Text

LaSalle, Units 1 and 2, Updated Final Safety Analysis Report (Ufsar), Revision 17, Chapter 8.0 - Electric Power
	ML081330060
Person / Time
Site:	LaSalle
Issue date:	04/14/2008
From:	; Exelon Generation Co, Exelon Nuclear
To:	; Office of Nuclear Reactor Regulation
References
	RS-08-045
	Download: ML081330060 (146)
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LSCS-UFSAR 8.0-i REV. 15, APRIL 2004 CHAPTER 8.0 - ELECTRIC POWER TABLE OF CONTENTS

8.1 INTRODUCTION

8.1-1 8.1.1 Offsite Power Systems - Summary Description 8.1-2 8.1.2 Onsite Power Systems - Summary Description 8.1-3 8.1.2.1 Unit Auxiliary Power System 8.1-4 8.1.2.2 Unit Class 1E A-C Power System 8.1-4 8.1.2.3 Unit Reactor Protection System (RPS) Power System 8.1-5 8.1.2.4 Unit Class 1E D-C Power System 8.1-6 8.1.2.5 Unit Non-Class 1E D-C Power System 8.1-6 8.1.3 Identification of Class 1E Loads 8.1-7 8.2 OFFSITE POWER SYSTEM 8.2-1 8.2.1 Description 8.2-1 8.2.1.1 Transmission Lines 8.2-1 8.2.1.2 Power Sources 8.2-1 8.2.1.3 Transmission System 8.2-2 8.2.2 Analysis 8.2-3 8.2.3 Adequacy of Offsite Power Distribution System 8.2-5 8.2.3.1 Introduction 8.2-5 8.2.3.2 Adequacy of Offsite Power 8.2-5 8.2.3.2.1 Loading Analysis 8.2-5 8.2.3.2.2 Criteria for Acceptable Voltage 8.2-6

8.2.3.2.3 System Performance 8.2-6 8.2.3.3 Undervoltage Relays 8.2-7 8.2.3.4 Conclusion 8.2-8 8.2.4 References 8.2-9 8.3 ONSITE POWER SYSTEMS 8.3-1 8.3.1 A-C Power Systems 8.3-1 8.3.1.1 Description 8.3-1 8.3.1.1.1 Unit Non-Class 1E Auxiliary Power Systems 8.3-1 8.3.1.1.2 Unit Class 1E A-C Power System 8.3-3 8.3.1.1.3 Unit Reactor Protection System (RPS) Power System 8.3-11

LSCS-UFSAR Table of Contents (Cont'd)

PAGE 8.0-ii REV. 15, APRIL 2004 8.3.1.1.4 Instrument Power System 8.3-13 8.3.1.2 Analysis 8.3-14 8.3.1.3 Physical Identification of Safety-Related Equipment 8.3-17 8.3.1.3.1 General 8.3-17 8.3.1.3.2 Raceway Identification 8.3-17 8.3.1.3.3 Cable Identification 8.3-18 8.3.1.4 Physical Independence of Redundant Systems 8.3-18 8.3.1.4.1 General Criteria 8.3-18 8.3.1.4.2 Physical Separation Criteria 8.3-18 8.3.1.4.2.1 Raceway Separation Criteria 8.3-20 8.3.1.4.2.2 Cable Routing Criteria 8.3-21 8.3.1.4.2.3 Panel Criteria 8.3-27 8.3.1.4.2.4 Containment Electrical Penetration Criteria 8.3-28 8.3.1.4.3 Cable Tray Criteria 8.3-28 8.3.1.4.4 Cable Criteria 8.3-29 8.3.1.4.5 Control Procedures - Independence 8.3-30 8.3.1.4.6 General Arrangement of Class 1E Components 8.3-32 8.3.1.5 References 8.3-33 8.3.2 D-C Power Systems 8.3-33 8.3.2.1 Description 8.3-33 8.3.2.1.1 Unit Class 1E D-C Power System 8.3-33 8.3.2.2 Analysis 8.3-43 8.3.3 Fire Protection for Cable Systems 8.3-43 8.3.3.1 Cable Derating and Cable Tray Fill 8.3-43 8.3.3.2 Fire Detection and Protection in the Areas Where Cables are Installed 8.3-45 8.3.3.3 Fire Barriers and Separation Between Redundant Cable Trays 8.3-47 8.3.3.4 Fire Stops 8.3-47 8.3.3.5 Integrity of the Essential (ESF) Electrical Auxiliary Power and Controls 8.3-47 8.3.3.6 Provisions for Protection of ESF Auxiliary Power from Effects of Fire-Suppressing Agents 8.3-48 8.4 Other Electrical Features and Requirements for Safety 8.4-1 8.4.1 Containment Electrical Penetrations 8.4-1

LSCS-UFSAR 8.0-iii REV. 15, APRIL 2004 CHAPTER 8.0 - ELECTRIC POWER LIST OF TABLES NUMBER TITLE 8.1-1 Assignment of Safety/Related Systems to Electrical Divisions for Separation 8.1-2 Non-Safety-Related Equipment Fed from Class 1E Power Supplies 8.1-3 List of Nuclear Safety Electrical Design Criteria 8.1-4 Buses Supplied by Unit and System Auxiliary Transformers 8.1-5 4160-Volt ESF Buses for Units 1 and 2 8.1-6 List of 480-Volt ESF Auxiliary Power Transformers for Units 1 and 2 8.1-7 Equipment Supplied by 4160-Volt ESF Buses - Unit 1 8.1-8 Equipment Supplied by 4160-Volt ESF Buses - Unit 2 8.1-9 Equipment Supplied by 480-Volt ESF Substation Buses - Unit 1 8.1-10 Equipment Supplied by 480-Volt ESF Substation Buses - Unit 2 8.2-1 Bus Loadings Assumed for Offsite Power Supply Analyses 8.2-2 No-Load Voltages 8.2-3 Running Voltages at Selected Loads 8.3-1 Loading on 4160-Volt ESF Buses 8.3-2 Summary of Relay Protection for ESF 4160-Volt Equipment 8.3-3 Diesel-Generator Ratings 8.3-4 Tabulation of Diesel-Generator Protective and Supervisory Functions 8.3-5 Cable Tray Segregation Codes 8.3-6 Cable Segregation Codes (Non-RPS Cables) 8.3-7 Cable Ampacities kV Cables 8.3-8 Cable Ampacities kV Cables

LSCS-UFSAR LIST OF TABLES (Cont'd)

NUMBER TITLE 8.0-iv REV. 15, APRIL 2004 8.3-9 Cable Ampacities - 600-Volt Cables 8.3-10 Cable Insulation 8.3-11 250-Volt Battery 1(2) (ESF Division 1) Load Requirements 8.3-12 125-Volt Battery 1A (2A) (ESF Division 1) Load Requirements 8.3-13 125-Volt Battery 1B (2B) (ESF Division 2) Load Requirements 8.3-14 ESF Division 3 (HPCS) 125-Vdc Battery Load Requirements 8.4-1 Unit 1 Primary Containment Penetration Conductor Overcurrent Protective Devices 8.4-2 Unit 2 Primary Containment Penetration Conductor Overcurrent Protective Devices LSCS-UFSAR 8.0-v REV. 15, APRIL 2004 CHAPTER 8.0 - ELECTRIC POWER LIST OF FIGURES NUMBER TITLE

