 
10 CFR 50.36(c)(2)(ii).
 
LCO As part of the primary containment pressure boundary, the air lock safety function is related to control of
 
containment leakage following a DBA. Thus, the air lock
 
structural integrity and leak tightness are essential to the
 
successful mitigation of such an event.
The primary containment air lock is required to be OPERABLE.
 
For the air lock to be considered OPERABLE, the air lock
 
interlock mechanism must be OPERABLE, the air lock must be
 
in compliance with the Type B air lock leakage test, and
 
both air lock doors must be OPERABLE. The interlock allows
 
only one air lock door to be open at a time. This provision
 
ensures that a gross breach of primary containment does not
 
exist when primary containment is required to be OPERABLE. 
 
Closure of a single door in the air lock is sufficient to (continued)
Primary Containment Air Lock B 3.6.1.2
 
LaSalle 1 and 2 B 3.6.1.2-3 Revision 0 BASES LCO provide a leak tight barrier following postulated events. 
  (continued) Nevertheless, both doors are kept closed when the air lock is not being used for normal entry into or exit from primary
 
containment.
 
APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4
 
and 5, the probability and consequences of these events are
 
reduced due to the pressure and temperature limitations of
 
these MODES. Therefore, the primary containment air lock is
 
not required to be OPERABLE in MODES 4 and 5 to prevent
 
leakage of radioactive material from primary containment.
 
ACTIONS The ACTIONS are modified by Note 1, which allows entry and exit to perform repairs of the affected air lock component.
 
If the outer door is inoperable, then it may be easily
 
accessed for most repairs. If the inner door is the one
 
that is inoperable, however, then a short time exists when
 
the primary containment boundary is not intact (during
 
access through the OPERABLE door). The allowance to open
 
the OPERABLE door, even if it means the primary containment
 
boundary is temporarily not intact, is acceptable due to the
 
low probability of an event that could pressurize the
 
primary containment during the short time in which the
 
OPERABLE door is expected to be open. The required
 
administrative controls consist of stationing a dedicated
 
individual to assure closure of the OPERABLE door except
 
during the entry and exit and to assure the OPERABLE door is
 
relocked after completion of the containment entry and exit.
The ACTIONS are modified by a second Note, which ensures
 
appropriate remedial actions are taken when necessary, if
 
airlock leakage results in exceeding overall containment
 
leakage rate acceptance criteria. Pursuant to LCO 3.0.6, ACTIONS are not required even if primary containment leakage
 
is exceeding leakage L
: a. Therefore, the Note is added to require ACTIONS for LCO 3.6.1.1, "Primary Containment," to
 
be taken in this event.
 
(continued)
Primary Containment Air Lock B 3.6.1.2
 
LaSalle 1 and 2 B 3.6.1.2-4 Revision 0 BASES ACTIONS A.1, A.2, and A.3 (continued)
With one primary containment air lock door inoperable, the
 
OPERABLE door must be verified closed (Required Action A.1).
 
This ensures that a leak tight primary containment barrier
 
is maintained by the use of an OPERABLE air lock door. This
 
action must be completed within 1 hour. The 1 hour
 
Completion Time is consistent with the ACTIONS of
 
LCO 3.6.1.1, which requires that primary containment be
 
restored to OPERABLE status within 1 hour.
 
In addition, the air lock penetration must be isolated by
 
locking closed the OPERABLE air lock door within the 24 hour
 
Completion Time. The 24 hour Completion Time is considered
 
reasonable for locking the OPERABLE air lock door, considering the OPERABLE door of the air lock is being
 
maintained closed.
 
Required Action A.3 ensures that the air lock penetration
 
has been isolated by the use of a locked closed OPERABLE air
 
lock door. This ensures that an acceptable primary
 
containment leakage boundary is maintained. The Completion
 
Time of once per 31 days is based on engineering judgment
 
and is considered adequate given the low likelihood of a
 
locked door being mispositioned and other administrative
 
controls. Required Action A.3 is modified by a Note that
 
applies to air lock doors located in high radiation areas or
 
areas with limited access due to inerting and allows these
 
doors to be verified locked closed by use of administrative
 
controls. Allowing verification by administrative controls
 
is considered acceptable, since access to these areas is
 
typically restricted. Therefore, the probability of
 
misalignment of the door, once it has been verified to be in
 
the proper position, is small.
 
The Required Actions have been modified by two Notes. 
 
Note 1 ensures that only the Required Actions and associated
 
Completion Times of Condition C are required if both doors
 
in the air lock are inoperable. With both doors in the air
 
lock inoperable, an OPERABLE door is not available to be
 
closed. Required Actions C.1 and C.2 are the appropriate
 
remedial actions. The exception of Note 1 does not affect
 
tracking the Completion Time from the initial entry into
 
Condition A; only the requirement to comply with the
 
(continued)
Primary Containment Air Lock B 3.6.1.2
 
LaSalle 1 and 2 B 3.6.1.2-5 Revision 0 BASES ACTIONS A.1, A.2, and A.3 (continued)
Required Actions. Note 2 allows use of the air lock for
 
entry and exit for 7 days under administrative controls. 
 
This 7 day restriction begins when the air lock is
 
discovered inoperable. 
 
Primary containment entry may be required to perform
 
Technical Specifications (TS) Surveillances and Required
 
Actions, as well as other activities inside primary
 
containment that are required by TS or activities that
 
support TS-required equipment. This Note is not intended to
 
preclude performing other activities (i.e., non-TS-related
 
activities) if the primary containment was entered, using
 
the inoperable air lock, to perform an allowed activity
 
listed above. The required administrative controls consist
 
of stationing a dedicated individual to assure closure of
 
the OPERABLE door except during periods of entry and exit, and to assure the OPERABLE door is relocked after completion
 
of the containment entry and exit  This allowance is
 
acceptable due to the low probability of an event that could
 
pressurize the primary containment during the short time
 
that the OPERABLE door is expected to be open.
 
B.1, B.2, and B.3
 
With the air lock interlock mechanism inoperable, the
 
Required Actions and associated Completion Times are
 
consistent with those specified in Condition A.
 
The Required Actions have been modified by two Notes. 
 
Note 1 ensures that only the Required Actions and associated
 
Completion Times of Condition C are required if both doors
 
in the air lock are inoperable. With both doors in the air
 
lock inoperable, an OPERABLE door is not available to be
 
closed. Required Actions C.1 and C.2 are the appropriate
 
remedial actions. Note 2 allows entry into and exit from
 
the primary containment under the control of a dedicated
 
individual stationed at the air lock to ensure that only one
 
door is opened at a time (i.e., the individual performs the
 
function of the interlock).
 
Required Action B.3 is modified by a Note that applies to
 
air lock doors located in high radiation areas or areas with
 
limited access due to inerting and allows these doors to be (continued)
Primary Containment Air Lock B 3.6.1.2
 
LaSalle 1 and 2 B 3.6.1.2-6 Revision 0 BASES ACTIONS B.1, B.2, and B.3 (continued) verified locked closed by use of administrative controls.
 
Allowing verification by administrative controls is
 
considered acceptable, since access to these areas is
 
typically restricted. Therefore, the probability of
 
misalignment of the door, once it has been verified to be in
 
the proper position, is small.
 
C.1, C.2, and C.3
 
With the air lock inoperable for reasons other than those
 
described in Condition A or B, Required Action C.1 requires
 
action to be immediately initiated to evaluate containment
 
overall leakage rates using current air lock leakage test
 
results. An evaluation is acceptable since it is overly
 
conservative to immediately declare the primary containment
 
inoperable if both doors in the air lock have failed a seal
 
test or if the overall air lock leakage is not within
 
limits. In many instances (e.g., only one seal per door has
 
failed) primary containment remains OPERABLE, yet only
 
1 hour (according to LCO 3.6.1.1) would be provided to
 
restore the air lock door to OPERABLE status prior to
 
requiring a plant shutdown. In addition, even with both
 
doors failing the seal test, the overall containment leakage
 
rate can still be within limits.
 
Required Action C.2 requires that one door in the primary
 
containment air locks must be verified closed. This
 
Required Action must be completed within the 1 hour
 
Completion Time. This specified time period is consistent
 
with the ACTIONS of LCO 3.6.1.1, which require that primary
 
containment be restored to OPERABLE status within 1 hour.
 
Additionally, the air lock must be restored to OPERABLE
 
status within 24 hours (Required Action C.3). The 24 hour
 
Completion Time is reasonable for restoring the inoperable
 
air lock to OPERABLE status considering that at least one
 
door is maintained closed in the air lock.
 
(continued)
Primary Containment Air Lock B 3.6.1.2
 
LaSalle 1 and 2 B 3.6.1.2-7 Revision 0 BASES ACTIONS D.1 and D.2 (continued)
If the inoperable primary containment air lock cannot be
 
restored to OPERABLE status within the associated Completion
 
Time, the plant must be brought to a MODE in which the LCO
 
does not apply. To achieve this status, the plant must be
 
brought to at least MODE 3 within 12 hours and to MODE 4
 
within 36 hours. The allowed Completion Times are
 
reasonable, based on operating experience, to reach the
 
required plant conditions from full power conditions in an
 
orderly manner and without challenging plant systems.
 
SURVEILLANCE SR  3.6.1.2.1 REQUIREMENTS Maintaining the primary containment air lock OPERABLE
 
requires compliance with the leakage rate test requirements
 
of the Primary Containment Leakage Rate Testing Program.
 
This SR reflects the leakage rate testing requirements with
 
regard to air lock leakage (Type B leakage tests). The
 
acceptance criteria were established as a small fraction of
 
the total allowable primary containment leakage. The
 
periodic testing requirements verify that the air lock
 
leakage does not exceed the allowed fraction of the overall
 
primary containment leakage rate. The Frequency is required
 
by the Primary Containment Leakage Rate Testing Program.
 
The SR has been modified by two Notes. Note 1 states that
 
an inoperable air lock door does not invalidate the previous
 
successful performance of the overall air lock leakage test.
 
This is considered reasonable since either air lock door is
 
capable of providing a fission product barrier in the event
 
of a DBA. Note 2 has been added to this SR, requiring the
 
results to be evaluated against the acceptance criteria
 
which is applicable to SR 3.6.1.1.1. This ensures that air
 
lock leakage is properly accounted for in determining the
 
combined Types B and C primary containment leakage rate.
 
SR  3.6.1.2.2
 
The air lock interlock mechanism is designed to prevent
 
simultaneous opening of both doors in the air lock. Since
 
both the inner and outer doors of the air lock are designed
 
to withstand the maximum expected post accident primary
 
(continued)
Primary Containment Air Lock B 3.6.1.2
 
LaSalle 1 and 2 B 3.6.1.2-8 Revision 0 BASES SURVEILLANCE SR  3.6.1.2.2 (continued)
REQUIREMENTS containment pressure (Ref. 2), closure of either door will
 
support primary containment OPERABILITY. Thus, the
 
interlock feature supports primary containment OPERABILITY
 
while the air lock is being used for personnel transit in
 
and out of the containment. Periodic testing of this
 
interlock demonstrates that the interlock will function as
 
designed and that simultaneous inner and outer door opening
 
will not inadvertently occur. Due to the purely mechanical
 
nature of this interlock, and given that the interlock
 
mechanism is not normally challenged when the primary
 
containment air lock door is used for entry and exit (procedures require strict adherence to single door
 
opening), this test is only required to be performed every
 
24 months. The 24 month Frequency is based on the need to
 
perform this Surveillance under the conditions that apply
 
during a plant outage, and the potential for loss of primary
 
containment OPERABILITY if the Surveillance were performed
 
with the reactor at power. Operating experience has shown
 
these components usually pass the Surveillance when
 
performed at the 24 month Frequency. The 24 month Frequency
 
is based on engineering judgment and is considered adequate
 
given that the interlock is not challenged during use of the
 
air lock.
 
REFERENCES 1. UFSAR, Section 3.8.1.1.3.5.1.
: 2. UFSAR, Section 6.2.6.1.
 
PCIVs B 3.6.1.3
 
LaSalle 1 and 2 B 3.6.1.3-1 Revision 0 B 3.6  CONTAINMENT SYSTEMS
 
B 3.6.1.3  Primary Containment Isolation Valves (PCIVs)
 
BASES
 
BACKGROUND The function of the PCIVs, in combination with other accident mitigation systems, is to limit fission product
 
release during and following postulated Design Basis
 
Accidents (DBAs) to within limits. Primary containment
 
isolation within the time limits specified for those PCIVs
 
designed to close automatically ensures that the release of
 
radioactive material to the environment will be consistent
 
with the assumptions used in the analyses for a DBA.
The OPERABILITY requirements for PCIVs help ensure that an
 
adequate primary containment boundary is maintained during
 
and after an accident by minimizing potential paths to the
 
environment. Therefore, the OPERABILITY requirements
 
provide assurance that the primary containment function
 
assumed in the safety analysis will be maintained. These
 
isolation devices consist of either passive devices or
 
active (automatic) devices. Manual valves, de-activated
 
automatic valves secured in their closed position (including
 
check valves with flow through the valve secured), blind
 
flanges (which include plugs and caps as listed in
 
Reference 1), and closed systems are considered passive
 
devices. Check valves, or other automatic valves designed
 
to close without operator action following an accident, are
 
considered active devices. Two barriers in series are
 
provided for each penetration, except for penetrations
 
isolated by excess flow check valves, so that no single
 
credible failure or malfunction of an active component can
 
result in a loss of isolation or leakage that exceeds limits
 
assumed in the safety analysis. One of these barriers may
 
be a closed system.
 
The 8 and 26 inch primary containment purge valves are PCIVs
 
that are qualified for use during all operational
 
conditions. The 8 and 26 inch primary containment purge
 
valves are normally maintained closed in MODES 1, 2, and 3
 
to ensure the primary containment boundary is maintained. 
 
However, these purge valves may be open when being used for
 
inerting, de-inerting pressure control, ALARA, or air
 
quality considerations since they are fully qualified.
 
(continued)
PCIVs B 3.6.1.3
 
LaSalle 1 and 2 B 3.6.1.3-2 Revision 0 BASES  (continued)
 
APPLICABLE The PCIVs LCO was derived from the assumptions related SAFETY ANALYSES to minimizing the loss of reactor coolant inventory, and establishing the primary containment boundary during major
 
accidents. As part of the primary containment boundary, PCIV OPERABILITY supports leak tightness of primary
 
containment. Therefore, the safety analysis of any event
 
requiring isolation of primary containment is applicable to
 
this LCO.
The DBAs that result in a release of radioactive material
 
for which the consequences are mitigated by PCIVs are a loss
 
of coolant accident (LOCA) and a main steam line break (MSLB) (Refs. 2 and 3). In the analysis for each of these
 
accidents, it is assumed that PCIVs are either closed or
 
function to close within the required isolation time
 
following event initiation. This ensures that potential
 
paths to the environment through PCIVs (including primary
 
containment purge valves) are minimized. Of the events
 
analyzed in References 2 and 3, the LOCA is the most
 
limiting event due to radiological consequences. For the
 
MSLB, the closure time of the main steam isolation valves (MSIVs) is a significant variable from a radiological
 
standpoint. The MSIVs are required to close within 3 to
 
5 seconds since the 3 second closure time is assumed in the
 
MSIV closure (the most severe overpressurization transient)
 
analysis (Ref. 4) and the 5 second closure time is assumed
 
in the MSLB analysis (Ref. 3). Likewise, it is assumed that
 
the primary containment isolates such that release of
 
fission products to the environment is controlled.
 
The DBA analysis assumes that isolation of the primary
 
containment is complete and leakage terminated, except for
 
the maximum allowable leakage prior to fuel damage.
 
The single failure criterion required to be imposed in the
 
conduct of unit safety analyses was considered in the
 
original design of the primary containment purge valves. 
 
Two valves in series on each purge line provide assurance
 
that both the supply and exhaust lines could be isolated
 
even if a single failure occurred.
 
PCIVs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).
 
(continued)
PCIVs B 3.6.1.3
 
LaSalle 1 and 2 B 3.6.1.3-3 Revision 0 BASES  (continued)
 
LCO PCIVs form a part of the primary containment boundary. The PCIV safety function is related to minimizing the loss of
 
reactor coolant inventory and establishing the primary
 
containment boundary during a DBA.
The power operated, automatic isolation valves are required
 
to have isolation times within limits and actuate on an
 
automatic isolation signal. The valves covered by this LCO
 
are listed with their associated stroke times in the
 
Technical Requirements Manual (Ref. 1).
 
The normally closed manual PCIVs are considered OPERABLE
 
when the valves are closed and blind flanges are in place, or open under administrative controls. Normally closed
 
automatic PCIVs which are required by design (e.g., to meet
 
10 CFR 50 Appendix R requirements) to be de-activated and
 
closed, are considered OPERABLE when the valves are
 
de-activated and closed. These passive isolation valves and
 
devices are those listed in Reference 1. MSIVs and
 
hydrostatically tested valves must meet additional leakage
 
rate requirements. Other PCIV leakage rates are addressed
 
by LCO 3.6.1.1, "Primary Containment," as Type B or C
 
testing.
 
This LCO provides assurance that the PCIVs will perform
 
their designed safety functions to minimize the loss of
 
reactor coolant inventory and establish the primary
 
containment boundary during accidents.
 
APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4
 
and 5, the probability and consequences of these events are
 
reduced due to the pressure and temperature limitations of
 
these MODES. Therefore, most PCIVs are not required to be
 
OPERABLE and the primary containment purge valves are not
 
required to be normally closed in MODES 4 and 5. Certain
 
valves are required to be OPERABLE, however, to prevent
 
inadvertent reactor vessel draindown. These valves are
 
those whose associated instrumentation is required to be
 
OPERABLE according to LCO 3.3.6.1, "Primary Containment
 
Isolation Instrumentation."  (This does not include the
 
valves that isolate the associated instrumentation.)
(continued)
PCIVs B 3.6.1.3
 
LaSalle 1 and 2 B 3.6.1.3-4 Revision 0 BASES  (continued)
 
ACTIONS The ACTIONS are modified by a Note allowing penetration flow path(s) to be unisolated intermittently under administrative
 
controls. These controls consist of stationing a dedicated
 
operator at the controls of the valve, who is in continuous
 
communication with the control room. In this way, the
 
penetration can be rapidly isolated when a need for primary
 
containment isolation is indicated.
A second Note has been added to provide clarification that, for the purpose of this LCO, separate Condition entry is
 
allowed for each penetration flow path. This is acceptable, since the Required Actions for each Condition provide
 
appropriate compensatory actions for each inoperable PCIV. 
 
Complying with the Required Actions may allow for continued
 
operation, and subsequent inoperable PCIVs are governed by
 
subsequent Condition entry and application of associated
 
Required Actions.
The ACTIONS are modified by Notes 3 and 4. Note 3 ensures
 
appropriate remedial actions are taken, if necessary, if the
 
affected system(s) are rendered inoperable by an inoperable
 
PCIV (e.g., an Emergency Core Cooling System subsystem is
 
inoperable due to a failed open test return valve). Note 4
 
ensures appropriate remedial actions are taken when the
 
primary containment leakage limits are exceeded. Pursuant
 
to LCO 3.0.6, these ACTIONS are not required even when the
 
associated LCO is not met. Therefore, Notes 3 and 4 are
 
added to require the proper actions be taken.
 
A.1 and A.2
 
With one or more penetration flow paths with one PCIV
 
inoperable, except for MSIV leakage rate or hydrostatically
 
tested line leakage rate not within limit, the affected
 
penetration flow path must be isolated. The method of
 
isolation must include the use of at least one isolation
 
barrier that cannot be adversely affected by a single active
 
failure. Isolation barriers that meet this criterion are a
 
closed and de-activated automatic valve, a closed manual
 
valve, a blind flange, and a check valve with flow through
 
the valve secured. For penetrations isolated in accordance
 
with Required Action A.1, the device used to isolate the (continued)
PCIVs B 3.6.1.3
 
LaSalle 1 and 2 B 3.6.1.3-5 Revision 0 BASES ACTIONS A.1 and A.2 (continued) penetration should be the closest available one to the
 
primary containment. The Required Action must be completed
 
within the 4 hour Completion Time (8 hours for main steam
 
lines). The specified time period of 4 hours is reasonable
 
considering the time required to isolate the penetration and
 
the relative importance of supporting primary containment
 
OPERABILITY during MODES 1, 2, and 3. For main steam lines, an 8 hour Completion Time is allowed. The Completion Time
 
of 8 hours for the main steam lines allows a period of time
 
to restore the MSIVs to OPERABLE status given the fact that
 
MSIV closure will result in isolation of the main steam
 
line(s) and a potential for plant shutdown.
 
For affected penetrations that have been isolated in
 
accordance with Required Action A.1, the affected
 
penetration flow path must be verified to be isolated on a 
 
periodic basis. This is necessary to ensure that primary
 
containment penetrations required to be isolated following
 
an accident, and no longer capable of being automatically
 
isolated, will be in the isolation position should an event
 
occur. This Required Action does not require any testing or
 
device manipulation. Rather, it involves verification that
 
those devices outside the primary containment and capable of
 
being mispositioned are in the correct position. The
 
Completion Time for this verification of "once per 31 days
 
for isolation devices outside primary containment" is
 
appropriate because the devices are operated under
 
administrative controls and the probability of their
 
misalignment is low. For devices inside the primary
 
containment, the specified time period of "prior to entering
 
MODE 2 or 3 from MODE 4 if primary containment was de-
 
inerted while in MODE 4, if not performed within the
 
previous 92 days," is based on engineering judgment and is
 
considered reasonable in view of the inaccessibility of the
 
devices and the existence of other administrative controls
 
ensuring that device misalignment is an unlikely
 
possibility.
 
Condition A is modified by a Note indicating that this
 
Condition is only applicable to those penetration flow paths
 
with two or more PCIVs. For penetration flow paths with one
 
PCIV, Condition C provides appropriate Required Actions.
(continued)
PCIVs B 3.6.1.3
 
LaSalle 1 and 2 B 3.6.1.3-6 Revision 0 BASES ACTIONS A.1 and A.2 (continued)
Required Action A.2 is modified by two Notes. Note 1
 
applies to isolation devices located in high radiation areas
 
and allows them to be verified by use of administrative
 
means. Allowing verification by administrative means is
 
considered acceptable, since access to these areas is
 
typically restricted. Note 2 applies to isolation devices
 
that are locked, sealed, or otherwise secured in position
 
and allows these devices to be verified closed by use of
 
administrative means. Allowing verification by
 
administrative means is considered acceptable, since the
 
function of locking, sealing, or securing components is to
 
ensure that these devices are not inadvertently
 
repositioned. Therefore, the probability of misalignment, 
 
once they have been verified to be in the proper position, is low.
 
B.1 With one or more penetration flow paths with two or more
 
PCIVs inoperable, except for MSIV leakage rate or
 
hydrostatically tested line leakage rate not within limit, either the inoperable PCIVs must be restored to OPERABLE
 
status or the affected penetration flow path must be
 
isolated within 1 hour. The method of isolation must
 
include the use of at least one isolation barrier that
 
cannot be adversely affected by a single active failure. 
 
Isolation barriers that meet this criterion are a closed and
 
de-activated automatic valve, a closed manual valve, and a
 
blind flange. The 1 hour Completion Time is consistent with
 
the ACTIONS of LCO 3.6.1.1.
 
Condition B is modified by a Note indicating this Condition
 
is only applicable to penetration flow paths with two or
 
more PCIVs. For penetration flow paths with one PCIV, Condition C provides the appropriate Required Actions.
(continued)
PCIVs B 3.6.1.3
 
LaSalle 1 and 2 B 3.6.1.3-7 Revision 0 BASES ACTIONS C.1 and C.2 (continued)
When one or more penetration flow paths with one PCIV
 
inoperable, except for MSIV leakage rate or hydrostatically
 
tested line leakage rate not within limit, the inoperable
 
valve must be restored to OPERABLE status or the affected
 
penetration flow path must be isolated. The method of
 
isolation must include the use of at least one isolation
 
barrier that cannot be adversely affected by a single active
 
failure. Isolation barriers that meet this criterion are a
 
closed and de-activated automatic valve, a closed manual
 
valve, and a blind flange. A check valve may not be used to
 
isolate the affected penetration. The Completion Time of 4
 
hours for valves other than EFCVs and in penetrations with a
 
closed system is reasonable considering the time required to
 
isolate the penetration and the relative importance of
 
supporting primary containment OPERABILITY during MODES 1, 2, and 3. The Completion Time of 72 hours for penetrations
 
with a closed system is reasonable considering the relative
 
stability of the closed system  (hence, reliability) to act
 
as a penetration isolation boundary and the relative
 
importance of supporting primary containment OPERABILITY
 
during MODES 1, 2, and 3. The closed system must meet the
 
requirements of Reference 5. The Completion Time of 72
 
hours for EFCVs is also reasonable considering the
 
instrument and the small pipe diameter of penetration (hence, reliability) to act as a penetration isolation
 
boundary and the small pipe diameter of the affected
 
penetration. In the event the affected penetration is
 
isolated in accordance with Required Action C.1, the
 
affected penetration flow path must be verified to be
 
isolated on a periodic basis. This is necessary to ensure
 
that primary containment penetrations required to be
 
isolated following an accident are isolated. This Required
 
Action does not require any testing or valve manipulation.
 
Rather, it involves verification that these devices outside
 
containment and capable of potentially being mispositioned
 
are in the correct position. The Completion Time of "once
 
per 31 days" is appropriate because the devices are operated
 
under administrative controls and the probability of their
 
misalignment is low. 
 
(continued)
PCIVs B 3.6.1.3
 
LaSalle 1 and 2 B 3.6.1.3-8 Revision 0 BASES ACTIONS C.1 and C.2 (continued)
Condition C is modified by a Note indicating this Condition
 
is applicable only to those penetration flow paths with only
 
one PCIV. For penetration flow paths with two or more
 
PCIVs, Conditions A and B provide the appropriate Required
 
Actions. This Note is necessary since this Condition is
 
written specifically to address those penetrations with a
 
single PCIV.
 
Required Action C.2 is modified by two Notes. Note 1
 
applies to isolation devices located in high radiation areas
 
and allows them to be verified by use of administrative
 
means. Allowing verification by administrative means is
 
considered acceptable, since access to these areas is
 
typically restricted. Note 2 applies to isolation devices
 
that are locked, sealed, or otherwise secured in position
 
and allows these devices to be verified closed by use of
 
administrative means. Allowing verification by
 
administrative means is considered acceptable, since the
 
function of locking, sealing, or securing components is to
 
ensure that these devices are not inadvertently
 
repositioned. Therefore, the probability of misalignment, once they have been verified to be in the proper position, is low.
 
D.1 With the MSIV leakage rate (SR 3.6.1.3.10) or
 
hydrostatically tested line leakage rate (SR 3.6.1.3.11) not
 
within limit, the assumptions of the safety analysis may not
 
be met. Therefore, the leakage rate must be restored to
 
within limit within the Completion Times appropriate for
 
each type of valve leakage: a) hydrostatically tested line
 
leakage not on a closed system is required to be restored
 
within 4 hours; b) MSIV leakage is required to be restored
 
within 8 hours; and c) hydrostatically tested line leakage
 
on a closed system is required to be restored within
 
72 hours. Restoration can be accomplished by isolating the
 
penetration that caused the limit to be exceeded by use of
 
one closed and de-activated automatic valve, closed manual
 
valve, or blind flange. When a penetration is isolated, the (continued)
PCIVs B 3.6.1.3
 
LaSalle 1 and 2 B 3.6.1.3-9 Revision 0 BASES ACTIONS D.1 (continued) leakage rate for the isolated penetration is assumed to be
 
the actual pathway leakage through the isolation device. If
 
two isolation devices are used to isolate the penetration, the leakage rate is assumed to be the lesser actual pathway
 
leakage of the two devices. The 4 hour Completion Time for
 
hydrostatically tested line leakage not on a closed system
 
is reasonable considering the time required to restore
 
leakage by isolating the penetration and the relative
 
importance of the hydrostatically tested line leakage to the
 
overall containment function. The Completion Time of 8
 
hours for MSIV leakage allows a period of time to restore
 
the MSIV leakage rate to within limit given the fact that
 
MSIV closure will result in isolation of the  main steam
 
line(s) and a potential for plant shutdown. The 72 hour
 
Completion Time for hydrostatically tested line leakage on a
 
closed system is acceptable based on the available water
 
seal expected to remain as a gaseous fission product
 
boundary during the accident, and, in many cases, the
 
associated closed system. The closed system must meet the
 
requirements of Reference 5.
 
E.1, and E.2
 
If any Required Action and associated Completion Time cannot
 
be met in MODE 1, 2, or 3, the plant must be brought to a
 
MODE in which the LCO does not apply. To achieve this
 
status, the plant must be brought to at least MODE 3 within
 
12 hours and to MODE 4 within 36 hours. The allowed
 
Completion Times are reasonable, based on operating
 
experience, to reach the required plant conditions from full
 
power conditions in an orderly manner and without
 
challenging plant systems.
 
F.1 and F.2
 
If any Required Action and associated Completion Time cannot
 
be met for PCIV(s) required OPERABLE in MODE 4 or 5, the
 
plant must be placed in a condition in which the LCO does
 
not apply. Action must be immediately initiated to suspend
 
operations with a potential for draining the reactor vessel (OPDRVs) to minimize the probability of a vessel draindown
 
(continued)
PCIVs B 3.6.1.3
 
LaSalle 1 and 2 B 3.6.1.3-10 Revision 0 BASES ACTIONS F.1 and F.2 (continued) and subsequent potential for fission product release. 
 
Actions must continue until OPDRVs are suspended. If
 
suspending the OPDRVs would result in closing the residual
 
heat removal (RHR) shutdown cooling isolation valves, an
 
alternative Required Action is provided to immediately
 
initiate action to restore the valves to OPERABLE status. 
 
This allows RHR shutdown cooling to remain in service while
 
actions are being taken to restore the valve.
 
SURVEILLANCE SR  3.6.1.3.1 REQUIREMENTS This SR verifies that the 8 inch and 26 inch primary
 
containment purge valves are closed as required or, if open, opened for an allowable reason. 
 
The SR is modified by a Note stating that the SR is not
 
required to be met when the purge valves are open for the
 
stated reasons. The Note states that these valves may be
 
opened for inerting, de-inerting, pressure control, ALARA, or air quality considerations for personnel entry, or for
 
Surveillances that require the valves to be open, provided
 
the drywell purge valves and suppression chamber purge
 
valves are not open simultaneously. This is required to
 
prevent a bypass path between the suppression chamber and
 
the drywell, which would allow steam and gases from a LOCA
 
to bypass the downcomers to the suppression pool. These
 
primary containment purge valves are capable of closing in
 
the environment following a LOCA. Therefore, these valves
 
are allowed to be open for limited periods of time. The
 
31 day Frequency is consistent with other primary
 
containment isolation valve requirements discussed in
 
SR 3.6.1.3.2.
 
SR  3.6.1.3.2
 
This SR verifies that each primary containment isolation
 
manual valve and blind flange that is located outside
 
primary containment and not locked, sealed, or otherwise
 
secured and is required to be closed during accident
 
conditions, is closed. The SR helps to ensure that post
 
(continued)
PCIVs B 3.6.1.3
 
LaSalle 1 and 2 B 3.6.1.3-11 Revision 0 BASES SURVEILLANCE SR  3.6.1.3.2 (continued)
REQUIREMENTS accident leakage of radioactive fluids or gases outside of
 
the primary containment boundary is within design limits. 
 
This SR does not require any testing or valve manipulation.
 
Rather, it involves verification that those PCIVs outside
 
primary containment, and capable of being mispositioned, are
 
in the correct position. Since verification of position for
 
PCIVs outside primary containment is relatively easy, the
 
31 day Frequency was chosen to provide added assurance that
 
the PCIVs are in the correct positions. This SR does not
 
apply to valves that are locked, sealed, or otherwise
 
secured in the closed position, since these were verified to
 
be in the correct position upon locking, sealing, or
 
securing.
 
Two Notes are added to this SR. The first Note applies to
 
valves and blind flanges located in high radiation areas and
 
allows them to be verified by use of administrative
 
controls. Allowing verification by administrative controls
 
is considered acceptable, since access to these areas is
 
typically restricted during MODES 1, 2, and 3 for ALARA
 
reasons. Therefore, the probability of misalignment of
 
these PCIVs, once they have been verified to be in the
 
proper position, is low. A second Note is included to
 
clarify that PCIVs open under administrative controls are
 
not required to meet the SR during the time the PCIVs are
 
open. These controls consist of stationing a dedicated
 
operator at the controls of the valve, who is in continuous
 
communication with the control room. In this way, the
 
penetration can be rapidly isolated when a need for primary
 
containment isolation is indicated.
 
SR  3.6.1.3.3
 
This SR verifies that each primary containment manual
 
isolation valve and blind flange located inside primary
 
containment and not locked, sealed, or otherwise secured and
 
required to be closed during accident conditions, is closed.
 
The SR helps to ensure that post accident leakage of
 
radioactive fluids or gases outside the primary containment
 
boundary is within design limits. For PCIVs inside primary (continued)
PCIVs B 3.6.1.3
 
LaSalle 1 and 2 B 3.6.1.3-12 Revision 0 BASES SURVEILLANCE SR  3.6.1.3.3 (continued)
REQUIREMENTS containment, the Frequency of "prior to entering MODE 2 or 3
 
from MODE 4 if primary containment was de-inerted while in
 
MODE 4, if not performed within the previous 92 days," is
 
appropriate since these PCIVs are operated under
 
administrative controls and the probability of their
 
misalignment is low. This SR does not apply to valves that
 
are locked, sealed, or otherwise secured in the closed
 
position, since these were verified to be in the correct
 
position upon locking, sealing, or securing.
 
Two Notes are added to this SR. The first Note allows
 
valves and blind flanges located in high radiation areas to
 
be verified by use of administrative controls. Allowing
 
verification by administrative controls is considered
 
acceptable since the primary containment is inerted and
 
access to these areas is typically restricted during
 
MODES 1, 2, and 3 for ALARA and personnel safety. 
 
Therefore, the probability of misalignment of these PCIVs, once they have been verified to be in their proper position, is low. A second Note is included to clarify that PCIVs
 
that are open under administrative controls are not required
 
to meet the SR during the time that the PCIVs are open. 
 
These controls consist of stationing a dedicated operator at
 
the controls of the valve, who is in continuous
 
communication with the control room. In this way, the
 
penetration can be rapidly isolated when a need for primary
 
containment isolation is indicated.
 
SR  3.6.1.3.4
 
The traversing incore probe (TIP) shear isolation valves are
 
actuated by explosive charges. Surveillance of explosive
 
charge continuity provides assurance that TIP valves will
 
actuate when required. Other administrative controls, such
 
as those that limit the shelf life and operating life, as
 
applicable, of the explosive charges, must be followed. The
 
31 day Frequency is based on operating experience that has
 
demonstrated the reliability of the explosive charge
 
continuity.
(continued)
PCIVs B 3.6.1.3
 
LaSalle 1 and 2 B 3.6.1.3-13 Revision 0 BASES SURVEILLANCE SR  3.6.1.3.5 REQUIREMENTS (continued) Verifying the isolation time of each power operated, automatic PCIV is within limits is required to demonstrate
 
OPERABILITY. MSIVs may be excluded from this SR since MSIV
 
full closure isolation time is demonstrated by SR 3.6.1.3.6.
 
The isolation time test ensures that each valve will isolate
 
in a time period less than or equal to that assumed in the
 
safety analysis. The Frequency of this SR is in accordance
 
with the Inservice Testing Program.
 
SR  3.6.1.3.6
 
Verifying that the full closure isolation time of each MSIV
 
is within the specified limits is required to demonstrate
 
OPERABILITY. The full closure isolation time test ensures
 
that the MSIV will isolate in a time period that does not
 
exceed the times assumed in the DBA and transient analyses.
 
The Frequency of this SR is in accordance with the Inservice
 
Testing Program.
 
SR  3.6.1.3.7
 
Automatic PCIVs close on a primary containment isolation
 
signal to prevent leakage of radioactive material from
 
primary containment following a DBA. This SR ensures that
 
each automatic PCIV will actuate to its isolation position
 
on a primary containment isolation signal. The LOGIC SYSTEM
 
FUNCTIONAL TEST in LCO 3.3.6.1, "Primary Containment
 
Isolation Instrumentation," overlaps this SR to provide
 
complete testing of the safety function. The 24 month
 
Frequency is based on the need to perform this Surveillance
 
under the conditions that apply during a plant outage and
 
the potential for an unplanned transient if the Surveillance
 
were performed with the reactor at power. Operating
 
experience has shown that these components usually pass this
 
Surveillance when performed at the 24 month Frequency.
 
Therefore, the Frequency was concluded to be acceptable from
 
a reliability standpoint.
 
(continued)
PCIVs B 3.6.1.3
 
LaSalle 1 and 2 B 3.6.1.3-14 Revision 11 BASES SURVEILLANCE SR  3.6.1.3.8 REQUIREMENTS (continued) This SR requires a demonstration that each reactor instrumentation line EFCV is OPERABLE by verifying that the valve actuates to the isolation position on an actual or
 
simulated instrumentation line break condition. This SR provides assurance that the reactor instrumentation line EFCVs will perform as designed. The 24 month Frequency is
 
based on the need to perform this Surveillance under the
 
conditions that apply during a plant outage and the
 
potential for an unplanned transient if the Surveillance
 
were performed with the reactor at power. Operating
 
experience has shown that these components usually pass this
 
Surveillance when performed at the 24 month Frequency. 
 
Therefore, the Frequency was concluded to be acceptable from
 
a reliability standpoint.
 
Instrumentation lines that connect to the containment atmosphere, such as those which measure drywell pressure, or monitor the containment atmosphere or suppression pool water level, are considered extensions of primary containment. A failure of one of these instrumentation lines during normal operation would not result in the closure of the associated EFCV, since normal operating containment pressure is not sufficient to operate the valve. Such EFCVs will only close with a downstream line break concurrent with a LOCA. Since these conditions are beyond the plant design basis, EFCV closure is not needed and containment atmospheric instrumentation line EFCVs need not be tested (Ref. 6).
 
SR  3.6.1.3.9
 
The TIP shear isolation valves are actuated by explosive
 
charges. An in place functional test is not possible with
 
this design. The explosive squib is removed and tested to
 
provide assurance that the valves will actuate when
 
required. The replacement charge for the explosive squib
 
shall be from the same manufactured batch as the one fired
 
or from another batch that has been certified by having one
 
of the batch successfully fired. Other administrative
 
controls, such as those that limit the shelf life and
 
operating life, as applicable, of the explosive charges, must be followed. The Frequency of 24 months on a STAGGERED
 
TEST BASIS is considered adequate given the administrative
 
controls on replacement charges and the frequency checks of
 
circuit continuity (SR 3.6.1.3.4). (continued)
PCIVs B 3.6.1.3
 
LaSalle 1 and 2 B 3.6.1.3-15 Revision 26 BASES SURVEILLANCE  SR  3.6.1.3.10 REQUIREMENTS (continued) The analyses in Reference 2 are based on leakage that is less than the specified leakage rate. Leakage through any
 
one main steam line must be  100 scfh and through all four main steam lines must be  400 scfh when tested at P t (25.0 psig). This ensures that MSIV leakage is properly accounted for in determining the overall primary containment
 
leakage rate. The Frequency is required by the Primary
 
Containment Leakage Rate Testing Program.
 
SR  3.6.1.3.11 Surveillance of hydrostatically tested lines provides
 
assurance that the calculation assumptions of Reference 2
 
are met. The acceptance criteria for the combined leakage
 
of all hydrostatically tested lines is 1 gpm times the total
 
number of hydrostatically tested PCIVs when tested at 1.1 P a , or other acceptable criteria based upon satisfying the acceptance criteria of 10 CFR 100, regarding the site radiological analysis. The combined leakage rates must be demonstrated in accordance with the leakage test Frequency required by the Primary Containment Leakage Rate Testing
 
Program.
REFERENCES 1. Technical Requirements Manual.
: 2. UFSAR, Section 15.6.5.
: 3. UFSAR, Section 15.6.4.
: 4. UFSAR, Section 15.2.4.
: 5. UFSAR, Section 6.2.4.2.3.
: 6. NEDO-32977-A, "Excess Flow Check Valve Testing Relaxation," June 2000
 
Drywell and Suppression Chamber Pressure B 3.6.1.4
 
LaSalle 1 and 2 B 3.6.1.4-1 Revision 0 B 3.6  CONTAINMENT SYSTEMS
 
B 3.6.1.4  Drywell and Suppression Chamber Pressure
 
BASES
 
BACKGROUND The drywell and suppression chamber internal pressure is limited during normal operation to preserve the initial
 
conditions assumed in the accident analyses for a Design
 
Basis Accident (DBA) or loss of coolant accident (LOCA).
Transient events, which include inadvertent drywell spray
 
initiation, can reduce the drywell and suppression chamber
 
internal pressure. Without an appropriate limit on the
 
minimum drywell and suppression chamber internal pressure
 
(-0.5 psig), the design limit for negative containment
 
differential pressure of 5.0 psid could be exceeded (Ref. 1).
 
The limitation on the maximum drywell and suppression
 
chamber internal pressure (0.75 psig) provides added
 
assurance that the peak LOCA drywell and suppression chamber
 
pressure does not exceed the design value of 45 psig (Ref. 1).
 
APPLICABLE Primary containment performance for the DBA is evaluated for SAFETY ANALYSES the entire spectrum of break sizes for postulated LOCAs inside containment (Ref. 2). Among the inputs to the design
 
basis analysis is the initial drywell and suppression
 
chamber internal pressure. The initial pressure limitation
 
requirements ensure that peak primary containment pressure
 
for a DBA LOCA does not exceed the design value of 45 psig
 
and that peak negative pressure for an inadvertent drywell
 
spray event does not exceed the design value of 5.0 psid.
Primary containment pressure satisfies Criterion 2 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO A limitation on the drywell and suppression chamber internal pressure of  -0.5 psig and  +0.75 psig is required to ensure that primary containment initial conditions are
 
consistent with the initial safety analyses assumptions so (continued)
Drywell and Suppression Chamber Pressure B 3.6.1.4
 
LaSalle 1 and 2 B 3.6.1.4-2 Revision 0 BASES LCO that containment pressures remain within design values (cont'd) during a LOCA and the design value of containment negative pressure is not exceeded during an inadvertent operation of
 
drywell sprays.
 
APPLICABILITY In MODES 1, 2, and 3, a DBA could result in a release of radioactive material to primary containment. In MODES 4
 
and 5, the probability and consequences of these events are
 
reduced due to the pressure and temperature limitations of
 
these MODES. Therefore, maintaining drywell and suppression
 
chamber internal pressure within limits is not required in
 
MODE 4 or 5.
 
ACTIONS A.1 When drywell or suppression chamber internal pressure is not
 
within the limits of the LCO, drywell and suppression
 
chamber internal pressure must be restored to within limits
 
within 1 hour. The Required Action is necessary to return
 
operation to within the bounds of the primary containment
 
analysis. The 1 hour Completion Time is consistent with the
 
ACTIONS of LCO 3.6.1.1, "Primary Containment," which
 
requires that primary containment be restored to OPERABLE
 
status within 1 hour.
 
B.1 and B.2
 
If drywell and suppression chamber internal pressure cannot
 
be restored to within limits within the required Completion
 
Time, the plant must be brought to a MODE in which the LCO
 
does not apply. To achieve this status, the plant must be
 
brought to at least MODE 3 within 12 hours and to MODE 4
 
within 36 hours. The allowed Completion Times are
 
reasonable, based on operating experience, to reach the
 
required plant conditions from full power conditions in an
 
orderly manner and without challenging plant systems.
 
(continued)
Drywell and Suppression Chamber Pressure B 3.6.1.4
 
LaSalle 1 and 2 B 3.6.1.4-3 Revision 0 BASES  (continued)
 
SURVEILLANCE SR  3.6.1.4.1 REQUIREMENTS Verifying that drywell and suppression chamber internal
 
pressure is within limits ensures that operation remains
 
within the limits assumed in the primary containment
 
analysis. The 12 hour Frequency of this SR was developed
 
based on operating experience related to trending primary
 
containment pressure variations during the applicable MODES.
 
Furthermore, the 12 hour Frequency is considered adequate in
 
view of other indications available in the control room, including alarms, to alert the operator to an abnormal
 
primary containment pressure condition.
 
REFERENCES 1. UFSAR, Section 6.2.1.1.3.
: 2. UFSAR, Section 6.2.1.1.3.1.
 
Drywell Air Temperature B 3.6.1.5 LaSalle 1 and 2 B 3.6.1.5-1 Revision 0 B 3.6  CONTAINMENT SYSTEMS
 
B 3.6.1.5  Drywell Air Temperature
 
BASES
 
BACKGROUND Heat loads from the drywell, as well as piping and equipment, add energy to the airspace and raise airspace
 
temperature. Coolers included in the unit design remove
 
this energy and maintain an appropriate average temperature.
 
The average airspace temperature affects the calculated
 
response to postulated Design Basis Accidents (DBAs). This
 
drywell air temperature limit is an initial condition input
 
for the Reference 1 safety analyses.
 
APPLICABLE Primary containment performance for the DBA is evaluated for SAFETY ANALYSES a entire spectrum of break sizes for postulated loss of coolant accidents (LOCAs) inside containment (Ref. 1).
 
Among the inputs to the design basis analysis is the initial
 
drywell average air temperature. Analyses assume an initial
 
average drywell temperature of 135
&deg;F. Maintaining the expected initial conditions ensures that safety analyses
 
remain valid and ensures that the peak LOCA primary drywell
 
temperature does not exceed the maximum allowable
 
temperature of 340
&deg;F (Ref. 1). Exceeding this design temperature may result in the degradation of the primary
 
containment structure under accident loads. Equipment
 
inside primary containment, and needed to mitigate the
 
effects of a DBA, is designed to operate and be capable of
 
operating under environmental conditions expected for the
 
accident.
Drywell air temperature satisfies Criterion 2 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO With an initial drywell average air temperature less than or equal to the LCO temperature limit, the peak accident
 
temperature is maintained below the drywell design
 
temperature. As a result, the ability of primary
 
containment to perform its design function is ensured.
 
APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4
 
and 5, the probability and consequences of these events are (continued)
Drywell Air Temperature B 3.6.1.5
 
LaSalle 1 and 2 B 3.6.1.5-2 Revision 0 BASES APPLICABILITY reduced due to the pressure and temperature limitations of (continued) these MODES. Therefore, maintaining drywell average air temperature within the limit is not required in MODE 4 or 5.
 
ACTIONS A.1 When drywell average air temperature is not within the limit
 
of the LCO, it must be restored within 8 hours. This
 
Required Action is necessary to return operation to within
 
the bounds of the primary containment analysis. The 8 hour
 
Completion Time is acceptable, considering the sensitivity
 
of the analysis to variations in this parameter, and
 
provides sufficient time to correct minor problems.
 
B.1 and B.2
 
If the drywell average air temperature cannot be restored to
 
within the limit within the required Completion Time, the
 
plant must be brought to a MODE in which the LCO does not
 
apply. To achieve this status, the plant must be brought to
 
at least MODE 3 within 12 hours and to MODE 4 within
 
36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant
 
conditions from full power conditions in an orderly manner
 
and without challenging plant systems.
 
SURVEILLANCE SR  3.6.1.5.1 REQUIREMENTS Verifying that the drywell average air temperature is within
 
the LCO limit ensures that operation remains within the
 
limits assumed for the primary containment analyses. The
 
drywell average air temperature is determined using the
 
average temperature of the operating return air plenum(s)
 
upstream of the primary containment ventilation heat
 
exchanger coil and cabinet located at elevation
 
740 ft 0 inches, azimuth 248
&deg;, and elevation 740 ft 0 inches, azimuth 76
&deg;. This provides a representative sample of the overall drywell atmosphere.   
(continued)
Drywell Air Temperature B 3.6.1.5
 
LaSalle 1 and 2 B 3.6.1.5-3 Revision 0 BASES SURVEILLANCE SR 3.6.1.5.1 (continued)
REQUIREMENTS The 24 hour Frequency of this SR was developed based on
 
operating experience related to drywell average air
 
temperature variations and temperature dependent drift of
 
instrumentation located in the drywell during the applicable
 
MODES and the low probability of a DBA occurring between
 
Surveillances. Furthermore, the 24 hour Frequency is
 
considered adequate in view of other indications available
 
in the control room, including alarms, to alert the operator
 
to an abnormal drywell air temperature condition.
REFERENCES 1. UFSAR, Section 6.2.
 
Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6
 
LaSalle 1 and 2 B 3.6.1.6-1 Revision 0 B 3.6  CONTAINMENT SYSTEMS
 
B 3.6.1.6  Suppression Chamber-to-Drywell Vacuum Breakers
 
BASES
 
BACKGROUND The function of the suppression-chamber-to-drywell vacuum breakers is to relieve vacuum in the drywell. There are
 
four vacuum breakers located outside the primary containment
 
which form an extension of the primary containment boundary.
 
The vacuum relief valves are mounted in special piping
 
between the drywell and the suppression chamber, which allow
 
air and steam flow from the suppression chamber to the
 
drywell when the drywell is at a negative pressure with
 
respect to the suppression chamber. Therefore, suppression
 
chamber-to-drywell vacuum breakers prevent an excessive
 
negative differential pressure across the wetwell drywell
 
boundary. Each vacuum breaker is a self actuating valve
 
with one vacuum breaker in each line. Manual isolation
 
valves are located on each side of each vacuum breaker.
A negative differential pressure across the drywell wall is
 
caused by rapid depressurization of the drywell. Events
 
that cause this rapid depressurization are cooling cycles, inadvertent drywell spray actuation, and steam condensation
 
from sprays or subcooled water reflood of a break in the
 
event of a primary system rupture. Cooling cycles result in
 
minor pressure transients in the drywell that occur slowly
 
and are normally controlled by heating and ventilation
 
equipment. Spray actuation or spill of subcooled water out
 
of a break results in more significant pressure transients
 
and becomes important in sizing the vacuum breakers.
 
In the event of a primary system rupture, steam condensation
 
within the drywell results in the most severe pressure
 
transient. Following a primary system rupture, air in the
 
drywell is purged into the suppression chamber free
 
airspace, leaving the drywell full of steam. Subsequent
 
condensation of the steam can be caused in two possible
 
ways, namely, Emergency Core Cooling Systems flow from a
 
recirculation line break, or drywell spray actuation
 
following a loss of coolant accident (LOCA). These two
 
cases determine the maximum depressurization rate of the
 
drywell.  (continued)
Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6
 
LaSalle 1 and 2 B 3.6.1.6-2 Revision 0 BASES BACKGROUND In addition, the water column in the Mark II Vent System (continued) downcomer is controlled by the drywell-to-suppression chamber differential pressure. If the drywell pressure is
 
less than the suppression chamber pressure, there will be an
 
increase in the downcomer water column height. This will
 
result in an increase in the water clearing inertia in the
 
event of a postulated LOCA, resulting in an increase in the
 
peak drywell pressure. This in turn will result in an
 
increase in the pool swell dynamic loads. The vacuum
 
breakers limit the height of the waterleg in the downcomer
 
during normal operation.
 
APPLICABLE Analytical methods and assumptions involving the SAFETY ANALYSES suppression chamber-to-drywell vacuum breakers are presented in Reference 1 as part of the accident response of the
 
primary containment systems. Suppression chamber-to-drywell
 
vacuum breakers are provided as part of the primary
 
containment to limit the negative differential pressure
 
across the drywell and suppression chamber walls to maintain
 
the structural integrity of primary containment.
The safety analyses assume that the vacuum breakers are
 
closed initially and are fully open at a differential
 
pressure of 1.0 psid (Refs. 1 and 2). Additionally, one of
 
the four vacuum breakers is assumed to fail in a closed
 
position (Refs. 1 and 2). The results of the analyses show
 
that the design pressure is not exceeded even under the
 
worst case accident scenario. The vacuum breaker opening
 
differential pressure setpoint and the requirement that four
 
vacuum breakers be OPERABLE (the additional vacuum breaker
 
is required to meet the single failure criterion) are a
 
result of the requirement placed on the vacuum breakers to
 
limit the downcomer waterleg height. Design Basis Accident (DBA) analyses assume the vacuum breakers to be closed
 
initially and to remain closed and leak tight until the
 
suppression pool is at a positive pressure relative to the
 
drywell.
 
The suppression chamber-to-drywell vacuum breakers satisfy
 
Criterion 3 of 10 CFR 50.36(c)(2)(ii).
 
(continued)
Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6
 
LaSalle 1 and 2 B 3.6.1.6-3 Revision 0 BASES  (continued)
 
LCO All vacuum breakers must be OPERABLE to provide assurance that the vacuum breakers will open so that drywell-to-
 
suppression chamber negative differential pressure remains
 
below the design value. This LCO also ensures that all
 
suppression chamber-to-drywell vacuum breakers are closed (except during testing or when the vacuum breakers are
 
performing their intended design function). The manual
 
isolation valves in each vacuum breaker line must also be
 
open for the associated vacuum breaker to be considered
 
OPERABLE. The requirement that the vacuum breakers be
 
closed ensures that there is no excessive bypass leakage
 
should a LOCA occur.
 
APPLICABILITY In MODES 1, 2, and 3, a DBA could result in excessive negative differential pressure across the drywell wall, caused by the rapid depressurization of the drywell. The
 
event that results in the limiting rapid depressurization of
 
the drywell is the primary system rupture that purges the
 
drywell of air and fills the drywell free airspace with
 
steam. Subsequent condensation of the steam would result in
 
depressurization of the drywell. The limiting pressure and
 
temperature of the primary system prior to a DBA occur in
 
MODES 1, 2, and 3. Excessive negative pressure inside the
 
drywell could occur due to inadvertent actuation of drywell
 
sprays. In MODES 4 and 5, the probability and consequences of these
 
events are reduced by the pressure and temperature
 
limitations in these MODES; therefore, maintaining
 
suppression chamber-to-drywell vacuum breakers OPERABLE is
 
not required in MODE 4 or 5.
 
ACTIONS A.1 With one of the vacuum breakers inoperable for opening (e.g., the vacuum breaker is not open and may be stuck
 
closed or not within its opening setpoint limit, so that it
 
would not function as designed during an event that
 
depressurized the drywell), the remaining three OPERABLE
 
vacuum breakers are capable of providing the vacuum relief
 
function. However, overall system reliability is reduced
 
because a single failure in one of the remaining vacuum
 
breakers could result in an excessive suppression chamber-
 
to-drywell differential pressure during a DBA. Therefore, (continued)
Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6
 
LaSalle 1 and 2 B 3.6.1.6-4 Revision 32 BASES ACTIONS A.1 (continued) with one of the four vacuum breakers inoperable, 72 hours is
 
allowed to restore the inoperable vacuum breaker to OPERABLE
 
status so that plant conditions are consistent with those
 
assumed for the design basis analysis. The 72 hour
 
Completion Time is considered acceptable due to the low
 
probability of an event in which the remaining vacuum
 
breaker capability would not be adequate.
 
B.1  If a required suppression chamber-to-drywell vacuum breaker is inoperable for opening and is not restored to OPERABLE status within the required Completion Time, the plant must be brought to a condition in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short.
However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
 
C.1 and C.2
 
With one vacuum breaker not closed, communication between
 
the drywell and suppression chamber airspace exists, and, as
 
a result, there is the potential for primary containment
 
overpressurization due to this bypass leakage if a LOCA were
 
to occur. Therefore, both manual isolation valves in the
 
affected vacuum breaker line must be closed. A short time
 
is allowed to close the manual valves due to the low
 
probability of an event that would pressurize primary
 
containment. The required 4 hour Completion Time is
 
considered adequate to perform this activity. With both 
 
(continued)
 
Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6
 
LaSalle 1 and 2 B 3.6.1.6-5 Revision 32 BASES ACTIONS C.1 and C.2 (continued)
 
manual isolation valves closed, the vacuum breaker is not
 
capable of performing the vacuum relief function. While the
 
remaining three OPERABLE vacuum breakers are capable of
 
providing the vacuum relief function, the overall
 
reliability is reduced because a single failure in one of
 
the remaining vacuum breakers could result in an excessive
 
suppression chamber-to-drywell differential pressure during
 
a DBA. Therefore, under this condition, 72 hours is allowed
 
to restore the inoperable vacuum breaker to OPERABLE status
 
so that the plant conditions are consistent with those
 
assumed for the design basis analysis. The 72 hour
 
Completion Time is considered acceptable due to the low
 
probability of an event in which the remaining vacuum
 
breaker capability would not be adequate.
 
D.1 and D.2
 
If the open suppression chamber-to-drywell vacuum breaker cannot be closed within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to
 
at least MODE 3 within 12 hours and to MODE 4 within
 
36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant
 
conditions from full power conditions in an orderly manner
 
and without challenging plant systems.
 
E.1 With two or more vacuum breakers inoperable, an excessive
 
suppression chamber-to-drywell differential pressure could
 
occur during a DBA. Therefore, an immediate plant shutdown
 
in accordance with LCO 3.0.3 is required.
 
SURVEILLANCE SR  3.6.1.6.1 REQUIREMENTS Each vacuum breaker is verified closed to ensure that this
 
potential large bypass leakage path is not present. This
 
Surveillance is performed by observing the vacuum breaker
 
position indication or by verifying that a differential
 
pressure of 0.25 psid between the suppression chamber and (continued)
Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6
 
LaSalle 1 and 2 B 3.6.1.6-6 Revision 32 BASES SURVEILLANCE SR  3.6.1.6.1 (continued)
REQUIREMENTS
 
drywell is maintained for 1 hour without makeup. The 14 day
 
Frequency is based on engineering judgment, is considered
 
adequate in view of other indications of vacuum breaker
 
status available to operations personnel, and has been shown
 
to be acceptable through operating experience. Two Notes
 
are added to this SR. The first Note allows suppression
 
chamber-to-drywell vacuum breakers opened in conjunction
 
with the performance of a Surveillance to not be considered
 
as failing this SR. These periods of opening vacuum
 
breakers are controlled by plant procedures and do not
 
represent inoperable vacuum breakers. The second Note is
 
included to clarify that vacuum breakers open due to an
 
actual differential pressure are not considered as failing
 
this SR.
 
SR  3.6.1.6.2
 
Each vacuum breaker must be manually cycled to ensure that
 
it opens adequately to perform its design function and
 
returns to the fully closed position. This ensures that the
 
safety analysis assumptions are valid. The 92 day Frequency
 
of this SR was developed, based on Inservice Testing Program
 
requirements to perform valve testing at least once every
 
92 days. In addition, this functional test is required
 
within 12 hours after a discharge of steam to the
 
suppression chamber from the safety/relief valves.
 
SR  3.6.1.6.3
 
Verification of the vacuum breaker opening setpoint of 0.5 psid from the closed position is necessary to ensure that the safety analysis assumption regarding vacuum breaker
 
full open differential pressure of 1.0 psid is valid. 
 
The24 month Frequency is based on the need to perform this
 
Surveillance under the conditions that apply during a plant
 
outage and the potential for an unplanned transient if the
 
Surveillance were performed with the reactor at power. The
 
24 month Frequency has been shown to be acceptable, based on
 
operating experience, and is further justified because of
 
other surveillances performed at shorter Frequencies that
 
convey the proper functioning status of each vacuum breaker.
 
  (continued)
Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6
 
LaSalle 1 and 2 B 3.6.1.6-7 Revision 32 BASES  (continued)
 
REFERENCES 1. UFSAR, Section 6.2.1.
: 2. FSAR, Response to NRC Question 021.4.
: 3. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants," December 2002.
 
Suppression Pool Average Temperature B 3.6.2.1
 
LaSalle Unit 1 and 2 B 3.6.2.1-1 Revision 0 B 3.6  CONTAINMENT SYSTEMS
 
B 3.6.2.1  Suppression Pool Average Temperature
 
BASES
 
BACKGROUND The primary containment utilizes a Mark II over/under pressure suppression configuration, with the suppression
 
pool located at the bottom of the primary containment. The
 
suppression pool is designed to absorb the decay heat and
 
sensible heat released during a reactor blowdown from
 
safety/relief valve discharges or from a loss of coolant
 
accident (LOCA). The suppression pool must also condense
 
steam from the Reactor Core Isolation Cooling System turbine
 
exhaust and provides the main emergency water supply source
 
for the reactor vessel. The suppression pool must quench
 
all the steam released through the downcomer lines during a
 
loss of coolant accident (LOCA). This is the essential
 
mitigative feature of a pressure suppression containment
 
that ensures that the peak containment pressure is
 
maintained below the design value (45 psig). Suppression
 
pool average temperature (along with LCO 3.6.2.2, "Suppression Pool Water Level") is a key indication of the
 
capacity of the suppression pool to fulfill these
 
requirements.
The technical concerns that lead to the development of
 
suppression pool average temperature limits are as follows:
: a. Complete steam condensation;
: b. Primary containment peak pressure and temperature;
: c. Condensation oscillation (CO) loads; and
: d. Chugging loads.
 
APPLICABLE The postulated DBA against which the primary containment SAFETY ANALYSES performance is evaluated is the entire spectrum of postulated pipe breaks within the primary containment.
 
Inputs to the safety analyses include initial suppression
 
pool water volume and suppression pool temperature (Reference 1 for LOCAs and References 1 and 2 for the
 
suppression pool temperature analyses required by
 
Reference 3). An initial pool temperature of 105
&deg;F is  (continued)
Suppression Pool Average Temperature B 3.6.2.1
 
LaSalle Unit 1 and 2 B 3.6.2.1-2 Revision 0 BASES APPLICABLE assumed for the Reference 1 analyses. Reactor shutdown at a SAFETY ANALYSES pool temperature of 110
&deg;F and vessel depressurization at a    (continued) pool temperature of 120
&deg;F are assumed for the Reference 1 and 2 analyses.
Suppression pool average temperature satisfies Criteria 2
 
and 3 of 10 CFR 50.36(c)(2)(ii).
 
LCO A limitation on the suppression pool average temperature is required to assure that the primary containment conditions
 
assumed for the safety analyses are met. This limitation
 
subsequently ensures that peak primary containment pressures
 
and temperatures do not exceed maximum allowable values
 
during a postulated DBA or any transient resulting in heatup
 
of the suppression pool. The LCO requirements are as
 
follows:  a. Average temperature  105&deg;F with THERMAL POWER
> 1% RTP. This requirement ensures that licensing bases initial conditions are met. This requirement
 
also ensures that the plant has testing flexibility, and was selected to provide margin below the 110
&deg;F limit at which reactor shutdown is required.
: b. Average temperature  110&deg;F with THERMAL POWER  1% RTP. This requirement ensures that the plant will be shut down at
> 110&deg;F. The pool is designed to absorb decay heat and sensible heat but could be
 
heated beyond design limits by the steam generated if
 
the reactor is not shut down.
At 1% RTP, heat input is approximately equal to normal
 
system heat losses.
 
APPLICABILITY In MODES 1, 2, and 3, a DBA could cause significant heatup of the suppression pool. In MODES 4 and 5, the probability
 
and consequences of these events are reduced due to the
 
pressure and temperature limitations in these MODES. 
 
Therefore, maintaining suppression pool average temperature
 
within limits is not required in MODE 4 or 5.
(continued)
Suppression Pool Average Temperature B 3.6.2.1
 
LaSalle Unit 1 and 2 B 3.6.2.1-3 Revision 0 BASES  (continued)
 
ACTIONS A.1, A.2, and A.3 With the suppression pool average temperature above the
 
specified limit and when above the specified power limit, the initial conditions exceed the conditions assumed for the
 
Reference 1 and 2 analyses. However, primary containment
 
cooling capability still exists, and the primary containment
 
pressure suppression function will occur at temperatures
 
well above that assumed for safety analyses. Therefore, continued operation is allowed for a limited time. The
 
24 hour Completion Time is adequate to allow the suppression
 
pool temperature to be restored to below the limit.
 
Additionally, when pool temperature is > 105
&deg;F, increased monitoring of the pool temperature is required to ensure it
 
remains  110&deg;F. The once per hour Completion Time is adequate based on past experience, which has shown that
 
suppression pool temperature increases relatively slowly
 
except when testing that adds heat to the pool is being
 
performed. Furthermore, the once per hour Completion Time
 
is considered adequate in view of other indications in the
 
control room, including alarms, to alert the operator to an
 
abnormal suppression pool average temperature condition. In
 
addition, testing that adds heat to the suppression pool
 
must be immediately suspended to preserve the pool heat
 
absorption capability.
 
B.1 If the suppression pool average temperature cannot be
 
restored to within limits within the required Completion
 
Time, the plant must be brought to a MODE in which the LCO
 
does not apply. To achieve this status, THERMAL POWER must
 
be reduced to  1% RTP within 12 hours. The 12 hour Completion Time is reasonable, based on operating
 
experience, to reduce reactor power from full power in an
 
orderly manner and without challenging plant systems.
 
C.1, C.2, and C.3
 
Suppression pool average temperature > 110
&deg;F requires that the reactor be shut down immediately. This is accomplished
 
by placing the reactor mode switch in the shutdown position.
 
Further cooldown to MODE 4 within 36 hours is required at (continued)
Suppression Pool Average Temperature B 3.6.2.1
 
LaSalle Unit 1 and 2 B 3.6.2.1-4 Revision 0 BASES ACTIONS C.1, C.2, and C.3 (continued) normal cooldown rates (provided pool temperature remains 120&deg;F). Additionally, when pool temperature is > 110
&deg;F, increased monitoring of pool temperature is required to
 
ensure that it remains  120&deg;F. The once per 30 minute Completion Time is adequate, based on operating experience.
 
Given the high pool temperature in this condition, the
 
monitoring Frequency is increased to twice that of
 
Condition A. Furthermore, the 30 minute Completion Time is
 
considered adequate in view of other indications available
 
in the control room to alert the operator to an abnormal
 
suppression pool average temperature condition.
 
D.1 and D.2
 
If suppression pool average temperature cannot be maintained 120&deg;F, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the reactor
 
pressure must be reduced to < 200 psig within 12 hours and
 
the plant must be brought to MODE 4 within 36 hours. The
 
allowed Completion Times are reasonable, based on operating
 
experience, to reach the required plant conditions from full
 
power conditions in an orderly manner without challenging
 
plant systems.
 
Continued addition of heat to the suppression pool with pool
 
temperature > 120
&deg;F could result in exceeding the design basis maximum allowable values for primary containment
 
temperature or pressure. Furthermore, if a blowdown were to
 
occur when temperature was > 120
&deg;F, the maximum allowable bulk and local temperatures could be exceeded very quickly.
 
SURVEILLANCE SR  3.6.2.1.1 REQUIREMENTS The suppression pool average temperature is regularly
 
monitored to ensure that the required limits are satisfied.
 
Average temperature is determined by taking an arithmetic
 
average of the OPERABLE suppression pool water temperature
 
channels, and may include an allowance for temperature
 
stratification. The 24 hour Frequency has been shown to be
 
acceptable based on operating experience. When heat is
 
being added to the suppression pool by testing, however, it (continued)
Suppression Pool Average Temperature B 3.6.2.1
 
LaSalle Unit 1 and 2 B 3.6.2.1-5 Revision 0 BASES SURVEILLANCE SR  3.6.2.1.1 (continued)
REQUIREMENTS is necessary to monitor suppression pool temperature more
 
frequently. The 5 minute Frequency during testing is
 
justified by the rates at which testing will heat up the
 
suppression pool, has been shown to be acceptable based on
 
operating experience, and provides assurance that allowable
 
pool temperatures are not exceeded. The Frequencies are
 
further justified in view of other indications available in
 
the control room, including alarms, to alert the operator to
 
an abnormal suppression pool average temperature condition.
REFERENCES 1. UFSAR, Section 6.2.
: 2. LaSalle County Station Mark II Design Assessment Report, Section 6.2, June 1981.
: 3. NUREG-0783.
 
Suppression Pool Water Level B 3.6.2.2
 
LaSalle 1 and 2 B 3.6.2.2-1 Revision 0 B 3.6  CONTAINMENT SYSTEMS
 
B 3.6.2.2  Suppression Pool Water Level
 
BASES
 
BACKGROUND The primary containment utilizes a Mark II over/under pressure suppression configuration, with the suppression
 
pool located at the bottom of the primary containment. The
 
suppression pool is designed to absorb the decay heat and
 
sensible heat released during a reactor blowdown from
 
safety/relief valve (S/RV) discharges or from a loss of
 
coolant accident (LOCA). The suppression pool must also
 
condense steam from the Reactor Core Isolation Cooling (RCIC) System turbine exhaust and provides the main
 
emergency water supply source for the reactor vessel. The
 
suppression pool volume ranges between 128,800 ft 3 at the low water level limit of -4.5 inches and 131,900 ft 3 at the high water level limit of 3 inches. The level is referenced
 
to a plant elevation of 699 ft 11 inches.
If the suppression pool water level is too low, an
 
insufficient amount of water would be available to
 
adequately condense the steam from the S/RV quenchers, main
 
vents, or RCIC turbine exhaust lines. Low suppression pool
 
water level could also result in an inadequate emergency
 
makeup water source to the Emergency Core Cooling System. 
 
The lower volume would also absorb less steam energy before
 
heating up excessively. Therefore, a minimum suppression
 
pool water level is specified.
 
If the suppression pool water level is too high, it could
 
result in excessive clearing loads from S/RV discharges and
 
excessive pool swell loads resulting from a Design Basis
 
Accident (DBA) LOCA. Therefore, a maximum pool water level
 
is specified. This LCO specifies an acceptable range to
 
prevent the suppression pool water level from being either
 
too high or too low.
 
APPLICABLE Initial suppression pool water level affects suppression SAFETY ANALYSES pool temperature response calculations, calculated drywell pressure for a DBA, calculated pool swell loads for a DBA
 
LOCA, and calculated loads due to S/RV discharges. 
 
Suppression pool water level must be maintained within the
 
limits specified so that the safety analysis of Reference 1
 
remains valid.
(continued)
Suppression Pool Water Level B 3.6.2.2
 
LaSalle 1 and 2 B 3.6.2.2-2 Revision 0 BASES APPLICABLE Suppression pool water level satisfies Criteria 2 and 3 of SAFETY ANALYSES 10 CFR 50.36(c)(2)(ii).
 
  (continued)
 
LCO A limit that suppression pool water level be  -4.5 inches and  3 inches (referenced to plant elevation 699 ft 11 inches) is required to ensure that the primary
 
containment conditions assumed for the safety analysis are
 
met. Either the high or low water level limits were used in
 
the safety analysis, depending upon which is conservative
 
for a particular calculation.
 
APPLICABILITY In MODES 1, 2, and 3, a DBA could cause significant loads on the primary containment. In MODES 4 and 5, the probability
 
and consequences of these events are reduced because of the
 
pressure and temperature limitations in these MODES. The
 
requirements for maintaining suppression pool water level
 
within limits in MODE 4 or 5 is addressed in LCO 3.5.2, "ECCS-Shutdown." 
 
ACTIONS A.1 With suppression pool water level outside the limits, the
 
conditions assumed for the safety analysis are not met. If
 
water level is below the minimum level, the pressure
 
suppression function still exists as long as the downcomers
 
are covered, RCIC turbine exhausts are covered, and S/RV
 
quenchers are covered. If suppression pool water level is
 
above the maximum level, protection against
 
overpressurization still exists due to the margin in the
 
peak containment pressure analysis and the capability of the
 
suppression pool sprays. Therefore, continued operation for
 
a limited time is allowed. The 2 hour Completion Time is
 
sufficient to restore suppression pool water level to within
 
specified limits. Also, it takes into account the low
 
probability of an event impacting the suppression pool water
 
level occurring during this interval.
(continued)
Suppression Pool Water Level B 3.6.2.2
 
LaSalle 1 and 2 B 3.6.2.2-3 Revision 0 BASES ACTIONS B.1 and B.2 (continued)
If suppression pool water level cannot be restored to within
 
limits within the required Completion Time, the plant must
 
be brought to a MODE in which the LCO does not apply. To
 
achieve this status, the plant must be brought to at least
 
MODE 3 within 12 hours and to MODE 4 within 36 hours. The
 
allowed Completion Times are reasonable, based on operating
 
experience, to reach the required plant conditions from full
 
power conditions in an orderly manner and without
 
challenging plant systems.
 
SURVEILLANCE SR  3.6.2.2.1 REQUIREMENTS Verification of the suppression pool water level is to
 
ensure that the required limits are satisfied. The 24 hour
 
Frequency has been shown to be acceptable based on operating
 
experience. Furthermore, the 24 hour Frequency is
 
considered adequate in view of other indications available
 
in the control room, including alarms, to alert the operator
 
to an abnormal suppression pool water level condition.
REFERENCES 1. UFSAR, Section 6.2.
 
RHR Suppression Pool Cooling B 3.6.2.3
 
LaSalle 1 and 2 B 3.6.2.3-1 Revision 0 B 3.6  CONTAINMENT SYSTEMS
 
B 3.6.2.3  Residual Heat Removal (RHR) Suppression Pool Cooling
 
BASES
 
BACKGROUND Following a Design Basis Accident (DBA), the RHR Suppression Pool Cooling System removes heat from the suppression pool.
 
The suppression pool is designed to absorb the sudden input
 
of heat from the primary system. In the long term, the pool
 
continues to absorb residual heat generated by fuel in the
 
reactor core. Some means must be provided to remove heat
 
from the suppression pool so that the temperature inside the
 
primary containment remains within design limits. This
 
function is provided by two redundant RHR suppression pool
 
cooling subsystems. The purpose of this LCO is to ensure
 
that both subsystems are OPERABLE in applicable MODES.
Each RHR subsystem contains a pump and a heat exchanger and
 
is manually initiated and independently controlled. The two
 
RHR subsystems perform the suppression pool cooling function
 
by circulating water from the suppression pool through the
 
RHR heat exchangers and returning it to the suppression
 
pool. RHR service water, circulating through the tube side
 
of the heat exchangers, exchanges heat with the suppression
 
pool water and discharges this heat to the external heat
 
sink.
 
The heat removal capability of one RHR subsystem is
 
sufficient to meet the overall DBA pool cooling requirement
 
to limit peak temperature to 208
&deg;F for loss of coolant accidents (LOCAs) and transient events such as a turbine
 
trip or a stuck open safety/relief valve (S/RV). S/RV
 
leakage and Reactor Core Isolation Cooling System testing
 
increase suppression pool temperature more slowly. The RHR
 
Suppression Pool Cooling System is also used to lower the
 
suppression pool water bulk temperature following such
 
events.
APPLICABLE Reference 1 contains the results of analyses used to predict SAFETY ANALYSES primary containment pressure and temperature following large and small break LOCAs. The intent of the analyses is to
 
demonstrate that the heat removal capacity of the RHR
 
Suppression Pool Cooling System is adequate to maintain the
 
primary containment conditions within design limits. The (continued)
RHR Suppression Pool Cooling B 3.6.2.3
 
LaSalle 1 and 2 B 3.6.2.3-2 Revision 32 BASES APPLICABLE suppression pool temperature is calculated to remain below SAFETY ANALYSES the design limit.
 
  (continued)
The RHR Suppression Pool Cooling System satisfies
 
Criterion 3 of 10 CFR 50.36(c)(2)(ii).
 
LCO During a DBA, a minimum of one RHR suppression pool cooling subsystem is required to maintain the primary containment
 
peak pressure and temperature below the design limits (Ref. 1). To ensure that these requirements are met, two
 
RHR suppression pool cooling subsystems must be OPERABLE. 
 
Therefore, in the event of an accident, at least one
 
subsystem is OPERABLE, assuming the worst case single active
 
failure. An RHR suppression pool cooling subsystem is
 
OPERABLE when the pump, a heat exchanger, and associated
 
piping, valves, instrumentation, and controls are OPERABLE.
 
APPLICABILITY In MODES 1, 2, and 3, a DBA could cause both a release of radioactive material to primary containment and a heatup and
 
pressurization of primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced
 
due to the pressure and temperature limitations in these
 
MODES. Therefore, the RHR Suppression Pool Cooling System
 
is not required to be OPERABLE in MODE 4 or 5. 
 
ACTIONS A.1 With one RHR suppression pool cooling subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status
 
within 7 days. In this condition, the remaining RHR
 
suppression pool cooling subsystem is adequate to perform
 
the primary containment cooling function. However, the
 
overall reliability is reduced because a single failure in
 
the OPERABLE subsystem could result in reduced primary
 
containment cooling capability. The 7 day Completion Time
 
is acceptable in light of the redundant RHR suppression pool
 
cooling capabilities afforded by the OPERABLE subsystem and
 
the low probability of a DBA occurring during this period.
 
B.1  If one RHR suppression pool cooling subsystem is inoperable and is not restored to OPERABLE status within the required (continued)
RHR Suppression Pool Cooling B 3.6.2.3
 
LaSalle 1 and 2 B 3.6.2.3-3 Revision 32 BASES ACTIONS B.1 (continued)
Completion Time, the plant must be brought to a condition in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
C.1  With two RHR suppression pool cooling subsystems inoperable, one subsystem must be restored to OPERABLE status within 8
 
hours. In this condition, there is a substantial loss of
 
the primary containment pressure and temperature mitigation
 
function. The 8 hour Completion Time is based on this loss
 
of function and is considered acceptable due to the low
 
probability of a DBA and the potential avoidance of a plant
 
shutdown transient that could result in the need for the RHR
 
suppression pool cooling subsystems to operate.
 
D.1 and D.2
 
If any Required Action and associated Completion Time of Condition C cannot be met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this
 
status, the plant must be brought to at least MODE 3 within
 
12 hours and to MODE 4 within 36 hours. The allowed
 
Completion Times are reasonable, based on operating
 
experience, to reach the required plant conditions from full
 
power conditions in an orderly manner and without
 
challenging plant systems.
 
(continued)
RHR Suppression Pool Cooling B 3.6.2.3
 
LaSalle 1 and 2 B 3.6.2.3-4 Revision 32 BASES  (continued)
 
SURVEILLANCE SR  3.6.2.3.1 REQUIREMENTS Verifying the correct alignment for manual and power operated
 
valves in the RHR suppression pool cooling mode
 
flow path provides assurance that the proper flow path exists
 
for system operation. This SR does not apply to valves that
 
are locked, sealed, or otherwise secured in position since
 
these valves were verified to be in the correct position
 
prior to being locked, sealed, or secured. A valve is also
 
allowed to be in the nonaccident position, provided it can be
 
aligned to the accident position within the time assumed in
 
the accident analysis. This is acceptable, since the RHR
 
suppression pool cooling mode is manually initiated. This SR
 
does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being
 
mispositioned are in the correct position. This SR does not
 
apply to valves that cannot be inadvertently misaligned, such
 
as check valves.
 
The Frequency of 31 days is justified because the valves are
 
operated under procedural control, improper valve position
 
would affect only a single subsystem, the probability of an
 
event requiring initiation of the system is low, and the
 
system is a manually initiated system. This Frequency has
 
been shown to be acceptable, based on operating experience.
 
SR  3.6.2.3.2
 
Verifying each required RHR pump develops a flow rate 7200 gpm, while operating in the suppression pool cooling mode with flow through the associated heat exchanger, ensures
 
that peak suppression pool temperature can be maintained
 
below the design limits during a DBA (Ref. 1). The flow
 
verification is also a normal test of centrifugal pump
 
performance required by ASME OM Code (Ref. 2). This test
 
confirms one point on the pump design curve, and the results
 
are indicative of overall performance. Such inservice tests
 
confirm component OPERABILITY and detect incipient failures
 
by indicating abnormal performance. The Frequency of this SR
 
is in accordance with the Inservice Testing Program.
 
(continued)
RHR Suppression Pool Cooling B 3.6.2.3
 
LaSalle 1 and 2 B 3.6.2.3-5 Revision 32 BASES  (continued)
 
REFERENCES 1. UFSAR, Section 6.2.
: 2. ASME Code for Operation and Maintenance of Nuclear Power Plants (OM Code).
: 3. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants," December 2002.
 
RHR Suppression Pool Spray B 3.6.2.4
 
LaSalle 1 and 2 B 3.6.2.4-1 Revision 0 B 3.6  CONTAINMENT SYSTEMS
 
B 3.6.2.4  Residual Heat Removal (RHR) Suppression Pool Spray
 
BASES
 
BACKGROUND Following a Design Basis Accident (DBA), the RHR Suppression Pool Spray System removes heat from the suppression chamber
 
airspace. The suppression pool is designed to absorb the
 
sudden input of heat from the primary system from a DBA or a
 
rapid depressurization of the reactor pressure vessel (RPV)
 
through safety/relief valves. The heat addition to the
 
suppression pool results in increased steam in the
 
suppression chamber, which increases primary containment
 
pressure. Steam blowdown from a DBA can also bypass the
 
suppression pool and end up in the suppression chamber
 
airspace. Some means must be provided to remove heat from
 
the suppression chamber so that the pressure and temperature
 
inside primary containment remain within analyzed design
 
limits. This function is provided by two redundant RHR
 
suppression pool spray subsystems. The purpose of this LCO
 
is to ensure that both subsystems are OPERABLE in applicable
 
MODES. Each of the two RHR suppression pool spray subsystems
 
contains one pump and one heat exchanger, which are manually
 
initiated and independently controlled. The two subsystems
 
perform the suppression pool spray function by circulating
 
water from the suppression pool through the RHR heat
 
exchangers and returning it to the suppression pool spray
 
sparger. The sparger only accommodates a small portion of
 
the total RHR pump flow; the remainder of the flow returns
 
to the suppression pool through the suppression pool cooling
 
return line (provided the associated valve is open). Thus, both suppression pool cooling and suppression pool spray
 
functions are normally performed when the Suppression Pool
 
Spray System is initiated. Either RHR suppression pool
 
spray subsystem is sufficient to condense the steam from
 
small bypass leaks from the drywell to the suppression
 
chamber airspace during the postulated DBA.
 
APPLICABLE Reference 1 contains the results of analyses used to predict SAFETY ANALYSES primary containment pressure and temperature following large and small break loss of coolant accidents. The intent of
 
the analyses is to demonstrate that the pressure reduction (continued)
RHR Suppression Pool Spray B 3.6.2.4
 
LaSalle 1 and 2 B 3.6.2.4-2 Revision 0 BASES APPLICABLE capacity of the RHR Suppression Pool Spray System is SAFETY ANALYSES adequate to maintain the primary containment conditions (continued) within design limits. The time history for primary containment pressure is calculated to demonstrate that the
 
maximum pressure remains below the design limit.
The RHR Suppression Pool Spray System satisfies Criterion 3
 
of 10 CFR 50.36(c)(2)(ii).
 
LCO In the event of a DBA, a minimum of one RHR suppression pool spray subsystem is required to mitigate potential bypass
 
leakage paths and maintain the primary containment peak
 
pressure below the design limits (Ref. 1). To ensure that
 
these requirements are met, two RHR suppression pool spray
 
subsystems must be OPERABLE. Therefore, in the event of an
 
accident, at least one subsystem is OPERABLE assuming the
 
worst case single active failure. An RHR suppression pool
 
spray subsystem is OPERABLE when one of the pumps and
 
associated piping, valves, instrumentation, and controls are
 
OPERABLE.
 
APPLICABILITY In MODES 1, 2, and 3, a DBA could cause pressurization of primary containment. In MODES 4 and 5, the probability and
 
consequences of these events are reduced due to the pressure
 
and temperature limitations in these MODES. Therefore, maintaining RHR suppression pool spray subsystems OPERABLE
 
is not required in MODE 4 or 5.
 
ACTIONS A.1 With one RHR suppression pool spray subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status
 
within 7 days. In this condition, the remaining OPERABLE
 
RHR suppression pool spray subsystem is adequate to perform
 
the primary containment bypass leakage mitigation function. 
 
However, the overall reliability is reduced because a single
 
failure in the OPERABLE subsystem could result in reduced
 
primary containment bypass mitigation capability. The 7 day
 
Completion Time was chosen in light of the redundant RHR
 
suppression pool spray capabilities afforded by the OPERABLE
 
subsystem and the low probability of a DBA occurring during
 
this period.
 
(continued)
RHR Suppression Pool Spray B 3.6.2.4
 
LaSalle 1 and 2 B 3.6.2.4-3 Revision 32 BASES ACTIONS B.1 (continued)
With both RHR suppression pool spray subsystems inoperable, at least one subsystem must be restored to OPERABLE status
 
within 8 hours. In this condition, there is a substantial
 
loss of the primary containment bypass leakage mitigation
 
function. The 8 hour Completion Time is based on this loss
 
of function and is considered acceptable due to the low
 
probability of a DBA and because alternative methods to
 
reduce pressure in the primary containment are available.
 
C.1 If any Required Action and associated Completion Time cannot
 
be met, the plant must be brought to a MODE in which the
 
overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within
 
12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short.
However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
 
SURVEILLANCE SR  3.6.2.4.1 REQUIREMENTS Verifying the correct alignment for manual and power
 
operated valves in the RHR suppression pool spray mode flow
 
path provides assurance that the proper flow paths will
 
exist for system operation. This SR does not apply to
 
valves that are locked, sealed, or otherwise secured in
 
position since these valves were verified to be in the
 
correct position prior to locking, sealing, or securing. A
 
valve is also allowed to be in the nonaccident position
 
provided it can be aligned to the accident position within
 
the time assumed in the accident analysis. This is
 
acceptable since the RHR suppression pool spray mode is
 
manually initiated. This SR does not require any testing or
 
valve manipulation; rather, it involves verification that
 
those valves capable of being mispositioned are in the 
 
(continued)
RHR Suppression Pool Spray B 3.6.2.4
 
LaSalle 1 and 2 B 3.6.2.4-4 Revision 32 BASES SURVEILLANCE SR  3.6.2.4.1 (continued)
REQUIREMENTS correct position. This SR does not apply to valves that
 
cannot be inadvertently misaligned, such as check valves.
 
The Frequency of 31 days is justified because the valves are
 
operated under procedural control, improper valve position
 
would affect only a single subsystem, the probability of an
 
event requiring initiation of the system is low, and the
 
subsystem is a manually initiated system. This Frequency
 
has been shown to be acceptable based on operating
 
experience.
 
SR  3.6.2.4.2
 
Verifying each required RHR pump develops a flow rate 450 gpm through the spray sparger while operating in the suppression pool spray mode helps ensure that the primary
 
containment pressure can be maintained below the design
 
limits during a DBA (Ref. 1). The normal test of
 
centrifugal pump performance required by the ASME OM Code (Ref. 2) is covered by the requirements of LCO 3.6.2.3, "RHR
 
Suppression Pool Cooling."  The Frequency of this SR is in
 
accordance with the Inservice Testing Program.
 
REFERENCES 1. UFSAR, Section 6.2.1.1.3.
: 2. ASME Code for Operation and Maintenance of Nuclear Power Plants (OM Code).
: 3. NEDC-32998-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants," December 2002.
 
Primary Containment Hydrogen Recombiners B 3.6.3.1
 
LaSalle 1 and 2 B 3.6.3.1-1 Revision 19 B 3.6  CONTAINMENT SYSTEMS
 
B 3.6.3.1  Primary Containment Hydrogen Recombiners - Deleted 
 
Primary Containment Oxygen Concentration B 3.6.3.2
 
LaSalle 1 and 2 B 3.6.3.2-1 Revision 19 B 3.6  CONTAINMENT SYSTEMS
 
B 3.6.3.2  Primary Containment Oxygen Concentration
 
BASES
 
BACKGROUND The primary containment is designed to withstand events that generate hydrogen either due to the zirconium metal water
 
reaction in the core or due to radiolysis. The primary
 
method to control hydrogen is to inert the primary
 
containment. With the primary containment inerted, that is, oxygen concentration < 4.0 volume percent (v/o), a
 
combustible mixture cannot be present in the primary
 
containment for any hydrogen concentration. An event that rapidly generates hydrogen from zirconium metal water
 
reaction will result in excessive hydrogen in primary
 
containment, but oxygen concentration will remain < 4.0 v/o
 
and no combustion can occur. This LCO ensures that oxygen concentration does not exceed 4.0 v/o during operation in
 
the applicable conditions.
 
APPLICABLE The Reference 1 calculations assume that the primary SAFETY ANALYSES containment is inerted when a Design Basis Accident loss of coolant accident occurs. Thus, the hydrogen assumed to be
 
released to the primary containment as a result of metal
 
water reaction in the reactor core will not produce
 
combustible gas mixtures in the primary containment.
Primary containment oxygen concentration satisfies
 
Criterion 2 of 10 CFR 50.36(c)(2)(ii).
 
  (continued)
Primary Containment Oxygen Concentration B 3.6.3.2
 
LaSalle 1 and 2 B 3.6.3.2-2 Revision 19 BASES  (continued)
 
LCO The primary containment oxygen concentration is maintained
< 4.0 v/o to ensure that an event that produces any amount
 
of hydrogen does not result in a combustible mixture inside
 
primary containment.
 
APPLICABILITY The primary containment oxygen concentration must be within the specified limit when primary containment is inerted, except as allowed by the relaxations during startup and
 
shutdown addressed below. The primary containment must be
 
inert in MODE 1, since this is the condition with the
 
highest probability of an event that could produce hydrogen.
Inerting the primary containment is an operational problem
 
because it prevents containment access without an
 
appropriate breathing apparatus. Therefore, the primary
 
containment is inerted as late as possible in the plant
 
startup and de-inerted as soon as possible in the plant
 
shutdown. As long as reactor power is < 15% RTP, the
 
potential for an event that generates significant hydrogen
 
is low and the primary containment need not be inert. 
 
Furthermore, the probability of an event that generates
 
hydrogen occurring within the first 24 hours of a startup, or within the last 24 hours before a shutdown, is low enough
 
that these "windows," when the primary containment is not
 
inerted, are also justified. The 24 hour time period is a
 
reasonable amount of time to allow plant personnel to
 
perform inerting or de-inerting.
 
ACTIONS A.1 If oxygen concentration is  4.0 v/o at any time while operating in MODE 1, with the exception of the relaxations
 
allowed during startup and shutdown, oxygen concentration
 
must be restored to < 4.0 v/o within 24 hours. The 24 hour
 
Completion Time is allowed when oxygen concentration is 4.0 v/o because the low probability and long duration of an event that would generate significant amounts of hydrogen occurring during this period.
 
  (continued)
Primary Containment Oxygen Concentration B 3.6.3.2
 
LaSalle 1 and 2 B 3.6.3.2-3 Revision 0 BASES ACTIONS B.1 (continued)
If oxygen concentration cannot be restored to within limits
 
within the required Completion Time, the plant must be
 
brought to a MODE in which the LCO does not apply. To
 
achieve this status, power must be reduced to  15% RTP within 8 hours. The 8 hour Completion Time is reasonable, based on operating experience, to reduce reactor power from
 
full power conditions in an orderly manner and without
 
challenging plant systems.
SURVEILLANCE SR  3.6.3.2.1 REQUIREMENTS The primary containment must be determined to be inerted by
 
verifying that oxygen concentration is < 4.0 v/o. The 7 day
 
Frequency is based on the slow rate at which oxygen
 
concentration can change and on other indications of
 
abnormal conditions (which could lead to more frequent
 
checking by operators in accordance with plant procedures).
 
Also, this Frequency has been shown to be acceptable through
 
operating experience.
 
REFERENCES 1. UFSAR, Section 6.2.5.
 
Secondary Containment B 3.6.4.1
 
LaSalle 1 and 2 B 3.6.4.1-1 Revision 0 B 3.6  CONTAINMENT SYSTEMS
 
B 3.6.4.1  Secondary Containment
 
BASES
 
BACKGROUND The function of the secondary containment is to contain dilute, and hold up fission products that may leak from
 
primary containment following a Design Basis Accident (DBA).
 
In conjunction with operation of the Standby Gas Treatment (SGT) System and closure of certain valves whose lines
 
penetrate the secondary containment, the secondary
 
containment is designed to reduce the activity level of the
 
fission products prior to release to the environment and to
 
isolate and contain fission products that are released
 
during certain operations that take place inside primary
 
containment, when primary containment is not required to be
 
OPERABLE, or that take place outside primary containment.
The secondary containment is a structure that completely
 
encloses the primary containment and those components that
 
may be postulated to contain primary system fluid. This
 
structure forms a control volume that serves to hold up and
 
dilute the fission products. It is possible for the
 
pressure in the control volume to rise relative to the
 
environmental pressure (e.g., due to pump/motor heat load
 
additions). To prevent ground level exfiltration while
 
allowing the secondary containment to be designed as a
 
conventional structure, the secondary containment requires
 
support systems to maintain the control volume pressure at
 
less than the external pressure. Requirements for these
 
systems are specified separately in LCO 3.6.4.2, "Secondary
 
Containment Isolation Valves (SCIVs)," and LCO 3.6.4.3, "Standby Gas Treatment (SGT) System."
APPLICABLE There are two principal accidents for which credit is SAFETY ANALYSES taken for secondary containment OPERABILITY. These are a LOCA (Ref. 1) and a fuel handling accident (Ref. 2). The
 
secondary containment performs no active function in
 
response to each of these limiting events; however, its leak
 
tightness is required to ensure that the release of
 
radioactive materials from the primary containment is
 
restricted to those leakage paths and associated leakage
 
rates assumed in the accident analysis, and that fission
 
products entrapped within the secondary containment (continued)
Secondary Containment B 3.6.4.1
 
LaSalle 1 and 2 B 3.6.4.1-2 Revision 0 BASES APPLICABLE structure will be treated by the SGT System prior to SAFETY ANALYSES discharge to the environment.
 
  (continued)
Secondary containment satisfies Criterion 3 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO An OPERABLE secondary containment provides a control volume into which fission products that bypass or leak from primary
 
containment, or are released from the reactor coolant
 
pressure boundary components located in secondary
 
containment, can be diluted and processed prior to release
 
to the environment. For the secondary containment to be
 
considered OPERABLE, it must have adequate leak tightness to
 
ensure that the required vacuum can be established and
 
maintained, the hatches and blowout panels must be closed
 
and sealed, the sealing mechanisms associated with each
 
secondary containment penetration (e.g., welds, bellows, or
 
O-rings) must be OPERABLE (such that secondary containment
 
leak tightness can be maintained), and all inner or all
 
outer doors in each secondary containment access opening
 
must be closed.
 
APPLICABILITY In MODES 1, 2, and 3, a LOCA could lead to a fission product release to primary containment that leaks to secondary
 
containment. Therefore, secondary containment OPERABILITY
 
is required during the same operating conditions that
 
require primary containment OPERABILITY.
In MODES 4 and 5, the probability and consequences of the
 
LOCA are reduced due to the pressure and temperature
 
limitations in these MODES. Therefore, maintaining
 
secondary containment OPERABLE is not required in MODE 4
 
or 5 to ensure a control volume, except for other situations
 
for which significant releases of radioactive material can
 
be postulated, such as during operations with a potential
 
for draining the reactor vessel (OPDRVs), during CORE
 
ALTERATIONS, or during movement of irradiated fuel
 
assemblies in the secondary containment.
 
(continued)
Secondary Containment B 3.6.4.1
 
LaSalle 1 and 2 B 3.6.4.1-3 Revision 32 BASES  (continued)
 
ACTIONS A.1 If secondary containment is inoperable, it must be restored
 
to OPERABLE status within 4 hours. The 4 hour Completion
 
Time provides a period of time to correct the problem that
 
is commensurate with the importance of maintaining secondary
 
containment during MODES 1, 2, and 3. This time period also
 
ensures that the probability of an accident (requiring
 
secondary containment OPERABILITY) occurring during periods
 
where secondary containment is inoperable is minimal.
 
B.1 If the secondary containment cannot be restored to OPERABLE
 
status within the required Completion Time, the plant must
 
be brought to a MODE in which overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 3), because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner
 
and without challenging plant systems.
 
C.1, C.2, and C.3
 
Movement of irradiated fuel assemblies in the secondary
 
containment, CORE ALTERATIONS, and OPDRVs can be postulated
 
to cause fission product release to the secondary
 
containment. In such cases, the secondary containment is
 
the only barrier to release of fission products to the
 
environment. CORE ALTERATIONS and movement of irradiated
 
fuel assemblies must be immediately suspended if the
 
secondary containment is inoperable.
 
Suspension of these activities shall not preclude completing
 
an action that involves moving a component to a safe
 
position. Also, action must be immediately initiated to
 
suspend OPDRVs to minimize the probability of a vessel
 
draindown and subsequent potential for fission product
 
release. Actions must continue until OPDRVs are suspended.
(continued)
Secondary Containment B 3.6.4.1
 
LaSalle 1 and 2 B 3.6.4.1-4 Revision 0 BASES ACTIONS C.1, C.2, and C.3 (continued)
Required Action C.1 has been modified by a Note stating that
 
LCO 3.0.3 is not applicable. If moving irradiated fuel
 
assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify
 
any action. If moving irradiated fuel assemblies while in
 
MODE 1, 2, or 3, the fuel movement is independent of reactor
 
operations. Therefore, in either case, inability to suspend
 
movement of irradiated fuel assemblies would not be a
 
sufficient reason to require a reactor shutdown.
 
SURVEILLANCE SR  3.6.4.1.1 REQUIREMENTS This SR ensures that the secondary containment boundary is
 
sufficiently leak tight to preclude exfiltration. The
 
24 hour Frequency of this SR was developed based on
 
operating experience related to secondary containment vacuum
 
variations during the applicable MODES and the low
 
probability of a DBA occurring.
 
Furthermore, the 24 hour Frequency is considered adequate in
 
view of other indications available in the control room, including alarms, to alert the operator to an abnormal
 
secondary containment vacuum condition.
 
SR  3.6.4.1.2 and SR  3.6.4.1.5
 
Verifying that one secondary containment access door in each
 
access opening is closed and each equipment hatch is closed
 
and sealed ensures that the infiltration of outside air of
 
such a magnitude as to prevent maintaining the desired
 
negative pressure does not occur. Verifying that all such
 
openings are closed provides adequate assurance that
 
exfiltration from the secondary containment will not occur.
 
In this application, the term "sealed" has no connotation of
 
leak tightness. In addition, for equipment hatches that are
 
floor plugs, the "sealed" requirement is effectively met by
 
gravity. Maintaining secondary containment OPERABILITY
 
requires verifying one door in the access opening is closed.
 
An access opening contains one inner and one outer door. In
 
some cases a secondary containment barrier contains multiple
 
inner or multiple outer doors. For these cases, the access
 
openings share the inner door or the outer door, i.e., the
 
access openings have (continued)
Secondary Containment B 3.6.4.1
 
LaSalle 1 and 2 B 3.6.4.1-5 Revision 0 BASES SURVEILLANCE SR  3.6.4.1.2 and SR  3.6.4.1.
5  (continued)
REQUIREMENTS a common inner door or outer door. The intent is to not
 
breach the secondary containment at any time when secondary
 
containment is required. This is achieved by maintaining
 
the inner or outer portion of the barrier closed at all
 
times, i.e., all inner doors closed or all outer doors
 
closed. Thus each access opening has one door closed.
 
However, each secondary containment access door is normally
 
kept closed, except when the access opening is being used
 
for entry and exit or when maintenance is being performed on
 
the access opening. The 31 day Frequency for SR 3.6.4.1.2
 
has been shown to be adequate based on operating experience, and is considered adequate in view of the existing
 
administrative controls on door status. The 24 month
 
Frequency for SR 3.6.4.1.5 is considered adequate in view of
 
the existing administrative controls on equipment hatches.
 
SR  3.6.4.1.3 and SR  3.6.4.1.4
 
The SGT System exhausts the secondary containment atmosphere
 
to the environment through appropriate treatment equipment.
 
Each SGT subsystem is designed to drawdown pressure in the
 
secondary containment to  0.25 inches of vacuum water gauge in  300 seconds and maintain pressure in the secondary containment at  0.25 inches of vacuum water gauge for 1 hour at a flow rate of  4400 cfm. To ensure that all fission products released to secondary containment are
 
treated, SR 3.6.4.1.3 and SR 3.6.4.1.4 verify that a
 
pressure in the secondary containment that is less than the
 
pressure external to the secondary containment boundary can
 
rapidly be established and maintained. When the SGT System
 
is operating as designed, the establishment and maintenance
 
of secondary containment pressure cannot be accomplished if
 
the secondary containment boundary is not intact. 
 
Establishment of this pressure is confirmed by SR 3.6.4.1.3, which demonstrates that the secondary containment can be
 
drawn down to  0.25 inches of vacuum water gauge in  300 seconds using one SGT subsystem. SR 3.6.4.1.4 demonstrates that the pressure in the secondary containment
 
can be maintained  0.25 inches of vacuum water gauge for 1 hour using one SGT subsystem at a flow rate  4400 cfm.
This flow rate is the assumed secondary containment leak
 
rate during the drawdown period. The 1 hour test period
 
allows secondary containment to be in thermal equilibrium at (continued)
Secondary Containment B 3.6.4.1
 
LaSalle 1 and 2 B 3.6.4.1-6 Revision 32
 
BASES
 
SURVEILLANCE SR  3.6.4.1.3 and SR  3.6.4.1.4 (continued)
REQUIREMENTS steady state conditions. The primary purpose of the SRs is
 
to ensure secondary containment boundary integrity. The
 
secondary purpose of these SRs is to ensure that the SGT
 
subsystem being tested functions as designed. There is a
 
separate LCO with Surveillance Requirements that serves the
 
primary purpose of ensuring OPERABILITY of the SGT System.
 
These SRs need not be performed with each SGT subsystem.
 
The SGT subsystem used for these Surveillances is staggered
 
to ensure that in addition to the requirements of
 
LCO 3.6.4.3, either SGT subsystem will perform this test.
 
The inoperability of the SGT System does not necessarily
 
constitute a failure of these Surveillances relative to
 
secondary containment OPERABILITY. Operating experience has
 
shown the secondary containment boundary usually passes
 
these Surveillances when performed at the 24 month
 
Frequency. Therefore the Frequency was concluded to be
 
acceptable from a reliability standpoint.
 
REFERENCES 1. UFSAR, Section 15.6.5.
: 2. UFSAR, Section 15.7.4.
: 3. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants," December 2002.
 
SCIVs B 3.6.4.2
 
LaSalle 1 and 2 B 3.6.4.2-1 Revision 0 B 3.6  CONTAINMENT SYSTEMS
 
B 3.6.4.2  Secondary Containment Isolation Valves (SCIVs)
 
BASES
 
BACKGROUND The function of the SCIVs, in combination with other accident mitigation systems, is to limit fission product
 
release during and following postulated Design Basis
 
Accidents (DBAs) (Refs. 1 and 2). Secondary containment
 
isolation within the time limits specified for those
 
isolation valves designed to close automatically ensures
 
that fission products that leak from primary containment
 
following a DBA, that are released during certain operations
 
when primary containment is not required to be OPERABLE, or
 
that take place outside primary containment, are maintained
 
within the secondary containment boundary.
The OPERABILITY requirements for SCIVs help ensure that an
 
adequate secondary containment boundary is maintained during
 
and after an accident by minimizing potential paths to the
 
environment. These isolation devices are either passive or
 
active (automatic). Manual valves, de-activated automatic
 
valves secured in their closed position (including check
 
valves with flow through the valve secured), and blind
 
flanges are considered passive devices.
Automatic SCIVs (i.e., dampers) close on a secondary
 
containment isolation signal to establish a boundary for
 
untreated radioactive material within secondary containment
 
following a DBA or other accidents.
 
Other penetrations required to be closed during accident
 
conditions are isolated by the use of valves in the closed
 
position or blind flanges.
 
APPLICABLE The SCIVs must be OPERABLE to ensure the secondary SAFETY ANALYSES containment barrier to fission product releases is established. The principal accidents for which the
 
secondary containment boundary is required are a loss of
 
coolant accident (Ref. 1) and fuel handling accident (Ref. 2). The secondary containment performs no active
 
function in response to each of these limiting events, but (continued)
SCIVs B 3.6.4.2
 
LaSalle 1 and 2 B 3.6.4.2-2 Revision 0 BASES APPLICABLE the boundary established by SCIVs is required to ensure that SAFETY ANALYSES leakage from the primary containment is processed by the (continued) Standby Gas Treatment (SGT) System before being released to the environment.
Maintaining SCIVs OPERABLE with isolation times within
 
limits ensures that fission products will remain trapped
 
inside secondary containment so that they can be treated by
 
the SGT System prior to discharge to the environment.
 
SCIVs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).
 
LCO SCIVs form a part of the secondary containment boundary. The SCIV safety function is related to control of offsite
 
radiation releases resulting from DBAs.
The power operated, automatic isolation valves are
 
considered OPERABLE when their isolation times are within
 
limits and the valves actuate on an automatic isolation
 
signal. The valves covered by this LCO, along with their
 
associated stroke times, are listed in the Technical
 
Requirements Manual (Ref. 3).
 
The normally closed manual SCIVs are considered OPERABLE
 
when the valves are closed and blind flanges are in place, or open under administrative controls. These passive
 
isolation valves or devices are listed in Reference 3.
 
APPLICABILITY In MODES 1, 2, and 3, a DBA could lead to a fission product release to the primary containment that leaks to the
 
secondary containment. Therefore, OPERABILITY of SCIVs is
 
required.
In MODES 4 and 5, the probability and consequences of these
 
events are reduced due to pressure and temperature
 
limitations in these MODES. Therefore, maintaining SCIVs
 
OPERABLE is not required in MODE 4 or 5, except for other
 
situations under which significant releases of radioactive
 
material can be postulated, such as during operations with a
 
potential for draining the reactor vessel (OPDRVs), during
 
CORE ALTERATIONS, or during movement of irradiated fuel
 
assemblies in the secondary containment.
 
(continued)
SCIVs B 3.6.4.2
 
LaSalle 1 and 2 B 3.6.4.2-3 Revision 0 BASES  (continued)
 
ACTIONS The ACTIONS are modified by three Notes. The first Note allows penetration flow paths to be unisolated
 
intermittently under administrative controls. These
 
controls consist of stationing a dedicated operator, who is
 
in continuous communication with the control room, at the
 
controls of the isolation device. In this way, the
 
penetration can be rapidly isolated when the need for
 
secondary containment isolation is indicated.
The second Note provides clarification that, for the purpose
 
of this LCO, separate Condition entry is allowed for each
 
penetration flow path. This is acceptable, since the
 
Required Actions for each Condition provide appropriate
 
compensatory actions for each inoperable SCIV. Complying
 
with the Required Actions may allow for continued operation, and subsequent inoperable SCIVs are governed by subsequent
 
Condition entry and application of associated Required
 
Actions. 
 
The third Note ensures appropriate remedial actions are
 
taken, if necessary, if the affected system(s) are rendered
 
inoperable by an inoperable SCIV.
 
A.1 and A.2
 
In the event that there are one or more penetration flow
 
paths with one SCIV inoperable, the affected penetration
 
flow path(s) must be isolated. The method of isolation must
 
include the use of at least one isolation barrier that
 
cannot be adversely affected by a single active failure. 
 
Isolation barriers that meet this criteria are a closed and
 
de-activated automatic SCIV, a closed manual valve, and a
 
blind flange. For penetrations isolated in accordance with
 
Required Action A.1, the device used to isolate the
 
penetration should be the closest available device to
 
secondary containment. This Required Action must be
 
completed within the 8 hour Completion Time. The specified
 
time period is reasonable considering the time required to
 
isolate the penetration and the low probability of a DBA, which requires the SCIVs to close, occurring during this
 
short time.
(continued)
SCIVs B 3.6.4.2
 
LaSalle 1 and 2 B 3.6.4.2-4 Revision 0 BASES ACTIONS A.1 and A.2 (continued)
For affected penetrations that have been isolated in
 
accordance with Required Action A.1, the affected
 
penetration must be verified to be isolated on a periodic
 
basis. This is necessary to ensure that secondary
 
containment penetrations required to be isolated following
 
an accident, but no longer capable of being automatically
 
isolated, will be in the isolation position should an event
 
occur. The Completion Time of once per 31 days is
 
appropriate because the isolation devices are operated under
 
administrative controls and the probability of their
 
misalignment is low. This Required Action does not require
 
any testing or device manipulation. Rather, it involves
 
verification that the affected penetration remains isolated.
 
Required Action A.2 is modified by two Notes. Note 1
 
applies to isolation devices located in high radiation areas
 
and allows them to be verified by use of administrative
 
controls. Allowing verification by administrative controls
 
is considered acceptable, since access to these areas is
 
typically restricted. Note 2 applies to isolation devices
 
that are locked, sealed, or otherwise secured in position
 
and allows these devices to be verified closed by use of
 
administrative means. Allowing verification by
 
administrative means is considered acceptable, since the
 
function of locking, sealing, or securing components is to
 
ensure that these devices are not inadvertently
 
repositioned. Therefore, the probability of misalignment, once they have been verified to be in the proper position, is low.
 
B.1 With two SCIVs in one or more penetration flow paths
 
inoperable, the affected penetration flow path must be
 
isolated within 4 hours. The method of isolation must
 
include the use of at least one isolation barrier that
 
cannot be adversely affected by a single active failure. 
 
Isolation barriers that meet this criterion are a closed and
 
de-activated automatic valve, a closed manual valve, and a
 
blind flange. The 4 hour Completion Time is reasonable, considering the time required to isolate the penetration and
 
the low probability of a DBA, which requires the SCIVs to
 
close, occurring during this short time.
(continued)
SCIVs B 3.6.4.2
 
LaSalle 1 and 2 B 3.6.4.2-5 Revision 0 BASES ACTIONS B.1 (continued)
The Condition has been modified by a Note stating that
 
Condition B is only applicable to penetration flow paths
 
with two isolation valves. This clarifies that only
 
Condition A is entered if one SCIV is inoperable in each of
 
two penetrations.
 
C.1 and C.2
 
If any Required Action and associated Completion Time cannot
 
be met, the plant must be brought to a MODE in which the LCO
 
does not apply. To achieve this status, the plant must be
 
brought to at least MODE 3 within 12 hours and to MODE 4
 
within 36 hours. The allowed Completion Times are
 
reasonable, based on operating experience, to reach the
 
required plant conditions from full power conditions in an
 
orderly manner and without challenging plant systems.
 
D.1, D.2, and D.3
 
If any Required Action and associated Completion Time cannot
 
be met, the plant must be placed in a condition in which the
 
LCO does not apply. If applicable, CORE ALTERATIONS and the
 
movement of irradiated fuel assemblies in the secondary
 
containment must be immediately suspended. Suspension of
 
these activities shall not preclude completion of movement
 
of a component to a safe position. Also, if applicable, action must be immediately initiated to suspend OPDRVs in
 
order to minimize the probability of a vessel draindown and
 
the subsequent potential for fission product release. 
 
Actions must continue until OPDRVs are suspended.
 
Required Action D.1 has been modified by a Note stating that
 
LCO 3.0.3 is not applicable. If moving irradiated fuel
 
assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify
 
any action. If moving irradiated fuel assemblies while in
 
MODE 1, 2, or 3, the fuel movement is independent of reactor
 
operations. Therefore, in either case, inability to suspend
 
movement of irradiated fuel assemblies would not be a
 
sufficient reason to require a reactor shutdown.
 
(continued)
SCIVs B 3.6.4.2
 
LaSalle 1 and 2 B 3.6.4.2-6 Revision 0 BASES  (continued)
 
SURVEILLANCE SR  3.6.4.2.1 REQUIREMENTS This SR verifies each secondary containment isolation manual
 
valve and blind flange that is not locked, sealed, or
 
otherwise secured and is required to be closed during
 
accident conditions is closed. The SR helps to ensure that
 
post accident leakage of radioactive fluids or gases outside
 
of the secondary containment boundary is within design
 
limits. This SR does not require any testing or valve
 
manipulation. Rather, it involves verification that those
 
SCIVs in secondary containment that are capable of being
 
mispositioned are in the correct position.
 
Since these SCIVs are readily accessible to personnel during
 
normal unit operation and verification of their position is
 
relatively easy, the 31 day Frequency was chosen to provide
 
added assurance that the SCIVs are in the correct positions.
 
This SR does not apply to valves that are locked, sealed, or
 
otherwise secured in the closed position, since these were
 
verified to be in the correct position upon locking, sealing, or securing.
 
Two Notes have been added to this SR. The first Note
 
applies to valves and blind flanges located in high
 
radiation areas and allows them to be verified by use of
 
administrative controls. Allowing verification by
 
administrative controls is considered acceptable, since
 
access to these areas is typically restricted during
 
MODES 1, 2, and 3 for ALARA reasons. Therefore, the
 
probability of misalignment of these SCIVs, once they have
 
been verified to be in the proper position, is low.
 
A second Note has been included to clarify that SCIVs that
 
are open under administrative controls are not required to
 
meet the SR during the time the SCIVs are open. These
 
controls consist of stationing a dedicated operator at the
 
controls of the valve, who is in continuous communication
 
with the control room. In this way, the penetration can be
 
rapidly isolated when a need for secondary containment
 
isolation is indicated.
(continued)
SCIVs B 3.6.4.2
 
LaSalle 1 and 2 B 3.6.4.2-7 Revision 0 BASES SURVEILLANCE SR  3.6.4.2.2 REQUIREMENTS
 
  (continued)
Verifying the isolation time of each power operated, automatic SCIV is within limits is required to demonstrate
 
OPERABILITY. The isolation time test ensures that the SCIV
 
will isolate in a time period less than or equal to that
 
assumed in the safety analyses. The Frequency of this SR is
 
92 days.
SR  3.6.4.2.3
 
Verifying that each automatic SCIV closes on a secondary
 
containment isolation signal is required to prevent leakage
 
of radioactive material from secondary containment following
 
a DBA or other accidents. This SR ensures that each
 
automatic SCIV will actuate to the isolation position on a
 
secondary containment isolation signal. The LOGIC SYSTEM
 
FUNCTIONAL TEST in LCO 3.3.6.2, "Secondary Containment
 
Isolation Instrumentation," overlaps this SR to provide
 
complete testing of the safety function. While this
 
Surveillance can be performed with the reactor at power, operating experience has shown these components usually pass
 
the Surveillance when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the
 
Frequency was concluded to be acceptable from a reliability
 
standpoint.
 
REFERENCES 1. UFSAR, Section 15.6.5.
: 2. UFSAR, Section 15.7.4.
: 3. Technical Requirements Manual.
 
SGT System B 3.6.4.3
 
LaSalle 1 and 2 B 3.6.4.3-1 Revision 0 B 3.6  CONTAINMENT SYSTEMS
 
B 3.6.4.3  Standby Gas Treatment (SGT) System
 
BASES
 
BACKGROUND The SGT System is required by 10 CFR 50, Appendix A, GDC 41, "Containment Atmosphere Cleanup" (Ref. 1). The function of
 
the SGT System is to ensure that radioactive materials that
 
leak from the primary containment into the secondary
 
containment following a Design Basis Accident (DBA) are
 
filtered and adsorbed prior to exhausting to the
 
environment.
The SGT System consists of two independent subsystems that
 
are shared between Unit 1 and Unit 2, each with its own set
 
of ductwork, dampers, charcoal filter train, and controls. 
 
Each SGT System discharges to the plant vent stack through a
 
common exhaust pipe.
 
Each charcoal filter train consists of (components listed in
 
order of the direction of the air flow):
: a. A centrifugal filter unit fan and centrifugal cooling fan; 
: b. A demister;
: c. An electric heater;
: d. A prefilter bank;
: e. A high efficiency particulate air (HEPA) filter bank;
: f. A charcoal adsorber; and
: g. A second HEPA filter bank.
The sizing of the SGT System equipment and components is
 
based on the results of an infiltration analysis. Each SGT
 
subsystem is capable of processing the secondary containment
 
volume, which includes both Unit 1 and Unit 2. The internal
 
pressure of the SGT System boundary region is maintained at
 
a negative pressure of 0.25 inch water gauge when the system
 
is in operation, which represents the internal pressure
 
required to ensure zero exfiltration of air from the
 
building.
(continued)
SGT System B 3.6.4.3
 
LaSalle 1 and 2 B 3.6.4.3-2 Revision 0 BASES BACKGROUND The demister is provided to remove entrained water in the (continued) air, while the electric heater reduces the relative humidity of the airstream to  70% (Ref. 2). The prefilter removes large particulate matter, while the HEPA filter is provided
 
to remove fine particulate matter and protect the charcoal
 
from fouling. The charcoal adsorber removes gaseous
 
elemental iodine and organic iodides, and the final HEPA
 
filter is provided to collect any carbon fines exhausted
 
from the charcoal adsorber.
The SGT System automatically starts and operates in response
 
to actuation signals from either Unit 1 or Unit 2 indicative
 
of conditions or an accident that could require operation of
 
the system. Following initiation, both supply fans start. 
 
SGT System flows are controlled automatically by flow
 
control dampers located up stream of the supply fans.
 
APPLICABLE The design basis for the SGT System is to mitigate the SAFETY ANALYSES consequences of a loss of coolant accident and fuel handling accidents (Refs. 3 and 4). For all events analyzed, the SGT
 
System is shown to be automatically initiated to reduce, via
 
filtration and adsorption, the radioactive material released
 
to the environment.
The SGT System satisfies Criterion 3 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO Following a DBA, a minimum of one SGT subsystem is required to maintain the secondary containment at a negative pressure
 
with respect to the environment and to process gaseous
 
releases. Meeting the LCO requirements for two OPERABLE
 
subsystems ensures operation of at least one SGT subsystem
 
in the event of a single active failure.
 
APPLICABILITY In MODES 1, 2, and 3, a DBA could lead to a fission product release to primary containment that leaks to secondary
 
containment. Therefore, SGT System OPERABILITY is required
 
during these MODES.
In MODES 4 and 5, the probability and consequences of these
 
events are reduced due to the pressure and temperature
 
limitations in these MODES. Therefore, maintaining the SGT
 
System OPERABLE is not required in MODE 4 or 5, except for (continued)
SGT System B 3.6.4.3
 
LaSalle 1 and 2 B 3.6.4.3-3 Revision 32 BASES APPLICABILITY other situations under which significant releases of (continued) radioactive material can be postulated, such as during operations with a potential for draining the reactor vessel (OPDRVs), during CORE ALTERATIONS, or during movement of
 
irradiated fuel assemblies in the secondary containment.
 
ACTIONS A.1 With one SGT subsystem inoperable, the inoperable subsystem
 
must be restored to OPERABLE status within 7 days. In this
 
condition, the remaining OPERABLE SGT subsystem is adequate
 
to perform the required radioactivity release control
 
function. However, the overall system reliability is
 
reduced because a single failure in the OPERABLE subsystem
 
could result in the radioactivity release control function
 
not being adequately performed. The 7 day Completion Time
 
is based on consideration of such factors as the
 
availability of the OPERABLE redundant SGT subsystem and the
 
low probability of a DBA occurring during this period.
 
B.1 If the SGT subsystem cannot be restored to OPERABLE status
 
within the required Completion Time in MODE 1, 2, or 3, the
 
plant must be brought to a MODE in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 5) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner
 
and without challenging plant systems.
 
C.1, C.2.1, C.2.2, and C.2.3
 
During movement of irradiated fuel assemblies in the
 
secondary containment, during CORE ALTERATIONS, or during
 
OPDRVs, when Required Action A.1 cannot be completed within
 
the required Completion Time, the OPERABLE SGT subsystem 
 
(continued)
SGT System B 3.6.4.3
 
LaSalle 1 and 2 B 3.6.4.3-4 Revision 32 BASES ACTIONS C.1, C.2.1, C.2.2, and C.2.3 (continued) should be immediately placed in operation. This Required 
 
Action ensures that the remaining subsystem is OPERABLE, that no failures that could prevent automatic actuation will
 
occur, and that any other failure would be readily detected.
 
An alternative to Required Action C.1 is to immediately
 
suspend activities that represent a potential for releasing
 
radioactive material to the secondary containment, thus
 
placing the unit in a condition that minimizes risk. If
 
applicable, CORE ALTERATIONS and movement of irradiated fuel
 
assemblies must be immediately suspended. Suspension of
 
these activities shall not preclude completion of movement
 
of a component to a safe position. Also, if applicable, action must be immediately initiated to suspend OPDRVs to
 
minimize the probability of a vessel draindown and
 
subsequent potential for fission product release. Action
 
must continue until OPDRVs are suspended.
 
The Required Actions of Condition C have been modified by a
 
Note stating that LCO 3.0.3 is not applicable. If moving
 
irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3
 
would not specify any action. If moving irradiated fuel
 
assemblies while in MODE 1, 2, or 3, the fuel movement is
 
independent of reactor operations. Therefore, in either
 
case, inability to suspend movement of irradiated fuel
 
assemblies would not be a sufficient reason to require a
 
reactor shutdown.
 
D.1 If both SGT subsystems are inoperable in MODE 1, 2, or 3, the SGT system may not be capable of supporting the required
 
radioactivity release control function.
Therefore, the plant must be brought to a MODE in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 5) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short.
However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience,  (continued)
SGT System B 3.6.4.3
 
LaSalle 1 and 2 B 3.6.4.3-5 Revision 32 BASES ACTIONS D.1 (continued)
 
to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
 
E.1, E.2, and E.3
 
When two SGT subsystems are inoperable, if applicable, CORE
 
ALTERATIONS and movement of irradiated fuel assemblies in
 
the secondary containment must be immediately suspended. 
 
Suspension of these activities shall not preclude completion
 
of movement of a component to a safe position. Also, if
 
applicable, action must be immediately initiated to suspend
 
OPDRVs to minimize the probability of a vessel draindown and
 
subsequent potential for fission product release. Action
 
must continue until OPDRVs are suspended.
Required Action E.1 has been modified by a Note stating that
 
LCO 3.0.3 is not applicable. If moving irradiated fuel
 
assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify
 
any action. If moving irradiated fuel assemblies while in
 
MODE 1, 2, or 3, the fuel movement is independent of reactor
 
operations. Therefore, in either case, inability to suspend
 
movement of irradiated fuel assemblies would not be a
 
sufficient reason to require a reactor shutdown.
 
SURVEILLANCE SR  3.6.4.3.1 REQUIREMENTS Operating (from the control room) each SGT subsystem for 10 continuous hours ensures that both subsystems are OPERABLE and that all associated controls are functioning
 
properly. It also ensures that blockage, fan or motor
 
failure, or excessive vibration can be detected for
 
corrective action. Operation with the heaters on for 10 continuous hours every 31 days eliminates moisture on the adsorbers and HEPA filters. The 31 day Frequency was
 
developed in consideration of the known reliability of fan
 
motors and controls and the redundancy available in the
 
system.  (continued)
SGT System B 3.6.4.3
 
LaSalle 1 and 2 B 3.6.4.3-6 Revision 32 BASES SURVEILLANCE SR  3.6.4.3.2 REQUIREMENTS (continued) This SR verifies that the required SGT filter testing is performed in accordance with the Ventilation Filter Testing
 
Program (VFTP). The SGT System filter tests are in
 
accordance with ANSI/ASME N510-1989 (Ref. 6). The VFTP includes testing HEPA filter performance, charcoal adsorber
 
efficiency, minimum system flow rate, and the physical
 
properties of the activated charcoal (general use and
 
following specific operations). Specified test frequencies
 
and additional information are discussed in detail in the
 
VFTP.
 
SR  3.6.4.3.3 This SR requires verification that each SGT subsystem starts upon receipt of an actual or simulated initiation signal.
 
The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.2, "Secondary
 
Containment Isolation Instrumentation," overlaps this SR to
 
provide complete testing of the safety function. While this
 
Surveillance can be performed with the reactor at power, operating experience has shown these components usually pass
 
the Surveillance when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the
 
Frequency was concluded to be acceptable from a reliability
 
standpoint.
 
REFERENCES 1. 10 CFR 50, Appendix A, GDC 41.
: 2. UFSAR, Section 6.5.1.
: 3. UFSAR, Section 15.6.5.
: 4. UFSAR, Section 15.7.4
: 5. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants," December 2002.
: 6. ANSI/ASME N510-1989.
 
RHRSW System B 3.7.1 LaSalle 1 and 2 B 3.7.1-1 Revision 0 B 3.7  PLANT SYSTEMS
 
B 3.7.1  Residual Heat Removal Service Water (RHRSW) System
 
BASES
 
BACKGROUND The RHRSW System is designed to provide cooling water for the Residual Heat Removal (RHR) System heat exchangers, required for a safe reactor shutdown following a Design
 
Basis Accident (DBA) or transient. The RHRSW System is
 
operated whenever the RHR heat exchangers are required to
 
operate in the shutdown cooling mode or in the suppression
 
pool cooling or spray mode of the RHR System. The RHRSW
 
System also provides cooling water to the RHR pump seal
 
coolers which are required for RHR pump operation during the
 
shutdown cooling mode in MODE 3.
The RHRSW System consists of two independent and redundant
 
subsystems. Each subsystem is made up of two pumps (together capable of providing a nominal flow of 7400 gpm),
a suction source, valves, piping, heat exchanger, and
 
associated instrumentation. Either of the two subsystems is
 
capable of providing the required cooling capacity with both
 
pumps operating to maintain safe shutdown conditions. The
 
two subsystems are separated from each other so that failure
 
of one subsystem will not affect the OPERABILITY of the
 
other subsystem. The RHRSW System is designed with
 
sufficient redundancy so that no single active component
 
failure can prevent it from achieving its design function.
 
The RHRSW System is described in the UFSAR, Section 9.2.1, Reference 1.
 
The RHRSW and the Diesel Generator Cooling Water subsystems are subsystems to the Core Standby Cooling System (CSCS)-
 
Equipment Cooling Water System (ECWS). The CSCS-ECWS
 
consists of three independent piping subsystems
 
corresponding to essential electrical power supply Divisions
 
1, 2, and 3. The CSCS-ECWS subsystems take suction from
 
the service water tunnel located in the Lake Screen House.
 
The RHRSW subsystems are manually initiated. Cooling water
 
is then pumped from the service water tunnel by the RHRSW
 
pumps to the supported system and components (RHR heat
 
exchangers and RHR pump seal coolers). After removing heat
 
from its supported systems and components, the water from
 
the RHRSW subsystem is discharged to the CSCS Pond (i.e.,
the Ultimate Heat Sink) through a discharge line that is (continued)
RHRSW System B 3.7.1 LaSalle 1 and 2 B 3.7.1-2 Revision 0 BASES BACKGROUND common to the corresponding divisional discharge from the (continued) other unit. The discharge line terminates in the discharge structure at an elevation above the normal CSCS Pond level.
The system is initiated manually from the control room. In
 
addition, the Division 2 RHRSW subsystem may be initiated
 
manually from the remote shutdown panel in the auxiliary
 
electric equipment room. If operating during a loss of
 
offsite power, the system is automatically load shed to
 
allow the diesel generators to automatically power only that
 
equipment necessary to reflood the core. The system can be
 
manually started any time after the LOCA. 
 
APPLICABLE The RHRSW System removes heat from the suppression pool to SAFETY ANALYSES limit the suppression pool temperature and primary containment pressure following a LOCA. This ensures that
 
the primary containment can perform its function of limiting
 
the release of radioactive materials to the environment
 
following a LOCA. The ability of the RHRSW System to
 
support long term cooling of the reactor or primary
 
containment is discussed in the UFSAR, Chapters 6 and 15 (Refs. 2 and 3, respectively). These analyses explicitly
 
assume that the RHRSW System will provide adequate cooling
 
support to the equipment required for safe shutdown. These
 
analyses include the evaluation of the long term primary
 
containment response after a design basis LOCA.
The safety analyses for long term cooling were performed for
 
various combinations of RHR System failures. The worst case
 
single failure that would affect the performance of the
 
RHRSW System is any failure that would disable one subsystem
 
of the RHRSW System. As discussed in the UFSAR, Section 6.2.2.3.1 (Ref. 4) for these analyses, manual
 
initiation of the OPERABLE RHRSW subsystem and the
 
associated RHR System is assumed to occur 10 minutes after a
 
DBA. The RHRSW flow assumed in the analyses is 7400 gpm
 
with two pumps operating in one loop. In this case, the
 
maximum suppression chamber water temperature and pressure
 
are 200&deg;F and 30.6 psig, respectively, well below the design temperature of 275
&deg;F and maximum design pressure of 45 psig.
 
The RHRSW System satisfies Criterion 3 of
 
10 CFR 50.36(c)(2)(ii).
 
(continued)
RHRSW System B 3.7.1 LaSalle 1 and 2 B 3.7.1-3 Revision 0 BASES  (continued)
 
LCO Two RHRSW subsystems are required to be OPERABLE to provide the required redundancy to ensure that the system functions
 
to remove post accident heat loads, assuming the worst case
 
single active failure occurs coincident with the loss of
 
offsite power.
An RHRSW subsystem is considered OPERABLE when:
: a. Two pumps are OPERABLE; and
: b. An OPERABLE flow path is capable of taking suction from the CSCS service water tunnel and transferring
 
the water to the associated RHR heat exchanger at the
 
assumed flow rate.
An adequate suction source is not addressed in this LCO
 
since the minimum net positive suction head and the maximum
 
suction source temperature are covered by the requirements
 
specified in LCO 3.7.3, "Ultimate Heat Sink (UHS)." 
 