8.1-1 Single-Line Diagram - 345-kv Switchyard 8.1-2 One-Line Diagram - Station Auxiliary Power 8.1-3 One-Line Diagram - Station Auxiliary Power Distribution System 8.1-4 Diagram of Switchyard D-C Control System 8.2-1 Transmission System Interconnections 1981 Conditions 8.2-2 Property Plan 8.2-3 Routing of Transmission Corridors 1981 Conditions 8.2-4 Minimum Calculated Running Voltages and Minimum Starting Bus Voltages 8.3-1 Block Diagram Relay and Control Bus 142Y, DG1A 8.3-2 Block Logic Diagram: Bus 143, Transformer 142, Diesel Generator 1B 8.3-3 Block Diagram Relay and Control Bus 151 (Typical) 8.3-4 Load Shedding Initiated by Undervoltage for 480-Volt ESF Buses 135X, 135Y, 136X, 136Y, and 143 8.3-5 Single-Line Diagram Relay and Metering Diesel Generator 8.3-6 48/24-Vdc #1 Unit 1 8.3-7 Electrical Drywell Penetrations Plant Elevation 740 feet 0 inch 8.3-8 Electrical Drywell Penetrations Plant Elevation 761 feet 0 inch 8.3-9 250-Vdc Engineered Safety Feature Division 1 -

Unit 1 8.3-10 125-Vdc Engineered Safety Feature Division 1 -

Unit 1 8.3-10a 125-Vdc Engineered Safety Feature Division 1 - Unit 2 8.3-11 125-Vdc Engineered Safety Feature Division 2 -

Unit 1 8.3-11a 125-Vdc Engineered Safety Feature Division 2 - Unit 2 8.3-12 125-Vdc Engineered Safety Feature Division 3 -

Unit 1 LSCS-UFSAR 8.0-vi REV. 14, APRIL 2002 DRAWINGS CITED IN THIS CHAPTER*

DRAWING* SUBJECT M-130 Containment Combustible Gas Control System 1E-1(2)-4000A Single Line Diagram - Generator Transformers and 6900-V Buses 1E-1(2)-4000B Single Line Diagram - Standby Generators and 4160-V Buses 1E-1(2)-4000C Single Line Diagram - 480-V Substations On Switchgears 151(251) and 152(252) 1E-1(2)-4000D Single Line Diagram - 480-V Substations On Switchgears 141X(241X) and 141Y(241Y) 1E-1(2)-4000E Single Line Diagram - 480-V Substations On Switchgears 142X(242X) and 143(243)

The listed drawings are included as "General References" only; i.e., refer to the drawings to obtain additional detail or to obtain background information. These drawings are not part of the UFSAR. They are controlled by the Controlled Documents Program.

LSCS-UFSAR 8.1-1 REV. 13 CHAPTER 8.0 - ELECTRIC POWER

8.1 INTRODUCTION

The Commonwealth Edison Company (CECo) offsite electric power system connections to LaSalle County Station (LSCS), described in detail in Section 8.2, are designed to provide a diversity of reliabl e power sources which are physically and electrically isolated so that any single failure can affect only one source of supply and cannot propagate to alternate sources.

The onsite electric power system is described in detail in Section 8.3. The station auxiliary electric power system is designed to provide electrical isolation and physical separation of the redundant power supplies for station requirements which are important to nuclear safety. Means are provided for automatic detection and isolation of system faults. In the event of total loss of auxiliary power from offsite sources, auxiliary power required for sa fe shutdown is supplied from diesel generators located on the site. The diesel generators are physically and electrically independent. Each power source, onsite and offsite, is physically and electrically independent up to the point of connection to the engineered safety features (ESF) system power buses. Loads important to plant safety are split and diversified between independent ESF switchgear groups.

Batteries are provided as sources of control power for the ESF electric power systems. The safety loads that require electric power to perform their safety function are identified by function to be performed an d are included in Tables 8.1-1 and 8.1-2 (a-c loads) and 8.3-10 through 8.3-13 (d-c loads). The electrical systems which power the ESF loads use IEEE stan dards as far as they apply.

The functions of these safety loads ar e described in Chapters 6.0 and 7.0.

The safety design bases used for the Class 1E electric systems are given in Table 1, "Design Basis Events," of IEEE 308-1974, "I EEE Standard Criteria for Class 1E Electric Systems for Nuclear Power Generating Stations." The electric power system provides a reliable source of power for the reactor recirculation pumps and other auxiliaries during normal operation, and for engineered safety features during abnormal and accident conditions.

The plant consists of two main generating units designated as Unit 1 and Unit 2. Each main generator is directly connected to two half-size main power transformers through an isolated phase electrical bus duct. The two half-size main power transformers are connected in parallel at their high and low voltage terminals and LSCS-UFSAR 8.1-2 REV. 15, APRIL 2004 transform the output of each generator fr om generator voltage to a nominal 345-kV transmission system voltage.

The output of each unit's main powe r transformer is connected to a 345-kV switchyard section consisting of circuit breakers, disconnect switches, buses, and associated equipment arranged in a ring bus configuration as shown in Figure 8.1-1.

Four overhead 345-kV transmission lines di stribute power to the various points on the transmission system.

The 345-kV system provides redundant powe r sources to the two system auxiliary power transformers through two 345-kV ring buses (Figure 8.1-2). Each system auxiliary transformer has sufficient capacity to handle the auxiliary power requirements of one unit. Each of these auxiliary power supplies is available, through circuit breaker switching, to a ll emergency auxiliary equipment of both units and therefore serves as a redundant offsite source of essential auxiliary power. Normal auxiliary power for each unit is supplied from the unit auxiliary power transformer, which is connected to the generator leads, and from the system auxiliary power transformer, which is co nnected to a 345-kV ring bus. Startup auxiliary power is provided through the system auxiliary power transformers via any one of the four 345-kV transmission lines which make up the offsite sources.

8.1.1 Offsite Power Systems - Summary Description The CECo transmission system is interco nnected with the MAIN (Mid-America Interpool Network) region utilities.

Four 345-kV transmission lines connect the station to the transmission system, as shown in Figure 8.1-1.

Electric energy generated at the station is stepped up to 345 kV by the main power transformers and fed into the station' s 345-kV transmission terminal, which consists of ten circuit breakers and fo ur transmission lines. The four 345-kV overhead lines exit the station via two separate rights-of-way and are connected into CECo's 345-kV system at the Braidw ood Station and the Plano transmission substation.

The 345-kV transmission terminal is also connected to the 138-kV transmission system at LaSalle through a 345/138 kV tran sformer as shown in Figures 8.1-1 and 8.1-2. The 138 kV bus is connected to two 138 kV overhead lines that are routed to Streator and Mazon. The 138 kV transmissi on system provides power to the river screen house and on-the site 12-kV distribution system.

LSCS-UFSAR 8.1-2a REV. 14, APRIL 2002 A one-line diagram of the transmission sy stem interconnections and the 345-kV bus arrangement is shown in Figure 8.1-1. Two of the 345-kV transmission lines are in service for Unit 1. The remaining two lines apply for service with Unit 2.

The stations' 345-kV transmission terminal buses, which are continuously energized, serve as the preferred power source for the station's safety loads. Two physically independent circuits are provided for each unit, one via the unit's LSCS-UFSAR 8.1-3 REV. 13 assigned system auxiliary transformer, and the other from the system auxiliary transformer of the other unit.

Each circuit emanates from a separate, distinct transmission terminal ring bus section and is brought to the plant via separate transmission towers and right-of-way.

In addition, removable links are provided in the main generator leads which, when removed, make a third source of offsite auxiliary power available to each unit by backfeeding the unit auxiliary transfor mer through the main transformer.

8.1.2 Onsite Power Systems - Summary Description

The main power system is designed for the generation of electric power which serves: (a) for distribution to the offsite power system, and (b) to provide an independent source of onsite power for the onsite station auxiliary electric power system. The onsite auxiliary electric power system is designed to provide reliable power service to those auxiliaries necessary for generation and to those auxiliaries important to nuclear safety. The design also provides for the electrical isolation and physical separation of redundant engineered safety feature power supplies and for the automatic detection and isolation of system faults.

Loads important to plant safety are divided into three groups and are fed from redundant Class 1E safety feature (ESF) switchgear groups.

The safety design bases used for the Class 1E electric systems are given in Table 1, "Design Basis Events," of IEEE 308-1974, "I EEE Standard Criteria for Class 1E Electric Systems for Nuclear Power Generating Stations." In the event of total loss of auxiliary power from offsite and main power sources, the auxiliary power required for safe shutdown is supplied from redundant Class 1E diesel generators located on the site. The diesel generators are physically and electrically independent. Each ESF division power source, diesel-generator and offsite, is physically and electrically inde pendent up to the point of connection to the ESF power system bus.