APPLICABILITY In MODES 1, 2, and 3, the RHRSW System is required to be OPERABLE to support the OPERABILITY of the RHR System for
 
primary containment cooling (LCO 3.6.2.3, "Residual Heat
 
Removal (RHR) Suppression Pool Cooling" and decay heat
 
removal (LCO 3.4.9, "Residual Heat Removal (RHR) Shutdown
 
Cooling System-Hot Shutdown"). The Applicability is
 
therefore consistent with the requirements of these systems.
In MODES 4 and 5, the OPERABILITY requirements of the RHRSW
 
System are determined by the systems it supports and
 
therefore, the requirements are not the same for all facets
 
of operation in MODES 4 and 5. Thus, the LCOs of the RHR
 
Shutdown Cooling System (LCO 3.4.10, "Residual Heat Removal (RHR) Shutdown Cooling System-Cold Shutdown," LCO 3.9.8, "Residual Heat Removal (RHR)-High Water Level," and
 
LCO 3.9.9, "Residual Heat Removal (RHR)-Low Water Level"),
which require portions of the RHRSW System to be OPERABLE, will govern RHRSW System operation in MODES 4 and 5.
 
(continued)
RHRSW System B 3.7.1 LaSalle 1 and 2 B 3.7.1-4 Revision 21 BASES  (continued)
 
ACTIONS A.1 Condition A is modified by a Note indicating that this Condition is not applicable to Unit 2 during replacement of the Division 1 CSCS isolation valves during Unit 1 Refueling 11 while Unit 1 is in MODE 4, 5, or defueled.
When the Division 1 RHRSW subsystem is inoperable during the CSCS isolation valve maintenance, Condition B provides the appropriate Required Actions.
Required Action A.1 is intended to handle the inoperability
 
of one RHRSW subsystem. The Completion Time of 7 days is
 
allowed to restore the RHRSW subsystem to OPERABLE status. 
 
With the unit in this condition, the remaining OPERABLE
 
RHRSW subsystem is adequate to perform the RHRSW heat
 
removal function. However, the overall reliability is
 
reduced because a single failure in the OPERABLE RHRSW
 
subsystem could result in loss of RHRSW function. The
 
Completion Time is based on the redundant RHRSW capabilities
 
afforded by the OPERABLE subsystem and the low probability
 
of an event occurring requiring RHRSW during this period.
 
The Required Action is modified by a Note indicating that
 
the applicable Conditions of LCO 3.4.9, be entered and
 
Required Actions taken if the inoperable RHRSW subsystem
 
results in inoperable RHR shutdown cooling. This is an
 
exception to LCO 3.0.6 and ensures the proper actions are
 
taken for these components.
 
B.1 Condition B is modified by a Note indicating that this Condition is only applicable to Unit 2 during replacement of the Division 1 CSCS isolation valves during Unit 1 Refueling Outage 11 while the outage unit is in MODE 4, 5, or defueled.
Required Action B.1 is intended to handle the inoperability of one RHRSW subsystem. The Completion Time of 10 days is allowed to restore the RHRSW subsystem to OPERABLE status.
With the unit in this condition, the remaining OPERABLE RHRSW subsystem is adequate to perform the RHRSW heat removal function. However, the overall reliability is reduced because a single failure in the OPERABLE RHRSW subsystem could result in loss of RHRSW function. The (continued)
 
RHRSW System B 3.7.1 LaSalle 1 and 2 B 3.7.1-5 Revision 32 BASES ACTIONS B.1 (continued)
 
Completion Time is based upon a risk-informed assessment that concluded that the associated risk with the unit in the
 
specified configuration is acceptable (Ref. 5).
 
The Required Action is modified by a Note indicating that
 
the applicable Conditions of LCO 3.4.9, be entered and
 
Required Actions taken if the inoperable RHRSW subsystem
 
results in inoperable RHR shutdown cooling. This is an
 
exception to LCO 3.0.6 and ensures the proper actions are
 
taken for these components.
 
C.1 If one RHRSW subsystem is inoperable and not restored within the provided Completion Time, the plant must be brought to a condition in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 6) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
 
D.1 With both RHRSW subsystems inoperable (e.g., both subsystems
 
with inoperable pump(s) or flow paths, or one subsystem with
 
an inoperable pump and one subsystem with an inoperable flow
 
path), the RHRSW System is not capable of performing its
 
intended function. At least one subsystem must be restored
 
to OPERABLE status within 8 hours. The 8 hour Completion
 
Time for restoring one RHRSW subsystem to OPERABLE status, is based on the Completion Times provided for the RHR
 
suppression pool cooling and spray functions.
 
(continued)
RHRSW System B 3.7.1 LaSalle 1 and 2 B 3.7.1-6 Revision 32 BASES  (continued)
 
ACTIONS D.1 (continued)
The Required Action is modified by a Note indicating that
 
the applicable Conditions of LCO 3.4.9, be entered and
 
Required Actions taken if the inoperable RHRSW subsystem
 
results in inoperable RHR shutdown cooling. This is an
 
exception to LCO 3.0.6 and ensures the proper actions are
 
taken for these components.
 
E.1 and E.2 If any Required Action and associated Completion Time of
 
Condition D is not met, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the
 
unit must be placed in at least MODE 3 within 12 hours and
 
in MODE 4 within 36 hours. The allowed Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an
 
orderly manner and without challenging unit systems.
 
SURVEILLANCE SR  3.7.1.1 REQUIREMENTS Verifying the correct alignment for each manual, power
 
operated, and automatic valve in each RHRSW subsystem flow
 
path provides assurance that the proper flow paths will
 
exist for RHRSW operation. This SR does not apply to valves
 
that are locked, sealed, or otherwise secured in position, since these valves are verified to be in the correct
 
position prior to locking, sealing, or securing. A valve is
 
also allowed to be in the nonaccident position, and yet
 
considered in the correct position, provided it can be
 
realigned to its accident position. This is acceptable
 
because the RHRSW System is a manually initiated system. 
 
This SR does not require any testing or valve manipulation;
 
rather, it involves verification that those valves capable
 
of being mispositioned are in the correct position. This SR
 
does not apply to valves that cannot be inadvertently
 
misaligned, such as check valves.
 
The 31 day Frequency is based on engineering judgment, is
 
consistent with the procedural controls governing valve
 
operation, and ensures correct valve positions.
 
(continued)
 
RHRSW System B 3.7.1 LaSalle 1 and 2 B 3.7.1-7 Revision 32 BASES  (continued)
 
REFERENCES 1. UFSAR, Section 9.2.1.
: 2. UFSAR, Chapter 6.
: 3. UFSAR, Chapter 15.
: 4. UFSAR, Section 6.2.2.3.1.
: 5. Risk Management Document SA-1354, Rev. 0, "LaSalle Division 1 and 2 CSCS Valve Replacement Project -
 
Temporary Extension of Technical Specification  
 
Completion Times", December 02, 2004.
: 6. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants," December 2002.
 
DGCW System B 3.7.2 LaSalle 1 and 2 B 3.7.2-1 Revision 0 B 3.7  PLANT SYSTEMS
 
B 3.7.2  Diesel Generator Cooling Water (DGCW) System
 
BASES
 
BACKGROUND The DGCW System is designed to provide cooling water for the removal of heat from the standby diesel generators, low
 
pressure core spray (LPCS) pump motor cooling coils, and
 
Emergency Core Cooling System (ECCS) cubicle area cooling
 
coils that support equipment required for a safe reactor
 
shutdown following a design basis accident (DBA) or
 
transient.
The DGCW System consists of three independent cooling water
 
headers (Divisions 1, 2, and 3), and their associated pumps, valves, and instrumentation. The pump and header for the
 
Division 1 DGCW subsystem is common to both units (and
 
supplies cooling to equipment on both units). The other
 
divisions have independent pumps and suction headers. 
 
The following combinations of DGCW pumps are sized to
 
provide sufficient cooling capacity to support the required
 
safety related systems during safe shutdown of the unit
 
following a loss of coolant accident (LOCA):
: a. The Division 1 and 2 DGCW pumps;
: b. The Division 1 and 3 DGCW pumps and opposite unit Division 2 DGCW pump; or
: c. The Division 2 and 3 DGCW pumps.
The Division 1 DGCW subsystem services its associated Diesel
 
Generator (DG) and ECCS cubicle area coolers, and the LPCS
 
pump motor cooler. The Division 2 DGCW subsystem services
 
its associated DG and ECCS cubicle area cooler. The
 
Division 3 DGCW subsystem services the High Pressure Core
 
Spray (HPCS) DG and its associated ECCS cubicle area cooler.
 
The opposite unit Division 2 DGCW subsystem services its
 
associated DG for support of systems required by both units.
(continued)
DGCW System B 3.7.2 LaSalle 1 and 2 B 3.7.2-2 Revision 2 BASES
 
BACKGROUND The DGCW and the Residual Heat Removal Service Water (RHRSW)
  (continued) subsystems are subsystems to the Core Standby Cooling System (CSCS)-Equipment Cooling Water System (ECWS). The CSCS-
 
ECWS consists of three independent piping subsystems
 
corresponding to essential electrical power supply Divisions
 
1, 2, and 3. The CSCS-ECWS subsystems take a suction from
 
the service water tunnel located in the Lake Screen House.
 
Each DGCW pump auto-starts upon receipt of a diesel
 
generator (DG) start signal when power is available to the
 
pump's electrical bus or on start of ECCS cubicle area
 
coolers. The Division 1 DGCW pump also auto-starts upon
 
receipt of a start signal for the LPCS pump. Cooling water
 
is then pumped from the service water tunnel by the DGCW
 
pumps to the supported systems and components (i.e., the
 
DGs, LPCS pump motor cooler, and the ECCS cubicle area
 
coolers). After removing heat from these systems and
 
components, the water from the DGCW subsystem is discharged
 
to the CSCS pond (i.e., the Ultimate Heat Sink) through a
 
discharge line that is common to the corresponding
 
divisional discharge from the other unit. The discharge
 
line terminates in the discharge structure at an elevation
 
above the normal CSCS Pond level. A complete description of
 
the DGCW System is presented in the UFSAR, Section 9.2.1 (Ref. 1).
 
APPLICABLE The ability of the DGCW System to provide adequate cooling SAFETY ANALYSES to the DGs, LPCS pump motor cooling coils and ECCS cubicle area cooling coils is an implicit assumption for the safety
 
analyses presented in UFSAR, Chapters 6 and 15 (Refs. 2
 
and 3, respectively). The ability to provide onsite
 
emergency AC power is dependent on the ability of the DGCW
 
System to cool the DGs.
The DGCW System satisfies Criterion 3 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO The Division 1, 2, and 3, and the opposite unit's Division 2 DGCW subsystems are required to be OPERABLE to ensure the
 
effective operation of the DGs, the LPCS pump motor, and the
 
ECCS equipment supported by the ECCS cubicle area coolers
 
during a DBA or transient. The OPERABILITY of each DGCW (continued)
DGCW System B 3.7.2 LaSalle 1 and 2 B 3.7.2-3 Revision 21 BASES LCO subsystem is based on having an OPERABLE pump and an (continued) OPERABLE flow path capable of taking suction from the CSCS water tunnel and transferring cooling water to the
 
associated diesel generator, LPCS pump motor cooling coils, and ECCS cubicle area cooling coils, as required.
An adequate suction source is not addressed in this LCO
 
since the minimum net positive suction head of the DGCW pump
 
and the maximum suction source temperature are covered by
 
the requirements specified in LCO 3.7.3, "Ultimate Heat Sink (UHS)."
APPLICABILITY In MODES 1, 2, and 3, the DGCW subsystems are required to support the OPERABILITY of equipment serviced by the DGCW
 
subsystems and required to be OPERABLE in these MODES.
In MODES 4 and 5, the OPERABILITY requirements of the DGCW
 
subsystems are determined by the systems they support.
 
Therefore, the requirements are not the same for all facets
 
of operation in MODES 4 and 5. Thus, the LCOs of the
 
systems supported by the DGCW subsystems will govern DGCW
 
System OPERABILITY requirements in MODES 4 and 5.
 
ACTIONS The ACTIONS Table is modified by a Note indicating that separate Condition entry is allowed for each DGCW subsystem.
 
This is acceptable, since the Required Actions for the
 
Condition provide appropriate compensatory actions for each
 
inoperable DGCW subsystem. Complying with the Required
 
Actions for one inoperable DGCW subsystem may allow for
 
continued operation, and subsequent inoperable DGCW
 
subsystem(s) are governed by separate Condition entry and
 
application of associated Required Actions.
A.1 Condition A is modified by two Notes indicating that this Condition is not applicable during replacement of CSCS isolation valves during the specified unit outages while the outage unit is in MODE 4, 5, or defueled. When the specified DGCW subsystem(s) are inoperable during the CSCS isolation valve maintenance, Condition B provides appropriate Required Actions. 
(continued)
DGCW System B 3.7.2 LaSalle 1 and 2 B 3.7.2-4 Revision 21 BASES ACTIONS A.1 (continued)
If one or more DGCW subsystems are inoperable, the
 
associated DG(s) and ECCS components supported by the
 
affected DGCW loop, including LPCS pump motor cooling coils
 
or ECCS cubicle area cooling coils, as applicable, cannot
 
perform their intended function and must be immediately
 
declared inoperable. In accordance with LCO 3.0.6, this
 
also requires entering into the Applicable Conditions and
 
Required Actions for LCO 3.4.9, "RHR Shutdown Cooling System
-Hot Shutdown," LCO 3.5.1, "ECCS-Operating," LCO 3.5.3, 
 
"RCIC System," LCO 3.6.2.3, "RHR Suppression Pool Cooling,"
 
LCO 3.6.2.4, "RHR Suppression Pool Spray," and LCO 3.8.1, "AC Sources
-Operating," as appropriate.
B.1  Condition B is modified by two Notes indicating that this Condition is only applicable during replacement of CSCS isolation valves during the specified unit outages while the outage unit is in MODE 4, 5, or defueled.
If one or more DGCW subsystems are inoperable, the associated DG(s) and ECCS components supported by the affected DGCW loop, including LPCS pump motor cooling coils or ECCS cubicle area cooling coils, as applicable, cannot perform their intended function and must be restored to OPERABLE status within 6 days during replacement of Division 2 CSCS isolation valves or within 10 days during replacement of the Division 1 CSCS isolation valves. Overall ESF system reliability is reduced in this Condition because a single failure in one of the remaining OPERABLE subsystems concurrent with a design basis LOCA may result in the DGCW system not being able to perform its intended safety function. These Completion Times are based upon a risk-informed assessment that concluded that the associated risk with the unit in the specified configuration is acceptable (Ref. 4).
C.1 and C.2 If the Required Action and associated Completion Time of Condition B is not met, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 12 hours and (continued) 
 
BASES DGCW System B 3.7.2 LaSalle 1 and 2 B 3.7.2-5 Revision 21 ACTIONS C.1 and C.2 (continued) 
 
in MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.
______________________________________________________________________________
 
SURVEILLANCE SR  3.7.2.1 REQUIREMENTS Verifying the correct alignment for manual, power operated, and automatic valves in each DGCW subsystem flow path
 
provides assurance that the proper flow paths will exist for
 
DGCW subsystem operation. This SR does not apply to valves
 
that are locked, sealed, or otherwise secured in position
 
since these valves were verified to be in the correct
 
position prior to locking, sealing, or securing. A valve is
 
also allowed to be in the nonaccident position, and yet be
 
considered in the correct position provided it can be
 
automatically realigned to its accident position, within the
 
required time. This SR does not require any testing or
 
valve manipulation; rather, it involves verification that
 
those valves capable of being mispositioned are in the
 
correct position. This SR does not apply to valves that
 
cannot be inadvertently misaligned, such as check valves.
 
The 31 day Frequency is based on engineering judgment, is
 
consistent with the procedural controls governing valve
 
operation, and ensures correct valve positions.
SR  3.7.2.2
 
This SR ensures that each DGCW subsystem pump will
 
automatically start to provide required cooling to the
 
associated DG, LPCS pump motor cooling coils, and ECCS
 
cubicle area cooling coils, as applicable, when the
 
associated DG starts and the respective bus is energized. 
 
For the Division 1 DGCW subsystem, this SR also ensures the
 
DGCW pump automatically starts on receipt of a start signal
 
for the unit LPCS pump. These starts may be performed using
 
actual or simulated initiation signals.
 
Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which
 
is based at the refueling cycle. Therefore, this Frequency
 
is concluded to be acceptable from a reliability standpoint. (continued)
 
DGCW System B 3.7.2 LaSalle 1 and 2 B 3.7.2-6 Revision 21 BASES (continued)
 
REFERENCES 1. UFSAR, Section 9.2.1.
: 2. UFSAR, Chapter 6.
: 3. UFSAR, Chapter 15.
: 4. Risk Management Document SA-1354, Rev. 0, "LaSalle Division 1 and 2 CSCS Valve Replacement Project -
Temporary Extension of Technical Specification Completion Times", December 02, 2004.
 
UHS B 3.7.3 LaSalle 1 and 2 B 3.7.3-1 Revision 29 B 3.7  PLANT SYSTEMS
 
B 3.7.3  Ultimate Heat Sink (UHS)
 
BASES
 
BACKGROUND The UHS (i.e., the Core Standby Cooling System (CSCS) Pond) consists of the volume of water remaining in the cooling
 
lake following the failure of the main dike. This water has
 
a depth of approximately 5 feet and a top water elevation
 
established at 690 feet. The volume of the remaining water
 
in the cooling lake is sufficient to permit a safe shutdown
 
and cooldown of the station for 30 days with no water makeup
 
for both accident and normal conditions (Regulatory Guide
 
1.27, Ref. 1).
The CSCS Pond provides a source of water to the service
 
water tunnel from which the Residual Heat Removal Service
 
Water (RHRSW) and Diesel Generator Cooling Water (DGCW)
 
pumps take suction. The service water tunnel is filled from
 
the CSCS Pond by six inlet lines which connect to the
 
circulating water pump forebays. Prior to entering the
 
service water tunnel inlet pipes, the water is strained by
 
the Lake Screen House traveling screens to prevent large
 
pieces of debris from entering the system and blocking flow
 
or damaging equipment. However, because the traveling
 
screens are not safety related, a 54-inch bypass line around
 
the screens, isolated by a normally closed manual valve, is
 
provided to assure a continuous supply of CSCS Pond water to
 
the service water tunnel.
 
Additional information on the design and operation of the
 
CSCS Pond is provided in UFSAR, Sections 9.2.1 and 9.2.6 (Refs. 2 and 3). The excavation slopes of the CSCS Pond and
 
flume are designed to be stable under all conditions of
 
emergency operation while providing the capability to supply
 
adequate cooling water to equipment required for safe
 
reactor shutdown.
 
APPLICABLE The volume of the CSCS pond is sized to permit the safe SAFETY ANALYSES shutdown and cooldown of the units for a 30 day period with no additional makeup water source available for both normal
 
and accident conditions (Ref. 2). 
(continued)
 
UHS B 3.7.3  LaSalle 1 and 2 B 3.7.3-2 Revision 29 BASES APPLICABLE The UHS post-accident temperature is based on heat removal  SAFETY ANALYSES calculations (Ref. 5) that analyze for a maximum allowable  (continued) post-accident inlet cooling water temperature of 104&deg;F. To account for the worst-case scenario and to apply conservatism, the post-accident CSCS pond cooling water inlet temperature of 104
&deg;F consists of the CSCS pond TS temperature maximum of 101.25
&deg;F plus 2&deg;F for transient heat up plus 0.75
&deg;F to account for instrument uncertainty (Ref. 6).
There are four temperature measuring devices located in the Circulating Water inlet thermowells (i.e., two per unit).
The 0.75&deg;F allowance bounds the instrument uncertainty associated with any combination of operable temperature measurement devices.
The UHS satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 
 
LCO OPERABILITY of the UHS is based on a maximum water temperature being supplied to the plant of 101.25
&deg;F and a minimum pond water level at or above elevation 690 ft mean sea level. In addition, to ensure the volume of water
 
available in the CSCS pond is sufficient to maintain
 
adequate long term cooling, sediment deposition (in the
 
intake flume and in the pond) must be  1.5 ft and CSCS pond bottom elevation must be  686.5 ft.
 
APPLICABILITY In MODES 1, 2, and 3, the UHS is required to be OPERABLE to support OPERABILITY of the equipment serviced by the UHS, and is required to be OPERABLE in these MODES.
In MODES 4 and 5, the OPERABILITY requirements of the UHS
 
are determined by the systems it supports. Therefore, the requirements are not the same for all facets of operation in
 
MODES 4 and 5. The LCOs of the systems supported by the UHS
 
will govern UHS OPERABILITY requirements in MODES 4 and 5.
 
  (continued)
 
UHS B 3.7.3  LaSalle 1 and 2 B 3.7.3-3 Revision 29 BASES (continued)
 
ACTIONS A.1 If the CSCS pond is inoperable, due to sediment deposition
 
> 1.5 ft (in the intake flume, CSCS pond, or both) or the
 
pond bottom elevation > 686.5 ft, action must be taken to
 
restore the inoperable UHS to an OPERABLE status within 90
 
days. The 90 day Completion Time is reasonable based on the
 
low probability of an accident occurring during that time, historical data corroborating the low probability of
 
continued degradation (i.e., further excessive sediment
 
deposition or pond bottom elevation changes) of the CSCS
 
pond during that time, and the time required to complete the
 
Required Action.
 
B.1 and B.2
 
If the CSCS pond cannot be restored to OPERABLE status
 
within the associated Completion Time, or the CSCS pond is
 
determined inoperable for reasons other than Condition A (e.g., inoperable due to the temperature of the cooling
 
water supplied to the plant from the CSCS pond > 101.25
&deg;F, corrected for sediment level and time of day), the unit must be placed in a MODE in which the LCO does not apply. To
 
achieve this status, the unit must be placed in at least
 
MODE 3 within 12 hours and in MODE 4 within 36 hours. The
 
allowed Completion Times are reasonable, based on operating
 
experience, to reach the required unit conditions from full
 
power conditions in an orderly manner and without
 
challenging unit systems.
 
SURVEILLANCE SR  3.7.3.1 REQUIREMENTS Verification of the temperature of the water supplied to the
 
plant from the CSCS pond ensures that the heat removal
 
capabilities of the RHRSW System and DGCW System are within
 
the assumptions of the DBA analysis. To ensure that the
 
maximum post-accident temperature of water supplied to the
 
plant is not exceeded (i.e., 104
&deg;F determined in Ref. 4), the temperature during normal plant operation must be 101.25&deg;F (Ref. 3). This is to account for the CSCS pond design requirement that it provide adequate cooling water supply to the plant (i.e., temperature  104&deg;F) for 30 days (continued)
 
UHS B 3.7.3  LaSalle 1 and 2 B 3.7.3-4 Revision 29 BASES    SURVEILLANCE SR  3.7.3.1 (continued)
REQUIREMENTS (continued)      without makeup, while taking into account solar heat loads and plant decay heat during the worst historical weather
 
conditions. In addition, since the lake temperature follows
 
a diurnal cycle (it heats up during the day and cools off at
 
night), the allowable initial UHS temperature varies with
 
the time of day. The allowable initial UHS temperatures, based on the actual sediment level and the time of day have
 
been determined by analysis (Ref. 5). The limiting initial
 
UHS temperature of 102.3
&deg;F determined in this analysis ensures the maximum post-accident temperature of 104
&deg;F is not exceeded. These temperatures are analytical limits that
 
do not include instrument uncertainty or additional margin.
 
For example, if the lake temperature uncertainty and
 
additional margin are determined to be 0.5
&deg;F, the limiting initial UHS temperature becomes 101.8
&deg;F. This limiting initial temperature remains bounded by the SR 3.7.3.1 limit
 
of  101.25&deg;F. The 24 hour Frequency is based on operating experience related to trending of the parameter variations during the applicable MODES.
 
SR  3.7.3.2
 
This SR ensures adequate long term (30 days) cooling can be maintained, by verifying the sediment level in the intake
 
flume and the CSCS pond is  1.5 feet. Sediment level is determined by a series of sounding cross-sections compared
 
to as-built soundings. The 24 month Frequency is based on
 
historical data and engineering judgment regarding sediment deposition rate.
 
SR  3.7.3.3
 
This SR ensures adequate long term (30 days) cooling can be maintained, by verifying the CSCS pond bottom elevation is 686.5 feet. The 24-month Frequency is based on historical data and engineering judgment regarding pond bottom elevation changes.
(continued)
UHS B 3.7.3  LaSalle 1 and 2 B 3.7.3-5 Revision 29 BASES  (continued)
 
REFERENCES 1. Regulatory Guide 1.27, Revision 2, January 1976.
: 2. UFSAR, Section 9.2.1.
: 3. UFSAR, Section 9.2.6.
: 4. EC 334017, Rev. 0, "Increased Cooling Water Temperature Evaluation to a New Maximum Allowable of
 
104&deg;F."  5. L-002457, Rev. 5, "LaSalle County Station Ultimate Heat Sink Analysis."
: 6. L-003230, Rev. 1, "CW Inlet Temperature Uncertainty Analysis."
CRAF System B 3.7.4 LaSalle 1 and 2 B 3.7.4-1 Revision 0 B 3.7  PLANT SYSTEMS
 
B 3.7.4  Control Room Area Filtration (CRAF) System
 
BASES
 
BACKGROUND The CRAF System provides a radiologically controlled environment (control room and auxiliary electric equipment
 
room) from which the unit can be safely operated following a
 
Design Basis Accident (DBA). The Control Room Area Heating
 
Ventilation and Air Conditioning (HVAC) System is comprised
 
of the Control Room HVAC System and the Auxiliary Electric
 
Equipment Room (AEER) HVAC System. The Control Room HVAC
 
System is common to both units and serves the control room, main security control center, and the control room
 
habitability storage room (toilet room). The AEER HVAC
 
System is common to both units and services the auxiliary
 
electrical equipment rooms. The control room area is
 
comprised of the areas covered by the Control Room and AEER
 
HVAC Systems.
The safety related function of the CRAF System used to
 
control radiation exposure consists of two independent and
 
redundant high efficiency air filtration subsystems (i.e.,
the emergency makeup air filter units (EMUs) for treatment
 
of outside supply air). Recirculation filters are also
 
provided for treatment of recirculated air. Each EMU
 
subsystem consists of a demister, an electric heater, a
 
prefilter, a high efficiency particulate air (HEPA) filter, an activated charcoal adsorber section, a second HEPA
 
filter, a fan, and the associated ductwork, dampers, and
 
instrumentation and controls. Demisters remove water
 
droplets from the airstream. The electric heater reduces
 
the relative humidity of the air entering the EMUs. 
 
Prefilters and HEPA filters remove particulate matter that
 
may be radioactive. The charcoal adsorbers provide a holdup
 
period for gaseous iodine, allowing time for decay. Each
 
Control Room and AEER Ventilation System has a charcoal
 
recirculation filter in the supply of the system that is
 
normally bypassed. In addition, the OPERABILITY of the CRAF
 
System is dependent upon portions of the Control Room Area
 
HVAC System, including the control room and auxiliary
 
electric equipment room outside air intakes, supply fans, ducts, dampers, etc.
(continued)
CRAF System B 3.7.4 LaSalle 1 and 2 B 3.7.4-2 Revision 0 BASES BACKGROUND In addition to the safety related standby emergency (continued) filtration function, parts of the CRAF System that are shared with the Control Room Area HVAC System are operated
 
to maintain the control room area environment during normal
 
operation. Upon receipt of a high radiation signal from the
 
outside air intake  (indicative of conditions that could
 
result in radiation exposure to control room personnel), the
 
CRAF System automatically isolates the normal outside air
 
supply to the Control Room Area HVAC System, and diverts the
 
minimum outside air requirement through the EMUs before
 
delivering it to the control room area. The recirculation
 
filters for the control room and AEER must be manually
 
placed in service within 4 hours of receipt of any control
 
room high radiation alarm.
The CRAF System is designed to maintain the control room
 
area environment for a 30 day continuous occupancy after a
 
DBA, without exceeding a 5 rem whole body dose or its
 
equivalent to any part of the body. CRAF System operation
 
in maintaining the control room area habitability is
 
discussed in the UFSAR, Sections 6.4, 6.5.1, and 9.4.1 (Refs. 1, 2, and 3, respectively).
 
APPLICABLE The ability of the CRAF System to maintain the SAFETY ANALYSES habitability of the control room area is an explicit assumption for the safety analyses presented in the UFSAR, Chapters 6 and 15 (Refs. 4 and 5, respectively). The
 
pressurization mode of the CRAF System is assumed to operate
 
following a loss of coolant accident, main steam line break, fuel handling accident, and control rod drop accident. The
 
radiological doses to control room personnel as a result of
 
the various DBAs are summarized in Reference 5. No single
 
active failure will cause the loss of outside or
 
recirculated air from the control room area.
The CRAF System satisfies Criterion 3 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO Two redundant subsystems of the CRAF System are required to be OPERABLE to ensure that at least one is available, assuming a single failure disables the other subsystem. 
 
Total system failure could result in exceeding a dose of
 
5 rem to the control room operators in the event of a DBA.
(continued)
CRAF System B 3.7.4 LaSalle 1 and 2 B 3.7.4-3 Revision 0 BASES LCO The CRAF System is considered OPERABLE when the individual (continued) components necessary to control operator exposure are OPERABLE in both subsystems. A subsystem is considered
 
OPERABLE when its associated EMU is OPERABLE and the
 
associated charcoal recirculation filters for the control
 
room and AEER are OPERABLE. An EMU is considered OPERABLE
 
when its associated:
: a. Fan is OPERABLE;
: b. HEPA filter and charcoal adsorber are not excessively restricting flow and are capable of performing their
 
filtration functions; and
: c. Heater, demister, ductwork, valves, and dampers are OPERABLE, and air circulation through the EMU can be
 
maintained.
Additionally, the portions of the Control Room Area HVAC
 
System that supply the outside air to the EMUs are required
 
to be OPERABLE. This includes the outside air intakes, associated dampers and ductwork.
 
In addition, the control room area boundary must be
 
maintained, including the integrity of the walls, floors, ceilings, ductwork, and access doors, such that the
 
pressurization limit of SR 3.7.4.5 can be met. However, it
 
is acceptable for access doors to be open for normal control
 
room area entry and exit and not consider it to be a failure
 
to meet the LCO. 
 
APPLICABILITY In MODES 1, 2, and 3, the CRAF System must be OPERABLE to control operator exposure during and following a DBA, since
 
the DBA could lead to a fission product release.
In MODES 4 and 5, the probability and consequences of a DBA
 
are reduced due to the pressure and temperature limitations
 
in these MODES. Therefore, maintaining the CRAF System
 
OPERABLE is not required in MODE 4 or 5, except for the
 
following situations under which significant radioactive
 
releases can be postulated:
: a. During movement of irradiated fuel assemblies in the secondary containment; (continued)
CRAF System B 3.7.4 LaSalle 1 and 2 B 3.7.4-4 Revision 32 BASES APPLICABILITY b. During CORE ALTERATIONS; and
 
  (continued) c. During operations with a potential for draining the reactor vessel (OPDRVs).
 
ACTIONS A.1 With one CRAF subsystem inoperable, the inoperable CRAF
 
subsystem must be restored to OPERABLE status within 7 days.
 
With the unit in this condition, the remaining OPERABLE CRAF
 
subsystem is adequate to perform control room radiation
 
protection. However, the overall reliability is reduced
 
because a single failure in the OPERABLE subsystem could
 
result in loss of CRAF System function. The 7 day
 
Completion Time is based on the low probability of a DBA
 
occurring during this time period, and that the remaining
 
subsystem can provide the required capabilities.
 
B.1 In MODE 1, 2, or 3, if the inoperable CRAF subsystem cannot
 
be restored to OPERABLE status within the associated
 
Completion Time, the unit must be placed in a MODE that
 
minimizes overall plant risk. To achieve this status, the unit must be placed in at least MODE 3 within 12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 6) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short.
However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
The allowed Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.
 
C.1, C.2.1, C.2.2, and C.2.3
 
LCO 3.0.3 is not applicable while in MODE 4 or 5. However, since irradiated fuel assembly movement can occur in MODE 1, 2, or 3, the Required Actions of Condition C are modified by
 
a Note indicating that LCO 3.0.3 does not apply. If moving
 
irradiated fuel assemblies while in MODE 1, 2, or 3, the (continued)
CRAF System B 3.7.4 LaSalle 1 and 2 B 3.7.4-5 Revision 32 BASES ACTIONS C.1, C.2.1, C.2.2, and C.2.3 (continued) fuel movement is independent of reactor operations. 
 
Entering LCO 3.0.3 while in MODE 1, 2, or 3 would require
 
the unit to be shutdown, but would not require immediate
 
suspension of movement of irradiated fuel assemblies. The
 
Note to the ACTIONS, "LCO 3.0.3 is not applicable," ensures
 
that the actions for immediate suspension of irradiated fuel
 
assembly movement are not postponed due to entry into
 
LCO 3.0.3.
 
During movement of irradiated fuel assemblies in the
 
secondary containment, during CORE ALTERATIONS, or during
 
OPDRVs, if the inoperable CRAF subsystem cannot be restored
 
to OPERABLE status within the required Completion Time, the
 
OPERABLE CRAF subsystem may be placed in the pressurization
 
mode. This action ensures that the remaining subsystem is
 
OPERABLE, that no failures that would prevent automatic
 
actuation will occur, and that any active failure will be
 
readily detected.
 
An alternative to Required Action C.1 is to immediately
 
suspend activities that present a potential for releasing
 
radioactivity that might require isolation of the control
 
room area. This places the unit in a condition that
 
minimizes risk.
 
If applicable, CORE ALTERATIONS and movement of irradiated
 
fuel assemblies in the secondary containment must be
 
suspended immediately. Suspension of these activities shall
 
not preclude completion of movement of a component to a safe
 
position. Also, if applicable, action must be initiated
 
immediately to suspend OPDRVs to minimize the probability of
 
a vessel draindown and subsequent potential for fission
 
product release. Action must continue until the OPDRVs are
 
suspended.
 
D.1 If both CRAF subsystems are inoperable in MODE 1, 2, or 3, the CRAF System may not be capable of performing the
 
intended function. Therefore, the plant must be brought to a MODE in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is (continued)
CRAF System B 3.7.4 LaSalle 1 and 2 B 3.7.4-6 Revision 32 BASES  ACTIONS D.1 (continued)  similar to or lower than the risk in MODE 4 (Ref. 6) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions is an orderly manner and without challenging plant systems.
 
E.1, E.2, and E.3 LCO 3.0.3 is not applicable while in MODE 4 or 5. However, since irradiated fuel assembly movement can occur in MODE 1, 2, or 3, the Required Actions of Condition E are modified by
 
a Note indicating that LCO 3.0.3 does not apply. If moving
 
irradiated fuel assemblies while in MODE 1, 2, or 3, the
 
fuel movement is independent of reactor operations. 
 
Entering LCO 3.0.3 while in MODE 1, 2, or 3 would require
 
the unit to be shutdown, but would not require immediate
 
suspension of movement of irradiated fuel assemblies. The
 
Note to the ACTIONS, "LCO 3.0.3 is not applicable," ensures
 
that the actions for immediate suspension of irradiated fuel
 
assembly movement are not postponed due to entry into
 
LCO 3.0.3.
 
During movement of irradiated fuel assemblies in the
 
secondary containment, during CORE ALTERATIONS, or during
 
OPDRVs, with two CRAF subsystems inoperable, action must be
 
taken immediately to suspend activities that present a
 
potential for releasing radioactivity that might require
 
isolation of the control room. This places the unit in a
 
condition that minimizes risk.
 
If applicable, CORE ALTERATIONS and movement of irradiated
 
fuel assemblies in the secondary containment must be
 
suspended immediately. Suspension of these activities shall
 
not preclude completion of movement of a component to a safe
 
position. If applicable, action must be initiated
 
immediately to suspend OPDRVs to minimize the probability of
 
a vessel draindown and subsequent potential for fission
 
product release. Action must continue until the OPDRVs are
 
suspended.
(continued)
CRAF System B 3.7.4 LaSalle 1 and 2 B 3.7.4-7 Revision 32 BASES  (continued)
 
SURVEILLANCE SR  3.7.4.1 REQUIREMENTS This SR verifies that a subsystem in a standby mode starts
 
on demand and continues to operate. Standby systems should
 
be checked periodically to ensure that they start and
 
function properly. As the environmental and normal
 
operating conditions of this system are not severe, testing each subsystem once every month provides an adequate
 
check on this system. Monthly heater operation for 10 continuous hours during system operation dries out any moisture accumulated in the charcoal from humidity in the
 
ambient air. Furthermore, the 31 day Frequency is based on
 
the known reliability of the equipment and the two subsystem
 
redundancy available.
 
SR  3.7.4.2
 
This SR verifies that flow can be manually realigned through
 
the CRAF System recirculation filters and maintained for 10 hours. Standby systems should be checked periodically to ensure that they function. Monthly operation dries out
 
any moisture accumulated in the charcoal from humidity in
 
the ambient air. Furthermore, the 31 day Frequency is based
 
on the known reliability of the equipment and two subsystem
 
redundancy available.
 
SR  3.7.4.3
 
This SR verifies that the required CRAF testing is performed
 
in accordance with Specification 5.5.8, "Ventilation Filter
 
Testing Program (VFTP)."  The CRAF filter tests are in
 
accordance with ANSI/ASME N510-1989 (Ref. 7). The VFTP includes testing HEPA filter performance, charcoal adsorber
 
efficiency, system flow rate, and the physical properties of
 
the activated charcoal (general use and following specific
 
operations). Specific test frequencies and additional
 
information are discussed in detail in the VFTP.
 
SR  3.7.4.4
 
This SR verifies that each CRAF subsystem automatically
 
switches to the pressurization mode of operation on an
 
actual or simulated air intake radiation monitors initiation (continued)
CRAF System B 3.7.4 LaSalle 1 and 2 B 3.7.4-8 Revision 32 BASES SURVEILLANCE SR  3.7.4.4 (continued)
REQUIREMENTS signal. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.7.1.4 overlaps this SR to provide complete testing of the safety
 
function. Operating experience has shown that these
 
components normally pass the SR when performed at the
 
24 month Frequency. Therefore, the Frequency was found to
 
be acceptable from a reliability standpoint.
 
SR  3.7.4.5
 
This SR verifies the integrity of the control room area and
 
the assumed inleakage rates of potentially contaminated air.
 
The control room area positive pressure, with respect to
 
potentially contaminated adjacent areas, is periodically
 
tested to verify proper function of the CRAF System. During
 
the pressurization mode of operation, the CRAF System is
 
designed to slightly pressurize the control room area to 0.125 inches water gauge positive pressure with respect to adjacent areas to prevent unfiltered inleakage. The CRAF
 
System is designed to maintain this positive pressure at a
 
flow rate of  4000 cfm to the control room area in the pressurization mode. This test also requires manual
 
initiation of flow through the control room and AEER
 
recirculation filters line when the CRAF System is in the
 
pressurization mode of operation. The Frequency of
 
24 months is consistent with industry practice and other
 
filtration system SRs.
 
REFERENCES 1. UFSAR, Section 6.4.
: 2. UFSAR, Section 6.5.1.
: 3. UFSAR, Section 9.4.1.
: 4. UFSAR, Chapter 6.
: 5. UFSAR, Chapter 15.
: 6. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants," December 2002.
: 7. ANSI/ASME N510-1989.
 
Control Room Area Ventilation AC System B 3.7.5 LaSalle 1 and 2 B 3.7.5-1 Revision 0 B 3.7  PLANT SYSTEMS
 
B 3.7.5  Control Room Area Ventilation Air Conditioning (AC) System
 
BASES
 
BACKGROUND The Control Room Area Ventilation AC System provides temperature control for the control room area. The control
 
room area is comprised of the control room and the Auxiliary
 
Electric Equipment Rooms (AEERs).
The Control Room Area Ventilation AC System is comprised of
 
two independent, redundant subsystems that provide cooling
 
and heating of control room air and the auxiliary electric
 
equipment rooms air. Each Control Room Area Ventilation AC
 
subsystem consists of a Control Room AC subsystem and an
 
AEER AC subsystem. The associated Control Room AC and AEER
 
AC subsystems share a common outside air intake with a
 
common emergency makeup air filter unit. The Control Room
 
AC System is common to both units and serves the control
 
room, main security control center, and the control room
 
habitability storage room (toilet room). The AEER AC System
 
is common to both units and services the AEERs.
 
Each Control Room Area Ventilation AC subsystem is powered
 
from a Division 2 power source. One subsystem is powered
 
from Unit 1 Division 2 and the other subsystem is powered
 
from Unit 2 Division 2.
 
Each control room AC and AEER AC subsystem consists of a
 
supply air filter, supply and return air fans, direct
 
expansion cooling coils, an air-cooled condenser, a
 
refrigerant compressor and receiver, heating coils, ductwork, dampers, and instrumentation and controls to
 
provide temperature control for their respective areas. 
 
However, the heating coils are not safety related.
 
The Control Room Area Ventilation AC System is designed to
 
provide a controlled environment under both normal and
 
accident conditions. A single control room area ventilation
 
AC subsystem provides the required temperature control to
 
maintain a suitable control room and AEER environment for a
 
sustained occupancy of at least the required normal and
 
emergency shift crew complements. The design conditions for
 
(continued)
Control Room Area Ventilation AC System B 3.7.5 LaSalle 1 and 2 B 3.7.5-2 Revision 0 BASES BACKGROUND habitability of the control room and AEER environment are (continued) 65
&deg;F to 85&deg;F and a maximum of 50% relative humidity. The Control Room Area Ventilation AC System operation in
 
maintaining the temperatures of the control room and AEERs
 
is discussed in the UFSAR, Sections 6.4 and 9.4.1 (Refs. 1
 
and 2, respectively).
 
APPLICABLE The design basis of the Control Room Area Ventilation AC SAFETY ANALYSES System is to maintain temperatures of the control room and AEERs for a 30 day period after a Design Basis Accident (DBA). The Control Room Area Ventilation AC System components are
 
arranged in redundant safety related subsystems. During
 
emergency operation, the Control Room Area Ventilation AC
 
System maintains a habitable environment and ensures the
 
OPERABILITY of components in the control room and AEERs. A
 
single active failure of a component of the Control Room
 
Area Ventilation AC System, assuming a loss of offsite
 
power, does not impair the ability of the system to perform
 
its design function. Redundant detectors and controls are
 
provided for control room and AEERs temperature control. 
 
The Control Room Area Ventilation AC System is designed in
 
accordance with Seismic Category I requirements, with
 
exceptions described in UFSAR Section 9.4.1.1.1.1 (Ref. 3).
 
The Control Room Area Ventilation AC System is capable of
 
removing sensible and latent heat loads from the control
 
room and AEERs, including consideration of equipment heat
 
loads and personnel occupancy requirements to ensure
 
equipment OPERABILITY.
The Control Room Area Ventilation AC System satisfies
 
Criterion 3 of 10 CFR 50.36(c)(2)(ii).
 
LCO Two independent and redundant subsystems of the Control Room Area Ventilation AC System are required to be OPERABLE to
 
ensure that at least one subsystem is available, assuming a
 
single failure disables the other subsystem. Total system
 
failure could result in the equipment operating temperature
 
exceeding limits.
(continued)
Control Room Area Ventilation AC System B 3.7.5 LaSalle 1 and 2 B 3.7.5-3 Revision 0 BASES LCO The Control Room Area Ventilation AC System is considered (continued) OPERABLE when the individual components necessary to maintain the control room and AEERs temperatures are
 
OPERABLE in both subsystems. These components include the
 
supply and return air fans, direct expansion cooling coils, an air-cooled condenser, a refrigerant compressor and
 
receiver, ductwork, dampers, and instrumentation and
 
controls.
 
APPLICABILITY In MODE 1, 2, or 3, the Control Room Area Ventilation AC System must be OPERABLE to ensure that the control room and
 
AEERs temperatures will not exceed equipment OPERABILITY
 
limits during operation of the Control Room Area Filtration (CRAF) System in the pressurization mode.
In MODES 4 and 5, the probability and consequences of a
 
Design Basis Accident are reduced due to the pressure and
 
temperature limitations in these MODES. Therefore, maintaining the Control Room Area Ventilation AC System
 
OPERABLE is not required in MODE 4 or 5, except for the
 
following situations under which significant radioactive
 
releases can be postulated:
: a. During movement of irradiated fuel assemblies in the secondary containment;
: b. During CORE ALTERATIONS; and
: c. During operations with a potential for draining the reactor vessel (OPDRVs).
 
ACTIONS A.1 With one control room area ventilation AC subsystem
 
inoperable, the inoperable control room area ventilation AC
 
subsystem must be restored to OPERABLE status within
 
30 days. With the unit in this condition, the remaining
 
OPERABLE control room area ventilation AC subsystem is
 
adequate to perform the control room air conditioning
 
function. However, the overall reliability is reduced
 
because a single failure in the OPERABLE subsystem could
 
result in loss of the control room area ventilation air
 
conditioning function. The 30 day Completion Time is based (continued)
Control Room Area Ventilation AC System B 3.7.5 LaSalle 1 and 2 B 3.7.5-4 Revision 34 BASES ACTIONS A.1 (continued) on the low probability of an event occurring requiring
 
operation of the CRAF System in the pressurization mode and
 
the consideration that the remaining subsystem can provide
 
the required protection.
 
B.1 and B.2 If both control room area ventilation AC subsystems are inoperable, the control room area ventilation AC system may not be capable of performing its intended function.
Therefore, the control room area temperature is required to be monitored to ensure that temperature is being maintained low enough that equipment in the control room area is not adversely affected. With the control room area temperature being maintained within the temperature limit, 72 hours is allowed to restore a control room area ventilation AC subsystem to OPERABLE status. The Completion Time is reasonable considering that the control room area temperature is being maintained within limits and the low probability of an event occurring requiring control room area isolation.
 
C.1 In MODE 1, 2, or 3, if the inoperable control room area
 
ventilation AC subsystem(s) cannot be restored to OPERABLE status within the associated Completion Time, the unit must
 
be placed in a MODE that minimizes overall plant risk. To
 
achieve this status the unit must be placed in at least
 
MODE 3 within 12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is
 
similar to or lower than the risk in MODE 4 (Ref. 4) and
 
because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be
 
short. However, voluntary entry into MODE 4 may be made as
 
it is also an acceptable low-risk state.
The allowed Completion Time is reasonable, based on operating
 
experience, to reach the required unit conditions from full
 
power conditions in an orderly manner and without
 
challenging unit systems.
 
(continued)
 
Control Room Area Ventilation AC System B 3.7.5 LaSalle 1 and 2 B 3.7.5-5 Revision 34 BASES ACTIONS D.1, D.2.1, D.2.2, and D.2.3 (continued)
LCO 3.0.3 is not applicable while in MODE 4 or 5. However, since irradiated fuel assembly movement can occur in MODE 1, 2, or 3, the Required Actions of Condition D are modified by a Note indicating that LCO 3.0.3 does not apply. If moving
 
irradiated fuel assemblies while in MODE 1, 2, or 3, the
 
fuel movement is independent of reactor operations. 
 
Entering LCO 3.0.3 while in MODE 1, 2, or 3 would require
 
the unit to be shutdown, but would not require immediate
 
suspension of movement of irradiated fuel assemblies. The
 
Note to the ACTIONS, "LCO 3.0.3 is not applicable," ensures
 
that the actions for immediate suspension of irradiated fuel
 
assembly movement are not postponed due to entry into
 
LCO 3.0.3.
 
During movement of irradiated fuel assemblies in the
 
secondary containment, during CORE ALTERATIONS, or during
 
OPDRVs, if Required Action A.1 cannot be completed within
 
the required Completion Time, the OPERABLE control room AC
 
subsystem may be placed immediately in operation. 
 
This action ensures that the remaining subsystem is
 
OPERABLE, that no failures that would prevent actuation will
 
occur, and that any active failure will be readily detected.
 
An alternative to Required Action D.1 is to immediately suspend activities that present a potential for releasing
 
radioactivity that might require isolation of the control
 
room. This places the unit in a condition that minimizes
 
risk.
 
If applicable, CORE ALTERATIONS and movement of irradiated
 
fuel assemblies in the secondary containment must be
 
suspended immediately. Suspension of these activities shall
 
not preclude completion of movement of a component to a safe
 
position. Also, if applicable, action must be initiated
 
immediately to suspend OPDRVs to minimize the probability of
 
a vessel draindown and subsequent potential for fission
 
product release. Action must continue until the OPDRVs are
 
suspended.
(continued)
Control Room Area Ventilation AC System B 3.7.5 LaSalle 1 and 2 B 3.7.5-6 Revision 34 BASES ACTIONS E.1, E.2, and E.3 (continued)
The Required Actions of Condition E.1 are modified by a Note
 
indicating that LCO 3.0.3 does not apply. If moving
 
irradiated fuel assemblies while in MODE 1, 2, or 3, the
 
fuel movement is independent of reactor operations. 
 
Therefore, inability to suspend movement of irradiated fuel
 
assemblies is not sufficient reason to require a reactor
 
shutdown.
 
During movement of irradiated fuel assemblies in the
 
secondary containment, during CORE ALTERATIONS, or during
 
OPDRVs if Required Actions B.1 and B.2 cannot be met within the required Completion Times action must be taken to immediately suspend activities that present a potential for
 
releasing radioactivity that might require isolation of the
 
control room. This places the unit in a condition that
 
minimizes risk.
If applicable, CORE ALTERATIONS and handling of irradiated
 
fuel in the secondary containment must be suspended
 
immediately. Suspension of these activities shall not
 
preclude completion of movement of a component to a safe
 
position. Also, if applicable, action must be initiated
 
immediately to suspend OPDRVs to minimize the probability of
 
a vessel draindown and subsequent potential for fission
 
product release. Action must continue until the OPDRVs are
 
suspended.
 
SURVEILLANCE SR  3.7.5.1 REQUIREMENTS This SR monitors the control room and AEER temperatures for
 
indication of Control Room Area Ventilation AC System
 
performance. Trending of control room area temperature will
 
provide a qualitative assessment of refrigeration unit
 
OPERABILITY. Limiting the average temperature of the
 
Control Room and AEER to less than or equal to 85
&deg;F provides a threshold beyond which the operating control room area
 
ventilation AC subsystem is no longer demonstrating
 
capability to perform its function. This threshold provides
 
margin to temperature limits at which equipment
 
qualification requirements could be challenged. Subsystem
 
operation is routinely alternated to support planned
 
maintenance and to ensure each subsystem provides reliable
 
service. The 12 hour Frequency is adequate considering the
 
continuous manning of the control room by the operating
 
staff. (continued)
Control Room Area Ventilation AC System B 3.7.5 LaSalle 1 and 2 B 3.7.5-7 Revision 32 BASES SURVEILLANCE SR  3.7.5.2 REQUIREMENTS (continued) Verifying proper breaker alignment and power available to the control room area ventilation AC subsystems provides
 
assurance of the availability of the system function. The
 
7 day Frequency is appropriate in view of other
 
administrative controls that assure system availability.
 
REFERENCES 1. UFSAR, Section 6.4.
: 2. UFSAR, Section 9.4.1.
: 3. UFSAR, Section 9.4.1.1.1.1.
: 4. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants," December 2002.
 
Main Condenser Offgas B 3.7.6 LaSalle 1 and 2 B 3.7.6-1 Revision 0 B 3.7  PLANT SYSTEMS
 
B 3.7.6  Main Condenser Offgas
 
BASES
 
BACKGROUND During unit operation, steam from the low pressure turbine is exhausted directly into the main condenser. Air and
 
noncondensible gases are collected in the main condenser, then exhausted through the steam jet air ejectors (SJAEs) to
 
the Main Condenser Offgas System. The offgas from the main
 
condenser normally includes radioactive gases.
The Main Condenser Offgas System has been incorporated into
 
the unit design to reduce the gaseous radwaste emission.
 
This system uses a catalytic recombiner to recombine
 
radiolytically dissociated hydrogen and oxygen. The gaseous
 
mixture is cooled by the offgas condenser; the water and
 
condensibles are stripped out by the offgas condenser and
 
water separator. The radioactivity of the remaining gaseous
 
mixture (i.e., the offgas recombiner effluent) is monitored
 
downstream of the water separator prior to entering the
 
holdup line.
 
APPLICABLE The main condenser offgas gross gamma activity rate is an SAFETY ANALYSES initial condition of the Main Condenser Offgas System failure event as discussed in the UFSAR, Section 15.7.1.1 (Ref. 1). The analysis assumes a gross failure in the Main
 
Condenser Offgas System that results in the rupture of the
 
Main Condenser Offgas System pressure boundary. The gross
 
gamma activity rate is controlled to ensure that during the
 
event, the calculated offsite doses will be well within the
 
limits of 10 CFR 100 (Ref. 2).
The main condenser offgas limits satisfy Criterion 2 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO To ensure compliance with the assumptions of the Main Condenser Offgas System failure event (Ref. 1), the fission
 
product release rate should be consistent with a noble gas
 
release to the reactor coolant of 100
&#xb5;Ci/Mwt-second after decay of 30 minutes. The LCO is conservatively established
 
based on the safety analysis discussed in Reference 1.
(continued)
Main Condenser Offgas B 3.7.6 LaSalle 1 and 2 B 3.7.6-2 Revision 32 BASES  (continued)
 
APPLICABILITY The LCO is applicable when steam is being exhausted to the main condenser and the resulting noncondensibles are being
 
processed via the Main Condenser Offgas System. This occurs
 
during MODE 1, and during MODES 2 and 3 with any main steam
 
line not isolated and the SJAE in operation. In MODES 4
 
and 5, main steam is not being exhausted to the main
 
condenser and the requirements are not applicable.
 
ACTIONS A.1 If the offgas radioactivity rate limit is exceeded, 72 hours
 
is allowed to restore the gross gamma activity rate to
 
within the limit. The 72 hour Completion Time is
 
reasonable, based on engineering judgment considering the
 
time required to complete the Required Action, the large
 
margins associated with permissible dose and exposure
 
limits, and the low probability of a Main Condenser Offgas
 
System rupture occurring.
 
B.1, B.2 and B.3
 
If the gross gamma activity rate is not restored to within
 
the limits within the associated Completion Time, all main
 
steam lines or the SJAE must be isolated. This isolates the
 
Main Condenser Offgas System from significant sources of
 
radioactive steam. The main steam lines are considered
 
isolated if at least one main steam isolation valve in each
 
main steam line is closed, and at least one main steam line
 
drain valve in each drain line is closed. The 12 hour
 
Completion Time is reasonable, based on operating
 
experience, to perform the actions from full power
 
conditions in an orderly manner and without challenging unit
 
systems.
 
An alternative to Required Actions B.1 and B.2 is to place
 
the unit in a MODE in which the overall plant risk is minimized. To achieve this status, the unit must be placed in at least MODE 3 within 12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to (continued)
Main Condenser Offgas B 3.7.6 LaSalle 1 and 2 B 3.7.6-3 Revision 32 BASES ACTIONS B.1, B.2 and B.3 (continued)
OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
The allowed Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner
 
and without challenging unit systems.
SURVEILLANCE SR  3.7.6.1 REQUIREMENTS This SR, on a 31 day Frequency, requires an isotopic
 
analysis of a representative offgas sample taken prior to
 
the holdup line to ensure that the required limits are
 
satisfied. The noble gases to be sampled are Xe-133, Xe-135, Xe-135m, Xe-138, Kr-85m, Kr-87, and Kr-88. If the
 
measured rate of radioactivity increases significantly (by 50% after correcting for expected increases due to changes in THERMAL POWER), an isotopic analysis is also performed
 
within 4 hours after the increase is noted (as indicated by
 
the offgas pre-treatment noble gas activity monitor), to
 
ensure that the increase is not indicative of a sustained
 
increase in the radioactivity rate. The 31 day Frequency is
 
adequate in view of other instrumentation that continuously
 
monitor the offgas, and is acceptable based on operating
 
experience.
 
This SR is modified by a Note indicating that the SR is not
 
required to be performed until 31 days after any main steam
 
line is not isolated and the SJAE is in operation. Only in
 
this condition can radioactive fission gases be in the Main
 
Condenser Offgas System at significant rates.
 
REFERENCES 1. UFSAR, Section 15.7.1.
: 2. 10 CFR 100.
: 3. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants," December 2002.
 
Main Turbine Bypass System B 3.7.7 LaSalle 1 and 2 B 3.7.7-1 Revision 0 B 3.7  PLANT SYSTEMS
 
B 3.7.7  Main Turbine Bypass System
 
BASES
 
BACKGROUND The Main Turbine Bypass System is designed to control steam pressure when reactor steam generation exceeds turbine
 
requirements during unit startup, sudden load reduction, and
 
cooldown. It allows excess steam flow from the reactor to
 
the condenser without going through the turbine. The bypass
 
capacity of the system is approximately 25% of the Nuclear
 
Steam Supply System rated steam flow. Sudden load
 
reductions within the capacity of the steam bypass can be
 
accommodated without reactor scram. The Main Turbine Bypass
 
System consists of five valves mounted on a valve manifold
 
connected to the main steam lines between the main steam
 
isolation valves and the main turbine stop valves. Each of
 
these valves is sequentially operated by hydraulic
 
cylinders. The bypass valves are controlled by the pressure
 
regulation function of the Turbine Electro Hydraulic Control
 
System, as discussed in the UFSAR, Section 7.7.5.2 (Ref. 1).
 
The bypass valves are normally closed, and the pressure
 
regulator controls the turbine control valves, directing all
 
steam flow to the turbine. If the speed governor or the
 
load limiter restricts steam flow to the turbine, the
 
pressure regulator controls the system pressure by opening
 
the bypass valves. When the bypass valves open, the steam
 
flows from the bypass valve outlet manifold, through
 
connecting piping, to the pressure breakdown assemblies, where a series of orifices are used to further reduce the
 
steam pressure before the steam enters the condenser (Ref. 2).
 
APPLICABLE The Main Turbine Bypass System is assumed to function during SAFETY ANALYSES the turbine trip, turbine generator load rejection, and feedwater controller failure maximum demand transients, described in the UFSAR, Sections 15.2.3, 15.2.2A, and
 
15.1.2A (Refs. 3, 4, and 5, respectively). Opening the
 
bypass valves during the pressurization event mitigates the
 
increase in reactor vessel pressure, which affects the MCPR
 
during the event. An inoperable Main Turbine Bypass System
 
may result in an MCPR penalty.
The Main Turbine Bypass System satisfies Criterion 3 of
 
10 CFR 50.36(c)(2)(ii)
 
(continued)
Main Turbine Bypass System B 3.7.7 LaSalle 1 and 2 B 3.7.7-2 Revision 0 BASES  (continued)
 
LCO The Main Turbine Bypass System is required to be OPERABLE to limit peak pressure in the main steam lines and maintain
 
reactor pressure within acceptable limits during events that
 
cause rapid pressurization, such that the Safety Limit MCPR
 
is not exceeded. With the Main Turbine Bypass System
 
inoperable, modifications to the MCPR limits (LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)") may be applied to
 
allow continued operation.
An OPERABLE Main Turbine Bypass System requires the bypass
 
valves to open in response to increasing main steam line
 
pressure. This response is within the assumptions of the
 
applicable analysis (Refs. 3, 4, and 5). The MCPR limit for
 
the inoperable Main Turbine Bypass System is specified in
 
the COLR.
 
APPLICABILITY The Main Turbine Bypass System is required to be OPERABLE at  25% RTP to ensure that the fuel cladding integrity Safety Limit is not violated during the turbine trip, feedwater
 
controller failure maximum demand, and turbine generator
 
load rejection transients. As discussed in the Bases for
 
LCO 3.2.2 sufficient margin to these limits exists
 
< 25% RTP. Therefore, these requirements are only necessary
 
when operating at or above this power level.
 
ACTIONS A.1 If the Main Turbine Bypass System is inoperable (one or more
 
bypass valves inoperable), and the MCPR limits for an
 
inoperable Main Turbine Bypass System, as specified in the
 
COLR, are not applied, the assumptions of the design basis
 
transient analysis may not be met. Under such
 
circumstances, prompt action should be taken to restore the
 
Main Turbine Bypass System to OPERABLE status or adjust the
 
MCPR limits accordingly. The 2 hour Completion Time is
 
reasonable, based on the time to complete the Required
 
Action and the low probability of an event occurring during
 
this period requiring the Main Turbine Bypass System.
 
(continued)
Main Turbine Bypass System B 3.7.7 LaSalle 1 and 2 B 3.7.7-3 Revision 12 BASES ACTIONS B.1 (continued)
If the Main Turbine Bypass System cannot be restored to
 
OPERABLE status and the MCPR limits for an inoperable Main
 
Turbine Bypass System are not applied, THERMAL POWER must be
 
reduced to < 25% RTP. As discussed in the Applicability
 
section, operation at < 25% RTP results in sufficient margin
 
to the required limits, and the Main Turbine Bypass System
 
is not required to protect fuel integrity during the turbine
 
trip, turbine generator load rejection, and feedwater
 
controller failure maximum demand transients. The 4 hour
 
Completion Time is reasonable, based on operating
 
experience, to reach the required unit conditions from full
 
power conditions in an orderly manner and without
 
challenging unit systems.
 
SURVEILLANCE SR  3.7.7.1 REQUIREMENTS Cycling each main turbine bypass valve through one complete
 
cycle of full travel demonstrates that the valves are
 
mechanically OPERABLE and will function when required. The
 
31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve
 
operation, and ensures correct valve positions. Operating experience has shown that these components usually pass the SR when performed at the 31 day frequency. Therefore, the Frequency is acceptable from a reliability standpoint.
 
SR  3.7.7.2
 
The Main Turbine Bypass System is required to actuate
 
automatically to perform its design function. This SR
 
demonstrates that, with the required simulated system
 
initiation signals, the valves will actuate to their
 
required position. The 24 month Frequency is based on the
 
need to perform this Surveillance under conditions that
 
apply during a unit outage and because of the potential for
 
an unplanned transient if the Surveillance were performed
 
with the reactor at power. Operating experience has shown
 
that these components usually pass the SR when performed at
 
the 24 month Frequency, which is based on the refueling
 
cycle. Therefore, the Frequency was concluded to be
 
acceptable from a reliability standpoint.
(continued)
Main Turbine Bypass System B 3.7.7 LaSalle 1 and 2 B 3.7.7-4 Revision 0 BASES SURVEILLANCE SR  3.7.7.3 REQUIREMENTS (continued) This SR ensures that the TURBINE BYPASS SYSTEM RESPONSE TIME, as defined in the transient analysis inputs for the
 
cycle, is in compliance with the assumptions of the
 
appropriate safety analyses. The response time limits are
 
specified in the Technical Requirements Manual (Ref. 6). 
 
The 24 month Frequency is based on the need to perform this
 
Surveillance under conditions that apply during a unit
 
outage and because of the potential for an unplanned
 
transient if the Surveillance were performed with the
 
reactor at power. Operating experience has shown that these
 
components usually pass the SR when performed at the 24
 
month Frequency, which is based on the refueling cycle.
 
Therefore, the Frequency was concluded to be acceptable from
 
a reliability standpoint.
 
REFERENCES 1. UFSAR, Section 7.7.5.2.
: 2. UFSAR, Section 10.4.4.
: 3. UFSAR, Section 15.2.3.
: 4. UFSAR, Section 15.2.2A.
: 5. UFSAR, Section 15.1.2A.
: 6. Technical Requirements Manual.
 
Spent Fuel Storage Pool Water Level B 3.7.8 LaSalle 1 and 2 B 3.7.8-1 Revision 0 B 3.7  PLANT SYSTEMS
 
B 3.7.8  Spent Fuel Storage Pool Water Level
 
BASES
 
BACKGROUND The minimum water level in the spent fuel storage pool meets the assumptions of iodine decontamination factors following
 
a fuel handling accident.
A general description of the spent fuel storage pool design
 
is found in the UFSAR, Section 9.1.2 (Ref. 1). The
 
assumptions of the fuel handling accident are found in the
 
UFSAR, Sections 9.1.2 and 15.7.4 (Refs. 1 and 2, respectively).
 