Batteries are provided as sources of control power for the ESF electrical power systems. The engineered safety featur es electric systems are designed in accordance with industry standards, criteria, regulatory guides, and other documents insofar as they apply except as otherwise indicated in the text.

LSCS-UFSAR 8.1-4 REV. 13 There are no provisions for startup without offsite power. A sufficient number of stations on the Commonwealth Edison Company system have "black start" capability to supply adequate startup power to the remaining stations.

8.1.2.1 Unit Auxiliary Power System

The basic function of the auxiliary a-c power system is to provide power for plant auxiliaries during startup, operation, an d shutdown and to provide highly reliable redundant power sources for loads which are necessary to plant safety. The auxiliary a-c power systems for the two-unit plant are shown in Figures 8.1-2 and 8.1-3. A full-capacity unit auxiliary transformer is provided for each unit. These transformers are connected directly to their respective main generator buses, as shown on the diagram, and are capable of supplying all of the auxiliary power requirements of a unit during normal operation.

A full-capacity system auxiliary transformer is also provided for each unit. Each of these transformers is supplied from separa te sections of the 345-kV ring bus as shown on the diagram and provides highly reliable auxiliary power supplies to both units from the 345-kV system. Both transf ormers are normally energized and thus provide an available offsite supply to the auxiliaries of both units.

As shown in Figure 8.1-3, power from th e auxiliary transformers (UAT 141 and SAT 142 for Unit 1 and UAT 241 and SAT 242 for Un it 2) is distribu ted from five 4160-volt switch groups and two 6900-volt switch groups per unit. The 4160-volt switch groups which supply power to engineered safety features are buses 141Y, 142Y, and 143 for Unit 1 and 241Y, 242Y, and 243 for Unit 2; those which supply power to non-safety-related (NSR) equipment are buses 141X and 142X for Unit 1 and buses 241X and 242X for Unit 2. The 6900-volt switch groups supplying power to non-safety-related buses are 151 and 152 for Unit 1 and 251 and 252 for Unit 2.

Each of the seven switch groups, except bus 143 (243), can be fed from either UAT 141 (241) or SAT 142 (242). Bus 143 (243) can be fed only from SAT 142 (242). Upon a tripout of the main generator, those switch groups which, at that time, are fed from UAT 141 (241) are transferred automatically to SAT 142 (242) so that all seven switch groups of Unit 1 (2) will cont inue to be energized and are available for operating auxiliaries as required for a safe and orderly shutdown. In case of a tripout of SAT 142 (242) all switch groups transfer to UAT 141 (241) except for bus 143 (243), which is then fed by diesel generator 1B (2B).

8.1.2.2 Unit Class 1E A-C Power System All of the ESF equipment required to shut down the reactor safely and to remove reactor decay heat for extended periods of time following a loss of offsite power LSCS-UFSAR 8.1-5 REV. 13 and/or a loss-of-coolant accident are supplie d with a-c power from the Class 1E a-c power system. That portion of the station auxiliary power system which supplies a-c power to the ESF is designated as the Class 1E a-c powe r system. The unit Class 1E a-c power system is divided into three divisions (Divisions 1, 2 and 3 for Unit 1; Divisions 1, 2 and 3 for Unit 2), each of which is supplied from a 4160-volt bus (141Y, 142Y, and 143 for Unit 1 respectively).

Two ESF groups (Division 2 and 3) of each unit are supplied standby power from individual diesel-generator units, while th e third ESF group (Division 1) for each unit obtains its standby power from a common diesel-generator unit, "0", which serves either of the corresp onding switch groups in each unit (Bus 141Y or 241Y). With this arrangement, alternate or redu ndant components of all ESF systems are supplied from separate switch groups so th at no single failure can jeopardize the proper functioning of redundant ESF.

The assignment of ESF equipment to the three electrical divisions for each unit is indicated in Table 8.1-1. The division of the ESF loads among the system buses is such that the total loss of any one of the three electrical divisions cannot prevent the safe shutdown of the reactor under any normal or abnormal design condition.

In the event of loss of of fsite power supplies to an ES F 4160- volt switch group, there are provisions for automatic trippi ng of offsite supply circuit breakers, automatic shedding of certain non-ESF loads, automatic starting of the diesel generator, and automatic closing of the di esel-generator supply circuit breaker. Provisions are also made for sequential starting of certain ESF loads so as to prevent excessive overload of the diesel generators during their starting periods.

Automatic transfer capabilities are also provided in which failure of the normal supply causes immediate tripping of the normal supply breaker and closing of an alternate supply breaker.

8.1.2.3 Unit Reactor Protection System (RPS) Power System The RPS power system includes the motor-generator power supplies and distribution panels with associated control and indicating equipment and the sensors, relays, bypass circuitry, and switches that cause rapid insertion of control rods (scram) to shut the reactor down.

Power to each of the two reactor protection trip systems is supplied, via a separate bus, by its own high-inertia a-c motor-generator set.

Alternate power is available to either reactor protection system bus from a transformer connected to a bus fed from the standby electrical power system. An interlock prevents feeding both reactor protection system buses simultaneously from this transformer.

LSCS-UFSAR 8.1-6 REV. 14, APRIL 2002 8.1.2.4 Unit Class 1E D-C Power System A 250-volt battery is provided for each unit to supply po wer to the turbine emergency bearing oil pumps, generator emergency seal oil pumps, backup feed to the computer, and RCIC system, as shown in Fi gure 8.3-9 for Unit 1. This figure is directly analogous to Unit 2 250-Vdc system.

Each unit is provided with three physically separate and electrically isolated sources of 125-Vdc ESF power (each with its own battery, battery charger, and distribution bus). Figures 8.3-10, 8.3-11, and 8.3-12 include in single-line from the Unit 1 125-Vdc systems. These figures ar e directly analogous to the Unit 2 125-Vdc systems.

The a-c power supply for the various ESF system auxiliaries is of prime importance and is almost entirely dependent upon the supply of 125-Vdc power to control the switchgear, relays, solenoid valves, instruments, etc.

8.1.2.5 Unit Non-Class 1E D-C System

One 125-Vdc system is required for operat ion of equipment at the river screen house. The control power for the 138-kV and 345-kV switchyard breakers is supplied by two 58-cell, 125 volt, 270 ampere-hour batteries (non-safety-related) located in the switchyard relay house. The design of the protective relay circuits for the 345-kV oil circuit breakers and the 345-kV transmission lines is such that the loss of either battery or the loss of both batteries and associated feeder cables will not cause the loss of offsite power sources. Two protective relay systems are used on each transmission line and two trip coils are us ed on each 345-kV oil circuit breaker to assure tripping of faulted equipment (see Figure 8.1-4). The switchyard batteries and feeder cables are not physically or elec trically associated with the station Class 1E battery circuits.

The physical design of the switchyard control power supplies incorporates the following features:

a. Two control power supplies, each consisting of a battery, battery charger, and distribution cabinets (one supply is located at each end of the relay house).

b. Two separate cable pan systems in the relay house basement.

LSCS-UFSAR 8.1-7 REV. 14, APRIL 2002 c. Two separate access ducts for cables to exit relay house basement (one at each end of building).

d. Two separate concrete trough systems for feeder cable distribution in the switchyard proper.

Two independent +

24-Vdc systems are provided as the power supply for the neutron-monitoring and process radiation monitoring systems (Figure 8.3-6). This figure applies to Unit 1 but is directly analogous to the Unit 2 system.

8.1.3 Identification of Class 1E Loads Nuclear safety-related systems and components that require electrical power to perform their nuclear safety function are defined as Class 1E loads.

Table 8.1-1 lists systems that require power to perform their nuclear safety functions. All electrical loads within these systems that are essential to the system nuclear safety function are therefore Class 1E loads.

The systems listed in Table 8.1-2 do no t perform nuclear safety functions.

Tables 8.1-4 through 8.1-10 present detailed listings of station Class 1E loads.

Table 8.1-3 lists the industry electrical standards and co des which were used in the design of LSCS.

LSCS-UFSAR TABLE 8.1-1 TABLE 8.1-1 REV. 15, APRIL 2004 POWER ASSIGNMENT OF SAFETY/RELATED SYSTEMS TO ELECTRICAL DIVISIONS FOR SEPARATION DIVISION 1 DIVISION 2 DIVISION 3 RHR A **RHR B & C HPCS LPCS Automatic depressurization B Diesel generator 1B (2B)

Automatic depressurization A

Inboard isolation valves 125-Vdc system 3

Outboard isolation valves Diesel generator 1A (2A} 4160-volt bus 143 (243) Diesel generator 0 ESF 125-Vdc system 2 480-volt MCC 143-1 (243-1)

ESF 125-Vdc system 1 4160-volt bus 142Y (242Y) Auxiliary support systems, power and control for the preceding 4160-volt bus 141Y (241Y) 480-volt buses 136X (236X) and 136Y (236Y) 480-volt buses 135X (235X) and 135Y (235Y) SBGT **RCIC **Fuel pool emergency makeup B **Standby liquid control A **Standby liquid control B

- Fuel Pool Emergency Makeup A MSIV-LCS Combustible gas control MSIV-LCS (U2 deleted, U1 abandoned-in-place)

ESF 250-Vdc system 1 Aux. equip. room HVAC system OA (OB) 480-Volt MCC 135X-1 (235X-1) MCC 135X-2 (235X-2) MCC 135X-3 (235X-3)

MCC 135Y-1 (235Y-1) MCC 135Y-2 (235Y-2)

Control room HVAC system OA (OB)

Auxiliary support systems, power and control for the preceding 480-volt MCC 136X-1 (236X-1) MCC 136X-2 (236X-2) MCC 136X-3 (236X-3) MCC 136Y-1 (236Y-1) MCC 136Y-2 (236Y-2) Auxiliary support systems, power and control for the preceding

- All entries are ESF powered except those designated.

NOTE: Items in parenthesis indica te corresponding Unit 2 designations

Divisional assignment of isolation valves takes precedence over the ESF system divisional assignment.

LSCS-UFSAR TABLE 8.1-2 TABLE 8.1-2 REV. 13 NON-SAFETY-RELATED EQUIPMENT FED FROM CLASS 1E POWER SUPPLIES SYSTEM POWER SOURCE ESF DIVISION Control rod drive feed pump 1A (2A) 4160-volt bus 141Y (241Y) 1 Primary containment water chiller 1A (2A) 4160-volt bus 141Y (241Y) 1 480-volt switchgear 133 (233) 4160-volt bus 141Y (241Y) 1 Control rod drive feed pump 1B (2B) 4160-volt bus 142Y (242Y) 2 Suppression pool cleanup & transfer pump 1A (2A) 4160-volt bus 142Y (242Y) 2 Suppression pool cleanup & transfer pump 1B (2B) 4160-volt bus 141Y (241Y) 1 480-volt switchgear 134X and 134Y (234 & 234Y) 4160-volt bus 142Y (242Y) 2 Primary containment water chiller 1B (2B) 4160-volt bus 142Y (242Y) 2 Primary containment vent supply fan 1A (2A) 480-volt bus 135Y (235Y) 1 Cleanup recirculation pump 1A (2A) 480-volt bus 135Y (235Y) 1 Primary containment vent supply fan 1B (2B) 480-volt bus 136Y (236Y) 2 Turbine building 480-volt motor control center 136Y-3 (236Y-3) 480-volt bus 136Y (236Y) 2 Recirc. MG Set Drive Motor 1A (2A) Breaker 1A 4160-volt bus 141Y (241Y) 1 Recirc. MG Set Drive Motor 1B (2B) Breaker 1B 4160-volt bus 142Y (242Y) 2 LSCS-UFSAR TABLE 8.1-3 TABLE 8.1-3 REV. 0 LIST OF NUCLEAR SAFETY ELECTRICAL DESIGN CRITERIA

1. IEEE Standard 279-1971 - "Criteria for Protection Systems for Nuclear Power Generating Stations."

2. IEEE Standard 308-1971 - "Standard Criteria for Class IE Electric Systems for Nuclear Power Generating Stations."

3. IEEE Standard 317-1971 - "Criteria for Electrical Penetration Assemblies in Containment Structures for Nuclear Power Generating Stations."

4. IEEE Standard 323-1971 - "General Guide for Qualifying Class I Electric Equipment for Nuclear Powe r Generating Stations."

5. IEEE Standard 336-1971 - "Installation, Inspection and Testing Requirements for Instrumentation and Electric Equipment during the Construction of Nuclear Po wer Generating Stations."

6. IEEE Trial-Use Standard 338-1971 - "Criteria for the Periodic Testing of Nucl ear Power Generating Station Protection Systems."

7. IEEE Standard 344-1971 - "Guide for Seismic Qualification of Class I Electric Equipment for Nuclear Power Generating Stations," (ANSI N41.7).

8. IEEE Trial-Use Standard 379-1972 - "Guide for the Application of the Single-Failure Criterion to Nuclear Power Generating Station Protection Systems," (ANSI N41.2).

9. IEEE Trial-Use Standard 382-1972 - "Guide for the Type Test of Class I Electric Valve Operators for Nuclear Power Generating Stations," (ANSI N41.6).

10. IEEE Standard 383-1974 - "Type Test of Class IE Electric Cables, Field Splices, and Connec tions for Nuclear Power Generating Stations."

11. IEEE Trial-Use Standard 387-1972 - "Criteria for Diesel-Generator Units App lied as Standby Power Supplies for Nuclear Power Generating Stations."

LSCS-UFSAR TABLE 8.1-4 TABLE 8.1-4 REV. 14, APRIL 2002 BUSES SUPPLIED BY UNIT AND SYSTEM AUXILIARY TRANSFORMERS BUSES SUPPLIED DIRECTLY BUSES SUPPLIED BY BUS TIES UNIT NUMBER TRANSFORMER NUMBER BUS NUMBER kV BUS NUMBER kV 1 141 151 6.9 141Y (ESF) 4.16 1 141 152 6.9 142Y (ESF) 4.16 1 141 141X 4.16 1 141 142X 4.16 1 142 151 6.9 141X 4.16 1 142 152 6.9 142X 4.16 1 142 141Y (ESF) 4.16 1 142 142Y (ESF) 4.16 1 142 143 (ESF) 4.16 2 241 251 6.9 241Y (ESF) 4.16 2 241 252 6.9 242Y (ESF) 4.16 2 241 241X 4.16 2 241 242X 4.16 2 242 251 6.9 241X 4.16 2 242 252 6.9 242X 4.16 2 242 241Y (ESF) 4.16 2 242 242Y (ESF) 4.16 2 242 243 (ESF) 4.16

LSCS-UFSAR TABLE 8.1-5 TABLE 8.1-5 REV. 0 4160-VOLT ESF BUSES FOR UNITS 1 AND 2

UNIT NUMBER ESF BUS NUMBER ESF DIVISION NUMBER kV DIESEL GENERATOR TIE TO BUSES 1 141Y 1 4.16 0 141X and 241Y 1 142Y 2 4 16 1A 142X and 242Y 1 143 3 4.16 1B None 2 241Y 1 4.16 0 241X and 141Y 2 242Y 2 4.16 2A 242X and 142Y 2 243 3 4.16 2B None LSCS-UFSAR TABLE 8.1-6 TABLE 8.1-6 REV. 14, APRIL 2002 LIST OF 480-VOLT ESF AUXILIARY POWER TRANSFORMERS FOR UNITS 1 AND 2 480-VOLT ESF AUXILIAR Y POWER TRANSFORMERS UNIT NUMBER ESF SUPPLY BUS NUMBER SUPPLIED TRANSFORMER NUMBER VOLTAGE kVA NOMINAL IMPEDANCE SAFETY CLASS 1 141Y 2 135X+Y 4160-480/277 1000 5.75% 1E (Division 1) 1 142Y 2 136X+Y 4160-480/277 1000 5.75% 1E (Division 2) 1 143 1 143-1 4160-480/277 225 3.30% 1E (Division 3) 2 241Y 2 235X+Y 4160-480/277 1000 5.75% 1E (Division 1) 2 242Y 2 236X+Y 4160-480/277 1000 5.75% 1E (Division 2) 2 243 1 243-1 4160-480/277 225 3.30% 1E (Division 3)