APPLICABLE The water level above the irradiated fuel assemblies is an SAFETY ANALYSES explicit assumption of the fuel handling accident (Ref. 2).
A fuel handling accident is evaluated to ensure that the
 
radiological consequences (calculated whole body and thyroid
 
doses at the exclusion area and low population zone
 
boundaries) are  25% (NUREG-0800, Section 15.7.4, Ref. 3) of the 10 CFR 100 (Ref. 4) exposure guidelines. A fuel
 
handling accident could release a fraction of the fission
 
product inventory by breaching the fuel rod cladding as
 
discussed in the Regulatory Guide 1.25 (Ref. 5).
The fuel handling accident is evaluated for the dropping of
 
an irradiated fuel assembly onto the reactor core. The
 
consequences of a fuel handling accident over the spent fuel
 
storage pool are less severe than those of the fuel handling
 
accident over the reactor core (Ref. 2). The water level in
 
the spent fuel storage pool provides for absorption of water
 
soluble fission product gases and transport delays of
 
soluble and insoluble gases that must pass through the water
 
before being released to the secondary containment
 
atmosphere. This absorption and transport delay reduces the
 
potential radioactivity of the release during a fuel
 
handling accident.
The spent fuel storage pool water level satisfies
 
Criterion 2 of 10 CFR 50.36(c)(2)(ii).
 
(continued)
Spent Fuel Storage Pool Water Level B 3.7.8 LaSalle 1 and 2 B 3.7.8-2 Revision 0 BASES  (continued)
 
LCO The specified water level preserves the assumption of the fuel handling accident analysis (Ref. 2). As such, it is
 
the minimum required for fuel movement within the spent fuel
 
storage pool.
 
APPLICABILITY This LCO applies whenever movement of irradiated fuel assemblies occurs in the spent fuel storage pool or whenever
 
movement of new fuel assemblies occurs in the spent fuel
 
storage pool with irradiated fuel assemblies seated in the
 
spent fuel storage pool, since the potential for a release
 
of fission products exists.
 
ACTIONS A.1 Required Action A.1 is modified by a Note indicating that
 
LCO 3.0.3 does not apply. If moving fuel assemblies while
 
in MODE 1, 2, or 3, the fuel movement is independent of
 
reactor operations. Therefore, inability to suspend
 
movement of fuel assemblies is not a sufficient reason to
 
require a reactor shutdown.
 
When the initial conditions for an accident cannot be met, steps should be taken to preclude the accident from
 
occurring. With the spent fuel storage pool level less than
 
required, the movement of fuel assemblies in the spent fuel
 
storage pool is suspended immediately. Suspension of this
 
activity shall not preclude completion of movement of a fuel
 
assembly to a safe position. This effectively precludes a
 
spent fuel handling accident from occurring.
 
SURVEILLANCE SR  3.7.8.1 REQUIREMENTS This SR verifies that sufficient water is available in the
 
event of a fuel handling accident. The water level in the
 
spent fuel storage pool must be checked periodically. The
 
7 day Frequency is acceptable, based on operating
 
experience, considering that the water volume in the pool is
 
normally stable and water level changes are controlled by
 
unit procedures.
 
(continued)
Spent Fuel Storage Pool Water Level B 3.7.8 LaSalle 1 and 2 B 3.7.8-3 Revision 0 BASES  (continued)
 
REFERENCES 1. UFSAR, Section 9.1.2.
: 2. UFSAR, Section 15.7.4.
: 3. NUREG-0800, Section 15.7.4, Revision 1, July 1981.
: 5. 10 CFR 100.
: 6. Regulatory Guide 1.25, March 1972.
 
AC Sources-Operating B 3.8.1 LaSalle 1 and 2 B 3.8.1-1 Revision 19 B 3.8  ELECTRICAL POWER SYSTEMS
 
B 3.8.1  AC Sources-Operating
 
BASES
 
BACKGROUND The unit Class 1E AC Electrical Power Distribution System AC sources consist of the offsite power sources and the onsite
 
standby power sources (diesel generators (DGs)). As
 
required by 10 CFR 50, Appendix A, GDC 17 (Ref. 1), the
 
design of the AC electrical power system provides
 
independence and redundancy to ensure an available source of
 
power to the Engineered Safety Feature (ESF) systems.
 
The Class 1E AC distribution system supplies electrical
 
power to three divisional load groups, Divisions 1, 2, and
 
3, with each division powered by an independent Class 1E
 
4.16 kV emergency bus (refer to LCO 3.8.7, "Distribution
 
Systems-Operating"). The Division 2 emergency bus
 
associated with each unit is shared by each unit since some
 
systems are common to both units. The opposite unit
 
Division 2 emergency bus supports equipment required to be
 
OPERABLE by LCO 3.6.4.3, "Standby Gas Treatment (SGT)
System," LCO 3.7.4, "Control Room Area Filtration (CRAF)
 
System," and LCO 3.7.5, "Control Room Area Ventilation Air
 
Conditioning (AC) System." Division 1 and 2 emergency buses
 
have access to two offsite power supplies (one normal and
 
one alternate). The alternate offsite power source is
 
normally supplied via the opposite unit system auxiliary
 
transformer (SAT) and the opposite unit circuit path. The
 
alternate offsite circuit path includes the associated
 
opposite unit's 4.16 kV emergency bus, unit tie breakers, and associated interconnecting bus to the given unit's
 
4.16 kV emergency bus. Division 3 load group has access to
 
one offsite power supply (respective unit's SAT). Division
 
2 and 3 emergency buses on each unit have a dedicated onsite
 
DG. The Division 1 emergency bus of both units share a
 
common DG. The ESF systems of any two of the three
 
divisions provide for the minimum safety functions necessary
 
to shut down the unit and maintain it in a safe shutdown
 
condition.
 
Offsite power is supplied to the switchyard from the
 
transmission network. From the switchyard two electrically (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-2 Revision 0 BASES BACKGROUND and physically separated circuits provide AC power to the (continued) unit onsite Class 1E 4.16 kV emergency buses. The unit SAT provides the normal source of offsite power to the
 
respective unit's Division 1, 2, and 3 4.16 kV emergency
 
buses. In the event of a loss of unit SAT, the Division 1
 
and 2 emergency buses fast transfer to the UAT (which is
 
connected to the main generator output). The UAT is rated
 
to carry all onsite power to the unit, but is not considered
 
an offsite source unless it is being backfed with the main
 
generator disconnect links removed. The Division 3
 
emergency bus has no second offsite power source, and will
 
automatically be supplied by the Division 3 DG after the bus
 
is deenergized. The Division 1 and 2 emergency buses can be
 
manually transferred to the alternate offsite power source
 
through the unit ties on a dead bus transfer or on a live
 
bus transfer if the DG is supplying power to the bus. The
 
offsite AC electrical power sources are designed and located
 
so as to minimize to the extent practical the likelihood of
 
their simultaneous failure under operating and postulated
 
accident and environmental conditions. A detailed
 
description of the offsite power network and circuits to the
 
onsite Class 1E 4.16 kV emergency buses is found in UFSAR, Chapter 8 (Ref. 2).
 
A qualified offsite circuit consists of all breakers, transformers, switches, interrupting devices, cabling, and
 
controls required to transmit power from the offsite
 
transmission network to the onsite Class 1E emergency buses.
 
Onsite standby power is provided by a total of five DGs for
 
both units. The onsite standby power source for each
 
Division 2 and 3 4.16 kV emergency bus on each unit is a
 
dedicated DG.  (DGs 1A and 1B for Unit 1 and DGs 2A and 2B
 
for Unit 2). The onsite standby power source for the
 
Division 1 emergency bus on each unit is a common DG (DG 0).
 
Each DG will start on emergency bus degraded voltage or
 
undervoltage from its associated 4.16 kV emergency bus (refer to LCO 3.3.8.1, "Loss of Power (LOP)
 
Instrumentation"). The Division 2 and 3 DGs will start on
 
an Emergency Core Cooling System (ECCS) actuation signal (reactor vessel low water level or high drywell pressure)
 
from the respective unit. The Division 1 DG (common DG)
 
will start on an ECCS actuation signal (reactor vessel low (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-3 Revision 0 BASES BACKGROUND water level or high drywell pressure) from either unit. 
  (continued) Although the DGs start on an ECCS actuation signal from the respective unit, the DGs are not connected to the 4.16 kV
 
emergency bus unless an undervoltage condition occurs on the
 
bus.
 
In the event of a loss of offsite power, the ESF electrical
 
loads are automatically connected to the DGs, as required, in sufficient time to provide for safe reactor shutdown and
 
to mitigate the consequences of a Design Basis Accident (DBA) such as a loss of coolant accident (LOCA).
 
If an undervoltage condition occurs on a Division 1 or 2
 
emergency bus, the associated DG starts, bus loads are shed, the DG will automatically connect to the emergency bus, and
 
loads necessary for safe shutdown of the unit are connected
 
automatically or manually. If an ECCS actuation signal is
 
present concurrent with an undervoltage condition on the
 
Division 1 or 2 emergency bus, the associated DG starts, bus
 
loads are shed as required, the DG will automatically
 
connect to the emergency bus, and the required ESF loads are
 
automatically connected. Sequencing of Division 1 and 2
 
emergency loads is accomplished by time delay relays so that
 
overloading of the DG is prevented. The Division 3
 
emergency bus has no shedding or sequencing.
 
The DGs satisfy the following Regulatory Guide 1.9 (Ref. 3)
 
ratings:  a. 2600 kW - continuous;
: b. 2860 kW - 2000 hour;
: c. 2987 kW - 7 day;
: d. 2860 kW - 2 hours in any 24 hour period (10%
overload); and
: e. 3040 kW - 30 minute.
 
APPLICABLE The initial conditions of DBA and transient analyses in the SAFETY ANALYSES UFSAR, Chapter 6 (Ref. 4) and Chapter 15 (Ref. 5), assume ESF systems are OPERABLE. The AC electrical power sources (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-4 Revision 19 BASES APPLICABLE are designed to provide sufficient capacity, capability, SAFETY ANALYSES redundancy, and reliability to ensure the availability of (continued) necessary power to ESF systems so that the fuel, Reactor Coolant System (RCS), and containment design limits are not
 
exceeded. These limits are discussed in more detail in the
 
Bases for Section 3.2, Power Distribution Limits;
 
Section 3.5, Emergency Core Cooling System (ECCS) and
 
Reactor Core Isolation Cooling (RCIC) System; and
 
Section 3.6, Containment Systems.
 
The OPERABILITY of the AC electrical power sources is
 
consistent with the initial assumptions of the accident
 
analyses and is based upon meeting the design basis of the
 
unit. This includes maintaining the onsite or offsite AC
 
sources OPERABLE during accident conditions in the event of:
: a. An assumed loss of all offsite power or all onsite AC power; and 
: b. A worst case single failure.
 
AC sources satisfy the requirements of Criterion 3 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO Two qualified circuits (normal and alternate) between the offsite transmission network and the onsite Class 1E
 
Distribution System (i.e., the unit Division 1, 2, and 3
 
4.16 kV emergency buses and the opposite unit Division 2
 
4.16 kV emergency bus), three separate and independent unit
 
DGs, and the opposite unit's DG capable of supporting the
 
opposite unit Division 2 onsite Class 1E AC electrical power
 
distribution subsystem to power the equipment required to be
 
OPERABLE by LCO 3.6.4.3, LCO 3.7.4, and LCO 3.7.5 ensure availability of the required power to shut down the reactor
 
and maintain it in a safe shutdown condition after an
 
anticipated operational occurrence (AOO) or a postulated
 
DBA. A specific LCO requirement for a qualified circuit to
 
provide power to the opposite unit Division 2 4.16 kV
 
emergency bus is not provided since the alternate qualified
 
circuit to the units Division 2 4.16 kV emergency bus
 
encompasses the circuit path to the opposite unit Division 2
 
4.16 kV emergency bus.
 
Qualified offsite circuits are those that are described in
 
the UFSAR and are part of the licensing basis for the unit.
(continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-5 Revision 0 BASES LCO Each offsite circuit must be capable of maintaining rated (continued) frequency and voltage, and accepting required loads during an accident, while connected to the emergency buses. For
 
the normal offsite circuit, the OPERABLE qualified offsite
 
circuit consists of the required incoming breaker(s) and
 
disconnects from the 345 kV switchyard to and including the
 
SAT, the respective circuit path to and including the feeder
 
breakers to the required unit Division 1, 2, and 3 4.16 kV
 
emergency buses.
 
For the alternate offsite circuit, the OPERABLE qualified
 
offsite circuit consists of the required incoming breaker(s)
 
and disconnects from the 345 kV switchyard to and including
 
the SAT or UAT (backfeed mode), to and including the
 
opposite unit 4.16 kV emergency bus, the opposite unit
 
circuit path to and including the unit tie breakers (breakers 1414, 1424, 2414, 2424), and the respective
 
circuit path to the required Division 1 and 2 4.16 kV
 
emergency buses.
 
Each unit DG must be capable of starting, accelerating to
 
rated speed and voltage, and connecting to its respective
 
ESF bus on detection of bus undervoltage. This sequence
 
must be accomplished within 13 seconds. Each DG must also
 
be capable of accepting required loads within the assumed
 
loading sequence intervals, and must continue to operate
 
until offsite power can be restored to the 4.16 kV emergency
 
buses. These capabilities are required to be met from a
 
variety of initial conditions such as DG in standby with
 
engine hot and DG in standby with engine at ambient
 
conditions. Additional DG capabilities must be demonstrated
 
to meet required Surveillances, e.g., capability of the
 
Division 1 and 2 DGs to revert to standby status on an ECCS
 
signal while operating in parallel test mode. Proper
 
sequencing of loads, including tripping of nonessential
 
loads, is a required function for DG OPERABILITY.
 
The opposite unit's DG must be capable of starting, accelerating to rated speed and voltage, and connecting to
 
the opposite unit's Division 2 Class 1E AC electrical power
 
distribution subsystem on detection of bus undervoltage.
 
This sequence must be accomplished within 13 seconds and is
 
required to be met from the same variety of initial
 
conditions specified for the unit DGs.
(continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-6 Revision 0 BASES LCO In addition, day tank storage and fuel oil transfer system (continued) requirements must be met for each required DG.
 
The AC sources in one division must be separate and
 
independent (to the extent possible) of the AC sources in
 
the other division(s). For the DGs, the separation and
 
independence are complete. For the offsite AC sources, the
 
separation and independence are to the extent practical. A
 
qualified circuit may be connected to all divisions of
 
either unit, with manual transfer capability to the other
 
circuit OPERABLE, and not violate separation criteria. A
 
qualified circuit that is not connected to the 4.16 kV
 
emergency buses is required to have OPERABLE manual transfer
 
capability (from the control room) to the associated 4.16 kV
 
emergency buses to support OPERABILITY of that qualified
 
circuit.
APPLICABILITY The AC sources are required to be OPERABLE in MODES 1, 2, and 3 to ensure that:
: a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result
 
of AOOs or abnormal transients; and
: b. Adequate core cooling is provided and containment OPERABILITY and other vital functions are maintained
 
in the event of a postulated DBA.
Note 1 has been added taking exception to the Applicability requirements for Division 3 sources, provided the High
 
Pressure Core Spray (HPCS) System is declared inoperable.
 
This exception is intended to allow declaring of the
 
Division 3 inoperable either in lieu of declaring the
 
Division 3 source inoperable, or at any time subsequent to
 
entering ACTIONS for an inoperable Division 3 source. This
 
exception is acceptable since, with the Division 3
 
inoperable and the associated ACTIONS entered, the
 
Division 3 AC sources provide no additional assurance of
 
meeting the above criteria. In addition, when this Note
 
allowance is being used, both AC sources could be inoperable
 
such that the Division 3 AC distribution subsystem is de-
 
energized. In this case (the Division 3 AC electrical power
 
distribution subsystem inoperable), LCO 3.0.6 would not
 
preclude entry into the Distribution System ACTIONS since, with the Division 3 AC sources not required OPERABLE as (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-7 Revision 19 BASES APPLICABILITY allowed by this Note, the Division 3 AC sources cannot be (continued) considered as a support system to the Division 3 AC distribution subsystem. Thus, as required by LCO 3.0.2, the
 
Distribution System-Operating ACTIONS for the inoperable
 
Division 3 AC electrical power distribution subsystem must
 
be entered.
 
Note 2 has been added taking exception to the Applicability
 
requirements for the required opposite unit's Division 2 DG
 
in LCO 3.8.1.c, provided the associated required equipment
 
is inoperable (i.e., one SGT subsystem, one control room area filtration subsystem, and one control room area
 
ventilation air conditioning subsystem). This exception is
 
intended to allow declaring the opposite unit's Division 2
 
supported equipment inoperable either in lieu of declaring
 
the opposite unit's Division 2 DG inoperable, or at any time
 
subsequent to entering ACTIONS for an inoperable opposite
 
unit Division 2 DG. This exception is acceptable since, with the opposite unit powered Division 2 equipment
 
inoperable and the associated ACTIONS entered, the opposite
 
unit Division 2 DG provides no additional assurance of
 
meeting the above criteria.
 
AC power requirements for MODES 4 and 5 and other conditions
 
in which AC sources are required are covered in LCO 3.8.2, "AC Sources-Shutdown."
ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable DG. There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable DG and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in in this circumstance.
A.1 To ensure a highly reliable power source remains, it is
 
necessary to verify the availability of the remaining
 
required offsite circuits on a more frequent basis. Since
 
the Required Action only specifies "perform," a failure of
 
SR 3.8.1.1 acceptance criteria does not result in the
 
Required Action not met. However, if a second required
 
circuit fails SR 3.8.1.1, the second offsite circuit is (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-8 Revision 19 BASES
 
ACTIONS A.1 (continued) inoperable, and Condition D, for two required offsite
 
circuits inoperable, is entered.
 
A.2 Required Action A.2, which only applies if the division
 
cannot be powered from an offsite source, is intended to
 
provide assurance that an event with a coincident single
 
failure of the associated DG does not result in a complete
 
loss of safety function of critical systems. These features
 
are designed with redundant safety related divisions (i.e.,
single division systems are not included, although, for this
 
Required Action, Division 3 (HPCS System) is considered
 
redundant to Division 1 and 2 ECCS). Redundant required
 
features failures consist of inoperable features associated
 
with a division redundant to the division that has no
 
offsite power available.
 
The Completion Time for Required Action A.2 is intended to
 
allow time for the operator to evaluate and repair any
 
discovered inoperabilities. This Completion Time also
 
allows for an exception to the normal "time zero" for
 
beginning the allowed outage time "clock."  In this Required
 
Action, the Completion Time only begins on discovery that
 
both:  a. The division has no offsite power available to supply its loads; and
: b. A redundant required feature on another division is inoperable.
 
If, at any time during the existence of this Condition (one
 
required offsite circuit inoperable), a redundant required
 
feature subsequently becomes inoperable, this Completion
 
Time begins to be tracked.
 
Discovering no offsite power available to one division of
 
the onsite Class 1E Power Distribution System coincident
 
with one or more inoperable redundant required support or
 
supported features, or both, that are associated with the
 
other division that has offsite power, results in starting
 
the Completion Time for the Required Action. 
 
Twenty-four hours is acceptable because it minimizes risk (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-9 Revision 19 BASES ACTIONS A.2 (continued) while allowing time for restoration before the unit is
 
subjected to transients associated with shutdown.
 
The remaining OPERABLE offsite circuit and DGs are adequate
 
to supply electrical power to the onsite Class 1E
 
Distribution System. Thus, on a component basis, single
 
failure protection may have been lost for the required
 
feature's function; however, function is not lost. The
 
24 hour Completion Time takes into account the component
 
OPERABILITY of the redundant counterpart to the inoperable
 
required feature. Additionally, the 24 hour Completion Time
 
takes into account the capacity and capability of the
 
remaining AC sources, a reasonable time for repairs, and the
 
low probability of a DBA occurring during this period.
 
A.3 According to Regulatory Guide 1.93 (Ref. 6), operation may
 
continue in Condition A for a period that should not exceed
 
72 hours.
 
With one required offsite circuit inoperable, the
 
reliability of the offsite system is degraded, and the
 
potential for a loss of offsite power is increased, with
 
attendant potential for a challenge to the plant safety
 
systems. In this condition, however, the remaining OPERABLE
 
offsite circuit and DGs are adequate to supply electrical
 
power to the onsite Class 1E distribution system.
 
The Completion Time takes into account the capacity and
 
capability of the remaining AC sources, reasonable time for
 
repairs, and the low probability of a DBA occurring during
 
this period.
 
The second Completion Time for Required Action A.3
 
establishes a limit on the maximum time allowed for any
 
combination of required AC power sources to be inoperable
 
during any single contiguous occurrence of failing to meet
 
the LCO. If Condition A is entered while, for instance, the
 
common DG is inoperable and that DG is subsequently returned
 
OPERABLE, the LCO may already have been not met for up to 14
 
days. This situation could lead to a total of 17 days, since initial failure to meet the LCO, to restore the
 
offsite circuit. At this time, a unit DG could again become
 
inoperable, the circuit restored OPERABLE, and an additional  (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-10 Revision 19 BASES ACTIONS A.3 (continued) 14 days (for a total of 31 days) allowed prior to complete
 
restoration of the LCO. The 17 day Completion Time provides
 
a limit on the time allowed in a specified condition after
 
discovery of failure to meet LCO 3.8.1.a or b. This limit
 
is considered reasonable for situations in which Conditions 
 
are entered concurrently for combinations of Conditions A, B, and C. The "AND" connector between the 72 hour and 17 day Completion Times means that both Completion Times apply
 
simultaneously, and the more restrictive must be met.
 
Similar to Required Action A.2, the Completion Time of
 
Required Action A.3 allows for an exception to the normal "time zero" for beginning the allowed outage time "clock."
This exception results in establishing the "time zero" at
 
the time LCO 3.8.1.a or b was initially not met, instead of
 
at the time that Condition A was entered.
 
B.1 To ensure a highly reliable power source remains, it is
 
necessary to verify the availability of the remaining
 
required offsite circuit on a more frequent basis. Since
 
the Required Action only specifies "perform," a failure of
 
SR 3.8.1.1 acceptance criteria does not result in a Required
 
Action being not met. However, if a circuit fails to pass
 
SR 3.8.1.1, it is inoperable. Upon offsite circuit
 
inoperability, additional Conditions must then be entered.
B.2 Required Action B.2 is intended to provide assurance that a
 
loss of offsite power, during the period that the DG is
 
inoperable as described in Condition B, does not result in a
 
complete loss of safety function of critical systems. These
 
features are designed with redundant safety related
 
divisions (i.e., single division systems are not included, although, for this Required Action, Division 3 (HPCS System)
 
is considered redundant to Division 1 and 2 ECCS). 
 
Redundant required features failures consist of inoperable
 
features associated with a division redundant to the
 
division that has an inoperable DG.
The Completion Time is intended to allow the operator time
 
to evaluate and repair any discovered inoperabilities. This
 
Completion Time also allows for an exception to the normal  (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-11 Revision 19 BASES ACTIONS B.2 (continued)
"time zero" for beginning the allowed outage time "clock."
In this Required Action, the Completion Time only begins on
 
discovery that both:
: a. An inoperable DG exists; and
: b. A redundant required feature on another division is inoperable.
If, at any time during the existence of this Condition (DG
 
inoperable as described in Condition B), a redundant
 
required feature subsequently becomes inoperable, this
 
Completion Time begins to be tracked.
Discovering required DG(s) inoperable coincident with one or
 
more redundant required support or supported features, or 
 
both, that are associated with the redundant OPERABLE DG(s),
results in starting the Completion Time for the Required
 
Action. Four hours from the discovery of these events
 
existing concurrently is acceptable because it minimizes
 
risk while allowing time for restoration before subjecting
 
the unit to transients associated with shutdown.
The remaining OPERABLE DGs and offsite circuits are adequate
 
to supply electrical power to the onsite Class 1E
 
Distribution System. Thus, on a component basis, single
 
failure protection for the required feature's function may
 
have been lost; however, function has not been lost. The 
 
4 hour Completion Time takes into account the component 
 
OPERABILITY of the redundant counterpart to the inoperable
 
required feature. Additionally, the 4 hour Completion Time
 
takes into account the capacity and capability of the
 
remaining AC sources, reasonable time for repairs, and low
 
probability of a DBA occurring during this period.
 
B.3.1 and B.3.2
 
Required Action B.3.1 provides an allowance to avoid
 
unnecessary testing of OPERABLE DGs. If it can be
 
determined that the cause of the inoperable DG(s) does not
 
exist on the OPERABLE DG(s), SR 3.8.1.2 does not have to be
 
performed. If the cause of inoperability exists on other
 
DGs, the other DGs are declared inoperable upon discovery, and Condition F or H of LCO 3.8.1 is entered, as applicable. (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-12 Revision 5 BASES ACTIONS B.3.1 and B.3.2 (continued)
  (continued)
Once the failure is repaired, and the common cause failure no longer exists, Required Action B.3.1 is satisfied. If the cause of the initial inoperable DG cannot be confirmed not to exist on the remaining DG(s), performance of SR 3.8.1.2 suffices to provide assurance of continued OPERABILITY of those DG(s). In the event the inoperable DG(s) is restored to OPERABLE status prior to completing either B.3.1 or B.3.2, the station corrective action program will continue to evaluate the common cause possibility.
This continued evaluation, however, is no longer under the 24 hour constraint imposed while in Condition B.
According to Generic Letter 84-15 (Ref. 7), 24 hours is reasonable time to confirm that the OPERABLE DG(s) are not affected by the same problem as the inoperable DG.
B.4 In this condition, the remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1E distribution system. The 14 day Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and low probability of a DBA occurring during this period.
The second Completion Time for Required Action B.4 established a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet LCO 3.8.1.a or b. If Condition B is entered while, for instance, one required offsite circuit is inoperable and that offsite circuit is subsequently restored OPERABLE, the LCO may already have been not met for up to 3 days. This situation could lead to a total of 17 days, since initial failure to meet the LCO, to restore the offsite circuit. At this time, another offsite circuit could become inoperable, the DG restored OPERABLE, and an additional 72 hours (for a total of 20 days) allowed prior to complete restoration of the LCO. The 17 day Completion Time provides a limit on the time allowed in a specified condition after discovery of failure to meet LCO 3.8.1.a or b. This limit is considered reasonable for situations in which Conditions are entered concurrently for combinations of Conditions A, B, and C.
(continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-13 Revision 28 BASES ACTIONS B.4 (continued)
The "AND" connector between the 14 day and 17 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive Completion Time must be met. 
 
Similar to Required Action B.2, the Completion Time of
 
Required Action B.4 allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." 
 
This exception results in establishing the "time zero" at
 
the time the LCO was initially not met, instead of the time
 
Condition B was entered.
 
Condition C Condition C is modified by two Notes indicating that this Condition is not applicable during replacement of Division 2 CSCS isolation valves during the specified unit outages while the outage unit is in MODE 4, 5, or defueled. When the Division 2 DGs are inoperable during the CSCS isolation valve maintenance, Condition G provides appropriate Required Actions. 
 
C.1  To ensure a highly reliable power source remains, it is
 
necessary to verify the availability of the remaining
 
required offsite circuit on a more frequent basis. Since
 
the Required Action only specifies "perform," a failure of
 
SR 3.8.1.1 acceptance criteria does not result in a Required
 
Action being not met. However, if a circuit fails to pass
 
SR 3.8.1.1, it is inoperable. Upon offsite circuit
 
inoperability, additional Conditions must then be entered.
 
C.2 Required Action C.2 is intended to provide assurance that a
 
loss of offsite power, during the period that the DG(s) is
 
inoperable as described in Condition C, does not result in a
 
complete loss of safety function of critical systems. These
 
features are designed with redundant safety related
 
divisions (i.e., single division systems are not included, although, for this Required Action, Division 3 (HPCS System)
 
is considered redundant to Division 1 and 2 ECCS). 
 
(continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-14 Revision 28 BASES ACTIONS C.2 (continued) 
 
Redundant required features failures consist of inoperable
 
features associated with a division redundant to the
 
division that has an inoperable DG.
 
The Completion Time is intended to allow the operator time
 
to evaluate and repair any discovered inoperabilities. This
 
Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock."
 
In this Required Action, the Completion Time only begins on
 
discovery that both:
: a. An inoperable DG exists; and
: b. A redundant required feature on another division is inoperable.
 
If, at any time during the existence of this Condition (DG(s) inoperable as described in Condition C), a redundant 
 
required feature subsequently becomes inoperable, this
 
Completion Time begins to be tracked.
 
Discovering required DG(s) inoperable coincident with one or
 
more redundant required support or supported features, or
 
both, that are associated with the redundant OPERABLE DG(s),
results in starting the Completion Time for the Required
 
Action. Four hours from the discovery of these events
 
existing concurrently is acceptable because it minimizes
 
risk while allowing time for restoration before subjecting
 
the unit to transients associated with shutdown.
 
The remaining OPERABLE DGs and offsite circuits are adequate
 
to supply electrical power to the onsite Class 1E
 
Distribution System. Thus, on a component basis, single
 
failure protection for the required feature's function may
 
have been lost; however, function has not been lost. The
 
4 hour Completion Time takes into account the component
 
OPERABILITY of the redundant counterpart to the inoperable
 
required feature. Additionally, the 4 hour Completion Time
 
takes into account the capacity and capability of the
 
remaining AC sources, reasonable time for repairs, and low
 
probability of a DBA occurring during this period.
 
(continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-15 Revision 28 BASES ACTIONS C.3.1 and C.3.2 (continued)
Required Action C.3.1 provides an allowance to avoid
 
unnecessary testing of OPERABLE DGs. If it can be
 
determined that the cause of the inoperable DG(s) does not
 
exist on the OPERABLE DG(s), SR 3.8.1.2 does not have to be
 
performed. If the cause of inoperability exists on other
 
DGs, the other DGs are declared inoperable upon discovery, and Condition F or H of LCO 3.8.1 is entered, as applicable.
Once the failure is repaired, and the common cause failure
 
no longer exists, Required Action C.3.1 is satisfied. If
 
the cause of the initial inoperable DG cannot be confirmed
 
not to exist on the remaining DG(s), performance of
 
SR 3.8.1.2 suffices to provide assurance of continued
 
OPERABILITY of those DG(s).
 
In the event the inoperable DG(s) is restored to OPERABLE
 
status prior to completing either C.3.1 or C.3.2, the
 
station corrective action program will continue to evaluate
 
the common cause possibility. This continued evaluation, however, is no longer under the 24 hour constraint imposed
 
while in Condition C. 
 
According to Generic Letter 84-15 (Ref. 7), 24 hours is
 
reasonable time to confirm that the OPERABLE DG(s) are not
 
affected by the same problem as the inoperable DG.
 
C.4 According to Regulatory Guide 1.93 (Ref. 6), operation may
 
continue in Condition C for a period that should not exceed
 
72 hours. In this condition, the remaining OPERABLE DGs and
 
offsite circuits are adequate to supply electrical power to
 
the onsite Class 1E distribution system. The 72 hour
 
Completion Time takes into account the capacity and
 
capability of the remaining AC sources, reasonable time for
 
repairs, and low probability of a DBA occurring during this
 
period.
 
The second Completion Time for Required Action C.4
 
established a limit on the maximum time allowed for any
 
combination of required AC power sources to be inoperable
 
during any single contiguous occurrence of failing to meet 
 
(continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-16 Revision 28 BASES ACTIONS C.4 (continued)
LCO 3.8.1.a or b. If Condition C is entered while, for
 
instance, the common DG is inoperable and that DG is
 
subsequently restored OPERABLE, the LCO may already have
 
been not met for up to 14 days. This situation could lead
 
to a total of 17 days, since initial failure to meet the
 
LCO, to restore the DG(s). At this time, an offsite circuit
 
could become inoperable, the DG(s) restored OPERABLE, and an
 
additional 72 hours (for a total of 20 days) allowed prior
 
to complete restoration of the LCO. The 17 day Completion
 
Time provides a limit on the time allowed in a specified
 
condition after discovery of failure to meet LCO 3.8.1.a or
: b. This limit is considered reasonable for situations in
 
which Conditions are entered concurrently for combinations
 
of Conditions A, B, and C. The "AND" connector between the 72 hour and 17 day Completion Times means that both
 
Completion Times apply simultaneously, and the more
 
restrictive Completion Time must be met. Similar to
 
Required Action C.2, the Completion Time of Required Action
 
C.4 allows for an exception to the normal "time zero" for
 
beginning the allowed outage time "clock." This exception
 
results in establishing the "time zero" at the time the LCO
 
was initially not met, instead of the time Condition C was
 
entered.
 
D.1 and D.2
 
Required Action D.1 addresses actions to be taken in the
 
event of concurrent failure of redundant required features.
 
Required Action D.1 reduces the vulnerability to a loss of
 
function. The Completion Time for taking these actions is
 
reduced to 12 hours from that allowed with only one division
 
without offsite power (Required Action A.2). The rationale
 
for the reduction to 12 hours is that Regulatory Guide 1.93 (Ref. 6) allows a Completion Time of 24 hours for two
 
required offsite circuits inoperable, based upon the
 
assumption that two complete safety divisions are OPERABLE.
 
When a concurrent redundant required feature failure exists, this assumption is not the case, and a shorter Completion
 
Time of 12 hours is appropriate. These features are
 
designed with redundant safety related divisions (i.e.,
single division systems are not included in the list, (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-17 Revision 28 BASES ACTIONS D.1 and D.2 (continued) although, for this Required Action, Division 3 (HPCS System)
 
is considered redundant to Division 1 and 2 ECCS).
 
Redundant required features failures consist of any of these
 
features that are inoperable, because any inoperability is
 
on a division redundant to a division with inoperable
 
offsite circuits.
 
The Completion Time for Required Action D.1 is intended to
 
allow the operator time to evaluate and repair any
 
discovered inoperabilities. This Completion Time also
 
allows for an exception to the normal "time zero" for
 
beginning the allowed outage time "clock."  In this Required
 
Action, the Completion Time only begins on discovery that
 
both:  a. Two required offsite circuits are inoperable; and
: b. A redundant required feature is inoperable.
 
If, at any time during the existence of this Condition (two
 
offsite circuits inoperable), a redundant required feature
 
subsequently becomes inoperable, this Completion Time begins
 
to be tracked.
 
According to Regulatory Guide 1.93 (Ref. 6), operation may
 
continue in Condition D for a period that should not exceed
 
24 hours. This level of degradation means that the offsite
 
electrical power system may not have the capability to
 
effect a safe shutdown and to mitigate the effects of an
 
accident; however, the onsite AC sources have not been
 
degraded. This level of degradation generally corresponds
 
to a total loss of the immediately accessible offsite power
 
sources.
 
Because of the normally high availability of the offsite
 
sources, this level of degradation may appear to be more
 
severe than other combinations of two AC sources inoperable
 
that involve one or more DGs inoperable. However, two
 
factors tend to decrease the severity of this degradation
 
level:  a. The configuration of the redundant AC electrical power system that remains available is not susceptible to a
 
single bus or switching failure; and (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-18 Revision 28 BASES ACTIONS D.1 and D.2 (continued)
: b. The time required to detect and restore an unavailable offsite power source is generally much less than that
 
required to detect and restore an unavailable onsite
 
AC source.
With two of the required offsite circuits inoperable, sufficient onsite AC sources are available to maintain the
 
unit in a safe shutdown condition in the event of a DBA or
 
transient. In fact, a simultaneous loss of offsite AC
 
sources, a LOCA, and a worst case single failure were
 
postulated as a part of the design basis in the safety
 
analysis. Thus, the 24 hour Completion Time provides a
 
period of time to effect restoration of one of the offsite
 
circuits commensurate with the importance of maintaining an
 
AC electrical power system capable of meeting its design
 
criteria. According to Regulatory Guide 1.93 (Ref. 6), with
 
the available offsite AC sources two less than required by
 
the LCO, operation may continue for 24 hours. If two offsite
 
sources are restored within 24 hours, unrestricted operation
 
may continue. If only one offsite source is restored within
 
24 hours, power operation continues in accordance with
 
Condition A.
 
E.1 and E.2
 
Pursuant to LCO 3.0.6, the Distribution System ACTIONS would
 
not be entered even if all AC sources to it were inoperable, resulting in de-energization. Therefore, the Required
 
Actions of Condition E are modified by a Note to indicate
 
that when Condition E is entered with no AC source to any
 
required division (i.e., the division is de-energized),
Actions for LCO 3.8.7, "Distribution Systems-Operating,"
must be immediately entered. This allows Condition E to
 
provide requirements for the loss of an offsite circuit and
 
one required unit DG without regard to whether a division is
 
de-energized. LCO 3.8.7 provides the appropriate
 
restrictions for a de-energized division.
(continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-19 Revision 28 BASES ACTIONS E.1 and E.2 (continued)
 
According to Regulatory Guide 1.93 (Ref. 6), operation may
 
continue in Condition E for a period that should not exceed
 
12 hours. In Condition E, individual redundancy is lost in
 
both the offsite electrical power system and the onsite AC
 
electrical power system. Since power system redundancy is
 
provided by two diverse sources of power, however, the
 
reliability of the power systems in this Condition may
 
appear higher than that in Condition D (loss of both
 
required offsite circuits). This difference in reliability
 
is offset by the susceptibility of this power system
 
configuration to a single bus or switching failure. The
 
12 hour Completion Time takes into account the capacity and
 
capability of the remaining AC sources, reasonable time for
 
repairs, and low probability of a DBA occurring during this
 
period.
 
Condition F Condition F is modified by two Notes indicating that this Condition is not applicable during replacement of Division 2 CSCS isolation valves during the specified unit outages while the outage unit is in MODE 4, 5, or defueled. When the Division 2 DGs are inoperable during the CSCS isolation valve maintenance, Condition G provides appropriate Required Actions.
F.1  With two required unit DGs inoperable or both required
 
Division 2 DGs inoperable, there is no more than two
 
remaining standby AC sources. Thus, with an assumed loss of
 
offsite electrical power, sufficient standby AC sources may
 
not be available to power the minimum required ESF
 
functions. Since the offsite electrical power system is the
 
only source of AC power for the majority of ESF equipment at
 
this level of degradation, the risk associated with
 
continued operation for a very short time could be less than
 
that associated with an immediate controlled shutdown (the
 
immediate shutdown could cause grid instability, which could
 
result in a total loss of AC power). Since any inadvertent
 
generator trip could also result in a total loss of offsite
 
AC power, however, the time allowed for continued operation (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-20 Revision 28 BASES ACTIONS F.1 (continued) is severely restricted. The intent here is to avoid the
 
risk associated with an immediate controlled shutdown and to
 
minimize the risk associated with this level of degradation.
 
According to Regulatory Guide 1.93 (Ref. 6), with Division 1
 
and 2 unit DGs inoperable, operation may continue for a
 
period that should not exceed 2 hours. This Completion Time
 
assumes complete loss of onsite (DG) AC capability to power
 
the minimum loads needed to respond to analyzed events.
 
In the event the unit Division 3 DG in conjunction with a
 
unit Division 1 or 2 DG is inoperable, with a unit Division
 
1 or 2 DG remaining, a significant spectrum of breaks would
 
be capable of being responded to with onsite power. Even
 
the worst case event would be mitigated to some extent-an
 
extent greater than a typical two division design in which
 
this condition represents a complete loss of function. 
 
Given the remaining function, a 72 hour Completion Time is
 
appropriate. At the end of this 72 hour period, the unit
 
Division 3 system (HPCS System) could be declared inoperable (See Applicability Note 1) and this Condition could be
 
exited with only one remaining required unit DG inoperable.
 
However, with a unit Division 1 or 2 DG remaining inoperable
 
and the HPCS System declared inoperable, a redundant
 
required feature failure exists, according to Required
 
Action B.3 or C.2.
 
In the event the required opposite unit Division 2 DG is
 
inoperable in conjunction with a unit Division 2 DG
 
inoperable, the opposite unit Division 2 subsystems (e.g.,
SGT subsystem) could be declared inoperable at the end of
 
the 2 hour Completion Time (see Applicability Note 2) and
 
this Condition could be exited with only one required unit
 
DG remaining inoperable. However, with the given unit
 
Division 2 DG remaining inoperable and the opposite unit
 
Division 2 subsystems declared inoperable, redundant
 
required feature failures exist, according to Required
 
Action C.2.
 
  (continued)
 
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-21 Revision 32 BASES ACTIONS Condition G (continued)
Condition G is modified by two Notes indicating that this
 
Condition is only applicable during replacement of Division
 
2 CSCS isolation valves during the specified unit outages
 
while the outage unit is in MODE 4, 5, or defueled.
 
G.1 With both required Division 2 DGs inoperable, there is no
 
more than two remaining OPERABLE standby AC sources. Thus, with an assumed loss of offsite electrical power, sufficient
 
standby AC sources may not be available to power the minimum
 
required Division 2 ESF functions. Since the offsite
 
electrical power system is the only source of AC power for
 
the Division 2 ESF equipment at this level of degradation, the risk associated with continued operation during the
 
Division 2 CSCS valve replacement maintenance must be
 
mitigated by the use of mechanical line stops to maintain
 
the availability of the Division 2 CSCS system for the
 
online Unit. The line stops are designed to the same
 
pressure rating and seismic design as the CSCS piping. At
 
least one required Division 2 DG must be restored to
 
OPERABLE status within 6 days of entry into Condition G. 
 
This Completion Time is based upon a risk-informed
 
assessment that concluded that the associated risk with the
 
unit in the specified configuration is acceptable (Ref. 13).
 
If at least one Division 2 DG is not maintained available
 
while in this Condition, the assumptions of the risk
 
assessment of Reference 13 are no longer valid and
 
Condition H should be entered immediately.
 
H.1 If the inoperable AC electrical power sources cannot be
 
restored to OPERABLE status within the associated Completion
 
Time, the unit must be brought to a MODE in which the
 
overall plant risk is minimized. To achieve this status, the unit must be brought to MODE 3 within 12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 14) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short.
However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
The allowed Completion Time is reasonable, based on operating experience, to (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-22 Revision 32 BASES ACTIONS H.1 (continued) reach the required plant conditions from full power
 
conditions in an orderly manner and without challenging
 
plant systems.
 
I.1  Condition I corresponds to a level of degradation in which all redundancy in the AC electrical power supplies has been
 
lost. At this severely degraded level, any further losses
 
in the AC electrical power system will cause a loss of
 
function. Therefore, no additional time is justified for
 
continued operation. The unit is required by LCO 3.0.3 to
 
commence a controlled shutdown.
 
SURVEILLANCE The AC sources are designed to permit inspection and REQUIREMENTS testing of all important areas and features, especially those that have a standby function, in accordance with
 
10 CFR 50, GDC 18 (Ref. 8). Periodic component tests are
 
supplemented by extensive functional tests during refueling
 
outages under simulated accident conditions. The SRs for
 
demonstrating the OPERABILITY of the DGs are consistent with
 
the recommendations of Regulatory Guide 1.9 (Ref. 3) and
 
Regulatory Guide 1.137 (Ref. 9).
 
The Surveillances are modified by two Notes to clearly
 
identify how the Surveillances apply to the given unit and
 
opposite unit's Division 2 DGs. Note 1 states that SR
 
3.8.1.1 through SR 3.8.1.20 are applicable only to the given
 
unit AC electrical power sources and Note 2 states that
 
SR 3.8.1.21 is applicable to the opposite unit's Division 2
 
DG. These Notes are necessary since the opposite unit AC
 
electrical power source is not required to meet all of the
 
requirements of the given unit AC electrical power sources (e.g., the opposite unit DG is not required to start on the
 
opposite unit's ECCS initiation signal to support
 
OPERABILITY of the given unit).
 
Where the SRs discussed herein specify voltage and frequency
 
tolerances, the following summary is applicable. The
 
minimum steady state output voltage of 4010 V is greater
 
than 90% of the nominal 4160 V output voltage. This value, which is conservative with respect to the value specified in
 
ANSI C84.1 (Ref. 10), allows for voltage drop to the
 
terminals of 4000 V motors whose minimum operating voltage
 
is specified as 90%, or 3600 V. It also allows for voltage (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-23 Revision 32 BASES SURVEILLANCE drops to motors and other equipment down through the 120 V REQUIREMENTS level where minimum operating voltage is also usually (continued) specified as 90% of name plate rating. The specified maximum steady state output voltage of 4310 V is within the
 
maximum operating voltage of 110% specified for 4000 V
 
motors. It ensures that for a lightly loaded distribution
 
system, the voltage at the terminals of 4000 V motors is no
 
more than the maximum rated operating voltages. The
 
specified minimum and maximum frequencies of the DG are
 
58.8 Hz and 61.2 Hz, respectively. These values are equal
 
to +/- 2% of the 60 Hz nominal frequency and are derived from
 
the recommendations given in Regulatory Guide 1.9 (Ref. 3).
 
SR  3.8.1.1
 
This SR ensures proper circuit continuity for the offsite AC
 
electrical power supply to the onsite distribution network
 
and availability of offsite AC electrical power. The breaker
 
alignment verifies that each breaker is in its correct
 
position to ensure that distribution buses and loads are
 
connected or capable of being connected to their power
 
source and that appropriate independence of offsite circuits
 
is maintained. The 7 day Frequency is adequate since
 
breaker position is not likely to change without the
 
operator being aware of it and because its status is
 
displayed in the control room.
 
SR  3.8.1.2 and SR  3.8.1.7
 
These SRs help to ensure the availability of the standby
 
electrical power supply to mitigate DBAs and transients and
 
maintain the unit in a safe shutdown condition.
 
To minimize the wear on moving parts that do not get
 
lubricated when the engine is not running, these SRs have
 
been modified by Notes (Note 1 for SR 3.8.1.7 and Note 1 for
 
SR 3.8.1.2) to indicate that all DG starts for these
 
Surveillances may be preceded by an engine prelube period
 
and followed by a warmup period prior to loading, as
 
recommended by the manufacturer.
 
For the purposes of SR 3.8.1.2, the DGs are started from
 
normal standby conditions and for the purposes of
 
SR 3.8.1.7, the DGs are started from ambient standby
 
conditions. Normal standby conditions for a DG means that
 
the diesel engine jacket water and lube oil are being
 
continuously circulated and temperature is being maintained (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-24 Revision 28 BASES SURVEILLANCE SR  3.8.1.2 and SR  3.8.1.7 (continued)
REQUIREMENTS consistent with manufacturer recommendations. Ambient
 
standby conditions for a DG mean that the diesel engine
 
jacket water and lube oil temperatures are within the
 
prescribed temperature bands of these subsystems when the DG
 
has been at rest for an extended period with the pre-lube
 
oil and jacket water circulating systems operational.
 
In order to reduce stress and wear on diesel engines, the
 
manufacturer has recommended that the starting speed of DGs
 
be limited, that warmup be limited to this lower speed, and
 
that DGs be gradually accelerated to synchronous speed prior
 
to loading. These start procedures are the intent of Note 2
 
of SR 3.8.1.2.
 
SR 3.8.1.7 requires that, at a 184 day Frequency, the DG
 
starts from standby conditions and achieves required voltage
 
and frequency within 13 seconds. The 13 second start
 
requirement supports the assumptions in the design basis
 
LOCA analysis (Ref. 5). The 13 second start requirement may
 
not be applicable to SR 3.8.1.2 (see Note 2 of SR 3.8.1.2),
when a modified start procedure as described above is used.
 
If a modified start is not used, the 13 second start
 
requirement of SR 3.8.1.7 applies. Since SR 3.8.1.7 does
 
require a 13 second start, it is more restrictive than
 
SR 3.8.1.2, and it may be performed in lieu of SR 3.8.1.2. 
 
In addition, the DG is required to maintain proper voltage
 
and frequency limits after steady state is achieved. The
 
voltage and frequency limits are normally achieved within 13
 
seconds. The time for the DG to reach steady state
 
operation, unless the modified DG start method is employed, is periodically monitored and the trend evaluated to
 
identify degradation of governor and voltage regulator
 
performance.
 
To minimize testing of the common DG, Note 3 of SR 3.8.1.2
 
and Note 2 of SR 3.8.1.7 allow a single test for the common
 
DG (instead of two tests, one for each unit) to satisfy the
 
requirements of both units. This is allowed since the main
 
purpose of the Surveillance can be met by performing the
 
test on either unit. However, to the extent practicable, the tests should be alternated between units. If the DG
 
fails one of these Surveillances, the DG should be (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-25 Revision 28 BASES SURVEILLANCE SR  3.8.1.2 and SR  3.8.1.7 (continued)
REQUIREMENTS considered inoperable on both units, unless the cause of the
 
failure can be directly related to only one unit.
 
The 31 day Frequency for SR 3.8.1.2 is consistent with
 
Regulatory Guide 1.9 (Ref. 3). The 184 day Frequency for
 
SR 3.8.1.7 is a reduction in cold testing consistent with
 
Generic Letter 84-15 (Ref. 7). These Frequencies provide
 
adequate assurance of DG OPERABILITY, while minimizing
 
degradation resulting from testing.
 
SR  3.8.1.3
 
This Surveillance demonstrates that the DGs are capable of
 
synchronizing and accepting greater than or equal to 90% of
 
the DG continuous load rating. A minimum run time of
 
60 minutes is required to stabilize engine temperatures, while minimizing the time that the DG is connected to the
 
offsite source.
 
Although no power factor requirements are established by
 
this SR, the DG is normally operated at a power factor
 
between 0.8 lagging and 1.0 when running synchronized with
 
the grid. The 0.8 power factor value is the design rating
 
of the machine at a particular kVA. The 1.0 power factor
 
value is an operational limitation condition where the
 
reactive power component is zero, which minimizes the
 
reactive heating of the generator. Operating the generator
 
at a power factor between 0.8 lagging and 1.0 avoids adverse
 
conditions associated with underexciting the generator and
 
more closely represents the generator operating requirements
 
when performing its safety function (running isolated on its
 
associated 4160 V emergency bus). The load band is provided
 
to avoid routine overloading of the DG. Routine overloading
 
may result in more frequent teardown inspections in
 
accordance with vendor recommendations in order to maintain
 
DG OPERABILITY.
 
The 31 day Frequency for this Surveillance is consistent
 
with Regulatory Guide 1.9 (Ref. 3).
 
  (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-26 Revision 28 BASES SURVEILLANCE SR  3.8.1.3 (continued)
REQUIREMENTS Note 1 modifies this Surveillance to indicate that diesel
 
engine runs for this Surveillance may include gradual
 
loading, as recommended by the manufacturer, so that
 
mechanical stress and wear on the diesel engine are
 
minimized.
 
Note 2 modifies this Surveillance by stating that momentary
 
transients because of changing bus loads do not invalidate
 
this test.
 
Note 3 indicates that this Surveillance must be conducted on
 
only one DG at a time in order to avoid common cause
 
failures that might result from offsite circuit or grid
 
perturbations.
 
Note 4 stipulates a prerequisite requirement for performance
 
of this SR. A successful DG start must precede this test to
 
credit satisfactory performance.
 
To minimize testing of the common DG, Note 5 allows a single
 
test of the common DG (instead of two tests, one for each
 
unit) to satisfy the requirements for both units. This is
 
allowed since the main purpose of the Surveillance can be
 
met by performing the test on either unit. However, to the
 
extent practicable, the test should be alternated between
 
units. If the DG fails one of these Surveillances, the DG
 
should be considered inoperable on both units, unless the
 
cause of the failure can be directly related to only one
 
unit.
 
SR  3.8.1.4
 
This SR provides verification that the level of fuel oil in
 
the day tank is at or above the level at which the low level
 
alarm is annunciated. The level is expressed as an
 
equivalent volume in gallons, and is selected to ensure
 
adequate fuel oil for a minimum of 50 minutes of DG
 
operation at rated capacity.
 
The 31 day Frequency is adequate to assure that a sufficient
 
supply of fuel oil is available, since low level alarms are
 
provided and facility operators would be aware of any large
 
uses of fuel oil during this period.
(continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-27 Revision 31 BASES SURVEILLANCE SR  3.8.1.5 REQUIREMENTS (continued) Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water
 
environment in order to survive. Removal of water from the
 
fuel oil day tanks once every 31 days eliminates the
 
necessary environment for bacterial survival. This is most
 
effective means in controlling microbiological fouling. In
 
addition, it eliminates the potential for water entrainment
 
in the fuel oil during DG operation. Water may come from
 
any of several sources, including condensation, rain water, contaminated fuel oil, and breakdown of the fuel oil by
 
bacteria. Frequent checking for and removal of accumulated
 
water minimizes fouling and provides data regarding the
 
watertight integrity of the fuel oil system. The
 
Surveillance Frequency is established by Regulatory
 
Guide 1.137 (Ref. 10). This SR is for preventive
 
maintenance. The presence of water does not necessarily
 
represent a failure of this SR provided that accumulated
 
water is removed during performance of this Surveillance.
 
SR  3.8.1.6
 
This Surveillance demonstrates that each required fuel oil
 
transfer pump operates and automatically transfers fuel oil
 
from its associated storage tank to its associated day tank.
 
It is required to support the continuous operation of
 
standby power sources. This Surveillance provides assurance
 
that the fuel oil transfer pump is OPERABLE, the fuel oil
 
piping system is intact, the fuel delivery piping is not
 
obstructed, and the controls and control systems for
 
automatic fuel transfer systems are OPERABLE.
The Frequency for this SR corresponds to the testing
 
requirements for pumps as contained in the ASME OM Code (Ref. 11).
 
SR  3.8.1.8
 
Transfer of each Division 1 and 2 4.16 kV emergency bus
 
power supply from the normal offsite circuit to the
 
alternate offsite circuit demonstrates the OPERABILITY of (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-28 Revision 28 BASES SURVEILLANCE SR  3.8.1.8 (continued)
REQUIREMENTS the alternate circuit distribution network to power the
 
Division 1 and 2 shutdown loads. The 24 month Frequency of
 
the Surveillance is based on engineering judgment taking
 
into consideration the plant conditions required to perform
 
the Surveillance, and is intended to be consistent with
 
expected fuel cycle lengths. Operating experience has shown
 
that these components usually pass the SR when performed on
 
the 24 month Frequency. Therefore, the Frequency was
 
concluded to be acceptable from a reliability standpoint.
 
This SR is modified by a Note. The reason for the Note is
 
that, during operation with the reactor critical, performance of this SR could cause perturbations to the
 
electrical distribution systems that could challenge
 
continued steady state operation and, as a result, plant
 
safety systems. This restriction from normally performing
 
the Surveillance in MODE 1 or 2 is further amplified to
 
allow the Surveillance to be performed for the purpose of
 
reestablishing OPERABILITY (e.g., post work testing
 
following corrective maintenance, corrective modifications, deficient or incomplete surveillance testing, and other
 
unanticipated OPERABILITY concerns) provided an assessment
 
determines plant safety is maintained or enhanced. This
 
assessment shall, as a minimum, consider the potential
 
outcomes and transients associated with a failed
 
Surveillance, a successful Surveillance, and a perturbation
 
of the offsite or onsite system when they are tied together
 
or operated independently for the Surveillance; as well as
 
the operator procedures available to cope with these
 
outcomes. These shall be measured against the avoided risk
 
of a plant shutdown and startup to determine that plant
 
safety is maintained or enhanced when the Surveillance is
 
performed in MODE 1 or 2. Risk insights or deterministic
 
methods may be used for this assessment. Credit may be
 
taken for unplanned events that satisfy this SR.
 
SR  3.8.1.9
 
Each DG is provided with an engine overspeed trip to prevent
 
damage to the engine. Recovery from the transient caused by
 
the loss of a large load could cause diesel engine
 
overspeed, which, if excessive, might result in a trip of
 
the engine. This Surveillance demonstrates the DG load (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-29 Revision 28 BASES SURVEILLANCE SR  3.8.1.9 (continued)
REQUIREMENTS response characteristics and capability to reject the
 
largest single load without exceeding predetermined
 
frequency and while maintaining a specified margin to the
 
overspeed trip. The load referenced for the Division 1
 
DG is the 1190 kW low pressure core spray pump; for the
 
Division 2 DG, the 638 kW residual heat removal (RHR) pump;
 
and for the Division 3 DG the 2421 kW HPCS pump. This
 
Surveillance may be accomplished by: 
: a. Tripping the DG output breaker with the DG carrying greater than or equal to its associated single largest
 
post-accident load while paralleled to offsite power, or while solely supplying the bus; or 
: b. Tripping its associated single largest post-accident load with the DG solely supplying the bus.
 
Consistent with Regulatory Guide 1.9 (Ref. 3), the load
 
rejection test is acceptable if the diesel speed does not
 
exceed 75% of the difference between nominal speed and the
 
overspeed trip setpoint, or 15% above nominal speed, whichever is lower. This corresponds to 66.7 Hz, which is
 
the nominal speed plus 75% of the difference between nominal
 
speed and the overspeed trip setpoint. The 24 month
 
Frequency takes into consideration the plant conditions
 
required to perform the Surveillance, and is intended to be
 
consistent with expected fuel cycle lengths.
 
This SR has been modified by two Notes. The reason for Note
 
1 is that during operation with the reactor critical, performance of this SR could cause perturbations to the
 
electrical distribution systems that could challenge
 
continued steady state operation and, as a result, plant
 
safety systems. This restriction from normally performing
 
the Surveillance in MODE 1 or 2 is further amplified to
 
allow the Surveillance to be performed for the purpose of
 
reestablishing OPERABILITY (e.g. post work testing following
 
corrective maintenance, corrective modification, deficient
 
or incomplete surveillance testing, and other unanticipated
 
OPERABILITY concerns) provided an assessment determines
 
plant safety is maintained or enhanced. This assessment
 
shall, as a minimum, consider the potential outcomes and
 
transients associated with a failed Surveillance, a (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-30 Revision 28 BASES SURVEILLANCE SR  3.8.1.9 (continued)
REQUIREMENTS successful Surveillance, and a perturbation of the offsite
 
or onsite system when they are tied together or operated
 
independently for the Surveillance; as well as the operator
 
procedures available to cope with these outcomes. These
 
shall be measured against the avoided risk of a plant
 
shutdown and startup to determine that plant safety is
 
maintained or enhanced when the Surveillance is performed in
 
MODE 1 or 2. Risk insights or deterministic methods may be
 
used for this assessment. Credit may be taken for unplanned
 
events that satisfy this SR. To minimize testing of the
 
common DG, Note 2 allows a single test of the common DG (instead of two tests, one for each unit) to satisfy the
 
requirements for both units. This is allowed since the main
 
purpose of the Surveillance can be met by performing the
 
test on either unit. If the DG fails one of these
 
Surveillances, the DG should be considered inoperable on
 
both units, unless the cause of the failure can be directly
 
related to only one unit.
 
SR  3.8.1.10
 
Consistent with Regulatory Guide 1.9 (Ref. 3), paragraph
 
C.2.2.8, this Surveillance demonstrates the DG capability to
 
reject a full load without overspeed tripping or exceeding
 
the predetermined voltage limits. The DG full load
 
rejection may occur because of a system fault or inadvertent
 
breaker tripping. This Surveillance ensures proper engine
 
generator load response under the simulated test conditions.
 
This test simulates the loss of the total connected load
 
that the DG experiences following a full load rejection and
 
verifies that the DG does not trip upon loss of the load.
 
These acceptance criteria provide DG damage protection.
 
While the DG is not expected to experience this transient
 
during an event, and continues to be available, this
 
response ensures that the DG is not degraded for future
 
application, including reconnection to the bus if the trip
 
initiator can be corrected or isolated.
 
The 24 month Frequency takes into consideration the plant
 
conditions required to perform the Surveillance, and is
 
intended to be consistent with expected fuel cycle lengths.
(continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-31 Revision 28 BASES SURVEILLANCE SR  3.8.1.10 (continued)
REQUIREMENTS This SR has been modified by two Notes. The reason for Note
 
1 is that during operation with the reactor critical, performance of this SR could cause perturbations to the
 
electrical distribution systems that could challenge
 
continued steady state operation and, as a result, plant
 
safety systems. This restriction from normally performing
 
the Surveillance in MODE 1 or 2 is further amplified to
 
allow the Surveillance to be performed for the purpose of
 
reestablishing OPERABILITY (e.g., post work testing
 
following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other
 
unanticipated OPERABILITY concerns) provided an assessment
 
determines plant safety is maintained or enhanced. This
 
assessment shall, as a minimum, consiser the potential
 
outcomes and transients associated with a failed
 
Surveillance, a successful Surveillance, and a perturbation
 
of the offsite or onsite system when they are tied together
 
or operated independently for the Surveillance; as well as
 
the operator procedures available to cope with these
 
outcomes. These shall be measured against the avoided risk
 
of a plant shutdown and startup to determine that plant
 
safety is maintained or enhanced when the Surveillance is
 
performed in MODE 1 or 2. Risk insights or deterministic
 
methods may be used for this assessment. Credit may be
 
taken for unplanned events that satisfy this SR. To
 
minimize testing of the common DG, Note 2 allows a single
 
test of the common DG (instead of two tests, one for each
 
unit) to satisfy the requirements for both units. This is
 
allowed since the main purpose of the Surveillance can be
 
met by performing the test on either unit. If the DG fails
 
one of these Surveillances, the DG should be considered
 
inoperable on both units, unless the cause of the failure
 
can be directly related to only one unit.
 
SR  3.8.1.11
 
Consistent with Regulatory Guide 1.9 (Ref. 3),
paragraph C.2.2.4, this Surveillance demonstrates the as
 
designed operation of the standby power sources during loss
 
of the offsite source. This test verifies all actions
 
encountered from the loss of offsite power, including (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-32 Revision 28 BASES SURVEILLANCE SR  3.8.1.11 (continued)
REQUIREMENTS shedding of the nonessential loads (Divisions 1 and 2 only)
 
and energization of the emergency buses and respective loads
 
from the DG. It further demonstrates the capability of the
 
DG to automatically achieve the required voltage and
 
frequency within the specified time.
 
The DG auto-start and energization of permanently connected
 
loads time of 13 seconds is derived from requirements of the
 
accident analysis for responding to a design basis large
 
break LOCA (Ref. 5). The Surveillance should be continued
 
for a minimum of 5 minutes in order to demonstrate that all
 
starting transients have decayed and stability has been
 
achieved.
 
The requirement to verify the connection and power supply of
 
permanently connected loads and auto-connected loads is
 
intended to satisfactorily show the relationship of these
 
loads to the DG loading logic. In certain circumstances, many of these loads cannot actually be connected or loaded
 
without undue hardship or potential for undesired operation.
 
For instance, ECCS injection valves are not desired to be
 
stroked open, systems are not capable of being operated at
 
full flow, or RHR systems performing a decay heat removal
 
function are not desired to be realigned to the ECCS mode of
 
operation. In lieu of actual demonstration of the
 
connection and loading of these loads, testing that
 
adequately shows the capability of the DG system to perform
 
these functions is acceptable. This testing may include any
 
series of sequential, overlapping, or total steps so that
 
the entire connection and loading sequence is verified.
 
The Frequency of 24 months takes into consideration plant
 
conditions required to perform the Surveillance, and is
 
intended to be consistent with expected fuel cycle lengths.
 
This SR is modified by two Notes. The reason for Note 1 is
 
to minimize wear and tear on the DGs during testing. The
 
prelube period shall be consistent with manufacturer
 
recommendations. For the purpose of this testing, the DGs
 
must be started from normal standby conditions, that is, with the engine jacket water and lube oil being continuously
 
circulated and temperature is being maintained consistent
 
with manufacturer recommendations. The reason for Note 2 is (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-33 Revision 28 BASES SURVEILLANCE SR  3.8.1.11 (continued)
REQUIREMENTS that performing the Surveillance would remove a required
 
offsite circuit from service, perturb the electrical
 
distribution system, and challenge plant safety systems.
 
This restriction from normally performing the Surveillance
 
in MODE 1 or 2 is further amplified to allow portions of the
 
Surveillance to be performed for the purpose of
 
reestablishing OPERABILITY (e.g., post work testing
 
following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other
 
unanticipated OPERABILITY concerns) provided an assessment
 
determines plant safety is maintained or enhanced. This
 
assessment shall, as a minimum, consider the potential
 
outcomes and transients associated with a failed partial
 
Surveillance, a successful partial Surveillance, and a
 
perturbation of the offsite or onsite system when they are
 
tied together or operated independently for the partial
 
Surveillance; as well as the operator procedures available
 
to cope with these outcomes. These shall be measured
 
against the avoided risk of a plant shutdown and startup to
 
determine that plant safety is maintained or enhanced when
 
portions of the Surveillance are performed in MODE 1 or 2.
 
Risk insights or deterministic methods may be used for this
 
assessment. Credit may be taken for unplanned events that
 
satisfy this SR.
 
SR  3.8.1.12
 
Consistent with Regulatory Guide 1.9 (Ref. 3), paragraph
 
C.2.2.5, this Surveillance demonstrates that the DG
 
automatically starts and achieves the required voltage and
 
frequency within the specified time (13 seconds) from the
 
design basis actuation signal (LOCA signal). In addition, the DG is required to maintain proper voltage and frequency
 
limits after steady state is achieved. The voltage and
 
frequency limits are normally achieved within 13 seconds.
 