LSCS-UFSAR TABLE 8.1-7 TABLE 8.1-7 REV. 0 EQUIPMENT SUPPLIED BY 4160-VOLT ESF BUSES - UNIT 1

BUS NUMBER EQUIPMENT RATING CLASS 141Y Control rod drive feed pump 1A 300 hp Non-Class 1E 141Y Residual heat removal pump 1A 800 hp Class 1E 141Y Low-pressure core spray pump 1 1500 hp Class 1E 141Y PRI CNMT water chiller 1A 600 kW Non-Class 1E 141Y 4160/480-volt transformer 133 1000 kVA Non-Class 1E 141Y 4160/480-volt transformer 135X 1000 kVA Class 1E 141Y 4160/480-volt transformer 135Y 1000 kVA Class 1E 141Y Suppression pool cleanup & Transfer pump 1B 450 hp Non-Class 1E 141Y Recirc. MG Set drive motor 1A 400 hp Non-Class 1E 142Y Control rod drive feed pump 1B 300 hp Non-Class 1E 142Y Residual heat removal pump 1B 800 hp Class 1E 142Y Residual heat removal pump 1C 800 hp Class 1E 142Y Suppression pool cleanup and transfer pump 1A 450 hp Non-Class 1E 142Y PRI CNMT water chiller 1B 600 kW Non-Class 1E 142Y 4160/480-volt transformer 134X 1000 kVA Non-Class 1E 142Y 4160/480-volt transformer 134Y 1000 kVA Non-Class 1E 142Y 4160/480-volt transformer 136X 1000 kVA Class 1E 142Y 4160/480-volt transformer 136Y 1000 kVA Class 1E 142Y Recirc. MG Set drive motor 1B 400 hp Non-Class 1E 143 High-pressure core spray pump 3000 hp Class 1E 143 4160/480-volt transformer 143-1 225 kVA Class 1E

LSCS-UFSAR TABLE 8.1-8 TABLE 8.1-8 REV. 0 EQUIPMENT SUPPLIED BY 4160-VOLT ESF BUSES - UNIT 2 BUS NUMBER EQUIPMENT RATING CLASS 241Y Control rod drive feed pump 2A 300 hp Non-Class 1E 241Y Residual heat removal pump 2A 800 hp Class 1E 241Y Low-pressure core spray pump 2 1500 hp Class 1E 241Y PRI CNMT water chiller 2A 600 kW Non-Class 1E 241Y 4160/480-volt transformer 233 1000 kVA Non-Class 1E 241Y 4160/480-volt transformer 235X 1000 kVA Class 1E 241Y 4160/480-volt transformer 235Y 1000 kVA Class 1E 241Y Suppression pool cleanup and transfer pump 2B 450 hp Non-Class 1E 241Y Recirc. MG Set drive motor 2A 400 hp Non-Class 1E 242Y Control rod drive feed pump 2B 300 hp Non-Class 1E 242Y Residual heat removal pump 2B 800 hp Class 1E 242Y Residual heat removal pump 2C 800 hp Class 1E 242Y Suppression pool cleanup and transfer pump 2A 450 hp Non-Class 1E 242Y PRI CNMT water chiller 2B 600 kW Non-Class 1E 242Y 4160/480-volt transformer 234X 1000 kVA Non-Class 1E 242Y 4160/480-volt transformer 234Y 1000 kVA Non-Class 1E 242Y 4160/480-volt transformer 236X 1000 kVA Class 1E 242Y 4160/480-volt transformer 236Y 1000 kVA Class 1E 242Y Recirc. MG Set drive motor 2B 400 hp Non-Class 1E 243 High-pressure core spray pump 3000 hp Class 1E 243 4160/480-volt transformer 243-1 225 kVA Class 1E

LSCS-UFSAR TABLE 8.1-9 TABLE 8.1-9 REV. 13 EQUIPMENT SUPPLIED BY 480-VOLT ESF SUBSTATION BUSES - UNIT 1 BUS NUMBER EQUIPMENT RATING CLASS 135X RHR service water pump 1A 200 hp Class 1E 135X Diesel-generator cooling water pump "0" 125 hp Class 1E 135X Reactor building motor control center 135X-1 250 hp Class 1E 135X Auxiliary building motor control center 135X-2 325 hp Class 1E 135X Auxiliary building motor control center 135X-3 250 hp Class 1E 135Y RHR service water pump 1B 200 hp Class 1E 135Y Primary cont. ventilation supply fan 1A 100 hp Non-Class 1E 135Y Fuel pool emergency makeup pump 1A 75 hp Class 1E 135Y Cleanup recirculation pump 1A 100 hp Non-Class 1E 135Y Reactor building motor control center 135Y-1 250 hp Class 1E 135Y Reactor building motor control center 135Y-2 250 hp Class 1E 136X RHR service water pump 1C 200 hp Class 1E 136X Diesel-generator cooling water pump 1A 75 hp Class 1E 136X Auxiliary equipment room refrigeration unit 0A 125 hp Class 1E 136X Auxiliary equipment room air-cooled condenser fan 0A 100 hp Class 1E 136X Auxiliary Equipment room supply fan 0A 100 hp Class 1E 136X Reactor building motor control center 136X-1 250 hp Class 1E 136X Auxiliary building motor control center 136X-2 325 hp Class 1E 136X Auxiliary building motor control center 136X-3 250 hp Class 1E 136Y RHR service water pump 1D 200 hp Class 1E 136Y Control room refrigeration unit 0A 100 hp Class 1E 136Y Control room air-cooled condenser fan 0A 100 hp Class 1E 136Y Primary cont. ventilation supply fan 1B 100 hp Non-Class 1E 136Y Fuel pool emergency makeup pump 1B 75 hp Class 1E 136Y Reactor building motor control center 136Y-1 250 hp Class 1E 136Y Reactor building motor control center 136Y-2 250 hp Class 1E 136Y Turbine building motor control center 136Y-3 250 hp Non-Class 1E 136Y Hydrogen recombiner power cabinet 1PLF3J 125 kVA Class 1E LSCS-UFSAR TABLE 8.1-10 TABLE 8.1-10 REV. 13 EQUIPMENT SUPPLIED BY 480-VOLT ESF SUBSTATION BUSES - UNIT 2 BUS NUMBER EQUIPMENT RATING CLASS 235X RHR service water pump 2A 200 hp Class 1E 235X Reactor building motor control center 235X-1 250 hp Class 1E 235X Auxiliary building motor control center 235X-2 325 hp Class 1E 235X Auxiliary building motor control center 235X-3 250 hp Class 1E 235X Diesel-generator cooling water pump "O" 125 hp Class 1E 235Y RHR service water pump 2B 200 hp Class 1E 235Y Primary cont. ventilation supply fan 2A 100 hp Non-Class 1E 235Y Fuel pool emergency makeup pump 2A 75 hp Class 1E 235Y Cleanup recirculation pump 2A 100 hp Non-Class 1E 235Y Reactor building motor control center 235Y-1 250 hp Class 1E 235Y Reactor building motor control center 235Y-2 250 hp Class 1E 235Y Reactor building 480-volt power panel 235Y-3 160 kW Non-Class 1E 236X RHR service water pump 2C 200 hp Class 1E 236X Diesel-generator cooling water pump 2A 75 hp Class 1E 236X Auxiliary equipment room refrigeration unit 0B 125 hp Class 1E 236X Auxiliary equipment room air-cooled condenser fan 0B 100 hp Class 1E 236X Auxiliary equipment room supply fan 0B 100 hp Class 1E 236X Reactor building motor control center 236X-1 250 hp Class 1E 236X Auxiliary building motor control center 236X-2 325 hp Class 1E 236X Auxiliary building motor control center 236X-3 250 hp Class 1E 236Y RHR service water pump 2D 200 hp Class 1E 236Y Control room refrigeration unit 0B 100 hp Class 1E 236Y Control room air-cooled condenser fan 0B 100 hp Class 1E 236Y Primary cont. ventilation supply fan 2B 100 hp Non-Class 1E 236Y Fuel pool emergency makeup pump 2B 75 hp Class 1E 236Y Reactor building motor control center 236Y-1 250 hp Class 1E 236Y Reactor building motor control center 236Y-2 250 hp Class 1E 236Y Turbine building motor control center 236Y-3 250 hp Non-Class 1E 236Y Hydrogen recombiner power cabinet 2PLF3J 125 kVA Class 1E

LSCS-UFSAR 8.2-1 REV. 14, APRIL 2002 8.2 OFFSITE POWER SYSTEM This section describes the offsite power system arrangement for LSCS.

8.2.1 Description

Electric energy generated at the station is transformed from generator voltage to a nominal 345-kV transmission system voltag e by the main power transformers. The main power transformers are connected via intermediate transmission towers to the station's 345-kV transmission terminal consisting of circuit breakers, disconnect switches, buses, support structures, and associated relay protection equipment. A one-line diagram of the 345-kV bus arrangem ent is shown on Figure 8.1-1. Four 345-kV overhead lines exit the transmission terminal on two separate rights-of-way as shown on Figure 8.2-1, and are connected into ComEd's 345-kV system at the Braidwood Station and Plano transmission substation.

The 345-kV transmission terminal is also connected to the 138-kV transmission system at LaSalle through a 345/138 kV tran sformer as shown in Figures 8.1-1 and 8.1-2. The 138 kV bus is connected to two 138-kV overhead lines that are routed on separate right-of-ways.

These 138-kV transmission lines connect to ComEd's 138-kV system at Streator and Mazon. One of the 138-kV lin es provides power to the river screen house. The 138-kV transmissi on system also powers the on-site 12-kV distribution system.

8.2.1.1 Transmission Lines Two of the 345-kV transmission lines, on e from Braidwood and one from Plano, were placed in service prior to fuel loading for Unit 1. The remaining two lines were placed in service prior to fuel loading for Unit 2. The two 138-kV transmission lines were placed in service prior to fuel loadin g of Unit 1. The transmission structures are designed for heavy ice, high wind an d broken wire loadings, and dampers are installed on all conductors and static wire s to control high frequency vibration. Figure 8.2-2 indicates transmission line routing on the site property, and Figure 8.2-3 shows the proximity of other transmission lines.

8.2.1.2 Power Sources The station's 345-kV transmission terminal buses are continuously energized and serve as the preferred power source for the station's safety loads. Two physically independent lines are provided for the station from the transmission terminal buses. Each line emanates from a separate and distinct bus sect ion, and is brought to the plant via separate intermediate transmission towers. The system auxiliary transformers step the 345-kV system voltage down to the station 4160-volt and 6900-volt power systems. Each system auxiliary transformer is sized to provide the total auxiliary power for one unit plus the ESF auxiliary power for the other unit.

LSCS-UFSAR 8.2-1a REV. 14, APRIL 2002 In an emergency, there are two breakers to allow 4160-vo lt switchgear 141Y of Unit 1 to be tied to 241Y of Unit 2, and two breakers to allow 4160-volt switchgear 142Y of Unit 1 to be tied to 242Y of Unit 2.

This configuration provides the availability of redundant sources of offsite power. In addition, the main generator leads contain removable links that can make a third source of offsite auxiliary power available for each unit by backfeeding the unit auxiliary transformer through the main power transformers. Further discussion concerning the relationship between the station's offsite power system and the onsite auxiliary power system can be found in Subsection 8.3.1.

LSCS-UFSAR 8.2-2 REV. 14, APRIL 2002 8.2.1.3 Transmission System The probability of losing the offsite electric power supply has been minimized by the design of the Commonwealth transmission sy stem. Increased reliability is provided through interconnections to neighboring systems. The Commonwealth transmission system consists, in part, of 74 345-kV lines totaling 2244 miles, and 3 765-kV lines totaling 152 miles. The transmission system is interconnected with neighboring electric utilities over 28 tie lines: 12 at 138 kV, 15 at 345 kV, and 1 at 765 kV. Commonwealth is a member of Mid-America Interpool Network (MAIN). In general, all electric utilities in Illinois, northern and eastern Missouri, Upper Michigan, and the eastern half of Wisconsin are members of MAIN. The transmission within MAIN currently consists of 120 345-kV lin es totaling 4714 miles and 3 765-kV lines totaling 152 miles.

The reliability of the transmission grid is demonstrated by the performance data of the 345-kV transmission lines. The av erage 345-kV line in the MAIN grid experienced 1.7 forced outages per year, wi th an average duration of 59 hours6.828704e-4 days 0.0164 hours 9.755291e-5 weeks 2.24495e-5 months per forced outage during 1975 and 1976 covering 219 line years of exposure (References 1 and 2). For the 12 years between January 1, 1965, and December 31, 1976, the average Commonwealth 345-kV lin e experienced 1.9 forced outages per year, with an average duration of 7.8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months per forced outage. This 12-year period represents 427 line years of experience.

The causes of the fo rced line outages may be summarized as follows:

% of Forced Outages

a. terminal-related 1. storm damage 3.4 2. equipment failure 18.4 3. human error 7.3 4. false trip 13.7 5. other 14.5

b. line-related 1. storm damage 17.5 2. equipment failure 3.0 3. other 13.7

c. unknown 8.5 100%

LSCS-UFSAR 8.2-3 REV. 15, APRIL 2004 The only source of fire or explosion in the area of the switchyard would be the 345-kV circuit breakers, 138-kV circuit breakers and the 345-kV-138-kV transformer. This equipment along with the combined microwave and

meteorological tower, are located so that the worst possible failure will not result in the total loss of offsite power.

The described design of the offsite power system is in compliance with NRC General Design Criterion 17 and Regulatory Guide 1.6.

8.2.2 Analysis

One of the functions of MAIN is to ensure that the transmission system is reliable and adequate. Power flow and transient stability studies are conducted on a regular basis using the criteria stated in Reference 3, a portion of which follows:

"The generation and transmission system shall be adequate to withstand the most severe of the following set of contingencies without resulting in an uncontrolled widespread tripping of lines and/or generators with resulting loss of load over a large area:

1. Sudden outage of any tower line at the time when any other one circuit is out of service.

2. Sudden outage of any transmission circuit at a time when a combination of any three generating units is out of service.

3. Sudden outage of any double-cir cuit transmission tower line at a time when a combination of any two generating units is out of service. 4. Sudden outage of all transmission lines on the same right-of-way. 5. Sudden outage of any generating unit at a time when any two other generating units are out of service.

6. Sudden outage of all generating capacity at any generating plant. 7. Sudden outage of any transmission station, including all generating capacity associated with such a station.

8. Sudden dropping of a large load or a major load center.

LSCS-UFSAR 8.2-4 REV. 14, APRIL 2002 9. Any credible contingency which might lead to system cascading." "The studies conducted to test the effect of the above contingencies should give due consideration to the following:

a. Steady-state, dynami c and transient stability consideration, including three-phase faults at the most

critical locations.

b. The effect of slow fault clearing as a consequence of improper relay operation or failure of a circuit breaker to open. c. Possible occurrence of the above contingencies not only on the interconnected MAIN network, but also on the network of adjacent power systems, where a major contingency might involve MAIN or portions there of in a cascading incident.

d. Expected normal and emergency power flow conditions.