The time for the DG to reach the steady state voltage and
 
frequency limits is periodically monitored and the trend
 
evaluated to identify degradation of governor and voltage
 
regulator performance. The DG is required to operate for 5 minutes. The 5 minute period provides sufficient time to demonstrate stability. 
(continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-34 Revision 28 BASES SURVEILLANCE SR  3.8.1.12 (continued)
REQUIREMENTS The Frequency of 24 months takes into consideration plant
 
conditions required to perform the Surveillance, and is
 
intended to be consistent with the expected fuel cycle
 
lengths. 
 
This SR is modified by two Notes. The reason for Note 1 is
 
to minimize wear and tear on the DGs during testing. The
 
prelube period shall be consistent with manufacturer
 
recommendations. For the purpose of this testing, the DGs
 
must be started from normal standby conditions, that is, with the engine jacket water and lube oil being continuously
 
circulated and temperature is being maintained consistent
 
with manufacturer recommendations. The reason for Note 2 is
 
that during operation with the reactor critical, performance
 
of this SR could cause perturbations to the electrical
 
distribution systems that could challenge continued steady
 
state operation and, as a result, plant safety systems.
 
This restriction from normally performing the Surveillance
 
in MODE 1 or 2 is further amplified to allow portions of the
 
Surveillance to be performed for the purpose of
 
reestablishing OPERABILITY (e.g., post work testing
 
following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other
 
unanticipated OPERABILITY concerns) provided an assessment
 
determines plant safety is maintained or enhanced. This
 
assessment shall, as a minimum, consider the potential
 
outcomes and transients associated with a failed partial
 
Surveillance, a successful partial Surveillance, and a
 
perturbation of the offsite or onsite system when they are
 
tied together or operated independently for the partial
 
Surveillance; as well as the operator procedures available
 
to cope with these outcomes. These shall be measured
 
against the avoided risk of a plant shutdown and startup to
 
determine that plant safety is maintained or enhanced when
 
portions of the Surveillance are performed in MODE 1 or 2.
 
Risk insights or deterministic methods may be used for this
 
assessment. Credit may be taken for unplanned events that
 
satisfy this SR. 
(continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-35 Revision 28 BASES SURVEILLANCE SR  3.8.1.13 REQUIREMENTS (continued) Consistent with Regulatory Guide 1.9 (Ref. 3) paragraph C.2.2.12, this Surveillance demonstrates that DG
 
non-critical protective functions (e.g., high jacket water
 
temperature) are bypassed on a loss of voltage signal
 
concurrent with an ECCS initiation test signal and critical
 
protective functions (engine overspeed and generator
 
differential current) trip the DG to avert substantial
 
damage to the DG unit. The non-critical trips are bypassed
 
during DBAs and provide an alarm on an abnormal engine
 
condition. This alarm provides the operator with sufficient
 
time to react appropriately. The DG availability to
 
mitigate the DBA is more critical than protecting the engine
 
against minor problems that are not immediately detrimental
 
to emergency operation of the DG.
 
The 24 month Frequency is based on engineering judgment, taking into consideration plant conditions required to
 
perform the Surveillance, and is intended to be consistent
 
with expected fuel cycle lengths.
 
This SR is modified by a Note. The reason for the Note is
 
that performing the Surveillance removes a required DG from
 
service. This restriction from normally performing the
 
Surveillance in MODE 1 or 2 is further amplified to allow
 
the Surveillance to be performed for the purpose of
 
reestablishing OPERABILITY (e.g., post work testing
 
following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other
 
unanticipated OPERABILITY concerns) provided an assessment
 
determines plant safety is maintained or enhanced. This
 
assessment shall, as a minimum, consider the potential
 
outcomes and transients associated with a failed
 
Surveillance, a successful Surveillance, and a perturbation
 
of the offsite or onsite system when they are tied together
 
or operated independently for the Surveillance; as well as
 
the operator procedures available to cope with these
 
outcomes. These shall be measured against the avoided risk
 
of a plant shutdown and startup to determine that plant
 
safety is maintained or enhanced when the Surveillance is
 
performed in MODE 1 or 2. Risk insights or deterministic
 
methods may be used for this assessment. Credit may be
 
taken for unplanned events that satisfy this SR.
(continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-36 Revision 30 BASES SURVEILLANCE SR  3.8.1.14 REQUIREMENTS (continued) Consistent with Regulatory Guide 1.9 (Ref. 3), paragraph C.2.2.9, this Surveillance requires demonstration
 
that the DGs can start and run continuously near full load
 
capability for an interval of not less than 24 hours, 22 hours of which is at a load equivalent to 92% and 100% of
 
the continuous rating of the DG, and 2 hours of which is at
 
a load between the 2000 hour rating and the 7 day rating of
 
the DG. The DG starts for this Surveillance can be
 
performed either from normal standby or hot conditions. The
 
provisions for prelube and warmup, discussed in SR 3.8.1.2, and for gradual loading, discussed in SR 3.8.1.3, are
 
applicable to this SR.
 
In order to ensure that the DG is tested under conditions that bound all credible design basis events, testing must be performed at a power factor as close to the accident load power factor as practicable. The accident kVAR load defines the power factor limit in the isochronous mode. Based on this relationship, if the reactive power (kVAR) level for the DG is maintained above the calculated accident load limiting value while the real power (kW) is maintained
 
within a specified 90 to 100% operating band during the 22-hour surveillance period, the power factor limit will be met. During the 2-hour period that the DG is operated  2860 kW, the power factor limit will be restricted by the DG overload ratings. Continuous operation of the DG above the overload rating will accelerate wear and may negatively impact the machine's reliability and result in more frequent teardown inspections.
The DG 2-hour overload limit within any 24-hour period allows up to 3420 kVA of apparent power. This kVA limit is based on values of 2860 kW (DG 24-hour rated limit) and 1876 kVAR (Operations kVAR loading limit with DG at 2860 kW). Therefore, the kVAR output of the DG during the 2-hour overload period should be maintained at a level that will ensure that the 3420 kVA limit is not exceeded. The established 3420 kVA value is slightly less than the generator manufacturers rating limit to provide margin for operating tolerances. The specific power factor limit for the emergency diesel generators is contained in the design basis loading calculations and varies for each particular DG. The kW and kVAR operating bands provided in the DG operating surveillances for performance of the 24-hour (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-37 Revision 30 BASES SURVEILLANCE SR  3.8.1.14 (continued)
REQUIREMENTS endurance tests envelope the accident kVAR load and therefore, the power factor requirements. This power factor is chosen to bound the actual worst case inductive loading that the DG could experience under design basis accident conditions. 
 
The 24 month Frequency takes into consideration plant
 
conditions required to perform the Surveillance, and is
 
intended to be consistent with expected fuel cycle lengths.
 
This Surveillance is modified by four Notes. Note 1 states
 
that momentary transients due to changing bus loads do not
 
invalidate this test. The load band is provided to avoid
 
routine overloading of the DG. Routine overloading may
 
result in more frequent teardown inspections in accordance
 
with vendor recommendations in order to maintain DG
 
OPERABILITY. Similarly, momentary power factor transients
 
above the limit do not invalidate the test. The reason for
 
Note 2 is that during operation with the reactor critical, performance of this SR could cause perturbations to the
 
electrical distribution systems that could challenge
 
continued steady state operation and, as a result, plant
 
safety systems. However, it is acceptable to perform this
 
SR in MODES 1 and 2 provided the other two DGs are OPERABLE, since a perturbation can only affect one divisional DG. If
 
during performance of this SR one of the other DGs becomes
 
inoperable, this Surveillance is to be suspended. In
 
addition, this restriction from normally performing the
 
Surveillance in MODE 1 or 2 with any of the remaining two
 
DGs inoperable is further amplified to allow the
 
Surveillance to be performed for the purpose of
 
reestablishing OPERABILITY (e.g., post work testing
 
following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other
 
unanticipated OPERABILITY concerns) provided an assessment
 
determines plant safety is maintained or enhanced. This
 
assessment shall, as a minimum, consider the potential
 
outcomes and transients associated with a failed
 
Surveillance, a successful Surveillance, and a perturbation
 
of the offsite or onsite system when they are tied together
 
or operated independently for the Surveillance; as well as
 
the operator procedures available to cope with these
 
outcomes. These shall be measured against the avoided risk
 
of a plant shutdown and startup to determine that plant  (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-38 Revision 30 BASES SURVEILLANCE SR  3.8.1.14 (continued)
REQUIREMENTS safety is maintained or enhanced when the Surveillance is
 
performed in MODE 1 or 2 with any of the remaining two DGs
 
inoperable . Risk insights or deterministic methods may be
 
used for this assessment. Credit may be taken for unplanned
 
events that satisfy this SR. Note 3 is provided in
 
recognition that under certain conditions, it is necessary
 
to allow the surveillance to be conducted at a power factor
 
other than the specified limit. During the Surveillance, the DG is normally operated paralleled to the grid, which is
 
not the configuration when the DG is performing its safety
 
function following a loss of offsite power (with or without
 
a LOCA). Given the parallel configuration to the grid
 
during the Surveillance, the grid voltage may be such that
 
the DG field excitation level needed to obtain the specified
 
power factor could result in a transient voltage within the
 
DG windings higher than the recommended values if the DG
 
output breaker were to trip during the Surveillance. 
 
Therefore, the power factor shall be maintained as close as
 
practicable to the specified limit while still ensuring that
 
if the DG output breaker were to trip during the
 
Surveillance that the maximum DG winding voltage would not
 
be exceeded. To minimize testing of the common DG, Note 4
 
allows a single test of the common DG (instead of two tests, one for each unit) to satisfy the requirements for both
 
units. This is allowed since the main purpose of the
 
Surveillance can be met by performing the test on either
 
unit. If the DG fails one of these Surveillances, the DG
 
should be considered inoperable on both units, unless the
 
cause of the failure can be directly related to only one
 
unit.
 
SR  3.8.1.15
 
This Surveillance demonstrates that the diesel engine can
 
restart from a hot condition, such as subsequent to shutdown
 
from normal Surveillances, and achieve the required voltage
 
and frequency within 13 seconds. The 13 second time is
 
derived from the requirements of the accident analysis for
 
responding to a design basis large break LOCA (Ref. 5). In
 
addition, the DG is required to maintain proper voltage and
 
frequency limits after steady state is achieved. The
 
voltage and frequency limits are normally achieved within (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-39 Revision 30 BASES SURVEILLANCE SR  3.8.1.15 (continued)
REQUIREMENTS 13 seconds. The time for the DG to reach the steady state
 
voltage and frequency limits is periodically monitored and
 
the trend evaluated to identify degradation of governor and
 
voltage regulator performance.
 
The 24 month Frequency takes into consideration the plant
 
conditions required to perform the Surveillance, and is
 
intended to be consistent with expected fuel cycle lengths.
 
This SR has been modified by three Notes. Note 1 ensures
 
that the test is performed with the diesel sufficiently hot.
 
The requirement that the diesel has operated for at least
 
2 hours at 92% to 100% of full load conditions prior to
 
performance of this Surveillance is based on manufacturer
 
recommendations for achieving hot conditions. The load band
 
is provided to avoid routine overloading of the DG. Routine
 
overloads may result in more frequent teardown inspections
 
in accordance with vendor recommendations in order to
 
maintain DG OPERABILITY. Momentary transients due to
 
changing bus loads do not invalidate this test. Note 2
 
allows all DG starts to be preceded by an engine prelube
 
period to minimize wear and tear on the diesel during
 
testing. The prelube period shall be consistent with
 
manufacturer recommendations. To minimize testing of the
 
common DG, Note 3 allows a single test of the common DG (instead of two tests, one for each unit) to satisfy the
 
requirements for both units. This is allowed since the main
 
purpose of the Surveillance can be met by performing the
 
test on either unit. If the DG fails one of these
 
Surveillances, the DG should be considered inoperable on
 
both units, unless the cause of the failure can be directly
 
related to only one unit.
 
SR  3.8.1.16
 
Consistent with Regulatory Guide 1.9 (Ref. 3),
paragraph C.2.2.11, this Surveillance ensures that the
 
manual synchronization and automatic load transfer from the
 
DG to the offsite source can be made and that the DG can be
 
returned to ready-to-load status when offsite power is
 
restored. It also ensures that the auto-start logic is
 
reset to allow the DG to reload if a subsequent loss of
 
offsite power occurs. The DG is considered to be in 
 
  (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-40 Revision 30 BASES SURVEILLANCE SR  3.8.1.16 (continued)
REQUIREMENTS ready-to-load status when the DG is at rated speed and
 
voltage, the output breaker is open and can receive an
 
auto-close signal on bus undervoltage, and the individual
 
load time delay relays are reset.
 
The Frequency of 24 months takes into consideration plant
 
conditions required to perform the Surveillance, and is
 
intended to be consistent with expected fuel cycle lengths. 
 
This SR is modified by a Note. The reason for the Note is
 
that performing the Surveillance would remove a required
 
offsite circuit from service, perturb the electrical
 
distribution system, and challenge plant safety systems. 
 
This restriction from normally performing the Surveillance
 
in MODE 1 or 2 is further amplified to allow the
 
Surveillance to be performed for the purpose of
 
reestablishing OPERABILITY (e.g., post work testing
 
following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other
 
unanticipated OPERABILITY concerns) provided an assessment
 
determines plant safety is maintained or enhanced. This
 
assessment shall, as a minimum, consider the potential
 
outcomes and transients associated with a failed
 
Surveillance, a successful Surveillance, and a perturbation
 
of the offsite or onsite system when they are tied together
 
or operated independently for the Surveillance; as well as
 
the operator procedures available to cope with these
 
outcomes. These shall be measured against the avoided risk
 
of a plant shutdown and startup to determine that plant
 
safety is maintained or enhanced when the Surveillance is
 
performed in MODE 1 or 2. Risk insights or deterministic
 
methods may be used for this assessment. Credit may be
 
taken for unplanned events that satisfy this SR.
 
SR  3.8.1.17
 
Consistent with Regulatory Guide 1.9 (Ref. 3), paragraph
 
C.2.2.13, demonstration of the parallel test mode override
 
ensures that the DG availability under accident conditions
 
is not compromised as the result of testing. Interlocks to
 
the LOCA sensing circuits cause the Divisions 1 and 2 DGs to
 
automatically reset to ready-to-load operation if an ECCS
 
initiation signal is received during operation in the test (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-41 Revision 30 BASES SURVEILLANCE SR  3.8.1.17 (continued)
REQUIREMENTS mode. Ready-to-load operation is defined as the DG running
 
at rated speed and voltage with the DG output breaker open.
 
These provisions for automatic switchover are required by
 
IEEE-308 (Ref. 12), paragraph 6.2.6(2).
 
The Division 3 DG overcurrent trip of the SAT feeder breaker
 
to the respective Division 3 emergency bus demonstrates the
 
ability of the Division 3 DG to remain connected to the
 
emergency bus and supplying the necessary loads.
 
The 24 month Frequency takes into consideration plant
 
conditions required to perform the Surveillance, and is
 
intended to be consistent with expected fuel cycle lengths.
 
This SR has been modified by a Note. The reason for the
 
Note is that performing the Surveillance would remove a
 
required offsite circuit from service, perturb the
 
electrical distribution system, and challenge safety
 
systems. This restriction from normally performing the
 
Surveillance in MODE 1 or 2 is further amplified to allow
 
portions of the Surveillance to be performed for the purpose
 
of reestablishing OPERABILITY (e.g., post work testing
 
following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other
 
unanticipated OPERABILITY concerns) provided an assessment
 
determines plant safety is maintained or enhanced. This
 
assessment shall, as a minimum, consider the potential
 
outcomes and transients associated with a failed partial
 
Surveillance, a successful partial Surveillance, and a
 
perturbation of the offsite or onsite system when they are
 
tied together or operated independently for the partial
 
Surveillance; as well as the operator procedures available
 
to cope with these outcomes. These shall be measured
 
against the avoided risk of a plant shutdown and startup to
 
determine that plant safety is maintained or enhanced when
 
portions of the Surveillance are performed in MODE 1 or 2. 
 
Risk insights or deterministic methods may be used for this
 
assessment. Credit may be taken for unplanned events that
 
satisfy this SR.
 
(continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-42 Revision 30 BASES SURVEILLANCE SR  3.8.1.18 REQUIREMENTS (continued) Under accident conditions with loss of offsite power loads are sequentially connected to the bus by the individual time
 
delay relays. The sequencing logic controls the permissive
 
and starting signals to motor breakers to prevent 
 
overloading of the DGs due to high motor starting currents.
 
The -10% load sequence time interval limit ensures that a
 
sufficient time interval exists for the DG to restore
 
frequency and voltage prior to applying the next load.
 
There is no upper limit for the load sequence time interval
 
since, for a single load interval (i.e., the time between
 
two load blocks), the capability of the DG to restore
 
frequency and voltage prior to applying the second load is
 
not negatively affected by a longer than designed load
 
interval, and if there are additional load blocks (i.e., the
 
design includes multiple load intervals), then the lower
 
limit requirements (-10%) will ensure that sufficient time
 
exists for the DG to restore frequency and voltage prior to
 
applying the remaining load blocks (i.e., all load intervals
 
must be  90% of the design interval). Reference 2 provides a summary of the automatic loading of emergency buses. 
 
Since only the Division 1 and 2 DGs have more than one load
 
block, this SR is only applicable to these DGs.
 
The Frequency of 24 months takes into consideration plant
 
conditions required to perform the Surveillance, and is
 
intended to be consistent with expected fuel cycle lengths.
 
This SR is modified by a Note. The reason for the Note is
 
that performing the Surveillance during these MODES would
 
remove a required offsite circuit from service, perturb the
 
electrical distribution system, and challenge plant safety
 
systems. This restriction from normally performing the
 
Surveillance in MODE 1 or 2 is further amplified to allow
 
portions of the Surveillance to be performed for the purpose
 
of reestablishing OPERABILITY (e.g., post work testing
 
following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other
 
unanticipated OPERABILITY concerns) provided an assessment
 
determines plant safety is maintained or enhanced. This
 
assessment shall, as a minimum, consider the potential
 
outcomes and transients associated with a failed partial
 
Surveillance, a successful partial Surveillance, and a  (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-43 Revision 30 BASES SURVEILLANCE SR  3.8.1.18 (continued)
REQUIREMENTS perturbation of the offsite or onsite system when they are
 
tied together or operated independently for the partial
 
Surveillance; as well as the operator procedures available
 
to cope with these outcomes. These shall be measured
 
against the avoided risk of a plant shutdown and startup to 
 
determine that plant safety is maintained or enhanced when
 
portions of the Surveillance are performed in MODE 1 or 2. 
 
Risk insights or deterministic methods may be used for this
 
assessment. Credit may be taken for unplanned events that
 
satisfy this SR.
 
SR  3.8.1.19
 
In the event of a DBA coincident with a loss of offsite
 
power, the DGs are required to supply the necessary power to
 
ESF systems so that the fuel, RCS, and containment design
 
limits are not exceeded.
 
This Surveillance demonstrates the DG operation, as
 
discussed in the Bases for SR 3.8.1.11, during a loss of
 
offsite power actuation test signal in conjunction with an
 
ECCS initiation signal. In lieu of actual demonstration of
 
connection and loading of loads, testing that adequately
 
shows the capability of the DG system to perform these
 
functions is acceptable. This testing may include any
 
series of sequential, overlapping, or total steps so that
 
the entire connection and loading sequence is verified.
 
The Frequency of 24 months takes into consideration plant
 
conditions required to perform the Surveillance and is
 
intended to be consistent with an expected fuel cycle
 
length.
 
This SR is modified by two Notes. The reason for Note 1 is
 
to minimize wear and tear on the DGs during testing. The
 
prelube period shall be consistent with manufacturer
 
recommendations. For the purpose of this testing, the DGs
 
must be started from normal standby conditions, that is, with the engine jacket water and lube oil being continuously
 
circulated and temperature is being maintained consistent  (continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-44 Revision 30 BASES SURVEILLANCE SR  3.8.1.19 (continued)
REQUIREMENTS with manufacturer recommendations. The reason for Note 2 is
 
that performing the Surveillance would remove a required
 
offsite circuit from service, perturb the electrical
 
distribution system, and challenge plant safety systems.
 
This restriction from normally performing the Surveillance
 
in MODE 1 or 2 is further amplified to allow portions of the
 
Surveillance to be performed for the purpose of
 
reestablishing OPERABILITY (e.g., post work testing
 
following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other
 
unanticipated OPERABILITY concerns) provided an assessment
 
determines plant safety is maintained or enhanced. This
 
assessment shall, as a minimum, consider the potential
 
outcomes and transients associated with a failed partial
 
Surveillance, a successful partial Surveillance, and a
 
perturbation of the offsite or onsite system when they are
 
tied together or operated independently for the partial
 
Surveillance; as well as the operator procedures available
 
to cope with these outcomes. These shall be measured
 
against the avoided risk of a plant shutdown and startup to
 
determine that plant safety is maintained or enhanced when
 
portions of the Surveillance are performed in MODE 1 or 2.
 
Risk insights or deterministic methods may be used for this
 
assessment. Credit may be taken for unplanned events that
 
satisfy this SR.
 
SR  3.8.1.20
 
This Surveillance demonstrates that the unit DG starting
 
independence has not been compromised. Also, this
 
Surveillance demonstrates that each engine can achieve
 
proper frequency and voltage within the specified time when
 
the unit DGs are started simultaneously.
 
The 10 year Frequency is consistent with the recommendations
 
of Regulatory Guide 1.9, paragraph C.2.2.14 (Ref. 3).
 
(continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-45 Revision 30 BASES SURVEILLANCE SR  3.8.1.20 (continued)
REQUIREMENTS This SR is modified by a Note. The reason for the Note is
 
to minimize wear on the DG during testing. The prelube
 
period shall be consistent with manufacturer
 
recommendations. For the purpose of this testing, the DGs
 
must be started from normal standby conditions, that is, with the engine jacket water and lube oil continuously
 
circulated and temperature is being maintained consistent
 
with manufacturer recommendations.
 
SR  3.8.1.21
 
With the exception of this Surveillance, all other
 
Surveillances of this Specification (SR 3.8.1.1 through
 
SR 3.8.1.20) are applied to the given unit AC sources. This
 
Surveillance is provided to direct that appropriate
 
Surveillances for the required opposite unit AC source is
 
governed by the applicable opposite unit Technical
 
Specifications. Performance of the applicable opposite unit
 
Surveillances will satisfy the opposite unit requirements as
 
well as satisfy the given unit Surveillance Requirement.
 
Exceptions are noted to the opposite unit SRs of LCO 3.8.1.
 
SR 3.8.1.20 is excepted since only one opposite unit DG is 
 
required by the given unit Specification. SR 3.8.1.12, SR 3.8.1.13, SR 3.8.1.17, SR 3.8.1.18, and SR 3.8.1.19 are
 
excepted since these SRs test the opposite unit's ECCS
 
initiation signal, which is not required for the AC
 
electrical power sources to be OPERABLE on a given unit.
 
The Frequency required by the applicable opposite unit SR
 
also governs performance of that SR for the given unit.
 
As noted, if the opposite unit is in MODE 4 or 5, or moving
 
irradiated fuel assemblies in secondary containment, SR 3.8.1.3, SR 3.8.1.9 through SR 3.8.1.11, and SR 3.8.1.14
 
through SR 3.8.1.16 are not required to be performed. This
 
ensures that a given unit SR will not require an opposite
 
unit SR to be performed, when the opposite unit Technical
 
Specifications exempts performance of an opposite unit SR (however, as stated in the opposite unit SR 3.8.2.1 Note 1, while performance of an SR is exempted, the SR must still be
 
met).
 
(continued)
AC Sources-Operating B 3.8.1  LaSalle 1 and 2 B 3.8.1-46 Revision 32 BASES  (continued)
 
REFERENCES 1. 10 CFR 50, Appendix A, GDC 17.
: 2. UFSAR, Chapter 8.
: 3. Regulatory Guide 1.9.
: 4. UFSAR, Chapter 6.
: 5. UFSAR, Chapter 15.
: 6. Regulatory Guide 1.93.
: 7. Generic Letter 84-15, July 2, 1984.
: 8. 10 CFR 50, Appendix A, GDC 18.
: 9. Regulatory Guide 1.137.
: 10. ANSI C84.1, 1982.
: 11. ASME Code for Operation and Maintenance for Nuclear Power Plants (OM Code).
: 12. IEEE Standard 308.
: 13. Risk Management Document SA-1354, Rev. 0, "LaSalle Division 1 and 2 CSCS Valve Replacement Project -
 
Temporary Extension of Technical Specification
 
Completion Times," December 2, 2004.
: 14. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants," December 2002.
 
AC Sources-Shutdown B 3.8.2 LaSalle 1 and 2 B 3.8.2-1 Revision 0 B 3.8  ELECTRICAL POWER SYSTEMS
 
B 3.8.2  AC Sources-Shutdown
 
BASES
 
BACKGROUND A description of the AC sources is provided in the Bases for LCO 3.8.1, "AC Sources-Operating."
APPLICABLE The OPERABILITY of the minimum AC sources during MODES 4 SAFETY ANALYSES and 5, and during movement of irradiated fuel assemblies in the secondary containment ensures that:
: a. The unit can be maintained in the shutdown or refueling condition for extended periods;
: b. Sufficient instrumentation and control capability is available for monitoring and maintaining the unit
 
status; and
: c. Adequate AC electrical power is provided to mitigate events postulated during shutdown, such as an
 
inadvertent draindown of the vessel or a fuel handling
 
accident.
 
In general, when the unit is shutdown the Technical
 
Specifications (TS) requirements ensure that the unit has
 
the capability to mitigate the consequences of postulated
 
accidents. However, assuming a single failure and
 
concurrent loss of all offsite or loss of all onsite power
 
is not required. The rationale for this is based on the
 
fact that many Design Basis Accidents (DBAs) that are
 
analyzed in MODES 1, 2, and 3 have no specific analyses in
 
MODES 4 and 5. Worst case bounding events are deemed not
 
credible in MODES 4 and 5 because the energy contained
 
within the reactor pressure boundary, reactor coolant
 
temperature and pressure, and the corresponding stresses
 
result in the probabilities of occurrence significantly
 
reduced or eliminated, and minimal consequences. These
 
deviations from DBA analysis assumptions and design
 
requirements during shutdown conditions are allowed by the
 
LCO for required systems.
(continued)
AC Sources-Shutdown B 3.8.2 LaSalle 1 and 2 B 3.8.2-2 Revision 0 BASES APPLICABLE During MODES 1, 2, and 3, various deviations from the SAFETY ANALYSES analysis assumptions and design requirements are allowed (continued) within the ACTIONS. This allowance is in recognition that certain testing and maintenance activities must be conducted
 
provided an acceptable level of risk is not exceeded. 
 
During MODES 4 and 5, performance of a significant number of
 
required testing and maintenance activities is also
 
required. In MODES 4 and 5, the activities are generally
 
planned and administratively controlled. Relaxations from
 
typical MODE 1, 2, and 3 LCO requirements are acceptable
 
during shutdown MODES based on:
: a. The fact that time in an outage is limited. This is a risk prudent goal as well as utility economic
 
consideration.
: b. Requiring appropriate compensatory measures for certain conditions. These may include administrative
 
controls, reliance on systems that do not necessarily
 
meet typical design requirements applied to systems
 
credited in operating MODE analyses, or both.
: c. Prudent utility consideration of the risk associated with multiple activities that could affect multiple
 
systems. 
: d. Maintaining, to the extent practical, the ability to perform required functions (even if not meeting
 
MODE 1, 2, and 3 OPERABILITY requirements) with
 
systems assumed to function during an event.
 
In the event of an accident during shutdown, this LCO
 
ensures the capability of supporting systems necessary to
 
avoid immediate difficulty, assuming either a loss of all
 
offsite power or a loss of all onsite (diesel generator (DG)) power.
 
The AC sources satisfy Criterion 3 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO One offsite circuit capable of supplying onsite unit Class 1E power distribution subsystem(s) of LCO 3.8.8, "Distribution Systems-Shutdown," ensures that all required
 
Division 1 loads, Division 2 loads, and Division 3 loads are (continued)
AC Sources-Shutdown B 3.8.2 LaSalle 1 and 2 B 3.8.2-3 Revision 0 BASES LCO powered from offsite power. An OPERABLE unit DG, associated (continued) with a Division 1 or Division 2 Distribution System emergency bus required OPERABLE by LCO 3.8.8, ensures a
 
diverse power source is available to provide electrical
 
power support, assuming a loss of the offsite circuit. 
 
Similarly, when the High Pressure Core Spray (HPCS) System
 
is required to be OPERABLE, an OPERABLE Division 3 DG
 
ensures a diverse source of power for the HPCS System is
 
available to provide electrical power support, assuming a
 
loss of the offsite power circuit. Additionally, when the
 
Standby Gas Treatment (SGT) System, Control Room Area
 
Filtration (CRAF) System, or Control Room Area Ventilation
 
Air Conditioning System is required to be OPERABLE, one
 
qualified offsite circuit (normal or alternate) between the
 
offsite transmission network and the opposite unit Division
 
2 onsite Class 1E AC electrical power distribution subsystem
 
or an opposite unit DG capable of supporting the opposite
 
unit Division 2 onsite Class 1E AC electrical power
 
distribution subsystem is required to be OPERABLE. 
 
Together, OPERABILITY of the required offsite circuit(s) and
 
DG(s) ensure the availability of sufficient AC sources to
 
operate the plant in a safe manner and to mitigate the
 
consequences of postulated events during shutdown (e.g.,
fuel handling accidents, reactor vessel draindown).
 
The qualified offsite circuit(s) must be capable of
 
maintaining rated frequency and voltage while connected to
 
their respective emergency bus(es), and of accepting
 
required loads during an accident. Qualified offsite
 
circuits are those that are described in the UFSAR and are
 
part of the licensing basis for the plant. An OPERABLE
 
qualified normal offsite circuit consists of the required
 
incoming breaker(s) and disconnects from the 345 kV
 
switchyard to and including the SAT or UAT (backfeed mode),
the respective circuit path to and including the feeder
 
breakers to the required Division 1, 2, and 3 emergency
 
buses.
 
An OPERABLE qualified alternate offsite circuit consists of
 
the required incoming breaker(s) and disconnects from the
 
345 kV switchyard to and including the SAT or UAT (backfeed
 
mode), to and including the opposite unit 4.16 kV emergency
 
bus, the opposite unit circuit path to and including the
 
unit tie breakers (breakers 1414, 1424, 2414, and 2424), and
 
the respective circuit path to the required Division 1 and 2
 
emergency buses.
(continued)
AC Sources-Shutdown B 3.8.2 LaSalle 1 and 2 B 3.8.2-4 Revision 0 BASES LCO The required DG must be capable of starting, accelerating to (continued) rated speed and voltage, and connecting to its respective emergency bus on detection of bus undervoltage, and
 
accepting required loads. This sequence must be
 
accomplished within 13 seconds. Each DG must also be
 
capable of accepting required loads within the assumed
 
loading sequence intervals, and must continue to operate
 
until offsite power can be restored to the emergency buses.
 
These capabilities are required to be met from a variety of
 
initial conditions such as:  DG in standby with the engine
 
hot and DG in standby with the engine at ambient conditions.
 
Additional DG capabilities must be demonstrated to meet
 
required Surveillances, e.g., capability of the Division 1
 
and 2 DGs to revert to standby status on an ECCS signal
 
while operating in parallel test mode.
 
Proper sequencing of loads, including tripping of
 
nonessential loads, is a required function for DG
 
OPERABILITY. The necessary portions of the DG Cooling Water
 
System and Ultimate Heat Sink capable of providing cooling
 
to the required DG(s) are also required.
 
It is acceptable for divisions to be cross tied during
 
shutdown conditions, permitting a single offsite power
 
circuit to supply all required divisions. 
 
APPLICABILITY The AC sources required to be OPERABLE in MODES 4 and 5 and during movement of irradiated fuel assemblies in the
 
secondary containment provide assurance that:
: a. Systems to provide adequate coolant inventory makeup are available for the irradiated fuel in the core in
 
case of an inadvertent draindown of the reactor
 
vessel; 
: b. Systems needed to mitigate a fuel handling accident are available;
: c. Systems necessary to mitigate the effects of events that can lead to core damage during shutdown are
 
available; and
: d. Instrumentation and control capability is available for monitoring and maintaining the unit in a cold
 
shutdown condition or refueling condition.
(continued)
AC Sources-Shutdown B 3.8.2 LaSalle 1 and 2 B 3.8.2-5 Revision 0 BASES APPLICABILITY The AC power requirements for MODES 1, 2, and 3 are covered (continued) in LCO 3.8.1.
 
ACTIONS LCO 3.0.3 is not applicable while in MODE 4 or 5. However, since irradiated fuel assembly movement can occur in MODE 1, 2, or 3, the ACTIONS have been modified by a Note stating
 
that LCO 3.0.3 is not applicable. If moving irradiated fuel
 
assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify
 
any action. If moving irradiated fuel assemblies while in
 
MODE 1, 2, or 3, the fuel movement is independent of reactor
 
operations. Entering LCO 3.0.3 while in MODE 1, 2, or 3
 
would require the unit to be shutdown, but would not require
 
immediate suspension of movement of irradiated fuel
 
assemblies. The Note to the ACTIONS, "LCO 3.0.3 is not
 
applicable," ensures that the actions for immediate
 
suspension of irradiated fuel assembly movement are not
 
postponed due to entry into LCO 3.0.3.
 
A.1 An offsite circuit is considered inoperable if it is not
 
available to one required 4.16 kV emergency bus. If two or
 
more 4.16 kV emergency buses are required per LCO 3.8.8, division(s) with offsite power available may be capable of
 
supporting sufficient required features to allow
 
continuation of CORE ALTERATIONS, fuel movement, and
 
operations with a potential for draining the reactor vessel.
 
By the allowance of the option to declare required features
 
inoperable that are not capable of being powered from
 
offsite power, appropriate restrictions can be implemented
 
in accordance with the required feature(s) LCOs' ACTIONS. 
 
Required features remaining capable of being powered from a
 
qualified offsite circuit, even if that circuit is
 
considered inoperable because it is not capable of powering
 
other required features, are not declared inoperable by this
 
Required Action. For example, if both Division 1 and 2
 
emergency buses are required OPERABLE by LCO 3.8.8 and only
 
the Division 1 emergency buses are not capable of being
 
powered from offsite power, then only the required features
 
powered from Division 1 emergency buses are required to be
 
declared inoperable.
(continued)
AC Sources-Shutdown B 3.8.2 LaSalle 1 and 2 B 3.8.2-6 Revision 0 BASES ACTIONS A.2.1, A.2.2, A.2.3, A.2.4, B.1, B.2, B.3, and B.4 (continued)
With the offsite circuit not available to all required
 
divisions, the option still exists to declare all required
 
features inoperable per Required Action A.1. Since this
 
option may involve undesired administrative efforts, the
 
allowance for sufficiently conservative actions is made. 
 
With the required DG inoperable, the minimum required
 
diversity of AC power sources is not available. It is, therefore, required to suspend CORE ALTERATIONS, movement of
 
irradiated fuel assemblies in the secondary containment, and
 
activities that could potentially result in inadvertent
 
draining of the reactor vessel.
 
Suspension of these activities shall not preclude completion
 
of actions to establish a safe conservative condition. 
 
These actions minimize probability of the occurrence of
 
postulated events. It is further required to initiate
 
action immediately to restore the required AC sources and to
 
continue this action until restoration is accomplished in
 
order to provide the necessary AC power to the plant safety
 
systems.
 
The Completion Time of immediately is consistent with the
 
required times for actions requiring prompt attention. The
 
restoration of the required AC electrical power sources
 
should be completed as quickly as possible in order to
 
minimize the time during which the plant safety systems may
 
be without sufficient power.
 
Pursuant to LCO 3.0.6, the Distribution System ACTIONS are
 
not entered even if all AC sources to it are inoperable, resulting in de-energization. Therefore, the Required
 
Actions of Condition A have been modified by a Note to
 
indicate that when Condition A is entered with no AC power
 
to any required emergency bus, ACTIONS for LCO 3.8.8 must be
 
immediately entered. This Note allows Condition A to
 
provide requirements for the loss of the offsite circuit
 
whether or not a division is de-energized. LCO 3.8.8
 
provides the appropriate restrictions for the situation
 
involving a de-energized division.
(continued)
AC Sources-Shutdown B 3.8.2 LaSalle 1 and 2 B 3.8.2-7 Revision 0 BASES ACTIONS C.1 (continued)
When the HPCS System is required to be OPERABLE, and the
 
Division 3 DG is inoperable, the required diversity of AC
 
power sources to the HPCS System is not available. Since
 
these sources only affect the HPCS System, the HPCS System
 
is declared inoperable and the Required Actions of
 
LCO 3.5.2, "Emergency Core Cooling Systems-Shutdown,"
entered.
 
In the event all sources of power to Division 3 are lost, Condition A will also be entered and direct that the ACTIONS
 
of LCO 3.8.8 be taken. If only the Division 3 DG is
 
inoperable, and power is still supplied to HPCS System, 72 hours is allowed to restore the DG to OPERABLE. This is
 
reasonable considering the HPCS System will still perform
 
its function, absent a loss of offsite power.
 
D.1 When the SGT System, CRAF System, or Control Room Area
 
Ventilation Air Conditioning System is required to be
 
OPERABLE, and the required opposite unit Division 2 AC
 
source is inoperable, the associated SGT subsystem, CRAF
 
subsystem, and control room ventilation area air
 
conditioning subsystem are declared inoperable and the
 
Required Actions of the affected LCOs are entered.
 
The immediate Completion Time is consistent with the
 
required times for actions requiring prompt attention. The
 
restoration of the required opposite unit Division 2 AC
 
electrical power source should be completed as quickly as
 
possible in order to minimize the time during which the
 
aforementioned safety systems are without sufficient power.
 
SURVEILLANCE SR  3.8.2.1 REQUIREMENTS SR 3.8.2.1 requires the SRs from LCO 3.8.1 that are
 
necessary for ensuring the OPERABILITY of the AC sources in
 
other than MODES 1, 2, and 3 to be applicable. SR 3.8.1.8
 
is not required to be met since only one offsite circuit is
 
required to be OPERABLE. SR 3.8.1.17 is not required to be (continued)
AC Sources-Shutdown B 3.8.2 LaSalle 1 and 2 B 3.8.2-8 Revision 0 BASES SURVEILLANCE SR  3.8.2.1 (continued)
REQUIREMENTS met because the required OPERABLE DG(s) is not required to
 
undergo periods of being synchronized to the offsite
 
circuit. SR 3.8.1.20 is excepted because starting
 
independence is not required with the DG(s) that is not
 
required to be OPERABLE. Refer to the corresponding Bases
 
for LCO 3.8.1 for a discussion of each SR.
 
This SR is modified by two Notes. The reason for Note 1 is
 
to preclude requiring the OPERABLE DG(s) from being
 
paralleled with the offsite power network or otherwise
 
rendered inoperable during the performance of SRs, and to
 
preclude de-energizing a required 4.16 kV emergency bus or
 
disconnecting a required offsite circuit during performance
 
of SRs. With limited AC sources available, a single event
 
could compromise both the required circuit and the DG. It
 
is the intent that these SRs must still be capable of being
 
met, but actual performance is not required during periods
 
when the DG and offsite circuit are required to be OPERABLE.
 
Note 2 states that SRs 3.8.1.12 and 3.8.1.19 are not
 
required to be met when its associated ECCS subsystem(s) are
 
not required to be OPERABLE. These SRs demonstrate the DG
 
response to an ECCS initiation signal (either alone or in
 
conjunction with a loss of offsite power signal). This is
 
consistent with the ECCS instrumentation requirements that
 
do not require the ECCS initiation signals when the
 
associated ECCS subsystem is not required to be OPERABLE per
 
LCO 3.5.2, "ECCS-Shutdown."
REFERENCES None.
 
Diesel Fuel Oil and Starting Air B 3.8.3 LaSalle 1 and 2 B 3.8.3-1 Revision 33 B 3.8  ELECTRICAL POWER SYSTEMS
 
B 3.8.3  Diesel Fuel Oil and Starting Air
 
BASES
 
BACKGROUND Each diesel generator (DG) is provided with a storage tank and a day tank. The Division 1 and 2 DGs and the opposite unit Division 2 DG onsite fuel oil capacity is sufficient to operate that DG for a period of 7 days while the DG is supplying rated load. The Division 3 DG onsite fuel oil capacity is sufficient to operate that DG for a period of 7 days while the DG is supplying maximum expected load profile (Ref. 1). The maximum load demand is calculated using the assumption that at least two DGs are available. 
 
This onsite fuel oil capacity is sufficient to operate the
 
DGs for longer than the time to replenish the onsite supply
 
from outside sources.
 
Fuel oil is transferred from each storage tank to its
 
respective day tank by a transfer pump associated with each
 
storage tank. Redundancy of pumps and piping precludes the
 
failure of one pump, or the rupture of any pipe, valve, or
 
tank to result in the loss of more than one DG. All system
 
piping and components, except for fill piping and vents, are
 
located within the diesel buildings. The fuel oil level in
 
the storage tanks is indicated locally, and each storage
 
tank is provided with low level switches that actuate alarm
 
annunciators in the main control room.
 
For proper operation of the standby DGs, it is necessary to
 
ensure the proper quality of the fuel oil. Regulatory
 
Guide 1.137 (Ref. 2) addresses the recommended fuel oil
 
practices as supplemented by ANSI N195 (Ref. 3). The fuel
 
oil properties governed by these SRs are the water and
 
sediment content, the flashpoint and kinematic viscosity, specific gravity (or API gravity), and impurity level.
 
Each Division 1 and Division 2 DG has two air start
 
subsystems, each with adequate capacity for five successive
 
starts on the DG without recharging the air start receivers.
 
Each Division 3 DG has two air start subsystems, each with
 
adequate capacity for three successive starts on the DG
 
without recharging the air start receivers.
 
(continued)
Diesel Fuel Oil and Starting Air B 3.8.3 LaSalle 1 and 2 B 3.8.3-2 Revision 33 BASES  (continued)
 
APPLICABLE The initial conditions of Design Basis Accident (DBA) and SAFETY ANALYSES transient analyses in UFSAR, Chapter 6 (Ref. 4) and Chapter 15 (Ref. 5), assume Engineered Safety Feature (ESF)
 
systems are OPERABLE. The DGs are designed to provide
 
sufficient capacity, capability, redundancy, and reliability
 
to ensure the availability of necessary power to ESF systems
 
so that fuel, reactor coolant system, and containment design
 
limits are not exceeded. These limits are discussed in more
 
detail in the Bases for Section 3.2, Power Distribution
 
Limits; Section 3.5, Emergency Core Cooling (ECCS) and
 
Reactor Core Isolation Cooling (RCIC) System; and
 
Section 3.6, Containment Systems.
 
Since diesel fuel oil and starting air subsystems support
 
the operation of the standby AC power sources, they satisfy
 
Criterion 3 of 10 CFR 50.36(c)(2)(ii).
 
LCO Stored diesel fuel oil is required to have sufficient supply for 7 days of rated load operation for Division 1 and 2 DG, and for 7 days of maximum expected load profile for Division 3 DG. It is also required to meet specific standards for quality. This requirement, in conjunction with an ability
 
to obtain replacement supplies within 7 days, supports the
 
availability of DGs required to shut down the reactor and to
 
maintain it in a safe condition for an anticipated
 
operational occurrence (AOO) or a postulated DBA with loss
 
of offsite power. DG day tank fuel requirements, as well as
 
transfer capability from the storage tank to the day tank, are addressed in LCO 3.8.1, "AC Sources-Operating," and
 
LCO 3.8.2, "AC Sources-Shutdown."
 
The starting air system is required to have a minimum
 
capacity for five successive Division 1 and 2 DG starts and
 
three successive Division 3 DG starts without recharging the
 
air start receivers. While each air start receiver set has
 
the required capacity, both air start receiver sets (and
 
associated air start headers) per DG are required to ensure
 
OPERABILITY of the DG.
 
APPLICABILITY The AC sources (LCO 3.8.1 and LCO 3.8.2), are required to ensure the availability of the required power to shut down
 
the reactor and maintain it in a safe shutdown condition
 
after an AOO or a postulated DBA. Since stored diesel fuel (continued)
Diesel Fuel Oil and Starting Air B 3.8.3 LaSalle 1 and 2 B 3.8.3-3 Revision 0 BASES APPLICABILITY oil and starting air subsystems support LCO 3.8.1 and (continued) LCO 3.8.2, stored diesel fuel oil and starting air are required to be within limits when the associated DG is
 
required to be OPERABLE.
 
ACTIONS The ACTIONS Table is modified by a Note indicating that separate Condition entry is allowed for each DG. This is
 
acceptable, since the Required Actions for each Condition
 
provide appropriate compensatory actions for each inoperable
 
DG subsystem. Complying with the Required Actions for one
 
inoperable DG subsystem may allow for continued operation, and subsequent inoperable DG subsystem(s) are governed by
 
separate Condition entry and application of associated
 
Required Actions. 
 
A.1 With stored fuel oil level not within the specified limit, the 7 day fuel oil supply for a DG is not available. 
 
However, the Condition is restricted to fuel oil level
 
reductions that maintain at least a 6 day supply. These
 
circumstances may be caused by events such as:
: a. Full load operation required after an inadvertent start while at minimum required level; or
: b. Feed and bleed operations that may be necessitated by increasing particulate levels or any number of other
 
oil quality degradations.
 
This restriction allows sufficient time for obtaining the
 
requisite replacement volume and performing the analyses
 
required prior to addition of the fuel oil to the tank. A
 
period of 48 hours is considered sufficient to complete
 
restoration of the required level prior to declaring the DG
 
inoperable. This period is acceptable based on the
 
remaining capacity (> 6 days), the fact that actions will be
 
initiated to obtain replenishment, and the low probability
 
of an event during this brief period.
(continued)
Diesel Fuel Oil and Starting Air B 3.8.3 LaSalle 1 and 2 B 3.8.3-4 Revision 0 BASES ACTIONS B.1 (continued)
This Condition is entered as a result of a failure to meet
 
the acceptance criterion for particulates. Normally, trending of particulate levels allows sufficient time to
 
correct high particulate levels prior to reaching the limit
 
of acceptability. Poor sample procedures (bottom sampling),
contaminated sampling equipment, and errors in laboratory
 
analysis can produce failures that do not follow a trend. 
 
Since the presence of particulates does not mean failure of
 
the fuel oil to burn properly in the diesel engine, since
 
particulate concentration is unlikely to change
 
significantly between Surveillance Frequency intervals, and
 
since proper engine performance has been recently
 
demonstrated (within 31 days), it is prudent to allow a
 
brief period prior to declaring the associated DG
 
inoperable. The 7 day Completion Time allows for further
 
evaluation, resampling, and re-analysis of the DG fuel oil.
 
C.1 With the new fuel oil properties defined in the Bases for
 
SR 3.8.3.2 not within the required limits, a period of
 
30 days is allowed for restoring the stored fuel oil
 
properties. This period provides sufficient time to test
 
the stored fuel oil to determine that the new fuel oil, when
 
mixed with previously stored fuel oil, remains acceptable, or to restore the stored fuel oil properties. This
 
restoration may involve feed and bleed procedures, filtering, or a combination of these procedures. Even if a
 
DG start and load was required during this time interval and
 
the fuel oil properties were outside limits, there is high
 
likelihood that the DG would still be capable of performing
 
its intended function.
 
D.1 With starting air receiver pressure < 200 psig, sufficient
 
capacity for five successive starts for the Division 1 or 2
 
DG or three successive starts for the Division 3 DG, as
 
applicable, does not exist. However, as long as the
 
receiver pressure is > 165 psig, there is adequate capacity (continued)
Diesel Fuel Oil and Starting Air B 3.8.3 LaSalle 1 and 2 B 3.8.3-5 Revision 33 BASES ACTIONS D.1 (continued) for at least one start, and the DG can be considered
 
OPERABLE while the air receiver pressure is restored to the
 
required limit. A period of 48 hours is considered
 
sufficient to complete restoration to the required pressure
 
prior to declaring the DG inoperable. This period is
 
acceptable based on the remaining air start capacity, the
 
fact that most DG starts are accomplished on the first
 
attempt, and the low probability of an event during this
 
brief period.
 
E.1 With a Required Action and associated Completion Time of
 
Condition A, B, C, or D not met, or the stored diesel fuel
 
oil or starting air subsystem not within limits of this
 
Specification for reasons other than addressed by
 
Conditions A through D, the associated DG may be incapable
 
of performing its intended function and must be immediately
 
declared inoperable.
 
SURVEILLANCE SR  3.8.3.1 REQUIREMENTS This SR provides verification that there is an adequate
 
inventory of fuel oil in the associated fuel oil storage
 
tank for the Division 1 and 2 DGs and the opposite unit
 
Division 2 DG. This volume plus a minimum of 250 gallons of fuel in the day tank that is verified by SR 3.8.1.4 ensures adequate fuel is available to support each DG's operation for 7 days at rated load. This SR provides verification that there is an adequate inventory of fuel oil in the associated fuel oil storage tank and day tank for the Division 3 DG to support its operation for 7 days at maximum expected load profile. Each DG's storage tank supplies fuel to ensure an adequate supply is maintained in its respective day tank. Each DG's day tank supplies fuel to the DG. The 7 day period is sufficient time to place the unit in a safe
 
shutdown condition and to bring in replenishment fuel from
 
an offsite location.
 
The 31 day Frequency is adequate to ensure that a sufficient
 
supply of fuel oil is available, since low level alarms are (continued)
Diesel Fuel Oil and Starting Air B 3.8.3 LaSalle 1 and 2 B 3.8.3-6 Revision 33 BASES SURVEILLANCE SR  3.8.3.1 (continued)
REQUIREMENTS provided and unit operators would be aware of any large uses of fuel oil during this period.
 
SR  3.8.3.2
 
The tests of new fuel prior to addition to the storage tanks are a means of determining whether new fuel oil is of the
 
appropriate grade and has not been contaminated with
 
substances that would have an immediate detrimental impact
 
on diesel engine combustion and operation. If results from
 
these tests are within acceptable limits, the fuel oil may
 
be added to the storage tanks without concern for
 
contaminating the entire volume of fuel oil in the storage
 
tanks. These tests are to be conducted prior to adding the
 
new fuel to the storage tank(s). The tests, limits, and
 
applicable ASTM Standards are as follows:
: a. Sample the new fuel oil in accordance with ASTM D4057-95 (Ref. 6);
: b. Verify in accordance with the tests specified in ASTM D975-98b (Ref. 6) that the sample has:  1) an absolute
 
specific gravity at 60
&deg;F of  0.83 and  0.89 (or an API gravity at 60
&deg;F of  27 and  39) when tested in accordance with ASTM D1298-99 (Ref. 6); 2) a kinematic
 
viscosity at 40
&deg;C of  1.9 centistokes and  4.1 centistokes when tested in accordance with ASTM D445-
 
97 (Ref. 6); and 3) a flash point of  125&deg;F when tested in accordance with ASTM D93-99c (Ref. 6); and
: c. Verify that the new fuel oil has a clear and bright appearance with proper color when tested in accordance
 
with ASTM D4176-93 (Ref. 6) or a water and sediment
 
content within limits when tested in accordance with
 
ASTM D2709-96e (Ref. 6). The clear and bright
 
appearance with proper color test is only applicable
 
to fuels that meet the ASTM color requirement (i.e.,
ASTM color 5 or less).
 
Failure to meet any of the above limits is cause for
 
rejecting the new fuel oil, but does not represent a failure
 
to meet the LCO since the fuel oil is not added to the
 
storage tanks.
(continued)
Diesel Fuel Oil and Starting Air B 3.8.3 LaSalle 1 and 2 B 3.8.3-7 Revision 33 BASES SURVEILLANCE SR  3.8.3.2 (continued)
REQUIREMENTS Following the initial new fuel oil sample, the fuel oil is
 
analyzed within 31 days following addition of the new fuel
 
oil to the fuel oil storage tank(s) to establish that the
 
other properties specified in Table 1 of ASTM D975-98b (Ref. 6) are met for new fuel oil when tested in accordance
 
with ASTM D975-98b (Ref. 6), except that the analysis for
 
sulfur may be performed in accordance with ASTM D1552-95 (Ref. 6), ASTM D2622-98 (Ref. 6), or ASTM D4294-98 (Ref. 6).
 
The 31 day period is acceptable because the fuel oil
 
properties of interest, even if not within stated limits, would not have an immediate effect on DG operation. This
 
Surveillance ensures the availability of high quality fuel
 
oil for the DGs.
 
Fuel oil degradation during long term storage shows up as an
 
increase in particulate, mostly due to oxidation. The
 
presence of particulate does not mean that the fuel oil will
 
not burn properly in a diesel engine. However, the
 
particulate can cause fouling of filters and fuel oil
 
injection equipment, which can cause engine failure.
 
Particulate concentrations should be determined in
 
accordance with ASTM D5452-98 (Ref. 6). This method
 
involves a gravimetric determination of total particulate
 
concentration in the fuel oil and has a limit of 10 mg/l. 
 
It is acceptable to obtain a field sample for subsequent
 
laboratory testing in lieu of field testing.
 
The Frequency of this Surveillance takes into consideration
 
fuel oil degradation trends indicating that particulate
 
concentration is unlikely to change between Frequency
 
intervals.
 
SR  3.8.3.3
 
This Surveillance ensures that, without the aid of the
 
refill compressor, sufficient air start capacity for each DG
 
is available. The system design requirements provide for a
 
minimum of five engine starts for each Division 1 and
 
Division 2 DG, and three engine starts for each Division 3
 
DG without recharging. The pressure specified in this SR is
 
intended to support the lowest value at which the required
 
number of starts can be accomplished.
 
                                                                    (continued)
Diesel Fuel Oil and Starting Air B 3.8.3 LaSalle 1 and 2 B 3.8.3-8  Revision 0 BASES SURVEILLANCE SR  3.8.3.3 (continued)
REQUIREMENTS The 31 day Frequency takes into account the capacity, capability, redundancy, and diversity of the AC sources and
 
other indications available in the control room, including
 
alarms, to alert the operator to below normal air start
 
pressure.
 
SR  3.8.3.4
 
Microbiological fouling is a major cause of fuel oil
 
degradation. There are numerous bacteria that can grow in
 
fuel oil and cause fouling, but all must have a water
 
environment in order to survive. Removal of water from the
 
fuel oil storage tank once every 92 days eliminates the
 
necessary environment for bacterial survival. This is the
 
most effective means of controlling microbiological fouling.
 
In addition, it eliminates the potential for water
 
entrainment in the fuel oil during DG operation. Water may
 
come from any of several sources, including condensation, ground water, rain water, contaminated fuel oil, and
 
breakdown of the fuel oil by bacteria. Frequent checking
 
for and removal of accumulated water minimizes fouling and
 
provides data regarding the watertight integrity of the fuel
 
oil system. The Surveillance Frequencies are established by
 
Regulatory Guide 1.137 (Ref. 2). This SR is for preventive
 
maintenance. The presence of water does not necessarily
 
represent a failure of this SR provided that accumulated
 
water is removed during performance of this Surveillance.
 
REFERENCES 1. UFSAR, Section 9.5.4.
: 2. Regulatory Guide 1.137.
: 3. ANSI N195, Appendix B, 1976.
: 4. UFSAR, Chapter 6.
: 5. UFSAR, Chapter 15.
: 6. ASTM Standards:  D4057-95; D975-98b; D1298-99; D445-97; D93-99c; D4176-93; D2709-96e; D1552-95; D2622-98;
 
D4294-98; D5452-98.
 
DC Sources-Operating B 3.8.4 LaSalle 1 and 2 B 3.8.4-1 Revision 27 B 3.8  ELECTRICAL POWER SYSTEMS
 
B 3.8.4  DC Sources-Operating
 
BASES
 
BACKGROUND The station DC electrical power system provides the AC emergency power system with control power. It also provides
 
both motive and control power to selected safety related
 
equipment. As required by 10 CFR 50, Appendix A, GDC 17 (Ref. 1), the DC electrical power system is designed to have
 
sufficient independence, redundancy, and testability to
 
perform its safety functions, assuming a single failure.
 
The DC electrical power system also conforms to the
 
requirements of Regulatory Guide 1.6 (Ref. 2) and IEEE-308 (Ref. 3).
 
The 125 VDC electrical power system consists of three
 
independent Class 1E DC electrical power subsystems, Divisions 1, 2, and 3. The 250 VDC electric power system
 
consists of one Class 1E DC electrical power subsystem, Division 1. Each subsystem consists of a battery, associated battery charger(s), and all the associated control equipment and interconnecting cabling.
 
During normal operation, the DC loads are powered from the
 
battery chargers with the batteries floating on the system.
 
In case of loss of normal power to the battery charger, the
 
DC loads are automatically powered from the batteries.
 
The Division 1 safety related DC power source consists of
 
one 58 cell, 125 V and one 116 cell, 250 V battery bank and associated full capacity battery charger(s). The Division 1 125 VDC power source provides the control power for its
 
associated Class 1E AC power load group, 4.16 kV switchgear, and 480 V load centers and control power for non-Class 1E
 
loads. Also, the 125 VDC power sources provide DC power to
 
the emergency lighting system, diesel generator (DG)
 
auxiliaries, and the DC control power for the Engineered
 
Safety Feature (ESF) and non-ESF systems. The 250 VDC power
 
source supplies power to the Reactor Core Isolation Cooling (RCIC) System, and RCIC primary containment isolation valves (PCIVs). It also supplies power to the main turbine
 
emergency bearing oil pumps, main generator emergency seal
 
oil pumps, and the process computer, however, these are not
 
Technical Specification related loads.
(continued)
DC Sources-Operating B 3.8.4 LaSalle 1 and 2 B 3.8.4-2 Revision 27 BASES BACKGROUND The Division 2 safety related DC power source consists of a (continued) 58 cell, 125 V battery bank and associated full capacity chargers. This 125 V battery provides the control power for its associated Class 1E AC power load group, 4.16 kV
 
switchgear, and 480 V load centers and control power for
 
non-Class 1E loads. Also, this 125 V battery provides DC
 
power to the emergency lighting system, diesel generator (DG) auxiliaries, and the DC control power for ESF and non-
 
ESF systems.
 
The Division 3 safety related DC power source consists of a 58 cell, 125 V battery bank and associated full capacity charger, and provides power for the High Pressure Core Spray (HPCS) DG field flashing control logic and switching
 
function of 4.16 kV Division 3 breakers. It also provides
 
power for the HPCS System logic, HPCS DG control and
 
protection, and Division 3 related controls.
 
The opposite unit Division 2 safety related DC power source
 
consists of a 58 cell, 125 V battery bank and associated full capacity chargers. This 125 V battery provides the control power for its associated Class 1E AC power load
 
group, 4.16 kV switchgear, and 480 V load centers and
 
control power for non-Class 1E loads. Also, this 125 V
 
battery provides DC power to the opposite unit's emergency
 
lighting system, diesel generator (DG) auxiliaries, and DC
 
control power for the ESF and non-ESF systems.
 
The DC power distribution system is described in more detail
 
in the Bases for LCO 3.8.7, "Distribution
 
Systems-Operating," and LCO 3.8.8, "Distribution
 
Systems-Shutdown."
 
Each DC battery subsystem is separately housed in a ventilated room apart from its charger and distribution
 
centers. Each subsystem is located in an area separated
 
physically and electrically from the other subsystems to
 
ensure that a single failure in one subsystem does not cause
 
a failure in a redundant subsystem. There is no sharing  between redundant Class 1E subsystems such as batteries, battery chargers, or distribution panels.
 
Each Division 1, 2, and 3 battery has adequate storage capacity to meet the duty cycle(s) discussed in the UFSAR, Section 8.3.2 (Ref. 4). The battery is designed with (continued)
DC Sources-Operating B 3.8.4 LaSalle 1 and 2 B 3.8.4-3 Revision 27 BASES BACKGROUND additional capacity above that required by the design duty    (continued) cycle to allow for temperature variations and other factors.
 
Based on LaSalle Station battery sizing calculations,      Divisions 1 and 2 batteries have a design margin of at least 5% (Ref. 10). The Division 3 batteries have a design margin of at least 10% (Ref. 10).   
 
The backup battery chargers associated with the Division 1 and Division 2 125 VDC system are fully qualified chargers that are powered from a diesel generator backed safety related (Class 1E) distribution system, and are fully capable of supporting system design requirements. These 100% capacity battery chargers are the "alternate means" for supporting the Division 1 and Division 2 125 VDC systems.   
 
The batteries for a DC electrical power subsystem are sized
 
to produce required capacity at 80% of nameplate rating, corresponding to warranted capacity at end of life cycles
 
and the 100% design demand. The minimum design voltage limit is 105/210 V.
The battery cells are of flooded lead acid construction with a nominal specific gravity of 1.215. This specific gravity corresponds to an open circuit battery voltage of approximately 120 V for a 58 cell battery and 240 V for a 116 cell battery (i.e., cell voltage of 2.065 volts per cell (Vpc)). The open circuit voltage is the voltage maintained when there is no charging or discharging. Once fully charged with its open circuit voltage >
2.065 Vpc, the battery will maintain its capacity for 30 days without further charging per manufacturers instructions. Optimal long term performance however, is obtained by maintaining a float voltage 2.17 Vpc to 2.25 Vpc for Division 1 and Division 2 and maintaining a float voltage of 2.20 Vpc to 2.25 Vpc for Division 3. This provides adequate over-potential, which limits the formation of lead sulfate and self discharge. The nominal float voltage of 2.23 Vpc corresponds to a total float voltage output of 129.3 V for a 58 cell battery and 258.7 V for a 116 cell battery as discussed in the UFSAR, Section 8.3.2 (Ref. 4).
 
Each Division 1, 2, and 3 DC electrical power subsystem
 
battery charger has ample power output capacity for the
 
steady state operation of connected loads required during (continued)
DC Sources-Operating B 3.8.4 LaSalle 1 and 2 B 3.8.4-4 Revision 27 BASES BACKGROUND normal operation, while at the same time maintaining its (continued) battery bank fully charged. Each battery charger has sufficient capacity to restore the battery bank from the design minimum charge to its fully charged state within 24 hours while supplying normal steady state loads (Ref. 4). 
 
The battery charger is normally in the float-charge mode.
Float-charge is the condition in which the charger is supplying the connected loads and the battery cells are receiving adequate current to optimally charge the battery.
This assures the internal losses of the battery are overcome and the battery is maintained in a fully charged state.
When desired, the charger can be placed in the equalize mode. The equalize mode is at a higher voltage than the float mode. The battery charger is operated in the equalize mode after a battery discharge or for routine maintenance.
Following a battery discharge, the battery recharge characteristic accepts current at the current limit of the battery charger (if the discharge was significant, e.g., following a battery service test) until the battery terminal voltage approaches the charger voltage setpoint. Charging current then reduces exponentially during the remainder of the recharge cycle. 
 
APPLICABLE The initial conditions of Design Basis Accident (DBA) and SAFETY ANALYSES transient analyses in the UFSAR, Chapter 6 (Ref. 5), and Chapter 15 (Ref. 6), assume that ESF systems are OPERABLE.
 
The DC electrical power system provides normal and emergency
 
DC electrical power for the DGs, emergency auxiliaries, and
 
control and switching during all MODES of operation.
 
The OPERABILITY of the DC subsystems is consistent with the
 
initial assumptions of the accident analyses and is based
 
upon meeting the design basis of the unit. This includes
 
maintaining DC sources OPERABLE during accident conditions
 
in the event of:
: a. An assumed loss of all offsite AC power or of all 
 
onsite AC power; and
: b. A worst case single failure.
 
The DC sources satisfy Criterion 3 of 10CFR50.36(c)(2)(ii).
 
(continued)
DC Sources-Operating B 3.8.4 LaSalle 1 and 2 B 3.8.4-5 Revision 27 BASES (continued)
 
LCO The Division 1 125 VDC and 250 VDC, Division 2 125 VDC, and Division 3 125 VDC, and opposite unit Division 2 125 VDC
 
electrical power subsystems, each subsystem consisting of
 
one battery, one required battery charger, and the corresponding control equipment and interconnecting cabling
 
supplying power to the associated bus within the divisions, are required to be OPERABLE to ensure the availability of
 
the required power to shut down the reactor and maintain it
 
in a safe condition after an anticipated operational
 
occurrence (AOO) or a postulated DBA. Loss of any DC
 
electrical power subsystem does not prevent the minimum
 
safety function from being performed (Ref. 4).
 
APPLICABILITY The DC electrical power sources are required to be OPERABLE in MODES 1, 2, and 3 to ensure safe unit operation and to
 
ensure that:
: a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result
 
of AOOs or abnormal transients; and
: b. Adequate core cooling is provided, and containment integrity and other vital functions are maintained in
 
the event of a postulated DBA.
 