The transmission system at Commonwealth is designed to meet all of these criteria.

The capacity of the Commonwealth transmission system to withstand the loss of transmission lines connecting the LaSalle 345-kV switchyard to the network has been investigated through stability studies to demonstrate adequacy of the transmission system during conditions be fore and after the installation of the Braidwood generation and its associated transmission.

The studies demonstrated the adequacy of the transmission system under various line contingencies on the LaSalle and Braidwood 345-kV lines. Contingencies studied were three-phase faults near the 345-kV switchyard, which are the most severe as concerns the stability of the units. Included were sing le-line faults with normal clearing of the line protective sy stems, and abnormal clearing involving the failure of a relay or circuit breaker. Other conditions studied were:

a. double-line tower faults, and

b. single-line faults during planned maintenance outages.

All units remained stable throughout all of the line outages mentioned.

LSCS-UFSAR 8.2-4a REV. 14, APRIL 2002 A grid stability review was performed for the LaSalle Power Uprate Project which consisted of the following studies: st eady state power flow analysis, voltage stability analysis, and transient stability an alysis. The steady state power flow analysis reviewed the steady state loading on the transmission system with the uprate at LaSalle modeled. The steady st ate power flow analysis assessed the risk of facility overload caused by various contingencies (line outages, transformer outages, etc.). The power flow studies did not identify any significant additional risks with the LaSalle uprate included.

The purpose of the voltage stability study was to identify the maximum loading the transmission system could withstand before a voltage collapse occurs. While the voltage collapse point did decrease slightly with the LaSalle uprate included, it was still within ComEd's planning criteria. The transient stability studies assessed the risk of generator instability after severe faults located at or near the generating station. The conclusion from these studies was that transient stability can be maintained for the severe faults (References 4-6).

LSCS-UFSAR 8.2-5 REV. 16, APRIL 2006 8.2.3 Adequacy of Offsite Power Distribution Systems 8.2.3.1 Introduction An analysis was made to show that the LaSalle County Station (LSCS) auxiliary electric system will provide adequate power to essential loads during the contingency which presents the largest load demand on the auxiliary system. This section presents the results of that adequacy study.

8.2.3.2 Adequacy of Offsite Power Offsite power is supplied to LSCS by th e Commonwealth Edison 345- kV system.

There are four incoming lines, two for each unit. The 345-kV switchyard is arranged in a double ring bus, as sh own in Figure 8.1-1. The switchyard arrangement is such that offsite power to both units cannot be lost due to any single failure.

The 345-kV system has four lines connected to the extensive Chicago area transmission system. As a result, the voltage variation band at the LSCS bus is quite narrow. The expected operating voltage range on the 345-kV busses is 354 kV to 362 kV. Lower voltages may be experien ced rarely during severe generation and transmissions outages. The three-phase fault current level at LSCS ranges from 10395 MVA to 35000 MVA.

The station auxiliaries are served from two 6.9-kV and five 4.16-kV buses, as shown in Figure 8.1-2. The engineered safety feature loads are fed from three of the 4.16-kV buses (buses 141Y, 142Y, and 143). The two 6.

9-kV buses (151 and 152) and the remaining 4.16-kV buses (141X and 142X) serve non-safety-related loads.

The unit substations connected radially to the various 6.9-kV and 4.16-kV buses serve low voltage (480 volt) loads.

During normal operation, both the unit auxiliary transformer (UAT) and the system auxiliary transformer (SAT) su pply the station auxiliary load as described in section 8.3.1.1.1. When the generator is not operating such as during start-up or shutdown or unit trip, the loads fed from the UAT ar e transferred to the SAT. The unit's SAT is the first offsite source to its safety-relat ed buses. The SAT of the other unit is the second offsite source through bus ties provided between corresponding safety-related buses of the two units. These ties woul d be closed only in the event of loss of offsite power to one of the units.

8.2.3.2.1 Loading Analysis The case chosen for detailed voltage evaluation represents the maximum loading to which the auxiliary system could be subj ected under any mode of plant operation.

LSCS-UFSAR 8.2-6 REV. 13 For this case it was assumed that the tota l non-safety-related load required by the unit (at full unit output) plus the unit's ma ximum safety-related load were supplied simultaneously from the SAT. All safety-related loads were assumed to operate at maximum output. The bus loadings under this condition are shown in Table 8.2-1.

In a loss of coolant accident (LOCA), the main generator would trip causing the loss

of the UAT and automatically transfer all running loads to the SAT. Those safety-related loads which receive a LOCA automatic start signal would start. However, many of these loads would operate at less than full load until ne eded. Also, the non-safety-related load would decrease after a few minutes. As a result, the maximum auxiliary load following an accident would be less than that shown in Table 8.2-1.

In the case of a unit trip, the non-safety-related loads would be transferred to the

SAT. However, the safety-related loads would not be started automatically. Thus, the resulting maximum load would be less than that for an accident situation.

In an accident or a unit trip, the UAT is not available to supply auxiliary power because it is directly connected to the ge nerator bus. A study of UAT electrical performance, therefore, is not germane to this analysis.

Bus ties are provided from safety-relat ed buses 141Y to 241Y and from 142Y to 242Y. These inter-unit ties are closed only when offsite power to one of the two units is lost. In accordance with Regula tory Guide 1.81, it is assumed in this analysis that the other unit is either running or is in a safe s hutdown condition.

Because the auxiliary system design for the two units at LSCS is similar, the voltages at the safety-related buses of Unit 1 while being supplied from Unit 2 SAT will be equal to or better than the worst case analyzed for Unit 1 SAT carrying the

loads indicated in Table 8.2-1.

8.2.3.2.2 Criteria For Acceptable Voltage The criteria for the acceptable voltage range at motors, contactors and control circuits is based on equipment ratings as defined by the National Electric Manufacturers Association (NEMA). Thes e standards require that the maximum voltage should be limited to 110% of equipment rated voltage and the minimum voltage to be limited to 90% of equipment rated voltage.

In order to provide adequate torque for motor starting and to prevent contactors from dropping out at 480-volt motor control centers, the starting voltage should be limited to some acceptable level. The minimum acceptable level (i.e. starting voltage) for safety-related motors and contactors is based on the minimum equipment terminal voltages postulated at the lower analytical limit or design basis of the second level undervoltage protection setpoint.

LSCS-UFSAR 8.2-7 REV. 16, APRIL 2006 8.2.3.2.3 System Performance The small variation in the switchyard voltage at LSCS allows the maintenance of high running voltages without the danger of excessive overvoltages. The no-load voltages on the auxiliary system buses are shown in Table 8.2-2. In no case is the NEMA guideline of 110% of rated voltage exceeded.

A voltage analysis was made for the Unit 1 SAT carrying its worst-case loading. The SAT of the second unit can simultaneously carry a similar loading without affecting the results of this analysis. This is due to the fact that the only common element during this condition is the hi gh-capacity 345-kV transmission network whose voltage is not measurably affected by the presence of the second unit auxiliary loads.

The minimum calculated running voltages on the various buses are shown in Figure 8.2-4. The voltages shown at the unit substations are the lowest on a 6.9-kV non-safety-related bus (131B), a 4.16-kV non-safety-related bus (132X), and a 4.16-kV safety-related bus (136X). In making the calculations, the minimum value of switchyard voltage and the maximum value of switchyard short circuit current were assumed. The running voltages at selected loads are shown in Table 8.2-3.

These values include voltage drop in the c ables from the bus to the load. The loads selected are those expected to have the maximum voltage drop from the bus to the equipment terminals.

The starting bus voltages are also shown in Figure 8.2-4. The starting voltage of the ESF loads is 3167 volts or 79.2% of motor-rated voltage. The ESF load includes all 4000-volt motors which would start in an accident as well as the difference between the maximum 480-volt loads on th e ESF buses and the 480-volt ESF loads which would be present during normal operat ion of the station. All of these loads were assumed to start simultaneously with no sequencing of starting motors.