The DC electrical power requirements for MODES 4 and 5 and
 
other conditions in which the DC electrical power sources
 
are required are addressed in LCO 3.8.5, "DC Sources-
 
Shutdown."
ACTIONS A.1, A.2, and A.3 Condition A represents one redundant ESF division with one required battery charger inoperable or the inoperability of one required battery charger on the 250 VDC electrical power subsystem supporting RCIC (e.g., the voltage limit of SR 3.8.4.1 is not maintained). The ACTIONS provide a tiered response that focuses on returning the battery to the fully charged state and restoring the fully qualified charger to OPERABLE status in a reasonable time period. Required (continued)
DC Sources-Operating B 3.8.4 LaSalle 1 and 2 B 3.8.4-6 Revision 27 BASES ACTIONS A.1, A.2, and A.3 (continued)
Action A.1 requires that the battery terminal voltage be restored to greater than or equal to the minimum established float voltage within 2 hours. This time provides for returning the inoperable charger to OPERABLE status or providing an alternate means of restoring battery terminal voltage to greater than or equal to the minimum established float voltage. Restoring the battery terminal voltage to greater than or equal to the minimum established float voltage provides good assurance that, within 12 hours, the battery will be restored to its fully charged condition (Required Action A.2) from any discharge that might have occurred due to the charger inoperability. A discharged battery having terminal voltage of at least the minimum established float voltage indicates that the battery is on the exponential charging current portion (the second part) of its recharge cycle. The time to return a battery to its fully charged state under this condition is simply a function of the amount of the previous discharge and the recharge characteristic of the battery. Thus there is good assurance of fully recharging the battery within 12 hours, avoiding a premature shutdown with its own attendant risk.
If battery terminal float voltage cannot be restored to greater than or equal to the minimum established float voltage within 2 hours, and the charger is not operating in the current-limiting mode, a faulty charger is indicated. A faulty charger that is incapable of maintaining established battery terminal float voltage does not provide adequate assurance that it can revert to and operate properly in the current limit mode that is necessary during the recovery period following a battery discharge event for which the DC system is designed.
If the charger is operating in the current-limit mode after 2 hours that is an indication that the battery is partially discharged and its capacity margins will be reduced. The time to return the battery to its fully charged condition in this case is a function of the battery charger capacity, the amount of loads on the associated DC system, the amount of the previous discharge, and the recharge characteristic of the battery. The charge time can be extensive, and there is not adequate assurance that it can be recharged within 12 hours (Required Action A.2).
  (continued)
DC Sources-Operating B 3.8.4 LaSalle 1 and 2 B 3.8.4-7 Revision 27 BASES ACTIONS A.1, A.2, and A.3 (continued)
Required Action A.2 requires that the battery float current be verified as less than or equal to 2 amps. This indicates that, if the battery has been discharged as a result of the inoperable battery charger, it has now been fully recharged.
If at the expiration of the initial 12 hour period the battery float current is not less than or equal to 2 amps, this indicates there may be additional battery problems and the battery must be declared inoperable.
Required Action A.3 limits the restoration time for the inoperable battery charger to 7 days. This action is applicable if an alternate means of restoring battery terminal voltage to greater than or equal to the minimum established float voltage has been used (e.g., balance of plant non-Class 1E battery charger). The 7 day Completion Time reflects a reasonable time to effect restoration of the qualified battery charger to OPERABLE status.
 
B.1    Condition B represents one division with a loss of ability to completely respond to an event, and a potential loss of
 
ability to remain energized during normal operation. It is, therefore, imperative that the operator's attention focus on
 
stabilizing the unit, minimizing the potential for complete
 
loss of DC power to the affected division. The 2 hour limit
 
is consistent with the allowed time for an inoperable DC
 
distribution system division.
 
If one of the Division 1 or 2 125 VDC electrical power
 
subsystems is inoperable for reasons other than Condition A (e.g., inoperable battery), the remaining DC electrical power subsystems have the capacity to support a safe
 
shutdown and to mitigate an accident condition. Since a subsequent worst case single failure could, however, result
 
in the loss of minimum necessary DC electrical subsystems, continued power operation should not exceed 2 hours. The
 
2 hour Completion Time is based on Regulatory Guide 1.93 (Ref. 7) and reflects a reasonable time to assess unit
 
status as a function of the inoperable DC electrical power
 
subsystem and, if the DC electrical power subsystem is not
 
restored to OPERABLE status, to prepare to effect an orderly
 
and safe unit shutdown.
(continued)
DC Sources-Operating B 3.8.4 LaSalle 1 and 2 B 3.8.4-8 Revision 27 BASES ACTIONS C.1 (continued)  If the Division 3 battery cannot be maintained OPERABLE, the required Division 3 battery charger cannot be restored, or the Division 3 DC electrical power subsystem is inoperable for reasons other than Condition A (e.g., inoperable battery), the HPCS System may be incapable of performing its intended function and must be immediately declared
 
inoperable. This declaration also requires entry into
 
applicable Conditions and Required Actions of LCO 3.5.1, "ECCS-Operating."
 
D.1 If the Division 1 250 VDC battery cannot be maintained OPERABLE, the required 250 VDC battery charger cannot be restored, or the Division 1 250 VDC electrical power subsystem is inoperable for reasons other than Condition A (e.g., inoperable battery), the RCIC System and the RCIC DC powered PCIVs may be incapable of performing their intended
 
functions and must be immediately declared inoperable. This
 
declaration also requires entry into applicable Conditions
 
and Required Actions of LCO 3.5.3, "RCIC System," and LCO
 
3.6.1.3, "PCIVs."
 
E.1 If the opposite unit Division 2 battery cannot be maintained OPERABLE, the required opposite unit Division 2 battery charger cannot be restored, or the opposite unit Division 2 125 VDC electrical power subsystem is inoperable for reasons other than Condition A (e.g., inoperable battery), certain redundant Division 2 features (e.g., a standby gas treatment
 
subsystem) will not function if a design basis event were to
 
occur. Therefore, a 7 day Completion Time is provided to
 
restore the opposite unit Division 2 125 VDC electrical
 
power subsystem to OPERABLE status. The 7 day Completion
 
Time takes into account the capacity and capability of the
 
remaining DC electrical power subsystems, and is based on
 
the shortest restoration time allowed for the systems
 
affected by the inoperable DC electrical power subsystem in
 
the respective system specifications.
(continued)
DC Sources-Operating B 3.8.4 LaSalle 1 and 2 B 3.8.4-9 Revision 32 BASES ACTIONS F.1 and F.2 (continued)
If the inoperable Division 1, Division 2, or opposite unit
 
Division 2 DC electrical power subsystem cannot be restored
 
to OPERABLE status within the associated Completion Time, the unit must be brought to a MODE in which the LCO does not
 
apply. To achieve this status, the plant must be brought to
 
at least MODE 3 within 12 hours and to MODE 4 within
 
36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant
 
conditions from full power conditions in an orderly manner
 
and without challenging plant systems. The Completion Time
 
to bring the unit to MODE 4 is consistent with the time
 
specified in Regulatory Guide 1.93 (Ref. 7).
 
G.1  If a Division 1 or 2 125 VDC electrical power subsystem is inoperable for reasons other than Condition A and not restored within the provided Completion Time, the plant must be brought to a condition in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 11) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE The Surveillances are modified by two Notes to clearly REQUIREMENTS identify how the Surveillances apply to the given unit and opposite unit DC electrical power sources. Note 1 states
 
that SR 3.8.4.1 through SR 3.8.4.3 are applicable only to
 
the given unit DC electrical power sources and Note 2 states
 
that SR 3.8.4.4 is applicable only to the opposite unit DC
 
electrical power sources. These Notes are necessary since
 
opposite unit DC electrical power sources are not required
 
to perform all of the requirements of the given unit DC
 
electrical power sources (e.g., the opposite unit battery is
 
not required to perform SR 3.8.4.2 and 3.8.4.3 under certain
 
conditions when not in MODE 1, 2, or 3). (continued)
DC Sources-Operating B 3.8.4 LaSalle 1 and 2 B 3.8.4-10 Revision 32 BASES SURVEILLANCE SR  3.8.4.1 REQUIREMENTS (continued) Verifying battery terminal voltage while on float charge helps to ensure the effectiveness of the battery chargers, which support the ability of the batteries to perform their
 
intended function. Float charge is the condition in which
 
the charger is supplying the continuous charge required to
 
overcome the internal losses of a battery and maintain the
 
battery in a fully charged state while supplying the
 
continuous steady state loads of the associated DC
 
subsystem. On float charge, battery cells will receive
 
adequate current to optimally maintain a charge on the
 
battery. The voltage requirements are based on the nominal
 
design voltage of the battery and are consistent with the
 
minimum float voltage established by the battery
 
manufacturer (2.17 Vpc or 125.86 V for the 125 V Div 1 and
 
Div 2 batteries, 2.20 Vpc or 127.60 V for the 125 V Div 3
 
battery and 2.17 Vpc or 251.72 for the 250 volt battery at
 
the battery terminals). This voltage maintains the battery
 
plates in a condition that supports maintaining the grid
 
life (expected to be approximately 20 years). The 7 day
 
Frequency is consistent with manufacturers recommendations
 
and IEEE-450 (Ref. 8).
 
SR  3.8.4.2
 
This SR verifies the design capacity of the battery chargers. According to Regulatory Guide 1.32 (Ref. 9), the
 
battery charger supply is recommended to be based on the
 
largest combined demands of the various steady state loads
 
and the charging capacity to restore the battery from the
 
design minimum charge state to the fully charged state, irrespective of the status of the unit during these demand
 
occurrences. The minimum required amperes and duration
 
ensure that these requirements can be satisfied.
 
This SR provides two options. One option requires that each
 
125 V and 250 V Division 1 and 2 battery charger be capable
 
of supplying 200 amps (50 amps for the 125 V Division 3
 
charger) at the minimum established float voltage for
 
4 hours. The ampere requirements are based on the output
 
rating of the chargers. The voltage requirements are based
 
on the charger voltage level after a response to a loss of
 
AC power. The time period is sufficient for the charger
 
temperature to have stabilized and to have been maintained
 
for at least 2 hours.
(continued)
DC Sources-Operating B 3.8.4 LaSalle 1 and 2 B 3.8.4-11 Revision 27 BASES SURVEILLANCE SR  3.8.4.2 (continued)
REQUIREMENTS The other option requires that each battery charger be capable of recharging the battery after a service test coincident with supplying the largest coincident demands of the various continuous steady state loads (irrespective of the status of the plant during which these demands occur).
This level of loading may not be normally available following the battery service test and will need to be supplemented with additional loads. The duration for this test may be longer than the charger sizing criteria since the battery recharge is affected by float voltage, temperature, and the exponential decay in charging current.
The battery is recharged when the measured charging current is < 2 amps. The Surveillance Frequency is acceptable, given the
 
administrative controls existing to ensure adequate charger
 
performance during these 24 month intervals. In addition, this Frequency is intended to be consistent with expected
 
fuel cycle lengths.
 
SR  3.8.4.3
 
A battery service test is a special test of the battery's
 
capability, as found, to satisfy the design requirements (battery duty cycle) of the DC electrical power system. The
 
discharge rate and test length correspond to the design duty
 
cycle requirements as specified in Reference 4.
 
The Surveillance Frequency of 24 months is acceptable, given
 
unit conditions required to perform the test and the other
 
requirements existing to ensure adequate battery performance
 
during these 24 month intervals. In addition, this
 
Frequency is intended to be consistent with expected fuel
 
cycle lengths.
 
This SR is modified by two Notes. Note 1 allows the
 
performance of a modified performance discharge test in lieu
 
of a service test. This substitution is acceptable because a modified performance discharge test represents a more
 
severe test of battery capacity than SR 3.8.4.3. The reason for Note 2 is that performing the Surveillance would remove
 
a required 125 VDC electrical power subsystem from service, (continued)
DC Sources-Operating B 3.8.4 LaSalle 1 and 2 B 3.8.4-12 Revision 27 BASES SURVEILLANCE SR  3.8.4.3 (continued)
REQUIREMENTS perturb the electrical distribution system, and challenge 
 
safety systems. This restriction from normally performing
 
the Surveillance in MODE 1 or 2 is further amplified to
 
allow portions of the Surveillance to be performed for the
 
purpose of reestablishing OPERABILITY (e.g., post work
 
testing following corrective maintenance, corrective
 
modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an
 
assessment determines plant safety is maintained or
 
enhanced. This assessment shall, as a minimum, consider the
 
potential outcomes and transients associated with a failed
 
partial Surveillance, a successful partial Surveillance, and
 
a perturbation of the offsite or onsite system when they are
 
tied together or operated independently for the partial
 
Surveillance; as well as the operator procedures available
 
to cope with these outcomes. These shall be measured
 
against the avoided risk of a plant shutdown and startup to
 
determine that plant safety is maintained or enhanced when
 
portions of the Surveillance are performed in MODE 1 or 2.
 
Risk insights or deterministic methods may be used for this
 
assessment. Credit may be taken for unplanned events that
 
satisfy the Surveillance.
 
SR  3.8.4.4
 
With the exception of this Surveillance, all other
 
Surveillances of this Specification (SR 3.8.4.1 through
 
3.8.4.3) are applied to the given unit DC sources. This Surveillance is provided to direct that appropriate
 
Surveillances for the required opposite unit DC source are
 
governed by the applicable opposite unit Technical
 
Specifications. Performance of the applicable opposite unit
 
Surveillances will satisfy the opposite unit requirements as
 
well as satisfy the given unit Surveillance Requirement.
 
The Frequency required by the applicable opposite unit SR
 
also governs performance of that SR for the given unit.
 
(continued)
DC Sources-Operating B 3.8.4 LaSalle 1 and 2 B 3.8.4-13 Revision 32 BASES
 
SURVEILLANCE SR  3.8.4.4 (continued)
REQUIREMENTS As noted, if the opposite unit is in MODE 4 or 5, or moving
 
irradiated fuel assemblies in secondary containment, SR 3.8.4.2 and SR 3.8.4.3 are not required to be performed.
 
This ensures that a given unit SR will not require an
 
opposite unit SR to be performed, when the opposite unit 
 
Technical Specifications exempts performance of an opposite
 
unit SR (however, as stated in the opposite unit SR 3.8.5.1
 
Note 1, while performance of an SR is exempted, the SR must
 
still be met).
 
REFERENCES 1. 10 CFR 50, Appendix A, GDC 17.
: 2. Regulatory Guide 1.6, March 10, 1971.
: 3. IEEE Standard 308, 1971.
: 4. UFSAR, Section 8.3.2.
: 5. UFSAR, Chapter 6.
: 6. UFSAR, Chapter 15.
: 7. Regulatory Guide 1.93, December 1974.
: 8. IEEE Standard 450, 1975.
: 9. Regulatory Guide 1.32, August 1972.
: 10. NRC Regulatory Commitment documented in letter from D. M. Benyak to NRC, "Additional Information
 
Supporting the License Amendment Request Associated
 
with Direct Current Electrical Request," dated
 
September 13, 2006.
: 11. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants," December 2002.
 
DC Sources-Shutdown B 3.8.5 LaSalle 1 and 2 B 3.8.5-1 Revision 0 B 3.8  ELECTRICAL POWER SYSTEMS
 
B 3.8.5  DC Sources-Shutdown
 
BASES
 
BACKGROUND A description of the DC sources is provided in the Bases for LCO 3.8.4, "DC Sources-Operating."
APPLICABLE The initial conditions of Design Basis Accident and SAFETY ANALYSES transient analyses in the UFSAR, Chapter 6 (Ref. 1) and Chapter 15 (Ref. 2), assume that Engineered Safety Feature
 
systems are OPERABLE. The DC electrical power system
 
provides normal and emergency DC electrical power for the
 
diesel generators, emergency auxiliaries, and control and
 
switching during all MODES of operation and during movement
 
of irradiated fuel assemblies in the secondary containment.
 
The OPERABILITY of the DC subsystems is consistent with the
 
initial assumptions of the accident analyses and the
 
requirements for the supported systems' OPERABILITY.
 
The OPERABILITY of the minimum DC electrical power sources
 
during MODES 4 and 5 and during movement of irradiated fuel
 
assemblies in the secondary containment ensures that:
: a. The facility can be maintained in the shutdown or refueling condition for extended periods;
: b. Sufficient instrumentation and control capability is available for monitoring and maintaining the unit
 
status; and
: c. Adequate DC electrical power is provided to mitigate events postulated during shutdown, such as an
 
inadvertent draindown of the vessel or a fuel handling
 
accident.
 
In general, when the unit is shut down, the Technical
 
Specifications requirements ensure that the unit has the
 
capability to mitigate the consequences of postulated
 
accidents. However, assuming a single failure and
 
concurrent loss of all offsite or all onsite power is not
 
required. The rationale for this is based on the fact that
 
many Design Basis Accidents (DBAs) that are analyzed in 
 
MODES 1, 2, and 3 have no specific analyses in MODES 4
 
(continued)
DC Sources-Shutdown B 3.8.5 LaSalle 1 and 2 B 3.8.5-2 Revision 27 BASES APPLICABLE and 5. Worst case bounding events are deemed not credible SAFETY ANALYSES in MODES 4 and 5 because the energy contained within the (continued) reactor pressure boundary, reactor coolant temperature and pressure, and the corresponding stresses result in the
 
probabilities of occurrence being significantly reduced or
 
eliminated, and in minimal consequences. These deviations
 
from DBA analysis assumptions and design requirements during
 
shutdown conditions are allowed by the LCO for required
 
systems.
 
The shutdown Technical Specification requirements are
 
designed to ensure that the unit has the capability to
 
mitigate the consequences of certain postulated accidents. 
 
Worst case Design Basis Accidents which are analyzed for
 
operating MODES are generally viewed not to be a significant
 
concern during shutdown MODES due to the lower energies
 
involved. The Technical Specifications therefore require a
 
lesser complement of electrical equipment to be available
 
during shutdown than is required during operating MODES. 
 
More recent work completed on the potential risks associated
 
with shutdown, however, have found significant risk
 
associated with certain shutdown evolutions. As a result, in addition to the requirements established in the Technical
 
Specifications, the Industry has adopted NUMARC 91-06, "Guidelines for Industry Actions to Assess Shutdown
 
Management," as an industry initiative to manage shutdown
 
tasks and associated electrical support to maintain risk at
 
an acceptable low level. This may require the availability
 
of additional equipment beyond that required by the shutdown
 
Technical Specifications.
 
The DC sources satisfy Criterion 3 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO The DC electrical power subsystems, each required subsystem consisting of one battery, one required battery charger, and the corresponding control equipment and interconnecting
 
cabling supplying power to the associated buses within the
 
division, are required to be OPERABLE to support some of the
 
required DC Distribution System divisions required OPERABLE
 
by LCO 3.8.8, "Distribution Systems-Shutdown."  This ensures
 
the availability of sufficient DC electrical power sources
 
to operate the unit in a safe manner and to mitigate the (continued)
DC Sources-Shutdown B 3.8.5 LaSalle 1 and 2 B 3.8.5-3 Revision 0 BASES LCO consequences of postulated events during shutdown (e.g.,
  (continued) fuel handling accidents and inadvertent reactor vessel draindown).
 
APPLICABILITY The DC electrical power sources required to be OPERABLE in MODES 4 and 5 and during movement of irradiated fuel
 
assemblies in the secondary containment provide assurance
 
that:  a. Required features to provide adequate coolant inventory makeup are available for the irradiated fuel
 
assemblies in the core in case of an inadvertent
 
draindown of the reactor vessel;
: b. Required features needed to mitigate a fuel handling accident are available; 
: c. Required features necessary to mitigate the effects of events that can lead to core damage during shutdown
 
are available; and
: d. Instrumentation and control capability is available for monitoring and maintaining the unit in a cold
 
shutdown condition or refueling condition.
 
The DC electrical power requirements for MODES 1, 2, and 3
 
are covered in LCO 3.8.4.
 
ACTIONS LCO 3.0.3 is not applicable while in MODE 4 or 5. However, since irradiated fuel assembly movement can occur in MODE 1, 2, or 3, the ACTIONS have been modified by a Note stating
 
that LCO 3.0.3 is not applicable. If moving irradiated fuel
 
assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify
 
any action. If moving irradiated fuel assemblies while in
 
MODE 1, 2, or 3, the fuel movement is independent of reactor
 
operations. Entering LCO 3.0.3 while in MODE 1, 2, or 3
 
would require the unit to be shutdown, but would not require
 
immediate suspension of movement of irradiated fuel
 
assemblies. The Note to the ACTIONS, "LCO 3.0.3 is not
 
applicable," ensures that the actions for immediate
 
suspension of irradiated fuel assembly movement are not
 
postponed due to entry into LCO 3.0.3.
(continued)
DC Sources-Shutdown B 3.8.5 LaSalle 1 and 2 B 3.8.5-4 Revision 27 BASES ACTIONS A.1, A.2, and A.3 (continued)
Condition A represents one required division with one required battery charger inoperable (e.g., the voltage limit of SR 3.8.4.1 is not maintained). This Condition is only entered under plant conditions in which LCO 3.8.8, "Distribution Systems - Shutdown," requires more than one division of Class 1E DC Electrical Power Distribution (e.g., during CORE ALTERATIONS, LCO 3.8.8 requires the operability of both the Division 2 and the opposite unit Division 2 DC electrical power distribution subsystems). Although the High Pressure Core Spray (HPCS) System is typically considered a single division system, for this Condition, Division 3 (HPCS System) is considered redundant to Division 1 and 2 Emergency Core Cooling Systems. If the redundant required division battery or battery charger are inoperable, or as stated above, LCO 3.8.8 does not require a redundant DC electrical power distribution subsystem, then Condition B must be entered.
The ACTIONS provide a tiered response that focuses on returning the battery to the fully charged state and restoring the fully qualified charger to OPERABLE status in a reasonable time period. Required Action A.1 requires that the battery terminal voltage be restored to greater than or equal to the minimum established float voltage within 2 hours. This time provides for returning the inoperable charger to OPERABLE status or providing an alternate means of restoring battery terminal voltage to greater than or equal to the minimum established float voltage. Restoring the battery terminal voltage to greater than or equal to the minimum established float voltage provides good assurance that, within 12 hours, the battery will be restored to its fully charged condition (Required Action A.2) from any discharge that might have occurred due to the charger inoperability. A discharged battery having terminal voltage of at least the minimum established float voltage indicates that the battery is on the exponential charging current portion (the second part) of its recharge cycle. The time to return a battery to its fully charged state under this condition is simply a function of the amount of the previous discharge and the recharge characteristic of the battery.
Thus there is good assurance of fully recharging the battery within 12 hours, avoiding a premature shutdown with its own attendant risk.
 
(continued)
DC Sources-Shutdown B 3.8.5 LaSalle 1 and 2 B 3.8.5-5 Revision 27 BASES ACTIONS A.1, A.2, and A.3 (continued)
If battery terminal float voltage cannot be restored to
 
greater than or equal to the minimum established float voltage within 2 hours, and the charger is not operating in the current-limiting mode, a faulty charger is indicated. A faulty charger that is incapable of maintaining established battery terminal float voltage does not provide adequate assurance that it can revert to and operate properly in the current limit mode that is necessary during the recovery period following a battery discharge event that the DC system is designed for.
If the charger is operating in the current limit mode after 2 hours that is an indication that the battery is partially discharged and its capacity margins will be reduced. The time to return the battery to its fully charged condition in this case is a function of the battery charger capacity, the amount of loads on the associated DC system, the amount of the previous discharge, and the recharge characteristic of the battery. The charge time can be extensive, and there is not adequate assurance that it can be recharged within 12 hours (Required Action A.2).
Required Action A.2 requires that the battery float current be verified as less than or equal to 2 amps. This indicates that, if the battery has been discharged as a result of the inoperable battery charger, it has now been fully recharged.
If at the expiration of the initial 12 hour period the battery float current is not less than or equal to 2 amps, this indicates there may be additional battery problems and the battery must be declared inoperable.
Required Action A.3 limits the restoration time for the inoperable battery charger to 7 days. This action is applicable if an alternate means of restoring battery terminal voltage to greater than or equal to the minimum established float voltage has been used (e.g., balance of plant non-Class 1E battery charger). The 7 day Completion Time reflects a reasonable time to effect restoration of the qualified battery charger to OPERABLE status.
 
  (continued)
DC Sources-Shutdown B 3.8.5 LaSalle 1 and 2 B 3.8.5-6 Revision 27 BASES ACTIONS B.1, B.2.1, B.2.2, B.2.3, and B.2.4 (continued)
By allowing the option to declare required features
 
inoperable with associated DC electrical power subsystems
 
inoperable, appropriate restrictions are implemented in
 
accordance with the affected system LCOs' ACTIONS. However, in many instances this option may involve undesired
 
administrative efforts. Therefore, the allowance for
 
sufficiently conservative actions is made (i.e., to suspend
 
CORE ALTERATIONS, movement of irradiated fuel assemblies in
 
the secondary containment, and any activities that could
 
result in inadvertent draining of the reactor vessel).
 
Suspension of these activities shall not preclude completion
 
of actions to establish a safe conservative condition. 
 
These actions minimize the probability of the occurrence of
 
postulated events. It is further required to immediately
 
initiate action to restore the required DC electrical power
 
subsystems and to continue this action until restoration is
 
accomplished in order to provide the necessary DC electrical
 
power to the plant safety systems.
 
The Completion Time of immediately is consistent with the
 
required times for actions requiring prompt attention. The
 
restoration of the required DC electrical power subsystems
 
should be completed as quickly as possible in order to
 
minimize the time during which the plant safety systems may
 
be without sufficient power.
 
SURVEILLANCE SR  3.8.5.1 REQUIREMENTS SR 3.8.5.1 requires all Surveillances required by SR 3.8.4.1
 
through SR 3.8.4.4 to be applicable. Therefore, see the corresponding Bases for LCO 3.8.4 for a discussion of each
 
SR.
 
This SR is modified by a Note. The reason for the Note is
 
to preclude requiring the OPERABLE DC sources from being
 
discharged below their capability to provide the required
 
power supply or otherwise rendered inoperable during the
 
performance of SRs. It is the intent that these SRs must
 
still be capable of being met, but actual performance is not
 
required.
 
(continued)
DC Sources-Shutdown B 3.8.5 LaSalle 1 and 2 B 3.8.5-7 Revision 27 BASES  (continued)
 
REFERENCES 1. UFSAR, Chapter 6.
: 2. UFSAR, Chapter 15.
 
Battery Parameters B 3.8.6  LaSalle 1 and 2 B 3.8.6-1 Revision 27 B 3.8  ELECTRICAL POWER SYSTEMS
 
B 3.8.6  Battery Parameters
 
BASES
 
BACKGROUND This LCO delineates the limits on battery float current as well as electrolyte temperature, level, and float voltage for the DC power source batteries. A discussion of these
 
batteries and their OPERABILITY requirements is provided in
 
the Bases for LCO 3.8.4, "DC Sources-Operating," and
 
LCO 3.8.5, "DC Sources-Shutdown."  In addition to the limitations of this Specification, the Battery Monitoring and Maintenance Program described in the Technical Requirements Manual (Ref. 7) implements the program specified in Specification 5.5.14 for monitoring various battery parameters including temperature, voltage, and level requirements that are based on the recommendations of IEEE Standard 450, "IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries for Stationary Applications" (Ref. 4).
The battery cells are of flooded lead acid construction with a nominal specific gravity of 1.215. This specific gravity corresponds to an open circuit battery voltage of approximately 120 V for a 58 cell battery and 240 V for a 116 cell battery (i.e., cell voltage of 2.065 volts per cell (Vpc)). The open circuit voltage is the voltage maintained when there is no charging or discharging. Once fully charged with its open circuit voltage >
2.065 Vpc, the battery will maintain its capacity for 30 days without further charging per manufacturers instructions. Optimal long term performance however, is obtained by maintaining a float voltage of 2.17 Vpc to 2.25 Vpc for Division 1 and Division 2 and maintainting a float voltage of 2.20 to 2.25 Vpc for Division 3. This provides adequate over-potential, which limits the formation of lead sulfate and self discharge. The nominal float voltage of 2.23 Vpc corresponds to a total float voltage output of 129.3 V for a 58 cell battery and 258.7 V for a 116 cell battery as discussed in the UFSAR, Section 8.3.2 (Ref. 2).
 
APPLICABLE The initial conditions of Design Basis Accident (DBA) and SAFETY ANALYSES transient analyses in UFSAR, Chapter 6 (Ref. 1) and Chapter 15 (Ref. 3), assume Engineered Safety Feature systems are OPERABLE. The DC electrical power subsystems (continued)
Battery Parameters B 3.8.6 LaSalle 1 and 2 B 3.8.6-2 Revision 27 BASES APPLICABLE provide normal and emergency DC electrical power for the SAFETY ANALYSES diesel generators, emergency auxiliaries, and control and (continued) switching during all MODES of operation.
 
ACTIONS The OPERABILITY of the DC subsystems is consistent with the initial assumptions of the accident analyses and is based
 
upon meeting the design basis of the unit as discussed in
 
the Bases for LCO 3.8.4 and LCO 3.8.5.
 
Since battery parameters support the operation of the DC power sources, they satisfy Criterion 3 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO Battery parameters must remain within acceptable limits to ensure availability of the required DC power to shut down
 
the reactor and maintain it in a safe condition after an
 
anticipated operational occurrence or a postulated DBA. 
 
Battery parameter limits are conservatively established, allowing continued DC electrical system function even with
 
limits not met. Additional preventative maintenance, testing, and monitoring performed in accordance with the Battery Monitoring and Maintenance Program is conducted as specified in Specification 5.5.14.
 
APPLICABILITY The battery parameters are required solely for the support of the associated DC electrical power subsystem. Therefore, battery parameter limits are only required when the associated DC electrical power subsystem is required to be
 
OPERABLE. Refer to the Applicability discussion in Bases
 
for LCO 3.8.4 and LCO 3.8.5.
 
The ACTIONS Table is modified by a Note which indicates that separate Condition entry is allowed for each battery. This
 
is acceptable, since the Required Actions for each Condition
 
provide appropriate compensatory actions for each inoperable
 
DC electrical power subsystem. Complying with the Required
 
Actions for one inoperable DC electrical power subsystem may
 
allow for continued operation, and subsequent inoperable DC
 
electrical power subsystem(s) are governed by separate
 
Condition entry and application of associated Required
 
Actions.
  (continued)
Battery Parameters B 3.8.6 LaSalle 1 and 2 B 3.8.6-3 Revision 27 BASES  (continued)
 
ACTIONS A.1, A.2, and A.3
 
With one or more cells of a battery < 2.07 V, the battery is degraded. Within 2 hours, verification of the required battery charger OPERABILITY is made by monitoring the  battery terminal voltage (SR 3.8.4.1) and the overall    battery state of charge by monitoring the battery float charge current (SR 3.8.6.1). This assures that there is still sufficient battery capacity to perform the intended function. Therefore, the affected battery is not required to be considered inoperable solely as a result of one or more cells in the battery being < 2.07 V, and continued operation is permitted for a limited period of up to 24 hours. Since the Required Actions only specify "perform", a failure of SR 3.8.4.1 or SR 3.8.6.1 acceptance criteria does not result in the Required Action not met. However, if one of the SRs is failed, the appropriate Condition(s), depending on the cause of the failure, is entered. If SR 3.8.6.1 is failed, then there is not assurance that there is still sufficient battery capacity to perform the intended function and the battery must be declared inoperable immediately as specified in Condition F.
B.1 and B.2 One or more batteries with float current > 2 amps indicates that a partial discharge of the battery capacity has occurred. This may be due to a temporary loss of a battery charger or possibly due to one or more battery cells in a low voltage condition reflecting some loss of capacity.
Within 2 hours, verification of the required battery charger OPERABILITY is made by monitoring the battery terminal voltage. If the terminal voltage is found to be less than the minimum established float voltage, there are two possibilities; the battery charger is inoperable or is operating in the current limit mode. Condition A of LCO 3.8.4 and LCO 3.8.5 address charger inoperability. If the charger is operating in the current limit mode after 2 hours, that is an indication that the battery has been substantially discharged and likely cannot perform its required design functions. The time to return the battery to its fully charged condition in this case is a function of the battery charger capacity, the amount of loads on the associated DC system, the amount of the previous discharge,  (continued)
Battery Parameters B 3.8.6 LaSalle 1 and 2 B 3.8.6-4 Revision 27 BASES ACTIONS  B.1 and B.2 (continued) and the recharge characteristic of the battery. The charge time can be extensive, and there is not adequate assurance that it can be recharged within 12 hours (Required Action B.2). The battery must therefore be declared inoperable as specified in Condition F.
 
If the float voltage is found to be satisfactory, but there are one or more battery cells with float voltage less than 2.07 V, the associated "OR
" statement in Condition F is applicable and the battery must be declared inoperable immediately. If float voltage is satisfactory and there are no battery cells less than 2.07 V, there is good assurance that, within 12 hours, the battery will be restored to its fully charged condition (Required Action B.2) from any discharge that might have occurred due to a temporary loss of the battery charger. A discharged battery with float voltage (the charger setpoint) across its terminals indicates that the battery is on the exponential charging current portion (the second part) of its recharge cycle.
The time to return a battery to its fully charged state under this condition is simply a function of the amount of the previous discharge and the recharge characteristic of the battery. Thus there is good assurance of fully recharging the battery within 12 hours, avoiding a premature shutdown with its own attendant risk.
If the condition is due to one or more cells in a low voltage condition but still greater than 2.07 V and float voltage is found to be satisfactory, this is not an indication of a substantially discharged battery and 12 hours is a reasonable time prior to declaring the battery inoperable.
Since Required Action B.1 only specifies "perform," a failure of SR 3.8.4.1 acceptance criteria does not result in the Required Action not met. However, if SR 3.8.4.1 is failed, the appropriate Condition(s), depending on the cause of the failure, is entered.
C.1, C.2, and C.3 With one or more batteries with one or more cells electrolyte level above the top of the plates but below the minimum established design limits, the battery still retains sufficient capacity to perform the intended function. 
(continued)
Battery Parameters B 3.8.6 LaSalle 1 and 2 B 3.8.6-5 Revision 27 BASES ACTIONS C.1, C.2, and C.3 (continued)
 
Therefore, the affected battery is not required to be considered inoperable solely as a result of electrolyte level not met. Within 31 days, the minimum established design limits for electrolyte level must be re-established.
 
With electrolyte level below the top of the plates, there is a potential for dryout and plate degradation. Required Actions C.1 and C.2 address this potential (as well as provisions in Specification 5.5.14, Battery Maintenance and Monitoring Program). They are modified by a Note that indicates they are only applicable if electrolyte level is below the top of the plates. Within 8 hours, level is required to be restored to above the top of the plates. The Required Action C.2 requirement to verify that there is no leakage by visual inspection and the Specification 5.5.14.b item to initiate action to equalize and test in accordance with the manufacturer's recommendation are performed following restoration of the electrolyte level to above the top of the plates. Based on the results of the manufacturer's recommended testing, the battery may have to be declared inoperable and the affected cell(s) replaced.
D.1  With one or more batteries with pilot cell temperature less than the minimum established design limits, 12 hours is allowed to restore the temperature to within limits. A low electrolyte temperature limits the current and power available. Since the battery is sized with margin, while battery capacity is degraded, sufficient capacity exists to perform the intended function and the affected battery is not required to be considered inoperable solely as a result of pilot cell temperature not met.
E.1  If two or more redundant division (e.g., both the Division 2 and the opposite unit Division 2) batteries have battery parameters not within limits there is not sufficient assurance that battery capacity has not been affected to the degree that the batteries are can still perform their required function, given that redundant batteries are involved. With redundant batteries involved, this potential could result in a total loss of function on multiple systems that rely upon the batteries. The longer Completion Times (continued)
Battery Parameters B 3.8.6 LaSalle 1 and 2 B 3.8.6-6 Revision 27 BASES ACTIONS E.1 (continued) specified for battery parameters on non-redundant batteries not within limits are therefore not appropriate, and the parameters must be restored to within limits on at least one affected division within 2 hours. Although the High Pressure Core Spray (HPCS) System is typically considered a single division system, for this Condition, the Division 3 (HPCS System) battery is considered redundant to Division 1 and 2 batteries for the Emergency Core Cooling function.
F.1 When any battery parameter is outside the allowances of the Required Actions for Condition A, B, C, D, or E, sufficient capacity to supply the maximum expected load requirement is
 
not assured and the corresponding battery must be declared inoperable. Additionally, discovering a battery with one or more battery cells float voltage less than 2.07 V and float current greater than 2 amps indicates that the battery capacity may not be sufficient to perform the intended functions. The battery must therefore be declared inoperable immediately.
 
SURVEILLANCE SR  3.8.6.1 REQUIREMENTS Verifying battery float current while on float charge is used to determine the state of charge of the battery. Float charge is the condition in which the charger is supplying the continuous charge required to overcome the internal losses of a battery and maintain the battery in a fully charged state. The float current requirements are based on the float current indicative of a charged battery.
This SR is modified by a Note that states the float current requirement is not required to be met when battery terminal voltage is less than the minimum established float voltage of SR 3.8.4.1. When this float voltage is not maintained, the Required Actions of LCO 3.8.4 or LCO 3.8.5 ACTION A, as applicable, are being taken, which provide the necessary and appropriate verifications of battery condition.
Furthermore, the float current limit of 2 amps is established based on the nominal float voltage and is not directly applicable when this voltage is not maintained.
(continued)
Battery Parameters B 3.8.6 LaSalle 1 and 2 B 3.8.6-7 Revision 27 BASES SURVEILLANCE SR  3.8.6.2 and SR  3.8.6.5 REQUIREMENTS (continued) Optimal long term battery performance is obtained by maintaining a float voltage greater than or equal to the minimum established design limits provided by the manufacturer, which corresponds to 125.86 V for the Division 1 and 2 125 V batteries, 127.60 V for the Division 3 125 V battery and 251.72 V for the 250 V battery at the battery terminals or 2.17 Vpc for Division 1 and 2 and 2.20 Vpc for Division 3. This provides adequate over-potential, which limits the formation of lead sulfate and self discharge, which could eventually render the battery inoperable. Float voltage in this range or less, but greater than 2.07 Vpc, is addressed in Specification 5.5.14. 
 
SRs 3.8.6.2 and 3.8.6.5 require verification that the cell float voltages are equal to or greater than the short term absolute minimum voltage of 2.07 V. The Frequency for cell voltage verification every 31 days for pilot cell and 92 days for each connected cell is consistent with IEEE-450 (Ref. 4).
 
SR  3.8.6.3
 
The limit specified for electrolyte level ensures that the plates suffer no physical damage and maintains adequate electron transfer capability. The Frequency is consistent with IEEE-450 (Ref. 4).
SR  3.8.6.4 This Surveillance verifies that the pilot cell temperature is greater than or equal to the minimum established design limit (i.e., 60&deg;F for 125 V batteries and 65&deg;F for the 250 V battery). Pilot cell electrolyte temperature is maintained above this temperature to assure the battery can provide the required current and voltage to meet the design requirements. Temperatures lower than assumed in the battery sizing calculations may act to inhibit or reduce battery capacity. The Frequency is consistent with IEEE-450 (Ref. 4).
  (continued)
Battery Parameters B 3.8.6 LaSalle 1 and 2 B 3.8.6-8 Revision 27 BASES    SURVEILLANCE SR  3.8.6.6 REQUIREMENTS    (continued) A battery performance discharge test is a test of constant current capacity of a battery, normally done in the as found condition, after having been in service, to detect any change in the capacity determined by the acceptance test.
The test is intended to determine overall battery degradation due to age and usage.
Either the battery performance discharge test or the modified performance discharge test is acceptable for satisfying SR 3.8.6.6; however, only the modified performance discharge test may be used to satisfy the battery service test requirements of SR 3.8.4.3 at the same time. A modified performance discharge test is a test of the battery capacity and its ability to provide a high rate, short duration load (usually the highest rate of the duty cycle). This will often confirm the battery's ability to meet the critical period of the load duty cycle, in addition to determining its percentage of rated capacity. Initial conditions for the modified performance discharge test should be identical to those specified for a service test when the modified performance discharge test is performed in lieu of a service test.
A battery modified performance discharge test is a simulated duty cycle normally consisting of multiple rates; these rates include the test rate employed for the performance discharge test and the rates published for the current load of the duty cycle, both of which envelope the duty cycle of the service test.  (The test can consist of a single rate if the test rate employed for the performance discharge test envelopes the duty cycle of the service test). The battery terminal voltage for the modified performance discharge test must remain above the minimum battery terminal voltage specified in the battery service test for the duration of time equal to that of the service test.
(continued)
Battery Parameters B 3.8.6 LaSalle 1 and 2 B 3.8.6-9 Revision 27 BASES SURVEILLANCE SR  3.8.6.6 (continued)
REQUIREMENTS The acceptance criteria for this Surveillance is consistent with IEEE-450 (Ref. 4) and IEEE-485 (Ref. 5). These references recommend that the battery be replaced if its capacity is below 80% of the manufacturer's rating, since IEEE-485 (Ref. 5) recommends using an aging factor of 125%
in the battery sizing calculation. A capacity of 80% shows that the battery rate of deterioration is increasing, even if there is ample capacity to meet the load requirements.
Furthermore, the battery is sized to meet the assumed duty cycle loads when the battery design capacity reaches this 80% limit. If an aging factor other than 125% is used, the minimum capacity should be adjusted accordingly.
The Surveillance Frequency for this test is normally 60 months. If the battery shows degradation, or if the battery has reached 85% of its expected life and capacity is
< 100% of the manufacturers rating, the Surveillance Frequency is reduced to 12 months. However, if the battery shows no degradation but has reached 85% of its expected life, the Surveillance Frequency is only reduced to 24 months for batteries that retain capacity  100% of the manufacturers rating. Degradation is indicated, consistent with IEEE-450 (Ref. 4), when the battery capacity drops by more than 10% relative to its capacity on the previous performance test or when it is  10% below the manufacturers rating. The 12 month and 60 month Frequencies are consistent with the recommendations in IEEE-450 (Ref. 4).
This SR is modified by three Notes. The reason for the first Note is that performing the Surveillance would remove a required 125 VDC electrical power subsystem from service, perturb the electrical distribution system, and challenge safety systems. This restriction from normally performing the Surveillance in MODE 1 or 2 is further amplified to allow portions of the Surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g., post work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or enhanced. This assessment shall, as a minimum, consider the potential outcomes and transients associated with a failed 
 
(continued)
Battery Parameters B 3.8.6 LaSalle 1 and 2 B 3.8.6-10 Revision 27 BASES SURVEILLANCE SR  3.8.6.6 (continued)
REQUIREMENTS partial Surveillance, a successful partial Surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the partial Surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when portions of the Surveillance are performed in MODE 1 or 2.
Risk insights or deterministic methods may be used for this assessment. Credit may be taken for unplanned events that satisfy this SR.
The reason for the second Note is if the opposite unit is in MODE 4 or 5, or moving irradiated fuel assemblies in secondary containment, this Surveillance is not required to be performed for an operating unit. This ensures that a given operating unit SR will not require an opposite unit SR to be performed, when the opposite unit Technical Specifications exempts performance of an opposite unit SR.
Furthermore, it precludes requiring the OPERABLE DC source on the shutdown unit from being discharged below its capability to provide the required power supply or otherwise be rendered inoperable during the performance of this Surveillance. It is the intent that this SR must still be capable of being met, but actual performance is not required.
 
The reason for the third Note is to preclude requiring the OPERABLE DC sources on the shutdown unit from being discharged below their capability to provide the required power supply or otherwise be rendered inoperable during the performance of this SR. It is the intent that this SR must still be capable of being met, but actual performance is not required.
REFERENCES 1. UFSAR, Chapter 6.
: 2. UFSAR, Chapter 8.
: 3. UFSAR, Chapter 15.
: 4. IEEE Standard 450, 1975.
(continued)
Battery Parameters B 3.8.6 LaSalle 1 and 2 B 3.8.6-11 Revision 27 BASES  REFERENCES  5. IEEE Standard 485, 1983.    (continued)  6. Technical Requirements Manual
: 7. NRC Regulatory Commitment documented in letter from D. M. Benyak to NRC, "Additional Information Supporting the License Amendment Request Associated with Direct Current Electrical Request," dated September 13, 2006.
 
Distribution Systems-Operating B 3.8.7 LaSalle 1 and 2 B 3.8.7-1 Revision 19 B 3.8  ELECTRICAL POWER SYSTEMS
 
B 3.8.7  Distribution Systems-Operating
 
BASES
 
BACKGROUND The onsite Class 1E AC and DC electrical power distribution system for each unit is divided by division into three
 
independent AC and DC electrical power distribution
 
subsystems. Each unit is also dependent on portions of the
 
opposite unit's Division 2 AC and DC power distribution
 
subsystems.
 
The primary AC Distribution System consists of three 4.16 kV
 
emergency buses that are supplied from the transmission
 
system by two physically independent circuits. The Division
 
2 and 3 emergency buses also have a dedicated onsite diesel
 
generator (DG) source, while the Unit 1 and 2 Division 1
 
buses share an onsite DG source. The Division 1, 2, and 3
 
4.16 kV emergency buses are normally supplied through the
 
system auxiliary transformer (SAT). In addition to the SAT, Division 1 and 2 can be supplied from the unit auxiliary
 
transformer or the opposite unit's SAT. Control power for
 
the 4.16 kV breakers is supplied from the Class 1E
 
batteries. Additional description of this system may be
 
found in the Bases for LCO 3.8.1, "AC Sources-Operating,"
and the Bases for LCO 3.8.4, "DC Sources-Operating."
 
The secondary plant AC distribution system includes 480 V
 
ESF load centers and associated loads, motor control
 
centers, and transformers.
 
There are three independent 125 VDC electrical power
 
distribution subsystems. The Division 2 Class 1E AC and DC
 
electrical power distribution subsystems associated with
 
each unit are shared by each unit since some systems are
 
common to both units. The opposite unit Division 2 Class 1E
 
AC and DC electrical power distribution subsystems support
 
equipment required to be OPERABLE by LCO 3.6.4.3, "Standby Gas Treatment (SGT) System," LCO 3.7.4, "Control Room Area
 
Filtration (CRAF) System," LCO 3.7.5, "Control Room Area
 
Ventilation Air Conditioning (AC) System," and LCO 3.8.1, "AC Sources-Operating."
 
  (continued)
Distribution Systems-Operating B 3.8.7 LaSalle 1 and 2 B 3.8.7-2 Revision 0 BASES BACKGROUND The list of all required distribution buses for Unit 1 and (continued) Unit 2 is located in Tables B 3.8.7-1 and B 3.8.7-2, respectively.
 
APPLICABLE The initial conditions of Design Basis Accident (DBA) and SAFETY ANALYSES transient analyses in the UFSAR, Chapter 6 (Ref. 1) and Chapter 15 (Ref. 2), assume Engineered Safety Features (ESF)
 
systems are OPERABLE. The AC and DC electrical power
 
distribution systems are designed to provide sufficient
 
capacity, capability, redundancy, and reliability to ensure
 
the availability of necessary power to ESF systems so that
 
the fuel, Reactor Coolant System, and containment design
 
limits are not exceeded. These limits are discussed in more
 
detail in the Bases for Section 3.2, Power Distribution
 
Limits; Section 3.5, Emergency Core Cooling Systems (ECCS)
 
and Reactor Core Isolation Cooling (RCIC) System; and
 
Section 3.6, Containment Systems.
 
The OPERABILITY of the AC and DC electrical power
 
distribution systems is consistent with the initial
 
assumptions of the accident analyses and is based upon
 
meeting the design basis of the plant. This includes
 
maintaining the AC and DC electrical power sources and
 
associated distribution systems OPERABLE during accident
 
conditions in the event of:
: a. An assumed loss of all offsite or onsite AC electrical power; and
: b. A worst case single failure.
 
The AC and DC electrical power distribution systems satisfy
 
Criterion 3 of 10 CFR 50.36(c)(2)(ii).
 
LCO The required AC and DC electrical power distribution subsystems listed in Table B 3.8.7-1 for Unit 1 and Table B
 
3.8.7-2 for Unit 2 ensure the availability of AC and DC
 
electrical power for the systems required to shut down the
 
reactor and maintain it in a safe condition after an
 
anticipated operational occurrence (AOO) or a postulated
 
DBA. The Division 1, 2, and 3 AC and DC bus electrical
 
power primary distribution subsystems are required to be (continued)
Distribution Systems-Operating B 3.8.7 LaSalle 1 and 2 B 3.8.7-3 Revision 19 BASES LCO OPERABLE and certain buses of the opposite unit Division 2 (continued) AC and DC electrical power distribution subsystems are required to be OPERABLE to support the equipment required to
 
be OPERABLE by LCO 3.6.4.3, LCO 3.7.4, LCO 3.7.5, and LCO 3.8.1. As noted in Table B 3.8.7-1 and Table B 3.8.7-2 (Footnote a), each division of the AC and DC electrical
 
power distribution systems is a subsystem.
 
Maintaining the Division 1, 2, and 3 AC and DC electrical
 
power distribution subsystems OPERABLE ensures that the
 
redundancy incorporated into the design of ESF is not
 
defeated. Any two of the three divisions of the
 
distribution system are capable of providing the necessary
 
electrical power to the associated ESF components. 
 
Therefore, a single failure within any system or within the
 
electrical power distribution subsystems does not prevent
 
safe shutdown of the reactor.
 
OPERABLE AC electrical power distribution subsystems require
 
the associated buses to be energized to their proper
 
voltages. OPERABLE DC electrical power distribution
 
subsystems require the associated buses to be energized to
 
their proper voltage from either the associated battery or
 
charger.
 
Based on the number of safety significant electrical loads
 
associated with each bus listed in Table B 3.8.7-1 for
 
Unit 1 and Table B 3.8.7-2 for Unit 2, if one or more of the
 
buses becomes inoperable, entry into the appropriate ACTIONS
 
of LCO 3.8.7 is required. Some buses, such as distribution
 
panels, which help comprise the AC and DC distribution
 
systems are not listed in Table B 3.8.7-1 for Unit 1 and
 
Table B 3.8.7-2 for Unit 2. The loss of electrical loads
 
associated with these buses may not result in a complete
 
loss of a redundant safety function necessary to shut down
 
the reactor and maintain it in a safe condition. Therefore, should one or more of these buses become inoperable due to a
 
failure not affecting the OPERABILITY of a bus listed in
 
Table B 3.8.7-1 for Unit 1 and Table B 3.8.7-2 for Unit 2 (e.g., a breaker supplying a single distribution panel fails
 
open), the individual loads on the bus would be considered
 
inoperable, and the appropriate Conditions and Required
 
Actions of the LCOs governing the individual loads would be
 
entered. However, if one or more of these buses is (continued)
Distribution Systems-Operating B 3.8.7 LaSalle 1 and 2 B 3.8.7-4 Revision 0 BASES LCO inoperable due to a failure also affecting the OPERABILITY (continued) of a bus listed in Table B 3.8.7-1 for Unit 1 and Table B 3.8.7-2 for Unit 2 (e.g., loss of 4.16 kV emergency bus, which results in de-energization of all buses powered from
 
the 4.16 kV emergency bus), then although the individual
 
loads are still considered inoperable, the Conditions and
 
Required Actions of the LCO for the individual loads are not
 
required to be entered, since LCO 3.0.6 allows this
 
exception (i.e., the loads are inoperable due to the
 
inoperability of a support system governed by a Technical
 
Specification; the 4.16 kV emergency bus).
 
In addition, at least one tie breaker between the redundant
 
Division 2, safety related DC emergency power distribution
 
subsystems must be open. This prevents an electrical
 
malfunction in one power distribution subsystem from
 
propagating to the redundant subsystem, which could cause
 
the failure of a redundant subsystem and a loss of essential
 
safety function(s). If at least one tie breaker is not
 
open, then both Division 2 DC electrical power distribution
 
subsystems are considered inoperable. The restriction of
 
maintaining electrical separation applies to the onsite, safety related, redundant electrical power distribution
 
subsystems. It does not, however, preclude redundant Class
 
1E 4.16 kV emergency buses from being supplied from the same
 
offsite source.
 
APPLICABILITY The electrical power distribution subsystems are required to be OPERABLE in MODES 1, 2, and 3 to ensure that:
: a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result
 
of AOOs or abnormal transients; and
: b. Adequate core cooling is provided, and containment OPERABILITY and other vital functions are maintained, in the event of a postulated DBA.
 
Electrical power distribution subsystem requirements for
 
MODES 4 and 5 and other conditions in which AC and DC
 
electrical power distribution subsystems are required. are
 
covered in the Bases for LCO 3.8.8, "Distribution
 
Systems-Shutdown." 
(continued)
Distribution Systems-Operating B 3.8.7 LaSalle 1 and 2 B 3.8.7-5 Revision 0 BASES  (continued)
 
ACTIONS A.1 With one or more Division 1 and 2 required AC buses, load
 
centers, motor control centers, or distribution panels
 
inoperable and a loss of function has not yet occurred, the
 
remaining AC electrical power distribution subsystems are
 
capable of supporting the minimum safety functions necessary
 
to shut down the reactor and maintain it in a safe shutdown
 
condition, assuming no single failure. The overall
 
reliability is reduced, however, because a single failure in
 
the remaining electrical power distribution subsystems could
 
result in the minimum required ESF functions not being
 
supported. Therefore, the required AC buses, load centers, motor control centers, and distribution panels must be
 
restored to OPERABLE status within 8 hours.
 
The Condition A worst scenario is two divisions without
 
AC power (i.e., no offsite power to the divisions and the
 
associated DGs inoperable). In this situation, the unit is
 
more vulnerable to a complete loss of AC power. It is, therefore, imperative that the unit operators' attention be
 
focused on minimizing the potential for loss of power to the
 
remaining division by stabilizing the unit and restoring
 
power to the affected division. The 8 hour time limit
 
before requiring a unit shutdown in this Condition is
 
acceptable because of:
: a. The potential for decreased safety if the unit operators' attention is diverted from the evaluations
 
and actions necessary to restore power to the affected
 
division to the actions associated with taking the
 
unit to shutdown within this time limit.
: b. The low potential for an event in conjunction with a single failure of a redundant component in the
 
division with AC power.  (The redundant component is
 
verified OPERABLE in accordance with
 
Specification 5.5.12, "Safety Function Determination
 
Program (SFDP).")
(continued)
Distribution Systems-Operating B 3.8.7 LaSalle 1 and 2 B 3.8.7-6 Revision 0 BASES ACTIONS A.1 (continued)
The second Completion Time for Required Action A.1
 
establishes a limit on the maximum time allowed for any
 
combination of required distribution subsystems to be
 
inoperable during any single contiguous occurrence of
 
failing to meet LCO 3.8.7.a. If Condition A is entered
 
while, for instance, a DC electrical power distribution
 
subsystem is inoperable and subsequently returned OPERABLE, LCO 3.8.7.a may already have been not met for up to 2 hours.
 
This situation could lead to a total duration of 10 hours, since initial failure of LCO 3.8.7.a, to restore the AC
 
electrical power distribution system. At this time, a DC
 
electrical power distribution subsystem could again become
 
inoperable, and the AC electrical power distribution could
 
be restored OPERABLE. This could continue indefinitely.
 
This Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." 
 
This results in establishing the "time zero" at the time
 
LCO 3.8.7.a was initially not met, instead of at the time
 
Condition A was entered. The 16 hour Completion Time is an
 
acceptable limitation on this potential to fail to meet
 
LCO 3.8.7.a indefinitely.
 
B.1 With one or more Division 1 and 2 DC electrical distribution
 
subsystems inoperable and a loss of function has not yet
 
occurred, the remaining DC electrical power distribution
 
subsystems are capable of supporting the minimum safety
 
functions necessary to shut down the reactor and maintain it
 
in a safe shutdown condition, assuming no single failure. 
 
The overall reliability is reduced, however, because a
 
single failure in the remaining DC electrical power
 
distribution subsystems could result in the minimum required
 
ESF functions not being supported. Therefore, the required
 
DC electrical power distribution subsystem(s) must be
 
restored to OPERABLE status within 2 hours by powering the
 
bus from the associated battery or charger.
(continued)
Distribution Systems-Operating B 3.8.7 LaSalle 1 and 2 B 3.8.7-7 Revision 0 BASES ACTIONS B.1 (continued)
Condition B worst scenario is two divisions without adequate
 
DC power, potentially with both the battery significantly
 
degraded and the associated charger nonfunctioning. In this
 
situation, the plant is significantly more vulnerable to a
 
complete loss of all DC power. It is, therefore, imperative
 
that the operator's attention focus on stabilizing the
 
plant, minimizing the potential for loss of power to the
 
remaining divisions, and restoring power to the affected
 
division(s).
 
This 2 hour limit is more conservative than Completion Times
 
allowed for the majority of components that could be without
 
power. Taking exception to LCO 3.0.2 for components without
 
adequate DC power, that would have Required Action
 
Completion Times shorter than 2 hours, is acceptable because
 
of:  a. The potential for decreased safety when requiring a change in plant conditions (i.e., requiring a
 
shutdown) while not allowing stable operations to
 
continue;
: b. The potential for decreased safety when requiring entry into numerous applicable Conditions and Required
 
Actions for components without DC power while not
 
providing sufficient time for the operators to perform
 
the necessary evaluations and actions for restoring
 
power to the affected division; and
: c. The potential for an event in conjunction with a single failure of a redundant component.
 
The 2 hour Completion Time for DC electrical power
 
distribution subsystems is consistent with Regulatory
 
Guide 1.93 (Ref. 3).
 
(continued)
Distribution Systems-Operating B 3.8.7 LaSalle 1 and 2 B 3.8.7-8 Revision 32 BASES ACTIONS B.1 (continued)
The second Completion Time for Required Action B.1
 
establishes a limit on the maximum time allowed for any
 
combination of required distribution subsystems to be
 
inoperable during any single contiguous occurrence of
 
failing to meet LCO 3.8.7.a. If Condition B is entered
 
while, for instance, an AC electrical power distribution
 
subsystem is inoperable and subsequently returned OPERABLE, LCO 3.8.7.a may already have been not met for up to 8 hours.
 
This situation could lead to a total duration of 10 hours, since initial failure of LCO 3.8.7.a, to restore the DC
 
electrical power distribution system. At this time, an AC
 
electrical power distribution subsystem could again become
 
inoperable, and DC electrical power distribution subsystem
 
could be restored OPERABLE. This could continue
 
indefinitely.
 
This Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." 
 
This allowance results in establishing the "time zero" at
 
the time LCO 3.8.7.a was initially not met, instead of the
 
time Condition B was entered. The 16 hour Completion Time
 
is an acceptable limitation on this potential of failing to
 
meet LCO 3.8.7.a indefinitely.
 
C.1 If one or both Division 1 and 2 AC or DC electrical power distribution subsystems are inoperable and not restored within the provided Completion Time, the plant must be brought to a condition in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 4) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
(continued)
Distribution Systems-Operating B 3.8.7 LaSalle 1 and 2 B 3.8.7-9 Revision 32 BASES ACTIONS D.1 (continued)
 
With one or more required opposite unit Division 2 AC or DC
 
electrical power distribution subsystems inoperable and a
 
loss of function has not yet occurred, certain redundant
 
Division 2 features (e.g., a standby gas treatment
 
subsystem) will not function if a design basis event were to
 
occur. Therefore, a 7 day Completion Time is provided to
 
restore the required opposite unit Division 2 AC and DC
 
electrical power distribution subsystems to OPERABLE status.
 
The 7 day Completion Time takes into account the capacity
 
and capability of the remaining AC and DC electrical power
 
distribution subsystems, and is based on the shortest
 
restoration time allowed for the systems affected by the
 
inoperable AC and DC electrical power distribution
 
subsystems in the respective system specifications.
The Required Action is modified by a Note indicating that
 
the applicable Conditions of LCO 3.8.1 be entered and
 
Required Actions taken if the inoperable opposite unit AC
 
electrical power distribution subsystem results in an
 
inoperable required offsite circuit. This is an exception
 
to LCO 3.0.6 and ensures the proper actions are taken for
 
these components.
 
E.1 and E.2
 
If the inoperable electrical power distribution system
 
cannot be restored to OPERABLE status within the associated
 
Completion Times, the plant must be brought to a MODE in
 
which the LCO does not apply. To achieve this status, the
 
plant must be brought to at least MODE 3 within 12 hours and
 
to MODE 4 within 36 hours. The allowed Completion Times are
 
reasonable, based on operating experience, to reach the
 
required plant conditions from full power conditions in an
 
orderly manner and without challenging plant systems.
 
F.1 With the Division 3 electrical power distribution system
 
inoperable (i.e., one or both Division 3 AC or DC electrical
 
power distribution subsystems inoperable), the Division 3 (continued)
Distribution Systems-Operating B 3.8.7 LaSalle 1 and 2 B 3.8.7-10 Revision 32 BASES ACTIONS F.1 (continued) powered systems are not capable of performing their intended
 
functions. Immediately declaring the affected supported
 
features, e.g., the High Pressure Core Spray System and its
 
associated primary containment isolation valves, inoperable
 
allows the ACTIONS of LCO 3.5.1, "ECCS-Operating," and
 
LCO 3.6.1.3, "Primary Containment Isolation Valves (PCIVs),"
to apply appropriate limitations on continued reactor
 
operation.
 
G.1 With the Division 1 250 V DC subsystem inoperable, the RCIC
 
System and the RCIC DC powered PCIVs may be incapable of
 
performing their intended functions and must be immediately
 
declared inoperable. This declaration also requires entry
 
into applicable Conditions and Required Actions of LCO
 
3.5.3, "Reactor Core Isolation Cooling (RCIC) System," and
 
LCO 3.6.1.3, "Primary Containment Isolation Valves (PCIVs)."
 
H.1 Condition H corresponds to a level of degradation in the electrical power distribution system that causes a required
 
safety function to be lost. When the inoperability of two
 
or more inoperable electrical power distribution subsystems, in combination, result in the loss of a required function, the plant is in a condition outside the accident analysis. 
 
Therefore, no additional time is justified for continued
 
operation. LCO 3.0.3 must be entered immediately to
 
commence a controlled shutdown. The term "in combination" means that the loss of function must result from the
 
inoperability of two or more AC and DC electrical power
 
distribution subsystems; a loss of function solely due to a
 
single AC or DC electrical power distribution subsystem
 
inoperability even with another AC or DC electrical power
 
distribution subsystem concurrently inoperable, does not
 
require entry into Condition H. In addition, for this Action, Division 3 is considered redundant to Division 1 and
 
2 ECCS.
  (continued)
Distribution Systems-Operating B 3.8.7 LaSalle 1 and 2 B 3.8.7-11 Revision 32 BASES  (continued)
 
SURVEILLANCE SR  3.8.7.1 REQUIREMENTS Meeting this Surveillance verifies that the AC and DC
 
electrical power distribution systems are functioning
 
properly, with the correct circuit breaker alignment. The
 
correct breaker alignment ensures the appropriate separation
 
and independence of the electrical divisions is maintained, and the appropriate voltage is available to each required
 
bus. The verification of proper voltage availability on the
 
buses ensures that the required voltage is readily available
 
for motive as well as control functions for critical system
 
loads connected to these buses. The 7 day Frequency takes
 
into account the redundant capability of the AC and DC
 
electrical power distribution subsystems, and other
 
indications available in the control room that alert the
 
operator to subsystem malfunctions.
 
REFERENCES 1. UFSAR, Chapter 6.
: 2. UFSAR, Chapter 15.
: 3. Regulatory Guide 1.93, Revision 0, December 1974.
: 4. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants," December 2002.
 
Distribution Systems-Operating B 3.8.7 LaSalle 1 and 2 B 3.8.7-12 Revision 0 Table B 3.8.7-1 (page 1 of 1)
Unit 1 AC and DC Electrical Power Distribution Systems TYPE VOLTAGE DIVISION 1 (a) DIVISION 2 (a)(b) DIVISION 3 (a)  AC buses  4160 V 480 V 
 
120 V  141Y 135X and 135Y  MCCs 135X-1, 135X-2, 135X-3, 135Y-1, and 135Y-2
 
Distribution Panels in 480V MCCS 135X-1, 135X-2, 135X-3, and 135Y-1 142Y 136X and 136Y MCCS 136X-1, 136X-2, 136X-3, 136Y-1, and 136Y-2
 
Distribution Panels in 480V MCCS 136X-1, 136X-2, 136X-3, and 136Y-2 143 MCC 143-1
 
Distribution Panels in 480V MCC 143-1 DC buses  250 V 125 V MCC 121Y Distribution Panel 111Y
 
Distribution Panel 112Y
 
Distribution Panel 113
 
  (a) Each division of the AC and DC electrical power distribution systems is a subsystem. 
 
(b) OPERABILITY requirements of the opposite unit's Division 2 AC and DC electrical power distribution subsystems require OPERABILITY of all the opposite unit's
 
Division 2 4160 VAC, 480 VAC, 120 VAC, and 125 VDC buses listed in the Unit 2
 
Table.
Distribution Systems-Operating B 3.8.7 LaSalle 1 and 2 B 3.8.7-13 Revision 0 Table B 3.8.7-2 (page 1 of 1)
Unit 2 AC and DC Electrical Power Distribution Systems TYPE VOLTAGE DIVISION 1 (a) DIVISION 2 (a)(b) DIVISION 3 (a)  AC buses  4160 V 480 V 
 
120 V  241Y 235X and 235Y MCCs 235X-1, 235X-2, 235X-3, 235Y-1, and 235Y-2
 
Distribution Panels in 480V MCCs 235X-1, 235X-2, 235X-3, and 235Y-1 242Y 236X and 236Y MCCS 236X-1, 236X-2, 236X-3, 236Y-1, and 236Y-2
 
Distribution Panels in 480V MCCs 236X-1, 236X-2, 236X-3, and 236Y-2 243 MCC 243-1
 
Distribution Panels in 480V MCC 243-1 DC buses  250 V 125 V  MCC 221Y Distribution Panel 211Y
 
Distribution Panel 212Y
 
Distribution Panel 213 (a) Each division of the AC and DC electrical power distribution systems is a subsystem. 
(b) OPERABILITY requirements of the opposite unit's Division 2 AC and DC electrical power distribution subsystems require OPERABILITY of all the opposite unit's
 
Division 2 4160 VAC, 480 VAC, 120 VAC, and 125 VDC buses listed in the Unit 1
 
Table.
Distribution Systems-Shutdown B 3.8.8 LaSalle 1 and 2 B 3.8.8-1 Revision 0 B 3.8  ELECTRICAL POWER SYSTEMS
 
B 3.8.8  Distribution Systems-Shutdown
 
BASES
 
BACKGROUND A description of the AC and DC electrical power distribution systems is provided in the Bases for LCO 3.8.7, "Distribution Systems-Operating."
APPLICABLE The initial conditions of Design Basis Accident and SAFETY ANALYSES transient analyses in the UFSAR, Chapter 6 (Ref. 1) and Chapter 15 (Ref. 2), assume Engineered Safety Feature (ESF)
 
systems are OPERABLE. The AC and DC electrical power
 
distribution systems are designed to provide sufficient
 
capacity, capability, redundancy, and reliability to ensure
 
the availability of necessary power to ESF systems so that
 
the fuel, Reactor Coolant System, and containment design
 
limits are not exceeded.
 
The OPERABILITY of the AC and DC electrical power
 
distribution system is consistent with the initial
 
assumptions of the accident analyses and the requirements
 
for the supported systems' OPERABILITY.
 
The OPERABILITY of the minimum AC and DC electrical power
 
sources and associated power distribution subsystems during
 
MODES 4 and 5, and during movement of irradiated fuel
 
assemblies in the secondary containment ensures that:
: a. The facility can be maintained in the shutdown or refueling condition for extended periods;
: b. Sufficient instrumentation and control capability is available for monitoring and maintaining the unit
 
status; and
: c. Adequate power is provided to mitigate events postulated during shutdown, such as an inadvertent
 
draindown of the vessel or a fuel handling accident.
 
The AC and DC electrical power distribution systems satisfy
 
Criterion 3 of 10 CFR 50.36(c)(2)(ii).
(continued)
Distribution Systems-Shutdown B 3.8.8 LaSalle 1 and 2 B 3.8.8-2 Revision 0 BASES  (continued)
 
LCO Various combinations of subsystems, equipment, and components are required OPERABLE by other LCOs, depending on
 
the specific plant condition. Implicit in those
 
requirements is the required OPERABILITY of necessary
 
support features. This LCO explicitly requires energization
 
of the portions of the electrical distribution system, including the opposite unit Division 2 electrical
 
distribution subsystem, necessary to support OPERABILITY of
 
Technical Specifications' required systems, equipment, and
 
components-both specifically addressed by their own LCOs, and implicitly required by the definition of OPERABILITY.
 
Maintaining these portions of the distribution system
 
energized ensures the availability of sufficient power to
 
operate the plant in a safe manner to mitigate the
 
consequences of postulated events during shutdown (e.g.,
fuel handling accidents and inadvertent reactor vessel
 
draindown).
 
APPLICABILITY The AC and DC electrical power distribution subsystems required to be OPERABLE in MODES 4 and 5 and during movement
 
of irradiated fuel assemblies in the secondary containment
 
provide assurance that:
: a. Systems to provide adequate coolant inventory makeup are available for the irradiated fuel in the core in
 
case of an inadvertent draindown of the reactor
 
vessel; 
: b. Systems needed to mitigate a fuel handling accident are available;
: c. Systems necessary to mitigate the effects of events that can lead to core damage during shutdown are
 
available; and
: d. Instrumentation and control capability is available for monitoring and maintaining the unit in a cold
 
shutdown or refueling condition.
 
The AC and DC electrical power distribution subsystem
 
requirements for MODES 1, 2, and 3 are covered in LCO 3.8.7.
(continued)
Distribution Systems-Shutdown B 3.8.8 LaSalle 1 and 2 B 3.8.8-3 Revision 0 BASES  (continued)
 
ACTIONS LCO 3.0.3 is not applicable while in MODE 4 or 5. However, since irradiated fuel assembly movement can occur in MODE 1, 2, or 3, the ACTIONS have been modified by a Note stating
 
that LCO 3.0.3 is not applicable. If moving irradiated fuel
 
assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify
 
any action. If moving irradiated fuel assemblies while in
 
MODE 1, 2, or 3, the fuel movement is independent of reactor
 
operations. Entering LCO 3.0.3 while in MODE 1, 2, or 3
 
would require the unit to be shutdown, but would not require
 
immediate suspension of movement of irradiated fuel
 
assemblies. The Note to the ACTIONS, "LCO 3.0.3 is not
 
applicable," ensures that the actions for immediate
 
suspension of irradiated fuel assembly movement are not
 
postponed due to entry into LCO 3.0.3.
 
A.1, A.2.1, A.2.2, A.2.3, A.2.4, and A.2.5
 
Although redundant required features may require redundant
 
divisions of electrical power distribution subsystems to be
 
OPERABLE, one OPERABLE distribution subsystem division may
 
be capable of supporting sufficient required features to
 
allow continuation of CORE ALTERATIONS, fuel movement, and
 
operations with a potential for draining the reactor vessel.
 
By allowing the option to declare required features
 
associated with an inoperable distribution subsystem
 
inoperable, appropriate restrictions are implemented in
 
accordance with the affected distribution subsystem LCO's
 
Required Actions. In many instances, this option may
 
involve undesired administrative efforts. Therefore, the
 
allowance for sufficiently conservative actions is made (i.e., to suspend CORE ALTERATIONS, movement of irradiated
 
fuel assemblies in the secondary containment and any
 
activities that could result in inadvertent draining of the
 
reactor vessel).
 
Suspension of these activities shall not preclude completion
 
of actions to establish a safe conservative condition.
 
These actions minimize the probability of the occurrence of
 
postulated events. It is further required to immediately
 
initiate action to restore the required AC and DC electrical
 
power distribution subsystems and to continue this action
 
until restoration is accomplished in order to provide the
 
necessary power to the plant safety systems.
(continued)
Distribution Systems-Shutdown B 3.8.8 LaSalle 1 and 2 B 3.8.8-4 Revision 0 BASES ACTIONS A.1, A.2.1, A.2.2, A.2.3, A.2.4, and A.2.5 (continued)
 
Notwithstanding performance of the above conservative
 
Required Actions, a required residual heat removal-shutdown
 
cooling (RHR-SDC) subsystem may be inoperable. In this
 
case, Required Actions A.2.1 through A.2.4 do not adequately
 
address the concerns relating to coolant circulation and
 
heat removal. Pursuant to LCO 3.0.6, the RHR-SDC ACTIONS
 
would not be entered. Therefore, Required Action A.2.5 is
 
provided to direct declaring RHR-SDC inoperable, which
 
results in taking the appropriate RHR-SDC ACTIONS.
 
The Completion Time of immediately is consistent with the
 
required times for actions requiring prompt attention. The
 
restoration of the required distribution subsystems should
 
be completed as quickly as possible in order to minimize the
 
time the plant safety systems may be without power.
 
SURVEILLANCE SR  3.8.8.1 REQUIREMENTS This Surveillance verifies that the AC and DC electrical
 
power distribution subsystem is functioning properly, with
 
the buses energized. The verification of proper voltage
 
availability on the buses ensures that the required power is
 
readily available for motive as well as control functions
 
for critical system loads connected to these buses. The
 
7 day Frequency takes into account the redundant capability
 
of the electrical power distribution subsystems, as well as
 
other indications available in the control room that alert
 
the operator to subsystem malfunctions.
 
REFERENCES 1. UFSAR, Chapter 6.
: 2. UFSAR, Chapter 15.
 
Refueling Equipment Interlocks B 3.9.1 LaSalle 1 and 2 B 3.9.1-1 Revision 0 B 3.9  REFUELING OPERATIONS
 
B 3.9.1  Refueling Equipment Interlocks
 
BASES
 
BACKGROUND Refueling equipment interlocks restrict the operation of the refueling equipment or the withdrawal of control rods to
 
reinforce unit procedures in preventing the reactor from
 
achieving criticality during refueling. The refueling
 
interlock circuitry senses the conditions of the refueling
 
equipment and the control rods. Depending on the sensed
 
conditions, interlocks are actuated to prevent the operation
 
of the refueling equipment or the withdrawal of control
 
rods.
 
GDC 26 of 10 CFR 50, Appendix A, requires that one of the
 
two required independent reactivity control systems be
 
capable of holding the reactor core subcritical under cold
 
conditions (Ref. 1). The control rods, when fully inserted, serve as the system capable of maintaining the reactor
 
subcritical in cold conditions during all fuel movement
 
activities and accidents.
 
The instrumentation provided to sense the position of the
 
refueling platform, the loading of the refueling platform
 
fuel grapple (main hoist), and the full insertion of all
 
control rods is single failure proof in that no single
 
failure can inhibit the interlocks. Additionally, inputs
 
are provided for the loading of the refueling platform
 
frame-mounted (auxiliary) hoist, the loading of the
 
refueling platform trolley-mounted (monorail) hoist, and the
 
loading of the service platform hoist. With the reactor
 
mode switch in the shutdown or refuel position, the
 
indicated conditions are combined in logic circuits to
 
determine if all restrictions on refueling equipment
 
operations and control rod insertion are satisfied.
 
A control rod not at its full-in position interrupts power
 
to the refueling equipment to prevent operating the
 
equipment over the reactor core when loaded with a fuel
 
assembly. Conversely, the refueling equipment located over
 
the core and loaded with fuel inserts a control rod
 
withdrawal block in the Reactor Manual Control System to
 
prevent withdrawing a control rod.
(continued)
Refueling Equipment Interlocks B 3.9.1    LaSalle 1 and 2 B 3.9.1-2 Revision 0 BASES BACKGROUND The refueling platform has two mechanical switches that open (continued) before the platform is physically located over the reactor vessel. The refueling platform hoists and the service
 
platform hoist have switches that open when the hoists are
 
loaded with fuel. The refueling interlocks use these
 
indications to prevent operation of the refueling equipment
 
with fuel loaded over the core whenever any control rod is
 
withdrawn, or to prevent control rod withdrawal whenever
 
fuel loaded refueling equipment is over the core (Ref. 2).
 
The hoist switches open at a load lighter than the weight of
 
a single fuel assembly in water.
 
APPLICABLE The refueling interlocks are explicitly assumed in the UFSAR SAFETY ANALYSES analysis of the control rod removal error during refueling (Ref. 3). This analysis evaluates the consequences of
 
control rod withdrawal during refueling. A prompt
 
reactivity excursion during refueling could potentially
 
result in fuel failure with subsequent release of
 
radioactive material to the environment.
 
Criticality and, therefore, subsequent prompt reactivity
 
excursions are prevented during the insertion of fuel, provided all control rods are fully inserted during the fuel
 
insertion. The refueling interlocks accomplish this by
 
preventing loading fuel into the core with any control rod
 
withdrawn, or by preventing withdrawal of a rod from the
 
core during fuel loading.
 
The refueling platform location switches activate at a point
 
outside of the reactor core, such that, with a fuel assembly
 
loaded and a control rod withdrawn, the fuel is not over the
 
core.
 
Refueling equipment interlocks satisfy Criterion 3 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO To prevent criticality during refueling, the refueling interlocks associated with the reactor mode switch refuel
 
position ensure that fuel assemblies are not loaded into the
 
core with any control rod withdrawn.
(continued)
Refueling Equipment Interlocks B 3.9.1    LaSalle 1 and 2 B 3.9.1-3 Revision 0 BASES LCO To prevent these conditions from developing, the (continued) all-rods-in, the refueling platform position, the refueling platform fuel grapple fuel-loaded, the refueling platform
 
frame-mounted hoist fuel-loaded, the refueling platform
 
trolley-mounted hoist fuel-loaded, and the service platform
 
hoist fuel-loaded inputs are required to be OPERABLE when
 
the associated equipment is in use for in-vessel fuel
 
movement. These inputs are combined in logic circuits that
 
provide refueling equipment or control rod blocks to prevent
 
operations that could result in criticality during refueling
 
operations.
 
APPLICABILITY In MODE 5, a prompt reactivity excursion could cause fuel damage and subsequent release of radioactive material to the
 
environment. The refueling equipment interlocks protect
 
against prompt reactivity excursions during MODE 5. The
 
interlocks are only required to be OPERABLE during in-vessel
 
fuel movement with refueling equipment associated with the
 
interlocks when the reactor mode switch is in the refuel
 
position. The interlocks are not required when the reactor
 
mode switch is in the shutdown position since a control rod
 
block (LCO 3.3.2.1, "Control Rod Block Instrumentation")
 
ensures control rod withdrawals cannot occur simultaneously
 
with in-vessel fuel movements.
 
In MODES 1, 2, 3, and 4, the reactor pressure vessel head is
 
on, and no fuel loading activities are possible. Therefore, the refueling interlocks are not required to be OPERABLE in
 
these MODES.
 
ACTIONS A.1, A.2.1, and A.2.2
 
With one or more of the required refueling equipment
 
interlocks inoperable, the unit must be placed in a
 
condition in which the LCO does not apply or is not
 
necessary. This can be performed by ensuring fuel
 
assemblies are not moved in the reactor vessel or by
 
ensuring that the control rods are inserted and cannot be
 
withdrawn. Therefore, Required Action A.1 requires that
 
in-vessel fuel movement with the affected refueling
 
equipment must be immediately suspended. This action
 
ensures that operations are not performed with equipment
 
that would potentially not be blocked from unacceptable
 
operations (e.g., loading fuel into a cell with a control (continued)
Refueling Equipment Interlocks B 3.9.1    LaSalle 1 and 2 B 3.9.1-4 Revision 0 BASES ACTIONS A.1, A.2.1, and A.2.2 (continued) rod withdrawn). Suspension of in-vessel fuel movement shall
 
not preclude completion of movement of a component to a safe
 
position. Alternately, Required Actions A.2.1 and A.2.2
 
require that a control rod withdrawal block be inserted and
 
that all control rods are subsequently verified to be fully
 
inserted. Required Action A.2.1 ensures that no control
 
rods can be withdrawn. This action ensures that control
 
rods cannot be inappropriately withdrawn since an electrical
 
or hydraulic block to control rod withdrawal is in place. 
 
Required Action A.2.2 is normally performed after placing
 
the rod withdrawal block in effect and provides a
 
verification that all control rods are fully inserted. Like
 
Required Action A.1, Required Actions A.2.1 and A.2.2 ensure
 
that unacceptable operations are prohibited (e.g., loading
 
fuel into a core cell with the control rod withdrawn).
 
SURVEILLANCE SR  3.9.1.1 REQUIREMENTS Performance of a CHANNEL FUNCTIONAL TEST demonstrates each
 
required refueling equipment interlock will function
 
properly when a simulated or actual signal indicative of a
 
required condition is injected into the logic. A successful
 
test of the required contact(s) of a channel relay may be
 
performed by the verification of the change of state of a
 
single contact of the relay. This clarifies what is an
 
acceptable CHANNEL FUNCTIONAL TEST of a relay. This is
 
acceptable because all of the other required contacts of the
 
relay are verified by other Technical Specifications and
 
non-Technical Specifications tests at least once per
 
refueling interval with applicable extensions.
 
The 7 day Frequency is based on engineering judgment and is
 
considered adequate in view of other indications of
 
refueling interlocks and their associated input status that
 
are available to unit operations personnel.
 
REFERENCES 1. 10 CFR 50, Appendix A, GDC 26.
: 2. UFSAR, Section 7.7.13.
: 3. UFSAR, Section 15.4.1.1.
 
Refuel Position One-Rod-Out Interlock B 3.9.2 LaSalle 1 and 2 B 3.9.2-1 Revision 0 B 3.9  REFUELING OPERATIONS
 
B 3.9.2  Refuel Position One-Rod-Out Interlock
 
BASES
 
BACKGROUND The refuel position one-rod-out interlock restricts the movement of control rods to reinforce unit procedures that
 
prevent the reactor from becoming critical during refueling
 
operations. During refueling operations, no more than one
 
control rod is permitted to be withdrawn.
 
GDC 26 of 10 CFR 50, Appendix A, requires that one of the
 
two required independent reactivity control systems be
 
capable of holding the reactor core subcritical under cold
 
conditions (Ref. 1). The control rods serve as the system
 
capable of maintaining the reactor subcritical in cold
 
conditions.
 
The refuel position one-rod-out interlock prevents the
 
selection of a second control rod for movement when any
 
other control rod is not fully inserted (Ref. 2). It is a
 
logic circuit that has redundant channels. It uses the
 
all-rods-in signal (from the control rod full-in position
 
indicators discussed in LCO 3.9.4, "Control Rod Position
 
Indication") and a rod selection signal (from the Reactor
 
Manual Control System).
 
This Specification ensures that the performance of the
 
refuel position one-rod-out interlock in the event of a
 
Design Basis Accident meets the assumptions used in the
 
safety analysis of Reference 3.
 
APPLICABLE The refuel position one-rod-out interlock is explicitly SAFETY ANALYSES assumed in the UFSAR analysis of the control rod removal error during refueling (Ref. 3). This analysis evaluates
 
the consequences of control rod withdrawal during refueling.
 
A prompt reactivity excursion during refueling could
 
potentially result in fuel failure with subsequent release
 
of radioactive material to the environment.
 
The refuel position one-rod-out interlock and adequate SDM (LCO 3.1.1, "SHUTDOWN MARGIN (SDM)") prevent criticality by
 
preventing withdrawal of more than one control rod. With (continued)
Refuel Position One-Rod-Out Interlock B 3.9.2 LaSalle 1 and 2 B 3.9.2-2 Revision 0 BASES APPLICABLE one control rod withdrawn, the core will remain subcritical, SAFETY ANALYSES thereby preventing any prompt critical excursion.
 
  (continued)
The refuel position one-rod-out interlock satisfies
 
Criterion 3 of 10 CFR 50.36(c)(2)(ii).
 
LCO To prevent criticality during MODE 5, the refuel position one-rod-out interlock ensures no more than one control rod
 
may be withdrawn. Both channels of the refuel position
 
one-rod-out interlock are required to be OPERABLE and the
 
reactor mode switch must be locked in the refuel position to
 
support the OPERABILITY of these channels.
 
APPLICABILITY In MODE 5, with the reactor mode switch in the refuel position, the OPERABLE refuel position one-rod-out interlock
 
provides protection against prompt reactivity excursions.
 
In MODES 1, 2, 3, and 4, the refuel position one-rod-out
 
interlock is not required to be OPERABLE and is bypassed. 
 
In MODES 1 and 2, the Reactor Protection System (LCO 3.3.1.1, "Reactor Protection System (RPS)
 
Instrumentation") and the control rods (LCO 3.1.3, "Control
 
Rod OPERABILITY") provide mitigation of potential reactivity
 
excursions. In MODES 3 and 4, with the reactor mode switch
 
in the shutdown position, a control rod block (LCO 3.3.2.1, "Control Rod Block Instrumentation") ensures all control
 
rods are inserted, thereby preventing criticality during
 
shutdown conditions.
 
ACTIONS A.1 and A.2
 
With the refuel position one-rod-out interlock inoperable, the refueling interlocks are not capable of preventing more
 
than one control rod from being withdrawn. This condition
 
may lead to criticality.
 
Control rod withdrawal must be immediately suspended, and
 
action must be immediately initiated to fully insert all
 
insertable control rods in core cells containing one or more
 
fuel assemblies. Action must continue until all such
 
control rods are fully inserted. Control rods in core cells
 
containing no fuel assemblies do not affect the reactivity
 
of the core and, therefore, do not have to be inserted.
 
(continued)
Refuel Position One-Rod-Out Interlock B 3.9.2 LaSalle 1 and 2 B 3.9.2-3 Revision 0 BASES  (continued)
 
SURVEILLANCE SR  3.9.2.1 REQUIREMENTS Proper functioning of the refueling position one-rod-out
 
interlock requires the reactor mode switch to be in Refuel.
 
During control rod withdrawal in MODE 5, improper
 
positioning of the reactor mode switch could, in some
 
instances, allow improper bypassing of required interlocks.
 
Therefore, this Surveillance imposes an additional level of
 
assurance that the refueling position one-rod-out interlock
 
will be OPERABLE when required. By "locking" the reactor
 
mode switch in the proper position (i.e., removing the
 
reactor mode switch key from the console while the reactor
 
mode switch is positioned in refuel), an additional
 
administrative control is in place to preclude operator
 
errors from resulting in unanalyzed operation.
 
The Frequency of 12 hours is sufficient in view of other
 
administrative controls utilized during refueling operations
 
to ensure safe operation.
 
SR  3.9.2.2
 
Performance of a CHANNEL FUNCTIONAL TEST on each channel
 
demonstrates the associated refuel position one-rod-out
 
interlock will function properly when a simulated or actual
 
signal indicative of a required condition is injected into
 
the logic. A successful test of the required contact(s) of
 
a channel relay may be performed by the verification of the
 
change of state of a single contact of the relay. This
 
clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a
 
relay. This is acceptable because all of the other required
 
contacts of the relay are verified by other Technical
 
Specifications and non-Technical Specifications tests at
 
least once per refueling interval with applicable
 
extensions. The 7 day Frequency is considered adequate
 
because of demonstrated circuit reliability, procedural
 
controls on control rod withdrawals, and visual indications
 
available in the control room to alert the operator of
 
control rods not fully inserted. To perform the required
 
testing, the applicable condition must be entered (i.e., a
 
control rod must be withdrawn from its full-in position). 
 
Therefore, SR 3.9.2.2 has been modified by a Note that
 
states the CHANNEL FUNCTIONAL TEST is not required to be
 
performed until 1 hour after any control rod is withdrawn. 
(continued)
Refuel Position One-Rod-Out Interlock B 3.9.2 LaSalle 1 and 2 B 3.9.2-4 Revision 0 BASES  (continued)
 
REFERENCES 1. 10 CFR 50, Appendix A, GDC 26.
: 2. UFSAR, Section 7.7.13.
: 3. UFSAR, Section 15.4.1.1.
 
Control Rod Position B 3.9.3 LaSalle 1 and 2 B 3.9.3-1 Revision 0 B 3.9  REFUELING OPERATIONS
 
B 3.9.3  Control Rod Position
 
BASES
 
BACKGROUND Control rods provide the capability to maintain the reactor subcritical under all conditions and to limit the potential
 
amount and rate of reactivity increase caused by a
 
malfunction in the Control Rod Drive System. During
 
refueling, movement of control rods is limited by the
 
refueling interlocks (LCO 3.9.1, "Refueling Equipment
 
Interlocks" and LCO 3.9.2, "Refuel Position One-Rod-Out
 
Interlock") or the control rod block with the reactor mode
 
switch in the shutdown position (LCO 3.3.2.1, "Control Rod
 
Block Instrumentation").
 
GDC 26 of 10 CFR 50, Appendix A, requires that one of the
 
two required independent reactivity control systems be
 
capable of holding the reactor core subcritical under cold
 
conditions (Ref. 1). The control rods serve as the system
 
capable of maintaining the reactor subcritical in cold
 
conditions.
 
The refueling interlocks allow a single control rod to be
 
withdrawn at any time unless fuel is being loaded into the
 
core. To preclude loading fuel assemblies into the core
 
with a control rod withdrawn, all control rods must be fully
 
inserted. This prevents the reactor from achieving
 
criticality during refueling operations.
 
APPLICABLE Prevention and mitigation of prompt reactivity excursions SAFETY ANALYSES during refueling are provided by the refueling interlocks (LCO 3.9.1 and LCO 3.9.2), the SDM (LCO 3.1.1, "SHUTDOWN
 
MARGIN (SDM)"), the intermediate range monitor neutron flux
 
scram (LCO 3.3.1.1, "Reactor Protection System (RPS)
 
Instrumentation"), and the control rod block instrumentation (LCO 3.3.2.1).
 
The safety analysis of the control rod removal error during
 
refueling in the UFSAR (Ref. 2) assumes the functioning of
 
the refueling interlocks and adequate SDM. Additionally, prior to fuel reload, all control rods must be fully
 
inserted to minimize the probability of an inadvertent
 
criticality.
 
(continued)
Control Rod Position B 3.9.3 LaSalle 1 and 2 B 3.9.3-2 Revision 0 BASES APPLICABLE Control rod position satisfies Criterion 3 of SAFETY ANALYSES 10 CFR 50.36(c)(2)(ii).
 
  (continued)
 
LCO All control rods must be fully inserted during applicable refueling conditions to minimize the probability of an
 
inadvertent criticality during refueling.
 
APPLICABILITY During MODE 5, loading fuel into core cells with control rods withdrawn may result in inadvertent criticality. 
 
Therefore, the control rods must be inserted before loading
 
fuel into a core cell. All control rods must be inserted
 
before loading fuel to ensure that a fuel loading error does
 
not result in loading fuel into a core cell with the control
 
rod withdrawn.
 
In MODES 1, 2, 3, and 4, the reactor pressure vessel head is
 
on, and no fuel loading activities are possible. Therefore, this Specification is not applicable in these MODES.
 
ACTIONS A.1
 
With all control rods not fully inserted during the
 
applicable conditions, an inadvertent criticality could
 
occur that is not analyzed in the UFSAR. All fuel loading
 
operations must be immediately suspended. Suspension of
 
these activities shall not preclude completion of movement
 
of a component to a safe position.
 
SURVEILLANCE SR  3.9.3.1 REQUIREMENTS During refueling, to ensure that the reactor remains
 
subcritical, all control rods must be fully inserted prior
 
to and during fuel loading. Periodic checks of the control
 
rod position ensure this condition is maintained.
 
The 12 hour Frequency takes into consideration the
 
procedural controls on control rod movement during refueling
 
as well as the redundant functions of the refueling
 
interlocks.
(continued)
Control Rod Position B 3.9.3 LaSalle 1 and 2 B 3.9.3-3 Revision 0 BASES  (continued)
 
REFERENCES 1. 10 CFR 50, Appendix A, GDC 26.
: 2. UFSAR, Section 15.4.1.1. 
 
Control Rod Position Indication B 3.9.4 LaSalle 1 and 2 B 3.9.4-1 Revision 0 B 3.9  REFUELING OPERATIONS
 
B 3.9.4  Control Rod Position Indication
 
BASES
 
BACKGROUND The full-in position indication channel for each control rod provides information necessary to the refueling interlocks
 
to prevent inadvertent criticalities during refueling
 
operations. During refueling, the refueling interlocks (LCO 3.9.1, "Refueling Equipment Interlocks" and LCO 3.9.2, "Refuel Position One-Rod-Out Interlock") use the full-in
 
position indication channel to limit the operation of the
 
refueling equipment and the movement of the control rods. 
 
Three full-in position indication detectors are provided for
 
each control rod (reed switches S00 and S52 provide
 
indication for full-in and switch S51 provides indication
 
for beyond full-in). All three full-in position indication
 
detectors provide input to the all-rods-in logic. The three
 
switches are wired in parallel, such that, if any one of the
 
three full-in position indication detectors indicates full-
 
in, the all-rods-in logic will receive a full-in signal for
 
that control rod. Therefore, each control rod is considered
 
to have only one "full-in" postion indication channel. The
 
absence of the full-in position indication channel signal
 
for any control rod removes the all-rods-in permissive for
 
the refueling equipment interlocks and prevents fuel
 
loading. Also, this condition causes the refuel position
 
one-rod-out interlock to not allow the selection of any
 
other control rod. The all-rods-in logic provides two
 
signals, one to each of the two Reactor Manual Control
 
System rod block logic circuits.
 
GDC 26 of 10 CFR 50, Appendix A, requires that one of the
 
two required independent reactivity control systems be
 
capable of holding the reactor core subcritical under cold
 
conditions (Ref. 1). The control rods serve as the system
 
capable of maintaining the reactor subcritical in cold
 
conditions.
 
APPLICABLE Prevention and mitigation of prompt reactivity excursions SAFETY ANALYSES during refueling are provided by the refueling interlocks (LCO 3.9.1 and LCO 3.9.2), the SDM (LCO 3.1.1, "SHUTDOWN
 
MARGIN (SDM)"), the intermediate range monitor neutron flux (continued)
Control Rod Position Indication B 3.9.4 LaSalle 1 and 2 B 3.9.4-2 Revision 0 BASES APPLICABLE scram (LCO 3.3.1.1, "Reactor Protection System (RPS)
SAFETY ANALYSES Instrumentation"), and the control rod block instrumentation (continued) (LCO 3.3.2.1, "Control Rod Block Instrumentation").
 
The safety analysis for the control rod removal error during
 
refueling (Ref. 2) assumes the functioning of the refueling
 
interlocks and adequate SDM. The full-in position
 
indication channel is required to be OPERABLE so that the
 
refueling interlocks can ensure that fuel cannot be loaded
 
with any control rod withdrawn and that no more than one
 
control rod can be withdrawn at a time.
 
Control rod position indication satisfies Criterion 3 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO The control rod full-in position indication channel for each control rod must be OPERABLE to provide the required inputs
 
to the refueling interlocks. A channel is OPERABLE if it
 
provides correct position indication to the refueling
 
equipment interlock all-rods-in logic (LCO 3.9.1) and the
 
refuel position one-rod-out interlock logic (LCO 3.9.2). 
 
APPLICABILITY During MODE 5, the control rods must have OPERABLE full-in position indication channels to ensure the applicable
 
refueling interlocks will be OPERABLE.
In MODES 1 and 2, requirements for control rod position are
 
specified in LCO 3.1.3, "Control Rod OPERABILITY."  In
 
MODES 3 and 4, with the reactor mode switch in the shutdown
 
position, a control rod block (LCO 3.3.2.1) ensures all
 
control rods are inserted, thereby preventing criticality
 
during shutdown conditions.
 
ACTIONS A Note has been provided to modify the ACTIONS related to control rod position indication channels. Section 1.3, Completion Times, specifies that once a Condition has been
 
entered, subsequent divisions, subsystems, components, or
 
variables expressed in the Condition, discovered to be
 
inoperable or not within limits, will not result in separate
 
entry into the Condition. Section 1.3 also specifies that
 
Required Actions of the Condition continue to apply for each
 
additional failure, with Completion Times based on initial (continued)
Control Rod Position Indication B 3.9.4 LaSalle 1 and 2 B 3.9.4-3 Revision 0 BASES ACTIONS entry into the Condition. However, the Required Actions for (continued) inoperable control rod position indication channels provide appropriate compensatory measures for separate inoperable
 
channels. As such, this Note has been provided, which
 
allows separate Condition entry for each inoperable required
 
control rod position indication channel.
 
A.1.1, A.1.2, A.1.3, A.2.1, and A.2.2
 
With one or more required full-in position indication
 
channels inoperable, compensating actions must be taken to
 
protect against potential reactivity excursions from fuel
 
assembly insertions or control rod withdrawals. This may be
 
accomplished by immediately suspending in-vessel fuel
 
movement and control rod withdrawal, and immediately
 
initiating action to fully insert all insertable control
 
rods in core cells containing one or more fuel assemblies. 
 
Actions must continue until all insertable control rods in
 
core cells containing one or more fuel assemblies are fully
 
inserted. Control rods in core cells containing no fuel
 
assemblies do not affect the reactivity of the core and, therefore, do not have to be inserted. Suspension of
 
in-vessel fuel movements and control rod withdrawal shall
 
not preclude moving a component to a safe position.
 
Alternatively, actions may be immediately initiated to fully
 
insert the control rod(s) associated with the inoperable
 
full-in position indicators(s) and to disarm (electrically
 
or hydraulically) the drive(s) to ensure that the control
 
rod is not withdrawn. A control rod can be hydraulically
 
disarmed by closing the drive water and exhaust water
 
isolation valves. A control rod can be electrically
 
disarmed by disconnecting power from all four directional
 
control valve solenoids. Actions must continue until all
 
associated control rods are fully inserted and drives are
 
disarmed. Under these conditions (control rod fully
 
inserted and disarmed), an inoperable full-in channel may be
 
bypassed to allow refueling operations to proceed. An
 
alternate method must be used to ensure the control rod is
 
fully inserted.
(continued)
Control Rod Position Indication B 3.9.4 LaSalle 1 and 2 B 3.9.4-4 Revision 0 BASES  (continued)
 
SURVEILLANCE SR  3.9.4.1 REQUIREMENTS The full-in position indication channels provide input to
 
the one-rod-out interlock and other refueling interlocks
 
that require an all-rods-in permissive. The interlocks are
 
activated when the full-in position indication for any
 
control rod is not present, since this indicates that all
 
rods are not fully inserted. Therefore, testing of the
 
full-in position indication channels is performed to ensure
 
that when a control rod is withdrawn, the full-in position
 
indication is not present. This is performed by verifying
 
both the absence of a full-in position indication and the
 
absence of an "00" indication for the control rod on the
 
four control rod group display, when the control rod is not
 
full-in. The full-in position indication channel is
 
considered inoperable even with the control rod fully
 
inserted, if it would continue to indicate full-in with the
 
control rod withdrawn. Performing the SR each time a
 
control rod is withdrawn from the full-in position is
 
considered adequate because of the procedural controls on
 
control rod withdrawals and the visual indications available
 
in the control room to alert the operator to control rods
 
not fully inserted.
 
REFERENCES 1. 10 CFR 50, Appendix A, GDC 26.
: 2. UFSAR, Section 15.4.1.1.
 
Control Rod OPERABILITY-Refueling B 3.9.5 LaSalle 1 and 2 B 3.9.5-1 Revision 0 B 3.9  REFUELING OPERATIONS
 
B 3.9.5  Control Rod OPERABILITY-Refueling
 
BASES
 
BACKGROUND Control rods are components of the Control Rod Drive (CRD)
System, the primary reactivity control system for the
 
reactor. In conjunction with the Reactor Protection System, the CRD System provides the means for the reliable control
 
of reactivity changes during refueling operation. In
 
addition, the control rods provide the capability to
 
maintain the reactor subcritical under all conditions and to
 
limit the potential amount and rate of reactivity increase
 
caused by a malfunction in the CRD System.
 
GDC 26 of 10 CFR 50, Appendix A, requires that one of the
 
two required independent reactivity control systems be
 
capable of holding the reactor core subcritical under cold
 
conditions (Ref. 1). The CRD System is the system capable
 
of maintaining the reactor subcritical in cold conditions.
 
APPLICABLE Prevention and mitigation of prompt reactivity excursions SAFETY ANALYSES during refueling are provided by refueling interlocks (LCO 3.9.1, "Refueling Equipment Interlocks" and LCO 3.9.2, "Refuel Position One-Rod-Out Interlock"), the SDM (LCO 3.1.1, "SHUTDOWN MARGIN (SDM)"), the intermediate range
 
monitor neutron flux scram (LCO 3.3.1.1, "Reactor Protection
 
System (RPS) Instrumentation"), and the control rod block
 
instrumentation (LCO 3.3.2.1, "Control Rod Block
 
Instrumentation").
 
The safety analysis for the control rod removal error during
 
refueling (Ref. 2) evaluates the consequences of control rod
 
withdrawal during refueling. A prompt reactivity excursion
 
during refueling could potentially result in fuel failure
 
with subsequent release of radioactive material to the
 
environment. Control rod scram provides protection should a
 
prompt reactivity excursion occur.
 
Control rod OPERABILITY during refueling satisfies
 
Criterion 3 of 10 CFR 50.36(c)(2)(ii).
(continued)
Control Rod OPERABILITY-Refueling B 3.9.5 LaSalle 1 and 2 B 3.9.5-2 Revision 0 BASES  (continued)
 
LCO Each withdrawn control rod must be OPERABLE. The withdrawn control rod is considered OPERABLE if the scram accumulator
 
pressure is  940 psig and the control rod is capable of being automatically inserted upon receipt of a scram signal.
 
Inserted control rods have already completed their
 
reactivity control function, and therefore, are not required
 
to be OPERABLE.
 
APPLICABILITY During MODE 5, withdrawn control rods must be OPERABLE to ensure that when a scram occurs the control rods will insert
 
and provide the required negative reactivity to maintain the
 
reactor subcritical.
 
For MODES 1 and 2, control rod requirements are found in
 
LCO 3.1.2, "Reactivity Anomalies," LCO 3.1.3, "Control Rod
 
OPERABILITY," LCO 3.1.4, "Control Rod Scram Times," and
 
LCO 3.1.5, "Control Rod Scram Accumulators."  During MODES 3
 
and 4, control rods are not able to be withdrawn since the
 
reactor mode switch is in shutdown and a control rod block
 
is applied. This provides adequate requirements for control
 
rod OPERABILITY during these conditions.
 
ACTIONS A.1
 
With one or more withdrawn control rods inoperable, action
 
must be immediately initiated to fully insert the inoperable
 
control rod(s). Inserting the control rod(s) ensures that
 
the shutdown and scram capabilities are not adversely
 
affected. Actions must continue until the inoperable
 
control rod(s) is fully inserted.
 
SURVEILLANCE SR  3.9.5.1 and SR  3.9.5.2 REQUIREMENTS During MODE 5, the OPERABILITY of control rods is primarily
 
required to ensure that a withdrawn control rod will
 
automatically insert if a signal requiring a reactor
 
shutdown occurs. Because no explicit analysis exists for
 
automatic shutdown during refueling, the shutdown function
 
is satisfied if the withdrawn control rod is capable of
 
automatic insertion and the associated CRD scram accumulator
 
pressure is  940 psig.
(continued)
Control Rod OPERABILITY-Refueling B 3.9.5 LaSalle 1 and 2 B 3.9.5-3 Revision 0 BASES SURVEILLANCE SR  3.9.5.1 and SR  3.9.5.2 (continued)
REQUIREMENTS The 7 day Frequency takes into consideration equipment
 
reliability, procedural controls over the scram
 
accumulators, and control room alarms and indicating lights
 
that indicate low accumulator charge pressures.
 
SR 3.9.5.1 is modified by a Note that allows 7 days after
 
withdrawal of the control rod to perform the Surveillance. 
 
This acknowledges that the control rod must first be
 
withdrawn before performance of the Surveillance, and
 
therefore avoids potential conflicts with SR 3.0.1.
 
REFERENCES 1. 10 CFR 50, Appendix A, GDC 26.
: 2. UFSAR, Section 15.4.1.1.
 
RPV Water Level-Irradiated Fuel B 3.9.6 LaSalle 1 and 2 B 3.9.6-1 Revision 0 B 3.9  REFUELING OPERATIONS
 
B 3.9.6  Reactor Pressure Vessel (RPV) Water Level-Irradiated Fuel
 
BASES
 
BACKGROUND The movement of irradiated fuel assemblies within the RPV requires a minimum water level of 22 ft above the top of the
 
RPV flange. During refueling, this maintains a sufficient
 
water level in the reactor vessel cavity and spent fuel
 
storage pool. Sufficient water is necessary to retain
 
iodine fission product activity in the water in the event of
 
a fuel handling accident (Refs. 1 and 2). Sufficient iodine
 
activity would be retained to limit offsite doses from the
 
accident to < 25% of 10 CFR 100 limits, as provided by the
 
guidance of Reference 3.
 
APPLICABLE During movement of irradiated fuel assemblies the water SAFETY ANALYSES level in the RPV is an initial condition design parameter in the analysis of a fuel handling accident in containment
 
postulated by Regulatory Guide 1.25 (Ref. 1). A minimum
 
water level of 23 ft (Regulatory Position C.1.c of Ref. 1)
 
allows a decontamination factor of 100 (Regulatory Position
 
C.1.g of Ref. 1) to be used in the accident analysis for
 
iodine. This relates to the assumption that 99% of the
 
total iodine released from the pellet to cladding gap of all
 
the dropped fuel assembly rods is retained by the refueling
 
cavity water. The fuel pellet to cladding gap is assumed to
 
contain 10% of the total fuel rod iodine inventory (Ref. 1).
 
Analysis of the fuel handling accident inside containment is
 
described in Reference 2. With a minimum water level of
 
22 ft (a decontamination factor of 100 is still expected at
 
a water level as low as 22 ft) and a minimum decay time of
 
24 hours prior to fuel handling, the analysis and test
 
programs demonstrate that the iodine release due to a
 
postulated fuel handling accident is adequately captured by
 
the water, and that offsite doses are maintained within
 
allowable limits (Ref. 4). While the worst case assumptions
 
include the dropping of the irradiated fuel assembly being
 
handled onto the reactor core, the possibility exists of the
 
dropped assembly striking the RPV flange and releasing
 
fission products. Therefore, the minimum depth for water
 
(continued)
RPV Water Level-Irradiated Fuel B 3.9.6  LaSalle 1 and 2 B 3.9.6-2 Revision 0 BASES APPLICABLE coverage to ensure acceptable radiological consequences is SAFETY ANALYSES specified from the RPV flange. Since the worst case event (continued) results in failed fuel assemblies seated in the core, as well as the dropped assembly, dropping an assembly on the
 
RPV flange will result in reduced releases of fission gases.
 
RPV water level satisfies Criterion 2 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO A minimum water level of 22 ft above the top of the RPV flange is required to ensure that the radiological
 
consequences of a postulated fuel handling accident are
 
within acceptable limits, as provided by the guidance of
 
Reference 3.
 
APPLICABILITY LCO 3.9.6 is applicable when moving irradiated fuel assemblies within the RPV. The LCO minimizes the
 
possibility of a fuel handling accident in containment that
 
is beyond the assumptions of the safety analysis. If
 
irradiated fuel is not present within the RPV, there can be
 
no significant radioactivity release as a result of a
 
postulated fuel handling accident. Requirements for
 
handling of new fuel assemblies or control rods (where water
 
depth to the RPV flange is not of concern) are covered by
 
LCO 3.9.7, "RPV Water Level - New Fuel or Control Rods." 
 
Requirements for fuel handling accidents in the spent fuel
 
storage pool are covered by LCO 3.7.8, "Spent Fuel Storage
 
Pool Water Level."
ACTIONS A.1
 
If the water level is < 22 ft above the top of the RPV
 
flange, all operations involving movement of irradiated fuel
 
assemblies within the RPV shall be suspended immediately to
 
ensure that a fuel handling accident cannot occur. The
 
suspension of irradiated fuel movement shall not preclude
 
completion of movement of a component to a safe position.
(continued)
RPV Water Level-Irradiated Fuel B 3.9.6  LaSalle 1 and 2 B 3.9.6-3 Revision 0 BASES  (continued)
 
SURVEILLANCE SR  3.9.6.1 REQUIREMENTS Verification of a minimum water level of 22 ft above the top
 
of the RPV flange ensures that the design basis for the
 
postulated fuel handling accident analysis during refueling
 
operations is met. Water at the required level limits the
 
consequences of damaged fuel rods, which are postulated to
 
result from a fuel handling accident in containment (Ref. 2).
 
The Frequency of 24 hours is based on engineering judgment
 
and is considered adequate in view of the large volume of
 
water and the normal procedural controls on valve positions, which make significant unplanned level changes unlikely.
 
REFERENCES 1. Regulatory Guide 1.25, March 23, 1972.
: 2. UFSAR, Section 15.7.4.
: 3. NUREG-0800, Section 15.7.4.
: 4. 10 CFR 100.11.
 
RPV Water Level-New Fuel or Control Rods B 3.9.7 LaSalle 1 and 2 B 3.9.7-1 Revision 0 B 3.9  REFUELING OPERATIONS
 
B 3.9.7  Reactor Pressure Vessel (RPV) Water Level-New Fuel or Control Rods
 
BASES
 
BACKGROUND The movement of new fuel assemblies or handling of control rods within the RPV when fuel assemblies seated within the
 
reactor vessel are irradiated requires a minimum water level
 
of 23 ft above the top of irradiated fuel assemblies seated
 
within the RPV. During refueling, this maintains a
 
sufficient water level above the irradiated fuel. 
 
Sufficient water is necessary to retain iodine fission
 
product activity in the water in the event of a fuel
 
handling accident (Refs. 1 and 2). Sufficient iodine
 
activity would be retained to limit offsite doses from the
 
accident to < 25% of 10 CFR 100 limits, as provided by the
 
guidance of Reference 3.
 
APPLICABLE During movement of new fuel assemblies or handling of SAFETY ANALYSES control rods over irradiated fuel assemblies, the water level in the RPV is an initial condition design parameter in
 
the analysis of a fuel handling accident in containment
 
postulated by Regulatory Guide 1.25 (Ref. 1). A minimum
 
water level of 23 ft (Regulatory Position C.1.c of Ref. 1)
 
allows a decontamination factor of 100  (Regulatory Position
 
C.1.g of Ref. 1) to be used in the accident analysis for
 
iodine. This relates to the assumption that 99% of the
 
total iodine released from the pellet to cladding gap of all
 
the dropped fuel assembly rods is retained by the refueling
 
cavity water. The fuel pellet to cladding gap is assumed to
 
contain 10% of the total fuel rod iodine inventory (Ref. 1).
 
Analysis of the fuel handling accident inside containment is
 
described in Reference 2. With a minimum water level of
 
23 ft and a minimum decay time of 24 hours prior to fuel
 
handling, the analysis and test programs demonstrate that
 
the iodine release due to a postulated fuel handling
 
accident is adequately captured by the water, and that
 
offsite doses are maintained within allowable limits (Ref. 4). The related assumptions include the worst case
 
dropping of an irradiated fuel assembly onto the reactor
 
core loaded with irradiated fuel assemblies.
 
(continued)
RPV Water Level-New Fuel or Control Rods B 3.9.7 LaSalle 1 and 2 B 3.9.7-2 Revision 0 BASES APPLICABLE RPV water level satisfies Criterion 2 of SAFETY ANALYSES 10 CFR 50.36(c)(2)(ii).
 
  (continued)
 
LCO A minimum water level of 23 ft above the top of irradiated fuel assemblies seated within the RPV is required to ensure
 
that the radiological consequences of a postulated fuel
 
handling accident are within acceptable limits, as provided
 
by the guidance of Reference 3.
 
APPLICABILITY LCO 3.9.7 is applicable when moving new fuel assemblies or handling control rods (i.e., movement with other than the
 
normal control rod drive) when irradiated fuel assemblies
 
are seated within the RPV. The LCO minimizes the
 
possibility of a fuel handling accident in containment that
 
is beyond the assumptions of the safety analysis. If
 
irradiated fuel is not present within the RPV, there can be
 
no significant radioactivity release as a result of a
 
postulated fuel handling accident. Requirements for fuel
 
handling accidents in the spent fuel storage pool are
 
covered by LCO 3.7.8, "Spent Fuel Storage Pool Water Level."
Requirements for handling irradiated fuel over the RPV are
 
covered by LCO 3.9.6, "Reactor Pressure Vessel (RPV) Water
 
Level-Irradiated Fuel."
ACTIONS A.1
 
If the water level is < 23 ft above the top of irradiated
 
fuel assemblies seated within the RPV, all operations
 
involving movement of new fuel assemblies and handling of
 
control rods within the RPV shall be suspended immediately
 
to ensure that a fuel handling accident cannot occur. The
 
suspension of fuel movement and control rod handling shall
 
not preclude completion of movement of a component to a safe
 
position.
(continued)
RPV Water Level-New Fuel or Control Rods B 3.9.7 LaSalle 1 and 2 B 3.9.7-3 Revision 0 BASES  (continued)
 
SURVEILLANCE SR  3.9.7.1 REQUIREMENTS Verification of a minimum water level of 23 ft above the top
 
of the irradiated fuel assemblies seated within the RPV
 
ensures that the design basis for the postulated fuel
 
handling accident analysis during refueling operations is
 
met. Water at the required level limits the consequences of
 
damaged fuel rods, which are postulated to result from a
 
fuel handling accident in containment (Ref. 2).
 
The Frequency of 24 hours is based on engineering judgment
 
and is considered adequate in view of the large volume of
 
water and the normal procedural controls on valve positions, which make significant unplanned level changes unlikely.
 
REFERENCES 1. Regulatory Guide 1.25, March 23, 1972.
: 2. UFSAR, Section 15.7.4.
: 3. NUREG-0800, Section 15.7.4.
: 4. 10 CFR 100.11.
 
RHR-High Water Level B 3.9.8 LaSalle 1 and 2 B 3.9.8-1 Revision 0 B 3.9  REFUELING OPERATIONS
 
B 3.9.8  Residual Heat Removal (RHR)-High Water Level
 
BASES
 
BACKGROUND The purpose of the RHR System in MODE 5 is to remove decay heat and sensible heat from the reactor coolant, as required
 
by GDC 34 (Ref. 1). Each of the two shutdown cooling loops
 
of the RHR System can provide the required decay heat
 
removal. Each loop consists of one motor driven pump, a
 
heat exchanger, and associated piping and valves. Both
 
loops have a common suction from the same recirculation
 
loop. Each pump discharges the reactor coolant, after it
 
has been cooled by circulation through the respective heat
 
exchangers, to the reactor via the associated recirculation
 
loop. The RHR heat exchangers transfer heat to the RHR
 
Service Water (RHRSW) System. The RHR shutdown cooling mode
 
is manually controlled.
 
In addition to the RHR subsystems, the volume of water above
 
the reactor pressure vessel (RPV) flange provides a heat
 
sink for decay heat removal.
 
APPLICABLE With the unit in MODE 5, the RHR shutdown cooling subsystem SAFETY ANALYSES is not required to mitigate any events or accidents evaluated in the safety analyses. The RHR shutdown cooling
 
subsystem is required for removing decay heat to maintain
 
the temperature of the reactor coolant.
 
The RHR System satisfies Criterion 4 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO Only one RHR shutdown cooling subsystem is required to be OPERABLE and in operation in MODE 5 with irradiated fuel in
 
the RPV and the water level  22 ft above the RPV flange.
Only one subsystem is required to be OPERABLE because the
 
volume of water above the RPV flange provides backup decay
 
heat removal capability.
 
An OPERABLE RHR shutdown cooling subsystem consists of an
 
RHR pump, a heat exchanger, the necessary portions of the
 
RHRSW System and Ultimate Heat Sink capable of providing (continued)
RHR-High Water Level B 3.9.8 LaSalle 1 and 2 B 3.9.8-2 Revision 0 BASES LCO cooling to the RHR heat exchanger, valves, piping, (continued) instruments, and controls to ensure an OPERABLE flow path.
 
Additionally, each RHR shutdown cooling subsystem is
 
considered OPERABLE if it can be manually aligned (remote or
 
local) in the shutdown cooling mode for removal of decay
 
heat. Operation (either continuous or intermittent) of one
 
subsystem can maintain and reduce the reactor coolant
 
temperature as required. However, to ensure adequate core
 
flow to allow for accurate average reactor coolant
 
temperature monitoring, nearly continuous operation is
 
required. A Note is provided to allow a 2 hour exception
 
for the operating subsystem to not be in operation every
 
8 hours. This is permitted because the core heat generation
 
can be low enough and the heatup rate slow enough to allow
 
some changes to the RHR subsystem or other operations
 
requiring RHR flow interruption.
 
APPLICABILITY One RHR shutdown cooling subsystem must be OPERABLE and in operation in MODE 5, with irradiated fuel in the RPV and
 
with the water level  22 ft above the top of the RPV flange, to provide decay heat removal. RHR shutdown cooling
 
subsystem requirements in other MODES are covered by LCOs in
 
Section 3.4, Reactor Coolant System (RCS). RHR shutdown
 
cooling subsystem requirements in MODE 5, with irradiated
 
fuel in the RPV and with the water level < 22 ft above the
 
RPV flange, are given in LCO 3.9.9, "Residual Heat Removal (RHR)-Low Water Level."
ACTIONS A.1
 
With no RHR shutdown cooling subsystem OPERABLE, an
 
alternate method of decay heat removal must be provided
 
within 1 hour. In this condition, the volume of water above
 
the RPV flange provides adequate capability to remove decay
 
heat from the reactor core. However, the overall
 
reliability is reduced because loss of water level could
 
result in reduced decay heat removal capability. The 1 hour
 
Completion Time is based on the decay heat removal function
 
and the probability of a loss of the available decay heat
 
removal capabilities. Furthermore, verification of the (continued)
RHR-High Water Level B 3.9.8 LaSalle 1 and 2 B 3.9.8-3 Revision 0 BASES ACTIONS A.1 (continued)
 
functional availability of the alternate method must be
 
reconfirmed every 24 hours thereafter. This will ensure
 
continued heat removal capability.
 
Alternate decay heat removal methods are available to the
 
operators for review and preplanning in the unit operating
 
procedures. The required cooling capacity of the alternate
 
method should be ensured by verifying (by calculation or
 
demonstration) its capability to maintain or reduce
 
temperature. For example, this may include the use of the
 
Fuel Pool Cooling System (operating with positive flow from
 
the reactor cavity to the skimmer surge tank), the Reactor
 
Water Cleanup System, or the Control Rod Drive System. The
 
method used to remove the decay heat should be the most
 
prudent choice based on unit conditions.
 
B.1, B.2, B.3, and B.4
 
If no RHR shutdown cooling subsystem is OPERABLE and an
 
alternate method of decay heat removal is not available in
 
accordance with Required Action A.1, actions shall be taken
 
immediately to suspend operations involving an increase in
 
reactor decay heat load by suspending the loading of
 
irradiated fuel assemblies into the RPV.
 
Additional actions are required to minimize any potential
 
fission product release to the environment. This includes
 
ensuring secondary containment is OPERABLE; one standby gas
 
treatment subsystem is OPERABLE; and secondary containment
 
isolation capability is available in each associated
 
penetration flow path not isolated that is assumed to be
 
isolated to mitigate radioactive releases (i.e., one
 
secondary containment isolation valve and associated
 
instrumentation are OPERABLE or other acceptable
 
administrative controls to assure isolation capability. 
 
These administrative controls consist of stationing a
 
dedicated operator, who is in continuous communication with
 
the control room, at the controls of the isolation device. 
 
In this way, the penetration can be rapidly isolated when a
 
need for secondary containment isolation is indicated).
(continued)
RHR-High Water Level B 3.9.8 LaSalle 1 and 2 B 3.9.8-4 Revision 0 BASES ACTIONS B.1, B.2, B.3, and B.4 (continued)
 
This may be performed as an administrative check, by
 
examining logs or other information to determine whether the
 
components are out of service for maintenance or other
 
reasons. It is not necessary to perform the Surveillances
 
needed to demonstrate the OPERABILITY of the components. 
 
If, however, any required component is inoperable, then it
 
must be restored to OPERABLE status. In this case, a
 
surveillance may need to be performed to restore the
 
component to OPERABLE status. Actions must continue until
 
all required components are OPERABLE.
 
C.1 and C.2
 
If no RHR shutdown cooling subsystem is in operation, an
 
alternate method of coolant circulation is required to be
 
established within 1 hour. The Completion Time is modified
 
such that 1 hour is applicable separately for each
 
occurrence involving a loss of coolant circulation.
 
During the period when the reactor coolant is being
 
circulated by an alternate method (other than by the
 
required RHR shutdown cooling subsystem), the reactor
 
coolant temperature must be periodically monitored to ensure
 
proper functioning of the alternate method. The once per
 
hour Completion Time is deemed appropriate.
 
SURVEILLANCE SR  3.9.8.1 REQUIREMENTS This Surveillance demonstrates that the required RHR
 
shutdown cooling subsystem is in operation and circulating
 
reactor coolant in accordance with normal procedural
 
requirements. The Frequency of 12 hours is sufficient in
 
view of other visual and audible indications available to
 
the operator for monitoring the RHR shutdown cooling
 
subsystem in the control room.
 
REFERENCES 1. 10 CFR 50, Appendix A, GDC 34.
 
RHR-Low Water Level B 3.9.9 LaSalle 1 and 2 B 3.9.9-1 Revision 0 B 3.9  REFUELING OPERATIONS
 
B 3.9.9  Residual Heat Removal (RHR)-Low Water Level
 
BASES
 
BACKGROUND The purpose of the RHR System in MODE 5 is to remove decay heat and sensible heat from the reactor coolant, as required
 
by GDC 34 (Ref. 1). Each of the two shutdown cooling loops
 
of the RHR System can provide the required decay heat
 
removal. Each loop consists of one motor driven pump, a
 
heat exchanger, and associated piping and valves. Both
 
loops have a common suction from the same recirculation
 
loop. Each pump discharges the reactor coolant, after it
 
has been cooled by circulation through the respective heat
 
exchangers, to the reactor via the associated recirculation
 
loop. The RHR heat exchangers transfer heat to the RHR
 
Service Water (RHRSW) System. The RHR shutdown cooling mode
 
is manually controlled.
 
APPLICABLE With the unit in MODE 5, the RHR shutdown cooling subsystems SAFETY ANALYSES are not required to mitigate any events or accidents evaluated in the safety analyses. The RHR shutdown cooling
 
subsystems are required for removing decay heat to maintain
 
the temperature of the reactor coolant.
 
The RHR System satisfies Criterion 4 of
 
10 CFR 50.36(c)(2)(ii).
 
LCO In MODE 5 with irradiated fuel in the reactor pressure vessel (RPV) and with the water level < 22 ft above the RPV
 
flange both RHR shutdown cooling subsystems must be OPERABLE
 
and one RHR shutdown cooling subsystem must be in operation.
 
An OPERABLE RHR shutdown cooling subsystem consists of an
 
RHR pump, a heat exchanger, the necessary portions of the
 
RHRSW System and Ultimate Heat Sink capable of providing
 
cooling to the RHR heat exchanger, valves, piping, instruments, and controls to ensure an OPERABLE flow path.
 
Additionally, each RHR shutdown cooling subsystem is
 
considered OPERABLE if it can be manually aligned (remote or
 
local) in the shutdown cooling mode for removal of decay (continued)
RHR-Low Water Level B 3.9.9 LaSalle 1 and 2 B 3.9.9-2 Revision 0 BASES LCO heat. Operation (either continuous or intermittent) of one (continued) subsystem can maintain and reduce the reactor coolant temperature as required. However, to ensure adequate core
 
flow to allow for accurate average reactor coolant
 
temperature monitoring, nearly continuous operation is
 
required. A Note is provided to allow a 2 hour exception
 
for the operating subsystem to not be in operation every
 
8 hours. This is permitted because the core heat generation
 
can be low enough and the heatup rate slow enough to allow
 
some changes to the RHR subsystem or other operations
 
requiring RHR flow interruption.
 
APPLICABILITY Two RHR shutdown cooling subsystems are required to be OPERABLE and one RHR shutdown cooling subsystem must be in
 
operation in MODE 5, with irradiated fuel in the RPV and
 
with the water level < 22 ft above the top of the RPV
 
flange, to provide decay heat removal. RHR shutdown cooling
 
subsystem requirements in other MODES are covered by LCOs in
 
Section 3.4, Reactor Coolant System (RCS). RHR shutdown
 
cooling subsystem requirements in MODE 5, with irradiated
 
fuel in the RPV and the water level  22 ft above the RPV flange, are given in LCO 3.9.8, "Residual Heat Removal (RHR)-High Water Level."
ACTIONS A.1 With one of the two RHR shutdown cooling subsystems
 
inoperable, the remaining subsystem is capable of providing
 
the required decay heat removal. However, the overall
 
reliability is reduced. Therefore, an alternate method of
 
decay heat removal must be provided. With both RHR shutdown
 
cooling subsystems inoperable, an alternate method of decay
 
heat removal must be provided in addition to that provided
 
for the initial RHR shutdown cooling subsystem
 
inoperability. This re-establishes backup decay heat
 
removal capabilities, similar to the requirements of the
 
LCO. The 1 hour Completion Time is based on the decay heat
 
removal function and the probability of a loss of the
 
available decay heat removal capabilities. Furthermore, verification of the functional availability of these
 
alternate method(s) must be reconfirmed every 24 hours
 
thereafter. This will ensure continued heat removal
 
capability.
 
(continued)
RHR-Low Water Level B 3.9.9 LaSalle 1 and 2 B 3.9.9-3 Revision 0 BASES ACTIONS A.1 (continued)
Alternate decay heat removal methods are available to the
 
operators for review and preplanning in the unit operating
 
procedures. The required cooling capacity of the alternate
 
method(s) should be ensured by verifying (by calculation or
 
demonstration) their capability to maintain or reduce
 
temperature. For example, this may include the use of the
 
Fuel Pool Cooling System (operating with positive flow from
 
the reactor cavity to the skimmer surge tank), the Reactor
 
Water Cleanup System, or the Control Rod Drive System. The
 
method used to remove decay heat should be the most prudent
 
choice based on unit conditions.
 
Condition A is modified by a Note allowing separate
 
Condition entry for each inoperable RHR shutdown cooling
 
subsystem. This is acceptable since the Required Actions
 
for this Condition provide appropriate compensatory actions
 
for each inoperable RHR shutdown cooling subsystem. 
 
Complying with the Required Actions allow for continued
 
operation. A subsequent inoperable RHR shutdown cooling
 
subsystem is governed by subsequent entry into the Condition
 
and application of the Required Actions.
 
B.1, B.2, and B.3
 
With the required decay heat removal subsystem(s) inoperable
 
and the required alternate method(s) of decay heat removal
 
not available in accordance with Required Action A.1, additional actions are required to minimize any potential
 
fission product release to the environment. This includes
 
ensuring secondary containment is OPERABLE; one standby gas
 
treatment subsystem is OPERABLE; and secondary containment
 
isolation capability is available in each associated
 
penetration flow path not isolated that is assumed to be
 
isolated to mitigate radioactive releases (i.e., one
 
secondary containment isolation valve and associated
 
instrumentation are OPERABLE or other acceptable
 
administrative controls to assure isolation capability.
 
These administrative controls consist of stationing a
 
dedicated operator, who is in continuous communication with
 
the control room, at the controls of the isolation device. 
(continued)
RHR-Low Water Level B 3.9.9 LaSalle 1 and 2 B 3.9.9-4 Revision 0 BASES ACTIONS B.1, B.2, and B.3 (continued)
In this way, the penetration can be rapidly isolated when a
 
need for secondary containment isolation is indicated).
 
This may be performed as an administrative check, by
 
examining logs or other information to determine whether the
 
components are out of service for maintenance or other
 
reasons. It is not necessary to perform the Surveillances
 
needed to demonstrate the OPERABILITY of the components.
 
If, however, any required component is inoperable, then it
 
must be restored to OPERABLE status. In this case, a
 
surveillance may need to be performed to restore the
 
component to OPERABLE status. Actions must continue until
 
all required components are OPERABLE.
 
C.1 and C.2
 
If no RHR shutdown cooling subsystem is in operation, an
 
alternate method of coolant circulation is required to be
 
established within 1 hour. The Completion Time is modified
 
such that the 1 hour is applicable separately for each 
 
occurrence involving a loss of coolant circulation.
 
During the period when the reactor coolant is being
 
circulated by an alternate method (other than by the
 
required RHR shutdown cooling subsystem), the reactor
 
coolant temperature must be periodically monitored to ensure
 
proper function of the alternate method. The once per hour
 
Completion Time is deemed appropriate.
 
SURVEILLANCE SR  3.9.9.1 REQUIREMENTS This Surveillance demonstrates that one RHR shutdown cooling
 
subsystem is in operation and circulating reactor coolant in
 
accordance with normal procedural requirements. The
 
Frequency of 12 hours is sufficient in view of other visual
 
and audible indications available to the operator for
 
monitoring the RHR shutdown cooling subsystem in the control
 
room.
REFERENCES 1. 10 CFR 50, Appendix A, GDC 34.
 
Reactor Mode Switch Interlock Testing B 3.10.1 LaSalle 1 and 2 B 3.10.1-1 Revision 0 B 3.10  SPECIAL OPERATIONS
 
B 3.10.1  Reactor Mode Switch Interlock Testing
 
BASES
 
BACKGROUND The purpose of this Special Operations LCO is to permit operation of the reactor mode switch from one position to
 
another to confirm certain aspects of associated interlocks
 
during periodic tests and calibrations in MODES 3, 4, and 5.
 
The reactor mode switch is a conveniently located, multiposition, keylock switch provided to select the
 
necessary scram functions for various plant conditions (Ref. 1). The reactor mode switch selects the appropriate
 
trip relays for scram functions and provides appropriate
 
bypasses. The mode switch positions and related scram
 
interlock functions are summarized as follows:
: a. Shutdown - Initiates a reactor scram; bypasses main steam line isolation scram;
: b. Refuel - Selects Neutron Monitoring System (NMS) scram function for low neutron flux level operation (but
 
does not disable the average power range monitor
 
scram); bypasses main steam line isolation scram;
: c. Startup/Hot Standby - Selects NMS scram function for low neutron flux level operation (intermediate range
 
monitors and average power range monitors); bypasses
 
main steam line isolation scram; and
: d. Run - Selects NMS scram function for power range operation.
 
The reactor mode switch also provides interlocks for such
 
functions as control rod blocks, scram discharge volume trip
 
bypass, refueling interlocks, and main steam isolation valve
 
isolations.
 
APPLICABLE The purpose for reactor mode switch interlock testing is to SAFETY ANALYSES prevent fuel failure by precluding reactivity excursions or core criticality.
(continued)
Reactor Mode Switch Interlock Testing B 3.10.1 LaSalle 1 and 2 B 3.10.1-2 Revision 0 BASES APPLICABLE The interlock functions of the shutdown and refuel positions SAFETY ANALYSES of the reactor mode switch in MODES 3, 4, and 5 are provided (continued) to preclude reactivity excursions that could potentially result in fuel failure. Interlock testing that requires
 
moving the reactor mode switch to other positions (run, or
 
startup/hot standby) while in MODE 3, 4, or 5, requires
 
administratively maintaining all control rods inserted and
 
no other CORE ALTERATIONS in progress. With all control
 
rods inserted in core cells containing one or more fuel
 
assemblies and no CORE ALTERATIONS in progress, there are no
 
credible mechanisms for unacceptable reactivity excursions
 
during the planned interlock testing.
 
For postulated accidents, such as control rod removal error
 
during refueling or loading of fuel with a control rod
 
withdrawn, the accident analysis demonstrates that fuel
 
failure will not occur (Ref. 2). The withdrawal of a single
 
control rod will not result in criticality when adequate SDM
 
is maintained. Also, loading fuel assemblies into the core
 
with a single control rod withdrawn will not result in
 
criticality, thereby preventing fuel failure.
 
As described in LCO 3.0.7, compliance with Special
 
Operations LCOs is optional, and therefore no criteria of
 
10 CFR 50.36(c)(2)(ii) apply. Special Operations LCOs
 
provide flexibility to perform certain operations by
 
appropriately modifying requirements of other LCOs. A
 
discussion of the criteria satisfied for the other LCOs is
 
provided in their respective Bases.
 
LCO As described in LCO 3.0.7, compliance with this Special Operations LCO is optional. MODES 3, 4, and 5 operations
 
not specified in Table 1.1-1 can be performed in accordance
 
with other Special Operations LCOs (i.e., LCO 3.10.2, "Single Control Rod Withdrawal-Hot Shutdown," LCO 3.10.3, "Single Control Rod Withdrawal-Cold Shutdown," and
 
LCO 3.10.7, "SDM Test-Refueling") without meeting this LCO
 
or its ACTIONS. If any testing is performed that involves
 
the reactor mode switch interlocks and requires
 
repositioning beyond that specified in Table 1.1-1 for the
 
current MODE of operation, the testing can be performed, provided all interlock functions potentially defeated are (continued)
Reactor Mode Switch Interlock Testing B 3.10.1 LaSalle 1 and 2 B 3.10.1-3 Revision 0 BASES LCO administratively controlled. In MODES 3, 4, and 5 with the (continued) reactor mode switch in shutdown as specified in Table 1.1-1, all control rods are fully inserted and a control rod block
 
is initiated. Therefore, all control rods in core cells
 
that contain one or more fuel assemblies must be verified
 
fully inserted while in MODES 3, 4, and 5 with the reactor
 
mode switch in other than the shutdown position. The
 
additional LCO requirement to preclude CORE ALTERATIONS is
 
appropriate for MODE 5 operations, as discussed below, and
 
is inherently met in MODES 3 and 4 by the definition of CORE
 
ALTERATIONS, which cannot be performed with the vessel head
 
in place.
 
In MODE 5, with the reactor mode switch in the refuel
 
position, only one control rod can be withdrawn under the
 
refuel position one rod out interlock (LCO 3.9.2, "Refuel
 
Position One-Rod-Out Interlock"). The refueling equipment
 
interlocks (LCO 3.9.1, "Refueling Equipment Interlocks")
 
appropriately control other CORE ALTERATIONS. Due to the
 
increased potential for error in controlling these multiple
 
interlocks and the limited duration of tests involving the
 
reactor mode switch position, conservative controls are
 
required, consistent with MODES 3 and 4. The additional
 
controls of administratively not permitting other CORE
 
ALTERATIONS will adequately ensure that the reactor does not
 
become critical during these tests.
 
APPLICABILITY Any required periodic interlock testing involving the reactor mode switch, while in MODES 1 and 2, can be
 
performed without the need for Special Operations
 
exceptions. Mode switch manipulations in these MODES would
 
likely result in unit trips. In MODES 3, 4, and 5, this
 
Special Operations LCO is only permitted to be used to allow
 
reactor mode switch interlock testing that cannot
 
conveniently be performed without this allowance or testing
 
that must be performed prior to entering another MODE. Such
 
interlock testing may consist of required Surveillances, or
 
may be the result of maintenance, repair, or troubleshooting
 
activities. In MODES 3, 4, and 5, the interlock functions
 
provided by the reactor mode switch in shutdown (i.e., all
 
control rods inserted and incapable of withdrawal) and
 
refueling (i.e., refueling interlocks to prevent inadvertent
 
criticality during CORE ALTERATIONS) positions can be
 
administratively controlled adequately during the
 
performance of certain tests.
(continued)
Reactor Mode Switch Interlock Testing B 3.10.1 LaSalle 1 and 2 B 3.10.1-4 Revision 0 BASES  (continued)
 
ACTIONS A.1, A.2, A.3.1, and A.3.2 These Required Actions are provided to restore compliance
 
with the Technical Specifications overridden by this Special
 
Operations LCO. Restoring compliance will also result in
 
exiting the Applicability of this Special Operations LCO.
 
All CORE ALTERATIONS, except control rod insertion, if in
 
progress, are immediately suspended in accordance with
 
Required Action A.1, and all insertable control rods in core
 
cells that contain one or more fuel assemblies are fully
 
inserted within 1 hour, in accordance with Required
 
Action A.2. This will preclude potential mechanisms that
 
could lead to criticality. Control rods in core cells
 
containing no fuel assemblies do not affect the reactivity
 
of the core and, therefore, do not have to be inserted. 
 
Suspension of CORE ALTERATIONS shall not preclude the
 
completion of movement of a component to a safe condition. 
 
Placing the reactor mode switch in the shutdown position
 
will ensure that all inserted control rods remain inserted
 
and result in operation in accordance with Table 1.1-1. 
 
Alternatively, if in MODE 5, the reactor mode switch may be
 
placed in the refuel position, which will also result in
 
operating in accordance with Table 1.1-1. A Note is added
 
to Required Action A.3.2 to indicate that this Required
 
Action is not applicable in MODES 3 and 4, since only the
 
shutdown position is allowed in these MODES. The allowed
 
Completion Time of 1 hour for Required Actions A.2, A.3.1, and A.3.2 provides sufficient time to normally insert the
 
control rods and place the reactor mode switch in the
 
required position, based on operating experience, and is
 
acceptable given that all operations that could increase
 
core reactivity have been suspended.
 
SURVEILLANCE SR  3.10.1.1 and SR  3.10.1.2 REQUIREMENTS Meeting the requirements of this Special Operations LCO
 
maintains operation consistent with or conservative to
 
operating with the reactor mode switch in the shutdown
 
position (or the refuel position for MODE 5). The functions
 
of the reactor mode switch interlocks that are not in
 
effect, due to the testing in progress, are adequately
 
compensated for by the Special Operations LCO requirements.
(continued)
Reactor Mode Switch Interlock Testing B 3.10.1 LaSalle 1 and 2 B 3.10.1-5 Revision 0 BASES SURVEILLANCE SR  3.10.1.1 and SR  3.10.1.2 (continued)
REQUIREMENTS The administrative controls are to be periodically verified
 
to ensure that the operational requirements continue to be
 
met. In addition, the all rods fully inserted Surveillance (SR 3.10.1.1) must be verified by a second licensed operator (Reactor Operator or Senior Reactor Operator) or other task
 
qualified member of the technical staff (e.g., a shift
 
technical advisor or reactor engineer). The Surveillances
 
performed at the 12 hour and 24 hour Frequencies are
 
intended to provide appropriate assurance that each
 
operating shift is aware of and verify compliance with these
 
Special Operations LCO requirements.
 
REFERENCES 1. UFSAR, Section 7.2.
: 2. UFSAR, Section 15.4.1.1.
 
Single Control Rod Withdrawal-Hot Shutdown B 3.10.2 LaSalle 1 and 2 B 3.10.2-1 Revision 0 B 3.10  SPECIAL OPERATIONS
 
B 3.10.2  Single Control Rod Withdrawal-Hot Shutdown
 
BASES
 
BACKGROUND The purpose of this MODE 3 Special Operations LCO is to permit the withdrawal of a single control rod for testing
 
while in hot shutdown, by imposing certain restrictions. In
 
MODE 3, the reactor mode switch is in the shutdown position, and all control rods are inserted and blocked from
 
withdrawal. Many systems and functions are not required in
 
these conditions, due to other installed interlocks that are
 
actuated when the reactor mode switch is in the shutdown
 
position. However, circumstances may arise while in MODE 3
 
that present the need to withdraw a single control rod for
 
various tests (e.g., rod exercising, friction tests, scram
 
timing, and coupling integrity checks). These single
 
control rod withdrawals are normally accomplished by
 
selecting the refuel position for the reactor mode switch. 
 
This Special Operations LCO provides the appropriate
 
additional controls to allow a single control rod withdrawal
 
in MODE 3.
 
APPLICABLE With the reactor mode switch in the refuel position, the SAFETY ANALYSES analyses for control rod withdrawal during refueling are applicable and, provided the assumptions of these analyses
 
are satisfied in MODE 3, these analyses will bound the
 
consequences of an accident. Explicit safety analyses in
 
the UFSAR (Ref. 1) demonstrate that the functioning of the
 
refueling interlocks and adequate SDM will preclude
 
unacceptable reactivity excursions.
 
Refueling interlocks restrict the movement of control rods
 
to reinforce operational procedures that prevent the reactor
 
from becoming critical. These interlocks prevent the
 
withdrawal of more than one control rod. Under these
 
conditions, since only one control rod can be withdrawn, the
 
core will always be shut down even with the highest worth
 
control rod withdrawn if adequate SDM exists.
 
The control rod scram function provides backup protection to
 
normal refueling procedures and the refueling interlocks, which prevent inadvertent criticalities during refueling.
(continued)
Single Control Rod Withdrawal-Hot Shutdown B 3.10.2 LaSalle 1 and 2 B 3.10.2-2 Revision 0 BASES APPLICABLE Alternate backup protection can be obtained by ensuring that SAFETY ANALYSES a five by five array of control rods, centered on the (continued) withdrawn control rod, are inserted and incapable of withdrawal.
 
As described in LCO 3.0.7, compliance with Special
 
Operations LCOs is optional, and therefore, no criteria of
 
10 CFR 50.36(c)(2)(ii) apply. Special Operations LCOs
 
provide flexibility to perform certain operations by
 
appropriately modifying requirements of other LCOs. A
 
discussion of the criteria satisfied for the other LCOs is
 
provided in their respective Bases.
 
LCO As described in LCO 3.0.7, compliance with this Special Operations LCO is optional. Operation in MODE 3 with the
 
reactor mode switch in the refuel position can be performed
 
in accordance with other Special Operations LCOs (i.e.,
LCO 3.10.1, "Reactor Mode Switch Interlock Testing") without
 
meeting this Special Operations LCO or its ACTIONS. 
 
However, if a single control rod withdrawal is desired in
 
MODE 3, controls consistent with those required during
 
refueling must be implemented and this Special Operations
 
LCO applied.  "Withdrawal" in this application includes the
 
actual withdrawal of the control rod as well as maintaining
 
the control rod in a position other than the full-in
 
position, and reinserting the control rod. The refueling
 
interlocks of LCO 3.9.2, "Refuel Position One-Rod-Out
 
Interlock," required by this Special Operations LCO, will
 
ensure that only one control rod can be withdrawn.
 
To back up the refueling interlocks (LCO 3.9.2), the ability
 
to scram the withdrawn control rod in the event of an
 
inadvertent criticality is provided by this Special
 
Operations LCO's requirements in Item d.1. Alternately, provided a sufficient number of control rods in the vicinity
 
of the withdrawn control rod are known to be inserted and
 
incapable of withdrawal (Item d.2), the possibility of
 
criticality on withdrawal of this control rod is
 
sufficiently precluded, so as not to require the scram
 
capability of the withdrawn control rod. Also, once this
 
alternate (Item d.2) is completed, the SDM requirement to
 
account for both the withdrawn-untrippable control rod and
 
the highest worth control rod may be changed to allow the
 
withdrawn-untrippable control rod to be the single highest
 
worth control rod. 
 
Single Control Rod Withdrawal-Hot Shutdown B 3.10.2 LaSalle 1 and 2 B 3.10.2-3 Revision 0 (continued)
BASES  (continued)
 
APPLICABILITY Control rod withdrawals are adequately controlled in MODES 1, 2, and 5 by existing LCOs. In MODES 3 and 4, control rod withdrawal is only allowed if performed in
 
accordance with this Special Operations LCO or Special
 
Operations LCO 3.10.3, "Single Control Rod Withdrawal-Cold
 
Shutdown," and if limited to one control rod. This
 
allowance is only provided with the reactor mode switch in
 
the refuel position. For these conditions, the one-rod-out
 
interlock (LCO 3.9.2), control rod position indication (LCO 3.9.4, "Control Rod Position Indication") full
 
insertion requirements for all other control rods, and scram
 
functions (LCO 3.3.1.1, "Reactor Protection System (RPS)
 
Instrumentation," and LCO 3.9.5, "Control Rod
 
OPERABILITY-Refueling"), or the added administrative
 
control in Item d.2 of this Special Operations LCO, minimizes potential reactivity excursions.
 
ACTIONS A Note has been provided to modify the ACTIONS related to a single control rod withdrawal while in MODE 3. Section 1.3, Completion Times, specifies once a Condition has been
 
entered, subsequent divisions, subsystems, components, or
 
variables expressed in the Condition discovered to be
 
inoperable or not within limits, will not result in separate
 
entry into the Condition. Section 1.3 also specifies
 
Required Actions of the Condition continue to apply for each
 
additional failure, with Completion Times based on initial
 
entry into the Condition. However, the Required Actions for
 
each requirement of the LCO not met provide appropriate
 
compensatory measures for separate requirements that are not
 
met. As such, a Note has been provided that allows separate
 
Condition entry for each requirement of the LCO.
 
A.1 If one or more of the requirements specified in this Special
 
Operations LCO are not met, the ACTIONS applicable to the
 
stated requirements of the affected LCOs are immediately
 
entered as directed by Required Action A.1. This Required
 
Action has been modified by a Note that clarifies the intent
 
of any other LCO's Required Action to insert all control
 
rods. This Required Action includes exiting this Special
 
Operations Applicability LCO by returning the reactor mode (continued)
Single Control Rod Withdrawal-Hot Shutdown B 3.10.2 LaSalle 1 and 2 B 3.10.2-4 Revision 0 BASES ACTIONS A.1 (continued)
 
switch to the shutdown position. A second Note has been
 
added, which clarifies that this Required Action is only
 
applicable if the requirements not met are for an affected
 
LCO.
 
A.2.1 and A.2.2
 
Required Actions A.2.1 and A.2.2 and are alternative
 
Required Actions that can be taken instead of Required
 
Action A.1 to restore compliance with the normal MODE 3
 
requirements, thereby exiting this Special Operations LCO's
 
Applicability. Actions must be initiated immediately to
 
insert all insertable control rods. Actions must continue
 
until all such control rods are fully inserted. Placing the
 
reactor mode switch in the shutdown position will ensure
 
that all inserted rods remain inserted and restore operation
 
in accordance with Table 1.1-1. The allowed Completion Time
 
of 1 hour to place the reactor mode switch in the shutdown
 
position provides sufficient time to normally insert the
 
control rods.
 
SURVEILLANCE SR  3.10.2.1, SR  3.10.2.2, and SR  3.10.2.3 REQUIREMENTS The other LCOs made applicable in this Special Operations
 
LCO are required to have their Surveillances met to
 
establish that this Special Operations LCO is being met. If
 
the local array of control rods is inserted and disarmed
 
while the scram function for the withdrawn rod is not
 
available, periodic verification in accordance with
 
SR 3.10.2.2 is required to preclude the possibility of
 
criticality. The control rods can be hydraulically disarmed
 
by closing the drive water and exhaust water isolation
 
valves. Electrically, the control rods can be disarmed by
 
disconnecting power from all four directional control valve
 
solenoids. SR 3.10.2.2 has been modified by a Note, which
 
clarifies that this SR is not required to be met if
 
SR 3.10.2.1 is satisfied for LCO 3.10.2.d.1 requirements, since SR 3.10.2.2 demonstrates that the alternative
 
LCO 3.10.2.d.2 requirements are satisfied. Also, SR 3.10.2.3 verifies that all control rods other than the (continued)
Single Control Rod Withdrawal-Hot Shutdown B 3.10.2 LaSalle 1 and 2 B 3.10.2-5 Revision 0 BASES SURVEILLANCE SR  3.10.2.1, SR  3.10.2.2, and SR  3.10.2.3 (continued)
REQUIREMENTS control rod being withdrawn are fully inserted. The 24 hour
 
Frequency is acceptable because of the administrative
 
controls on control rod withdrawals, the protection afforded
 
by the LCOs involved, and hardware interlocks that preclude
 
additional control rod withdrawals.
 
REFERENCES 1. UFSAR, Section 15.4.1.1.
 
Single Control Rod Withdrawal-Cold Shutdown B 3.10.3 LaSalle 1 and 2 B 3.10.3-1 Revision 0 B 3.10  SPECIAL OPERATIONS
 
B 3.10.3  Single Control Rod Withdrawal-Cold Shutdown
 
BASES
 
BACKGROUND The purpose of this MODE 4 Special Operations LCO is to permit the withdrawal of a single control rod for testing or
 
maintenance, while in cold shutdown, by imposing certain
 
restrictions. In MODE 4, the reactor mode switch is in the
 
shutdown position, and all control rods are inserted and
 
blocked from withdrawal. Many systems and functions are not
 
required in these conditions, due to the installed
 
interlocks associated with the reactor mode switch in the
 
shutdown position. Circumstances may arise while in MODE 4, however, that present the need to withdraw a single control
 
rod for various tests (e.g., rod exercising, friction tests, scram time testing, and coupling integrity checks). Certain
 
situations may also require the removal of the associated
 
control rod drive (CRD). These single control rod
 
withdrawals and possible subsequent removals are normally
 
accomplished by selecting the refuel position for the
 
reactor mode switch.
 
APPLICABLE With the reactor mode switch in the refuel position, the SAFETY ANALYSES analyses for control rod withdrawal during refueling are applicable and, provided the assumptions of these analyses
 
are satisfied in MODE 4, these analyses will bound the
 
consequences of an accident. Explicit safety analyses in
 
the UFSAR (Ref. 1) demonstrate that the functioning of the
 
refueling interlocks and adequate SDM will preclude
 
unacceptable reactivity excursions.
 
Refueling interlocks restrict the movement of control rods
 
to reinforce operational procedures that prevent the reactor
 
from becoming critical. These interlocks prevent the
 
withdrawal of more than one control rod. Under these
 
conditions, since only one control rod can be withdrawn, the
 
core will always be shut down even with the highest worth
 
control rod withdrawn if adequate SDM exists.
 
The control rod scram function provides backup protection in
 
the event normal refueling procedures and the refueling
 
interlocks fail to prevent inadvertent criticalities during (continued)
Single Control Rod Withdrawal-Cold Shutdown B 3.10.3 LaSalle 1 and 2 B 3.10.3-2 Revision 0 BASES APPLICABLE refueling. Alternate backup protection can be obtained by SAFETY ANALYSES ensuring that a five by five array of control rods, centered (continued) on the withdrawn control rod, are inserted and incapable of withdrawal. This alternate backup protection is required
 
when removing the CRD because this removal renders the
 
withdrawn control rod incapable of being scrammed.
 
As described in LCO 3.0.7, compliance with Special
 
Operations LCOs is optional, and therefore, no criteria of
 
10 CFR 50.36(c)(2)(ii) apply. Special Operations LCOs
 
provide flexibility to perform certain operations by
 
appropriately modifying requirements of other LCOs. A
 
discussion of the criteria satisfied for the other LCOs is
 
provided in their respective Bases.
 
LCO As described in LCO 3.0.7, compliance with this Special Operations LCO is optional. Operation in MODE 4 with the
 
reactor mode switch in the refuel position can be performed
 
in accordance with other LCOs (i.e., Special Operations
 
LCO 3.10.1, "Reactor Mode Switch Interlock Testing") 
 
without meeting this Special Operations LCO or its ACTIONS.
 
If a single control rod withdrawal is desired in MODE 4, controls consistent with those required during refueling
 
must be implemented and this Special Operations LCO applied.
"Withdrawal" in this application includes the actual
 
withdrawal of the control rod as well as maintaining the
 
control rod in a position other than the full-in position, and reinserting the control rod. 
 
The refueling interlocks of LCO 3.9.2, "Refuel Position
 
One-Rod-Out Interlock," required by this Special Operations
 
LCO will ensure that only one control rod can be withdrawn.
 
At the time CRD removal begins, the disconnection of the
 
position indication probe will cause LCO 3.9.4, "Control Rod
 
Position Indication," and therefore, LCO 3.9.2 to fail to be
 
met. Therefore, prior to commencing CRD removal, a control
 
rod withdrawal block is required to be inserted to ensure
 
that no additional control rods can be withdrawn and that
 
compliance with this Special Operations LCO is maintained.
 
To back up the refueling interlocks (LCO 3.9.2) or the
 
control rod withdrawal block, the ability to scram the
 
withdrawn control rod in the event of an inadvertent (continued)
Single Control Rod Withdrawal-Cold Shutdown B 3.10.3 LaSalle 1 and 2 B 3.10.3-3 Revision 0 BASES LCO criticality is provided by the Special Operations LCO (continued) requirements in Item c.1. Alternatively, when the scram function is not OPERABLE, or the CRD is to be removed, a
 
sufficient number of rods in the vicinity of the withdrawn
 
control rod are required to be inserted and made incapable
 
of withdrawal by electrically or hydraulically disarming the
 
CRD (Item c.2). This precludes the possibility of
 
criticality upon withdrawal of this control rod. Also, once
 
this alternate (Item c.2) is completed, the SDM requirement
 
to account for both the withdrawn-untrippable control rod
 
and the highest worth control rod may be changed to allow
 
the withdrawn-untrippable control rod to be the single
 
highest worth control rod.
 
APPLICABILITY Control rod withdrawals are adequately controlled in MODES 1, 2, and 5 by existing LCOs. In MODES 3 and 4, control rod withdrawal is only allowed if performed in
 
accordance with Special Operations LCO 3.10.2, "Single
 
Control Rod Withdrawal-Hot Shutdown," or this Special
 
Operations LCO, and if limited to one control rod. This
 
allowance is only provided with the reactor mode switch in
 
the refuel position.
 
During these conditions, the full insertion requirements for
 
all other control rods, the one-rod-out interlock (LCO 3.9.2), control rod position indication (LCO 3.9.4),
and scram functions (LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation," LCO 3.3.8.2, "Reactor Protection
 
System (RPS) Electric Power Monitoring," and LCO 3.9.5, "Control Rod OPERABILITY-Refueling"), or the added
 
administrative controls in Item b.2 and Item c.2 of this
 
Special Operations LCO, provide mitigation of potential
 
reactivity excursions.
 
ACTIONS A Note has been provided to modify the ACTIONS related to a single control rod withdrawal while in MODE 4. Section 1.3, Completion Times, specifies once a Condition has been
 
entered, subsequent divisions, subsystems, components, or
 
variables expressed in the Condition discovered to be
 
inoperable or not within limits, will not result in separate
 
entry into the Condition. Section 1.3 also specifies that
 
Required Actions of the Condition continue to apply for each (continued)
Single Control Rod Withdrawal-Cold Shutdown B 3.10.3 LaSalle 1 and 2 B 3.10.3-4 Revision 0 BASES ACTIONS additional failure, with Completion Times based on initial (continued) entry into the Condition. However, the Required Actions for each requirement of the LCO not met provide appropriate
 
compensatory measures for separate requirements that are not
 
met. As such, a Note has been provided that allows separate
 
Condition entry for each requirement of the LCO.
 
A.1, A.2.1, and A.2.2
 
If one or more of the requirements of this Special
 
Operations LCO are not met with the affected control rod
 
insertable, these Required Actions restore operation
 
consistent with normal MODE 4 conditions (i.e., all rods
 
inserted) or with the exceptions allowed in this Special
 
Operations LCO. Required Action A.1 has been modified by a
 
Note that clarifies the intent of any other LCO's Required
 
Action to insert all control rods. This Required Action
 
includes exiting this Special Operations LCO Applicability
 
by returning the reactor mode switch to the shutdown
 
position. A second Note has been added to Required
 
Action A.1 to clarify that this Required Action is only
 
applicable if the requirements not met are for an affected
 
LCO.
 
Required Actions A.2.1 and A.2.2 are specified, based on the
 
assumption that the control rod is being withdrawn. If the
 
control rod is still insertable, actions must be immediately
 
initiated to fully insert all insertable control rods and
 
within 1 hour place the reactor mode switch in the shutdown
 
position. Action must continue until all such control rods
 
are fully inserted. The allowed Completion Time of 1 hour
 
for placing the reactor mode switch in the shutdown position
 
provides sufficient time to normally insert the control
 
rods.
 
B.1, B.2.1, and B.2.2
 
If one or more of the requirements of this Special
 
Operations LCO are not met with the affected control rod not
 
insertable, withdrawal of the control rod and removal of the
 
associated CRD must immediately be suspended. If the CRD
 
has been removed, such that the control rod is not (continued)
Single Control Rod Withdrawal-Cold Shutdown B 3.10.3 LaSalle 1 and 2 B 3.10.3-5 Revision 0 BASES ACTIONS B.1, B.2.1, and B.2.2 (continued)
 
insertable, the Required Actions require the most
 
expeditious action be taken to either initiate action to
 
restore the CRD and insert its control rod, or restore
 
compliance with this Special Operations LCO.
 
SURVEILLANCE SR  3.10.3.1, SR  3.10.3.2, SR  3.10.3.3, and SR  3.10.3.4 REQUIREMENTS The other LCOs made applicable by this Special Operations
 
LCO are required to have their associated Surveillances met
 
to establish that this Special Operations LCO is being met.
 
If the local array of control rods is inserted and disarmed
 
while the scram function for the withdrawn rod is not
 
available, periodic verification is required to ensure that
 
the possibility of criticality remains precluded. The
 
control rods can be hydraulically disarmed by closing the
 
drive water and exhaust water isolation valves. 
 
Electrically, the control rods can be disarmed by
 
disconnecting power from all four directional control valve
 
solenoids. Verification that all the other control rods are
 
fully inserted is required to meet the SDM requirements. 
 
Verification that a control rod withdrawal block has been
 
inserted ensures that no other control rods can be
 
inadvertently withdrawn under conditions when position
 
indication instrumentation is inoperable for the affected
 
control rod. The 24 hour Frequency is acceptable because of
 
the administrative controls on control rod withdrawals, the
 
protection afforded by the LCOs involved, and hardware
 
interlocks to preclude an additional control rod withdrawal.
 
SR 3.10.3.2 and SR 3.10.3.4 have been modified by Notes, which clarify that these SRs are not required to be met if
 
the alternative requirements demonstrated by SR 3.10.3.1 are
 
satisfied.
 
REFERENCES 1. UFSAR, Section 15.4.1.1.
 
Single CRD Removal-Refueling B 3.10.4 LaSalle 1 and 2 B 3.10.4-1 Revision 0 B 3.10  SPECIAL OPERATIONS
 
B 3.10.4  Single Control Rod Drive (CRD) Removal-Refueling
 
BASES
 
BACKGROUND The purpose of this MODE 5 Special Operations LCO is to permit the removal of a single CRD during refueling
 
operations by imposing certain administrative controls. 
 
Refueling interlocks restrict the movement of control rods
 
and the operation of the refueling equipment to reinforce
 
operational procedures that prevent the reactor from
 
becoming critical during refueling operations. During
 
refueling operations, no more than one control rod, in a
 
core cell containing one or more fuel assemblies, is
 
permitted to be withdrawn. The refueling interlocks use the "full-in" position indicators to determine the position of
 
all control rods. If the "full-in" position signal is not
 
present for every control rod, then the all rods in
 
permissive for the refueling equipment interlocks is not
 
present and fuel loading is prevented. Also, the refuel
 
position one-rod-out interlock will not allow the withdrawal
 
of a second control rod.
 
The control rod scram function provides backup protection 
 
in the event normal refueling procedures and the refueling
 
interlocks described above fail to prevent inadvertent
 
criticalities during refueling. The requirement for the
 
refueling interlocks to be OPERABLE precludes the
 
possibility of removing the CRD once a control rod is
 
withdrawn from a core cell containing one or more fuel
 
assemblies. This Special Operations LCO provides controls
 
sufficient to ensure the possibility of an inadvertent
 
criticality is precluded, while allowing a single CRD to be
 
removed from a core cell containing one or more fuel
 
assemblies. The removal of the CRD involves disconnecting
 
the position indication probe, which causes noncompliance
 
with LCO 3.9.4, "Control Rod Position Indication," and, therefore, LCO 3.9.1, "Refueling Equipment Interlocks," and
 
LCO 3.9.2, "Refueling Position One-Rod-Out Interlock."  The
 
CRD removal also requires isolation of the CRD from the CRD
 
Hydraulic System, thereby causing inoperability of the
 
control rod (LCO 3.9.5, "Control Rod OPERABILITY-
 
Refueling").
(continued)
Single CRD Removal-Refueling B 3.10.4 LaSalle 1 and 2 B 3.10.4-2 Revision 0 BASES  (continued)
 
APPLICABLE With the reactor mode switch in the refuel position, the SAFETY ANALYSES analyses for control rod withdrawal during refueling are applicable and, provided the assumptions of these analyses
 
are satisfied, these analyses will bound the consequences of
 
accidents. Explicit safety analyses in the UFSAR (Ref. 1)
 
demonstrate that the proper operation of the refueling
 
interlocks and adequate SDM will preclude unacceptable
 
reactivity excursions.
 
Refueling interlocks restrict the movement of control rods
 
and the operation of the refueling equipment to reinforce
 
operational procedures that prevent the reactor from
 
becoming critical. These interlocks prevent the withdrawal
 
of more than one control rod. Under these conditions, since
 
only one control rod can be withdrawn, the core will always
 
be shut down even with the highest worth control rod
 
withdrawn if adequate SDM exists. By requiring all other
 
control rods to be inserted and a control rod withdrawal
 
block initiated, the function of the inoperable one-rod-out
 
interlock (LCO 3.9.2) is adequately maintained. This
 
Special Operations LCO requirement that no other CORE
 
ALTERATIONS are in progress adequately compensates for the
 
inoperable all rods in permissive for the refueling
 
equipment interlocks (LCO 3.9.1).
 
The control rod scram function provides backup protection to
 
normal refueling procedures and the refueling interlocks, which prevent inadvertent criticalities during refueling. 
 
Since the scram function and refueling interlocks may be
 
suspended, alternate backup protection required by this
 
Special Operations LCO is obtained by ensuring that a five
 
by five array of control rods, centered on the withdrawn
 
control rod, are inserted and are incapable of being
 
withdrawn, and all other control rods are inserted and
 
incapable of being withdrawn by insertion of a control rod
 
block.
 
As described in LCO 3.0.7, compliance with Special
 
Operations LCOs is optional, and therefore, no criteria of
 
10 CFR 50.36(c)(2)(ii) apply. Special Operations LCOs
 
provide flexibility to perform certain operations by
 
appropriately modifying requirements of other LCOs. A
 
discussion of the criteria satisfied for the other LCOs is
 
provided in their respective Bases.
(continued)
Single CRD Removal-Refueling B 3.10.4 LaSalle 1 and 2 B 3.10.4-3 Revision 0 BASES  (continued)
 
LCO As described in LCO 3.0.7, compliance with this Special Operations LCO is optional. Operation in MODE 5 with any of
 
the following LCOs - LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation," LCO 3.3.8.2, "Reactor Protection
 
System (RPS) Electric Power Monitoring," LCO 3.9.1, LCO 3.9.2, LCO 3.9.4, or LCO 3.9.5 - not met can be performed
 
in accordance with the Required Actions of these LCOs
 
without meeting this Special Operations LCO or its ACTIONS. 
 
However, if a single CRD removal from a core cell containing
 
one or more fuel assemblies is desired in MODE 5, controls
 
consistent with those required by LCO 3.3.1.1, LCO 3.3.8.2, LCO 3.9.1, LCO 3.9.2, LCO 3.9.4, and LCO 3.9.5 must be
 
implemented and this Special Operations LCO applied.
 
By requiring all other control rods to be inserted and a
 
control rod withdrawal block initiated, the function of the
 
inoperable one-rod-out interlock (LCO 3.9.2) is adequately
 
maintained. This Special Operations LCO requirement that no
 
other CORE ALTERATIONS are in progress adequately
 
compensates for the inoperable all-rods-in permissive for
 
the refueling equipment interlocks (LCO 3.9.1). Ensuring
 
that the five by five array of control rods, centered on the
 
withdrawn control rod, are inserted and incapable of
 
withdrawal (by electrically or hydraulically disarming the
 
CRD) adequately satisfies the backup protection that
 
LCO 3.3.1.1 and LCO 3.9.2 would have otherwise provided. 
 
Also, once these requirements (Items a, b, and c) are
 
completed, the SDM requirement to account for both the
 
withdrawn-untrippable control rod and the highest worth
 
control rod may be changed to allow the withdrawn-
 
untrippable control rod to be the single highest worth
 
control rod.
 
APPLICABILITY Operation in MODE 5 is controlled by existing LCOs. The allowance to comply with this Special Operations LCO in lieu
 
of the ACTIONS of LCO 3.3.1.1, LCO 3.3.8.2, LCO 3.9.1, LCO 3.9.2, LCO 3.9.4, and LCO 3.9.5 is appropriately
 
controlled with the additional administrative controls
 
required by this Special Operations LCO, which reduces the
 
potential for reactivity excursions.
(continued)
Single CRD Removal-Refueling B 3.10.4 LaSalle 1 and 2 B 3.10.4-4 Revision 0 BASES  (continued)
 
ACTIONS A.1, A.2.1, and A.2.2 If one or more of the requirements of this Special
 
Operations LCO are not met, the immediate implementation of
 
these Required Actions restores operation consistent with
 
the normal requirements for failure to meet LCO 3.3.1.1, LCO 3.9.1, LCO 3.9.2, LCO 3.9.4, and LCO 3.9.5 (i.e., all
 
control rods inserted) or with the allowances of this
 
Special Operations LCO. The Completion Times for Required
 
Action A.1, Required Action A.2.1, and Required Action A.2.2
 
are intended to require these Required Actions be
 
implemented in a very short time and carried through in an
 
expeditious manner to either initiate action to restore the
 
CRD and insert its control rod, or initiate action to
 
restore compliance with this Special Operations LCO. 
 
Actions must continue until either Required Action A.2.1 or
 
Required Action A.2.2 is satisfied.
 
SURVEILLANCE SR  3.10.4.1, SR  3.10.4.2, SR  3.10.4.3, SR  3.10.4.4, and REQUIREMENTS SR  3.10.4.5
 
Verification that all the control rods, other than the
 
control rod withdrawn for the removal of the associated CRD, are fully inserted is required to ensure the SDM is within
 
limits. Verification that the local five by five array of
 
control rods other than the control rod withdrawn for the
 
removal of the associated CRD, is inserted and disarmed, while the scram function for the withdrawn rod is not
 
available, is required to ensure that the possibility of
 
criticality remains precluded. The control rods can be
 
hydraulically disarmed by closing the drive water and
 
exhaust water isolation valves. Electrically, the control
 
rods can be disarmed by disconnecting power from all four
 
directional control valve solenoids. Verification that a
 
control rod withdrawal block has been inserted ensures that
 
no other control rods can be inadvertently withdrawn under
 
conditions when position indication instrumentation is
 
inoperable for the withdrawn control rod. The Surveillance
 
for LCO 3.1.1, which is made applicable by this Special
 
Operations LCO, is required in order to establish that this
 
Special Operations LCO is being met. Verification that no
 
other CORE ALTERATIONS are being made is required to ensure
 
the assumptions of the safety analysis are satisfied.
(continued)
Single CRD Removal-Refueling B 3.10.4 LaSalle 1 and 2 B 3.10.4-5 Revision 0 BASES SURVEILLANCE SR  3.10.4.1, SR  3.10.4.2, SR  3.10.4.3, SR  3.10.4.4, and REQUIREMENTS SR  3.10.4.5 (continued)
 
Periodic verification of the administrative controls
 
established by this Special Operations LCO is prudent to
 
preclude the possibility of an inadvertent criticality. The
 
24 hour Frequency is acceptable, given the administrative
 
controls on control rod removal and hardware interlocks to
 
block an additional control rod withdrawal.
 
REFERENCES 1. UFSAR, Section 15.4.1.1.
 
Multiple Control Rod Withdrawal-Refueling B 3.10.5 LaSalle 1 and 2 B 3.10.5-1 Revision 0 B 3.10  SPECIAL OPERATIONS
 
B 3.10.5  Multiple Control Rod Withdrawal-Refueling
 
BASES
 
BACKGROUND The purpose of this MODE 5 Special Operations LCO is to permit multiple control rod withdrawal during refueling by
 
imposing certain administrative controls.
 
Refueling interlocks restrict the movement of control rods
 
and the operation of the refueling equipment to reinforce
 
operational procedures that prevent the reactor from
 
becoming critical during refueling operations. During
 
refueling operations, no more than one control rod, in a
 
core cell containing one or more fuel assemblies is
 
permitted to be withdrawn. When all four fuel assemblies
 
are removed from a cell, the control rods may be withdrawn
 
with no restrictions. Any number of control rods may be
 
withdrawn and removed from the reactor vessel if their cells
 
contain no fuel.
 
The refueling interlocks use the "full-in" position
 
indicators to determine the position of all control rods. 
 
If the "full-in" position signal is not present for every
 
control rod, then the all rods in permissive for the
 
refueling equipment interlocks is not present and fuel
 
loading is prevented. Also, the refuel position one-rod-out
 
interlock will not allow the withdrawal of a second control
 
rod.
 
To allow more than one control rod to be withdrawn during
 
refueling, these interlocks must be defeated. This Special
 
Operations LCO establishes the necessary administrative
 
controls to allow bypass of the "full-in" position
 
indicators.
 
APPLICABLE Explicit safety analyses in the UFSAR (Ref. 1) demonstrate SAFETY ANALYSES that the functioning of the refueling interlocks and adequate SDM will prevent unacceptable reactivity excursions
 
during refueling. To allow multiple control rod
 
withdrawals, control rod removals, associated control rod
 
drive (CRD) removal, or any combination of these, the "full-
 
in" position indication is allowed to be bypassed for each (continued)
Multiple Control Rod Withdrawal-Refueling B 3.10.5 LaSalle 1 and 2 B 3.10.5-2 Revision 0 BASES APPLICABLE withdrawn control rod if all fuel has been removed from the SAFETY ANALYSES cell. With no fuel assemblies in the core cell, the (continued) associated control rod has no reactivity control function and is not required to remain inserted. Prior to reloading
 
fuel into the cell, however, the associated control rod must
 
be inserted to ensure that an inadvertent criticality does
 
not occur, as evaluated in the Reference 1 analysis.
 
As described in LCO 3.0.7, compliance with Special
 
Operations LCOs is optional, and therefore, no criteria of
 
10 CFR 50.36(c)(2)(ii) apply. Special Operations LCOs
 
provide flexibility to perform certain operations by
 
appropriately modifying requirements of other LCOs. A
 
discussion of the criteria satisfied for the other LCOs is
 
provided in their respective Bases.
 
LCO As described in LCO 3.0.7, compliance with this Special Operations LCO is optional. Operation in MODE 5 with
 
LCO 3.9.4, "Control Rod Position Indication," or LCO 3.9.5, "Control Rod OPERABILITY-Refueling," not met, can be
 
performed in accordance with the Required Actions of these
 
LCOs without meeting this Special Operations LCO or its
 
ACTIONS. If multiple control rod withdrawal or removal, or
 
CRD removal is desired, all four fuel assemblies are
 
required to be removed from the associated cells. Prior to
 
entering this LCO, any fuel remaining in a cell whose CRD
 
was previously removed under the provisions of another LCO
 
must be removed.  "Withdrawal" in this application includes
 
the actual withdrawal of the control rod as well as
 
maintaining the control rod in a position other than the
 
full-in position, and reinserting the control rod.
 
Loading of fuel assemblies into or shuffling within the
 
reactor pressure vessel is prohibited when multiple control
 
rods are withdrawn. This restriction is consistent with
 
existing conditions to the facility operating licenses.
 
APPLICABILITY Operation in MODE 5 is controlled by existing LCOs. The exceptions from other LCO requirements (e.g., the ACTIONS of
 
LCO 3.9.4 or LCO 3.9.5) allowed by this Special Operations
 
LCO are appropriately controlled by requiring all fuel to be
 
removed from cells whose "full-in" indicators are allowed to
 
be bypassed. 
(continued)
Multiple Control Rod Withdrawal-Refueling B 3.10.5 LaSalle 1 and 2 B 3.10.5-3 Revision 0 BASES  (continued)
 
ACTIONS A.1, A.2.1, and A.2.2 If one or more of the requirements of this Special
 
Operations LCO are not met, the immediate implementation of
 
these Required Actions restores operation consistent with
 
the normal requirements for refueling (i.e., all control
 
rods inserted in core cells containing one or more fuel
 
assemblies) or with the exceptions granted by this Special
 
Operations LCO. The Completion Times for Required
 
Action A.1, Required Action A.2.1, and Required Action A.2.2
 
are intended to require that these Required Actions be
 
implemented in a very short time and carried through in an
 
expeditious manner to either initiate action to restore the
 
affected CRDs and insert their control rods, or initiate
 
action to restore compliance with this Special Operations
 
LCO.
SURVEILLANCE SR  3.10.5.1, SR  3.10.5.2, and SR  3.10.5.3 REQUIREMENTS Periodic verification of the administrative controls
 
established by this Special Operations LCO is prudent to
 
preclude the possibility of an inadvertent criticality. The
 
24 hour Frequency is acceptable, given the administrative
 
controls on fuel assembly and control rod removal, and takes
 
into account other indications of control rod status
 
available in the control room.
 
REFERENCES 1. UFSAR, Section 15.4.1.1.
 
Control Rod Testing-Operating B 3.10.6 LaSalle 1 and 2 B 3.10.6-1 Revision 0 B 3.10  Special Operations
 
B 3.10.6  Control Rod Testing-Operating
 
BASES
 
BACKGROUND The purpose of this Special Operations LCO is to permit control rod testing, while in MODES 1 and 2, by imposing
 
certain administrative controls. Control rod patterns
 
during startup conditions are controlled by the operator and
 
the Rod Worth Minimizer (RWM) (LCO 3.3.2.1, "Control Rod
 
Block Instrumentation"), such that only the specified
 
control rod sequences and relative positions required by
 
LCO 3.1.6, "Rod Pattern Control," are allowed over the
 
operating range from all control rods inserted to the low
 
power setpoint (LPSP) of the RWM. The sequences effectively
 
limit the potential amount and rate of reactivity increase
 
that could occur during a control rod drop accident (CRDA).
 
During these conditions, control rod testing is sometimes
 
required that may result in control rod patterns not in
 
compliance with the prescribed sequences of LCO 3.1.6. 
 
These tests may include SDM demonstrations, control rod
 
scram time testing, and control rod friction testing. This
 
Special Operations LCO provides the necessary exceptions to
 
the requirements of LCO 3.1.6 and provides additional
 
administrative controls to allow the deviations in such
 
tests from the prescribed sequences in LCO 3.1.6.
 
APPLICABLE The analytical methods and assumptions used in evaluating SAFETY ANALYSES the CRDA are summarized in References 1, 2, 3, 4 and 5. CRDA analyses assume the reactor operator follows prescribed
 
withdrawal sequences. These sequences define the potential
 
initial conditions for the CRDA analyses. The RWM provides
 
backup to operator control of the withdrawal sequences to
 
ensure that the initial conditions of the CRDA analyses are
 
not violated. For special sequences developed for control
 
rod testing, the initial control rod patterns assumed in the
 
safety analysis of References 1, 2, 3, 4 and 5 may not be
 
preserved. Therefore, special CRDA analyses are required to
 
demonstrate that these special sequences will not result in
 
unacceptable consequences, should a CRDA occur during the
 
testing. These analyses, performed in accordance with an
 
NRC approved methodology, are dependent on the specific test
 
being performed.
(continued)
Control Rod Testing-Operating B 3.10.6 LaSalle 1 and 2 B 3.10.6-2 Revision 0 BASES APPLICABLE As described in LCO 3.0.7, compliance with Special SAFETY ANALYSES Operations LCOs is optional, and therefore, no criteria of (continued) 10 CFR 50.36(c)(2)(ii) apply. Special Operations LCOs provide flexibility to perform certain operations by
 
appropriately modifying requirements of other LCOs. A
 
discussion of the criteria satisfied for the other LCOs is
 
provided in their respective Bases.
 
LCO As described in LCO 3.0.7, compliance with this Special Operations LCO is optional. Control rod testing may be
 
performed in compliance with the prescribed sequences of
 
LCO 3.1.6, and during these tests, no exceptions to the
 
requirements of LCO 3.1.6 are necessary. For testing
 
performed with a sequence not in compliance with LCO 3.1.6, the requirements of LCO 3.1.6 may be suspended, provided
 
additional administrative controls are placed on the test to
 
ensure that the assumptions of the special safety analysis
 
for the test sequence are satisfied. Assurance that the
 
test sequence is followed can be provided by either
 
programming the test sequence into the RWM, with conformance
 
verified as specified in SR 3.3.2.1.8 and allowing the RWM
 
to monitor control rod withdrawal and provide appropriate
 
control rod blocks if necessary, or by verifying conformance
 
to the approved test sequence by a second licensed operator (Reactor Operator or Senior Reactor Operator) or other task
 
qualified member of the technical staff (e.g., a shift
 
technical advisor or reactor engineer). These controls are
 
consistent with those normally applied to operation in the
 
startup range as defined in the SRs and ACTIONS of
 
LCO 3.3.2.1, "Control Rod Block Instrumentation."
APPLICABILITY Control rod testing, while in MODES 1 and 2 with THERMAL POWER greater than 10% RTP, is adequately controlled by the
 
existing LCOs on power distribution limits and control rod
 
block instrumentation. Control rod movement during these
 
conditions is not restricted to prescribed sequences and can
 
be performed within the constraints of LCO 3.2.1, "AVERAGE
 
PLANAR LINEAR HEAT GENERATION RATE (APLHGR)," LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)," LCO 3.2.3, "LINEAR
 
HEAT GENERATION RATE (LHGR)," and LCO 3.3.2.1. With THERMAL
 
POWER less than or equal to 10% RTP, the provisions of this
 
Special Operations LCO are necessary to perform special
 
tests that are not in conformance with the prescribed (continued)
Control Rod Testing-Operating B 3.10.6 LaSalle 1 and 2 B 3.10.6-3 Revision 0 BASES APPLICABILITY control rod sequences of LCO 3.1.6. While in MODES 3 and 4, (continued) control rod withdrawal is only allowed if performed in accordance with Special Operations LCO 3.10.2, "Single
 
Control Rod Withdrawal-Hot Shutdown" or Special Operations
 
LCO 3.10.3, "Single Control Rod Withdrawal-Cold Shutdown,"
which provide adequate controls to ensure that the
 
assumptions of the safety analysis of Reference 3 are 
 
satisfied. During these Special Operations and while in
 
MODE 5, the one rod out interlock (LCO 3.9.2, "Refuel
 
Position One-Rod-Out Interlock) and scram functions (LCO 3.3.1.1, "Reactor Protection System (RPS)
 
Instrumentation," and LCO 3.9.5, "Control Rod
 
OPERABILITY-Refueling"), or the added administrative
 
controls prescribed in the applicable Special Operations
 
LCOs, minimize potential reactivity excursions.
 
ACTIONS A.1 With the requirements of the LCO not met (e.g., the control
 
rod pattern not in compliance with the special test
 
sequence, the sequence is improperly loaded in the RWM), the
 
testing is required to be immediately suspended. Upon
 
suspension of the special test, the provisions of LCO 3.1.6
 
are no longer excepted, and appropriate actions are to be
 
taken either to restore the control rod sequence to the
 
prescribed sequence of LCO 3.1.6, or to shut down the
 
reactor, if required by LCO 3.1.6.
 
SURVEILLANCE SR  3.10.6.1 REQUIREMENTS With the special test sequence not programmed into the RWM, a second licensed operator (Reactor Operator or Senior
 
Reactor Operator) or other task qualified member of the
 
technical staff (e.g., a shift technical advisor or reactor
 
engineer) is required to verify conformance with the
 
approved sequence for the test. This verification must be
 
performed during control rod movement to prevent deviations
 
from the specified sequence. A Note is added to indicate
 
that this Surveillance does not need to be met if
 
SR 3.10.6.2 is satisfied.
(continued)
Control Rod Testing-Operating B 3.10.6 LaSalle 1 and 2 B 3.10.6-4 Revision 0 BASES SURVEILLANCE SR  3.10.6.2 REQUIREMENTS (continued) When the RWM provides conformance to the special test sequence, the test sequence must be verified to be correctly
 
loaded into the RWM prior to control rod movement. This
 
Surveillance demonstrates compliance with SR 3.3.2.1.8, thereby demonstrating that the RWM is OPERABLE. A Note has
 
been added to indicate that this Surveillance does not need
 
to be met if SR 3.10.6.1 is satisfied.
 
REFERENCES 1. UFSAR, Section 15.4.10.
: 2. XN-NF-80-19(P)(A), Volume 1, Supplement 2, Section 7.1, Exxon Nuclear Methodology for Boiling Water
 
Reactor Neutronics Methods for Design Analysis, (as
 
specified in Technical Specification 5.6.5).
: 3. NEDE-24011-P-A-US, General Electric Standard Application for Reactor Fuel, (as specified in
 
Technical Specification 5.6.5).
: 4. Letter from T. Pickens (BWROG) to G.C. Lainas (NRC), "Amendment 17 to General Electric Licensing Topical
 
Report NEDE-24011-P-A," BWROG-8644, August 15, 1986.
: 5. NFSR-0091, Benchmark of CASMO/MICROBURN BWR Nuclear Design Methods, Commonwealth Edison Topical Report, (as specified in Technical Specification 5.6.5).
 
SDM Test-Refueling B 3.10.7 LaSalle 1 and 2 B 3.10.7-1 Revision 0 B 3.10  SPECIAL OPERATIONS
 
B 3.10.7  SHUTDOWN MARGIN (SDM) Test-Refueling
 
BASES
 
BACKGROUND The purpose of this MODE 5 Special Operations LCO is to permit SDM testing to be performed for those plant
 
configurations in which the reactor pressure vessel (RPV)
 
head is either not in place or the head bolts are not fully
 
tensioned.
 
LCO 3.1.1, "SHUTDOWN MARGIN (SDM)," requires that adequate
 
SDM be demonstrated following fuel movements or control rod
 
replacement within the RPV. The demonstration must be
 
performed prior to or within 4 hours after criticality is
 
reached. This SDM test may be performed prior to or during
 
the first startup following refueling. Performing the SDM
 
test prior to startup requires the test to be performed
 
while in MODE 5 with the vessel head bolts less than fully
 
tensioned (and possibly with the vessel head removed). 
 
While in MODE 5, the reactor mode switch is required to be
 
in the shutdown or refuel position, where the applicable
 
control rod blocks ensure that the reactor will not become
 
critical. The SDM test requires the reactor mode switch to
 
be in the startup/hot standby position, since more than one
 
control rod will be withdrawn for the purpose of
 
demonstrating adequate SDM. This Special Operations LCO
 
provides the appropriate additional controls to allow
 
withdrawing more than one control rod from a core cell
 
containing one or more fuel assemblies when the reactor
 
vessel head bolts are less than fully tensioned.
 
APPLICABLE Prevention and mitigation of unacceptable reactivity SAFETY ANALYSES excursions during control rod withdrawal, with the reactor mode switch in the startup/hot standby position while in
 
MODE 5, is provided by the Intermediate Range Monitor (IRM)
 
neutron flux scram (LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation"), and control rod block
 
instrumentation (LCO 3.3.2.1, "Control Rod Block
 
Instrumentation"). The limiting reactivity excursion during
 
startup conditions while in MODE 5 is the control rod drop
 
accident (CRDA).
(continued)
SDM Test-Refueling B 3.10.7 LaSalle 1 and 2 B 3.10.7-2 Revision 0 BASES APPLICABLE CRDA analyses assume that the reactor operator follows SAFETY ANALYSES prescribed withdrawal sequences. For SDM tests performed (continued) within these defined sequences, the analyses of References 1, 2, 3 and 4 are applicable. However, for some
 
sequences developed for the SDM testing, the control rod
 
patterns assumed in the safety analyses of References 1, 2, 3 and 4 may not be met. Therefore, special CRDA analyses, performed in accordance with an NRC approved methodology, are required to demonstrate that the SDM test sequence will
 
not result in unacceptable consequences should a CRDA occur
 
during the testing. For the purpose of this test, the
 
protection provided by the normally required MODE 5
 
applicable LCOs, in addition to the requirements of this
 
LCO, will maintain normal test operations as well as
 
postulated accidents within the bounds of the appropriate
 
safety analyses (Refs. 1, 2, 3 and 4). In addition to the
 
added requirements for the Rod Worth Minimizer (RWM), APRM, and control rod coupling, the single notch withdrawal mode
 
is specified for out of sequence withdrawals. Requiring the
 
single notch withdrawal mode limits withdrawal steps to a
 
single notch, which limits inserted reactivity, and allows
 
adequate monitoring of changes in neutron flux, which may
 
occur during the test.
 
As described in LCO 3.0.7, compliance with Special
 
Operations LCOs is optional, and therefore, no criteria of
 
10 CFR 50.36(c)(2)(ii) apply. Special Operations LCOs
 
provide flexibility to perform certain operations by
 
appropriately modifying requirements of other LCOs. A
 
discussion of the criteria satisfied for the other LCOs is
 
provided in their respective Bases.
 
LCO As described in LCO 3.0.7, compliance with this Special Operations LCO is optional. SDM tests may be performed
 
while in MODE 2, in accordance with Table 1.1-1, without
 
meeting this Special Operations LCO or its ACTIONS. For SDM
 
tests performed while in MODE 5, additional requirements
 
must be met to ensure that adequate protection against
 
potential reactivity excursions is available. To provide
 
additional scram protection, beyond the normally required
 
IRMs, the APRMs are also required to be OPERABLE (LCO
 
3.3.1.1, Functions 2.a and 2.d) as though the reactor were (continued)
SDM Test-Refueling B 3.10.7 LaSalle 1 and 2 B 3.10.7-3 Revision 0 BASES LCO in MODE 2. Because multiple control rods will be withdrawn (continued) and the reactor will potentially become critical, and the approved control rod withdrawal sequence must be enforced by
 
the RWM (LCO 3.3.2.1, Function 2, MODE 2), or must be
 
verified by a second licensed operator (Reactor Operator or
 
Senior Reactor Operator) or other task qualified member of
 
the technical staff (e.g., a shift technical advisor or
 
reactor engineer). To provide additional protection against
 
an inadvertent criticality, control rod withdrawals that do
 
not conform to the analyzed rod position sequence specified
 
in LCO 3.1.6, "Rod Pattern Control" (i.e., out of sequence
 
control rod withdrawals) must be made in the notched
 
withdrawal mode to minimize the potential reactivity
 
insertion associated with each movement. Coupling integrity
 
of withdrawn control rods is required to minimize the
 
probability of a CRDA and ensure proper functioning of the
 
withdrawn control rods, if they are required to scram. 
 
Because the reactor vessel head may be removed during these
 
tests, no other CORE ALTERATIONS may be in progress. 
 
Furthermore, since the control rod scram function with the
 
RCS at atmospheric pressure relies solely on the CRD
 
accumulator, it is essential that the CRD charging water
 
header remain pressurized. This Special Operations LCO then
 
allows changing the Table 1.1-1 reactor mode switch position
 
requirements to include the startup/hot standby position, such that the SDM tests may be performed while in MODE 5.
 
APPLICABILITY These SDM test Special Operations requirements are only applicable if the SDM tests are to be performed while in
 
MODE 5 with the reactor vessel head removed or the head
 
bolts not fully tensioned. Additional requirements during
 
these tests to enforce control rod withdrawal sequences and
 
restrict other CORE ALTERATIONS provide protection against
 
potential reactivity excursions. Operations in all other
 
MODES are unaffected by this LCO.
 
ACTIONS A.1 and A.2
 
With one or more control rods discovered uncoupled during
 
this Special Operation, a controlled insertion of each
 
uncoupled control rod is required; either to attempt (continued)
SDM Test-Refueling B 3.10.7 LaSalle 1 and 2 B 3.10.7-4 Revision 0 BASES ACTIONS A.1 and A.2 (continued) recoupling, or to preclude a control rod drop. This
 
controlled insertion is preferred since, if the control rod
 
fails to follow the drive as it is withdrawn (i.e., is "stuck" in an inserted position), placing the reactor mode
 
switch in the shutdown position per Required Action B.1
 
could cause substantial secondary damage. If recoupling is
 
not accomplished, operation may continue, provided the 
 
control rods are fully inserted within 3 hours and disarmed (electrically or hydraulically) within 4 hours. Inserting a
 
control rod ensures the shutdown and scram capabilities are
 
not adversely affected. The control rod is disarmed to
 
prevent inadvertent withdrawal during subsequent operations.
 
The control rods can be hydraulically disarmed by closing
 
the drive water and exhaust water isolation valves. 
 
Electrically, the control rods can be disarmed by
 
disconnecting power from all four directional control valve
 
solenoids. Required Action A.1 is modified by a Note that
 
allows the RWM to be bypassed if required to allow insertion
 
of the inoperable control rods and continued operation. 
 
LCO 3.3.2.1 ACTIONS provide additional requirements when the
 
RWM is bypassed to ensure compliance with the CRDA analysis.
 
The allowed Completion Times are reasonable, considering the
 
small number of allowed inoperable control rods, and provide
 
time to insert and disarm the control rods in an orderly
 
manner and without challenging plant systems.
 
Condition A is modified by a Note allowing separate
 
Condition entry for each uncoupled control rod. This is
 
acceptable since the Required Actions for this Condition
 
provide appropriate compensatory actions for each uncoupled
 
control rod. Complying with the Required Actions may allow
 
for continued operation. Subsequent uncoupled control rods
 
are governed by subsequent entry into the Condition and
 
application of the Required Actions. 
 
B.1 With one or more of the requirements of this LCO not met for
 
reasons other than an uncoupled control rod, the testing
 
should be immediately stopped by placing the reactor mode (continued)
SDM Test-Refueling B 3.10.7 LaSalle 1 and 2 B 3.10.7-5 Revision 0 BASES ACTIONS B.1 (continued)
 
switch in the shutdown or refuel position. This results in
 
a condition that is consistent with the requirements for
 
MODE 5 where the provisions of this Special Operations LCO
 
are no longer required.
 
SURVEILLANCE SR  3.10.7.1, SR  3.10.7.2, and SR  3.10.7.3 REQUIREMENTS LCO 3.3.1.1, Functions 2.a and 2.d, made applicable in this
 
Special Operations LCO, are required to have applicable
 
Surveillances met to establish that this Special Operations
 
LCO is being met (SR 3.10.7.1). However, the control rod
 
withdrawal sequences during the SDM tests may be enforced by
 
the RWM (LCO 3.3.2.1, Function 2, MODE 2 requirements) or by
 
a second licensed operator (Reactor Operator or Senior
 
Reactor Operator) or other task qualified member of the
 
technical staff (e.g., technical advisor or reactor
 
engineer). As noted, either the applicable SRs for the RWM (LCO 3.3.2.1) must be satisfied according to the applicable
 
Frequencies (SR 3.10.7.2), or the proper movement of control
 
rods must be verified (SR 3.10.7.3). This latter
 
verification (i.e., SR 3.10.7.3) must be performed during
 
control rod movement to prevent deviations from the
 
specified sequence. These Surveillances provide adequate
 
assurance that the specified test sequence is being
 
followed.
 
SR  3.10.7.4
 
Periodic verification of the administrative controls
 
established by this LCO will ensure that the reactor is
 
operated within the bounds of the safety analysis. The
 
12 hour Frequency is intended to provide appropriate
 
assurance that each operating shift is aware of and verifies
 
compliance with these Special Operations LCO requirements.
 
SR  3.10.7.5
 
Coupling verification is performed to ensure the control rod
 
is connected to the control rod drive mechanism and will
 
perform its intended function when necessary. The (continued)
SDM Test-Refueling B 3.10.7 LaSalle 1 and 2 B 3.10.7-6 Revision 0 BASES SURVEILLANCE SR  3.10.7.5 (continued)
REQUIREMENTS verification is required to be performed any time a control
 
rod is withdrawn to the "full-out" notch position or prior
 
to declaring the control rod OPERABLE after work on the
 
control rod or CRD System that could affect coupling. This
 
Frequency is acceptable, considering the low probability
 
that a control rod will become uncoupled when it is not
 
being moved as well as operating experience related to
 
uncoupling events.
 
SR  3.10.7.6
 
CRD charging water header pressure verification is performed
 
to ensure the motive force is available to scram the control
 
rods in the event of a scram signal. Since the reactor is
 
depressurized in MODE 5, there is insufficient reactor
 
pressure to scram the control rods. Verification of
 
charging water header pressure ensures that if a scram were
 
required, capability for rapid control rod insertion would
 
exist. The minimum pressure of 940 psig is well below the
 
expected pressure of 1400 psig to 1500 psig while still
 
ensuring sufficient pressure for rapid control rod
 
insertion. The 7 day Frequency has been shown to be
 
acceptable through operating experience and takes into
 
account indications available in the control room.
 
REFERENCES 1. UFSAR, Section 15.4.10.
: 2. XN-NF-80-19(P)(A), Volume 1, Supplement 2, Section 7.1, Exxon Nuclear Methodology for Boiling Water
 
Reactor Neutronics Methods for Design Analysis, (as
 
specified in Technical Specification 5.6.5).
: 3. NEDE-24011-P-A-US, General Electric Standard Application for Reactor Fuel, (as specified in
 
Technical Specification 5.6.5).
: 4. Letter, T.A. Pickens (BWROG) to G.C. Lainas (NRC), "Amendment 17 to General Electric Licensing Topical
 
Report NEDE-24011-P-A," BWROG-8644, August 15, 1986.
(continued)
SDM Test-Refueling B 3.10.7 LaSalle 1 and 2 B 3.10.7-7 Revision 0 BASES REFERENCES 5. NFSR-0091, Benchmark of CASMO/MICROBURN BWR Nuclear (continued)  Design Methods, Commonwealth Edison Topical Report, (as specified in Technical Specification 5.6.5).}}

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