UFSAR Table 8.2-3 and Figure 8.2-4 provid ed the calculated running and starting voltages at the time of licensing. An analysis is performed for any modification that affects the AC auxiliary power system to ensure that acceptable running and starting voltages are present on the buses. The results of these evaluations is provided in the applicable voltage analysis.

8.2.3.3 Undervoltage Relays Undervoltage relays are provided for each ESF bus to initiate load shedding and transfer the ESF load to the onsite diesel generator in case offsite power is lost or

degraded. The minimum voltage to transfer load to the ESF buses is 2625 volts or 65.6% of 4000 volts for Divisions 1 and 2 and 2870 volts or 71.8% of 4000 volts for Division 3. Because the minimum expected voltage during normal or emergency operation, 3167 volts, is well above the relay setting, transfer to the onsite power LSCS-UFSAR 8.2-7a REV. 14, APRIL 2002 supply should not occur. The undervoltage relays incorporate sufficient time delay so that short circuits can be cleared without undervoltage relay operation.

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 consid ered as two different undervo ltage 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. 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 witht eh same undervoltage permissive provided that the Division 3 bus main feeder breaker is open and the DG speed and voltage permissi ves are met. The Division 3 bus main feed breaker trip logic includes two trip systems. Each trip system consists of an undervoltage relay on the 4.16 kV bus (w ith 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 4.16kV emergency bus, and (for Divisions 1 and 2 only) the shedding of the appropriate 4.16 kV bus loads.

In response to the NRC's request, a second level of degraded grid voltage protection has been added at LaSalle. A brief discussion of the additional sc heme is as follows.

LSCS-UFSAR 8.2-8 REV. 14, April 2002 Two undervoltage relays are installed on each 4 kV ESF bus; these are connected in a two-out-of-two logic similar to the existing undervoltage relays.

If no LOCA condition exists, operation of both of these added relays initiates an alarm in the control room and starts a 5- minute timer. If the degraded voltage is not corrected within the 5-minute period, the bus will automatically transfer from the offsite power source to an onsite diesel-generator.

However, this transfer cannot be completed until the bus voltage has dropped below the setpoint of the existing (first level) undervoltage relays. These relays must pickup to initiate load shedding (ESF Di vision 1 and 2), start the ESF Division 3 diesel generator, and allow the diesel generator output breaker to close. The second level of undervoltage protection trips all the power source breakers except from the diesel generator and starts the ESF Divisi on 1 and 2 diesel generators. It also prevents the ECCS pumps starting until the bus voltage returns to normal.

If a LOCA condition does exist concurrent with degraded grid voltage, the above described control room alarm and automatic bus transfer will be initiated with the exception that the 5 minute delay period is eliminated.

Whenever the onsite diesel generator is the only source of power connected to an ESF bus, the second level of degraded gr id voltage protection for that bus is disabled. The first level of undervo ltage protection is never disabled.

This second level undervoltage protection has a nominal setpoint of 93.0% (+/-0.2%)

of normal bus voltage with a short time de lay; it picks up at 3870 volts (decreasing) on the buses with a 10 second delay to decrease the possibility of spurious operation due to transient voltage dips. The lower analytical or design basis of the second level undervoltage protection setpoint is 3814 volts or 91.7% of normal bus voltage. The upper analytical or design basis of the second level undervoltage protection setpoint is 3900 volts or 93.8% of normal bus voltage. The minimum voltage relay protection from the existing undervoltage re lays is set to pick up at 2625 volts or 65.6% of the normal bus voltage for Divisi ons 1 and 2 and 2870 volts or 71.8% of the normal bus voltage for Division 3 as previously described.

8.2.3.4 Conclusion This analysis shows that the auxiliary distribution system at LSCS has the capability to adequately handle worst case loading and maintain all voltages well within equipment ratings under the postulated most severe contingency conditions.

LSCS-UFSAR 8.2-9 REV. 14, APRIL 2002

8.2.4 References

1. MAIN report entitled "Summary of MAIN Transmission Line Performance for the year 1975--345 kV and 765 kV." 2. MAIN report entitled "Summary of MAIN Transmission Line Performance for the year 1976--345 kV and 765 kV." 3. MAIN Guide No. 2, "Criteria for Simulation Testing of the Reliability and Adequacy of the MAIN Bulk Power Transmission System." 4. LaSalle County Station Power Upra te Project, Task 600, "Off-Site Power System/Grid Stability," GE-NE-A1300384-57-01, Revision 0, October 1999.

5. Letter from J. A. Benjamin, Commonwealth Edison (ComEd) Company, to U. S. NRC, "Response to Request for Additional Information License Amendment Request for Power Uprate Operation," dated 02/23/2000.

6. Letter from Charles G. Pard ee, Commonwealth Edison (ComEd) Company, to U. S. NRC, "Response to Request for Additional Information License Amendment Request for Power Uprate Operation," dated 03/24/2000.

LSCS-UFSAR TABLE 8.2-1 TABLE 8.2-1 REV. 0 BUS LOADINGS ASSUMED FOR OFFSITE POWER SUPPLY ANALYSIS LOAD MVA 6.9-kV Non-Safety-Related 32 4.16-kV Non-Safety-Related 15 4.16-kV Safety-Related 12

TOTAL 59 LSCS-UFSAR TABLE 8.2-2 TABLE 8.2-2 REV. 0 NO-LOAD VOLTAGES

BUS NO LOAD VOLTS PERCENT OF EQUIPMENT RATING Switchyard 362,000 ---

6.9-kV Non-Safety-Related 7,240 109.6 Unit Subs Fed From 6.9-kV 504 109.5 4.16-kV Safety-Related and Non-Safety-Related 4,365 109.1 Unit Subs Fed From 4.16-kV 504 109.5

LSCS-UFSAR TABLE 8.2-3 TABLE 8.2-3 REV. 14, APRIL 2002 RUNNING VOLTAGES AT SELECTED LOADS LOAD HP RATED VOLTAGE (VOLTS) RUNNING VOLTS PERCENT OF MOTOR RATED BUS Reactor Recirculating Pump 1B 8900 6600 6598 100.0 152 Circulating Water Pump 1B 2000 4000 3920 98.0 142X Service Water Pump 1B 1250 4000 3920 98.0 142X Service Water Jockey Pump 0A 350 4000 3930 98.2 142X Fuel Pool Emergency Makeup Pump 1A 75 460 442 96.1 135Y (141Y) Control Room Supply Fan 0A 50 460 426 92.6 136X (142Y) Fuel Pool Emergency Makeup Pump 1B 75 460 443 96.3 136Y (142Y) HPCS Diesel Generator Cooling Water Pump 100 460 439 95.4 143-1 (143) NOTE: The motor running voltage values are historical in nature. The mo st recent voltage values ar e provided in the latest AC auxiliary power system evaluation.

LSCS-UFSAR 8.3-1 REV. 13 8.3 ONSITE POWER SYSTEMS The following onsite power systems supply electrical power to the auxiliary electrical loads for each unit:

a. the unit non-Class 1E au xiliary a-c power system, b. the unit Class 1E auxiliary a-c power system, c. the RPS power system, d. the unit Class 1E d-c power system, and

e. the instrument a-c power system (this system derives its power sources from the above systems).

The unit non-Class 1E auxiliary a-c and RPS power systems are not Class 1E and are described here only in sufficient detail to permit an understanding of their interactions with the two unit Class 1E systems.

The unit Class 1E systems (a-c and d-c) are described in sufficient detail to establish their functional adequacy to meet the current nuclear safety electrical design criteria listed in Table 8.1-3.

8.3.1 A-C Power Systems 8.3.1.1 Description For additional information see Section 8.1.

The unit Class 1E a-c and non-Class 1E a-c power systems are shown in single-line form in Figures 8.1-2 and 8.1-3.

8.3.1.1.1 Unit Non-Class 1E Auxiliary Power Systems The loads normally served by the unit no n-Class 1E auxiliary power systems are those unit a-c loads that are not Class 1E.

The system also serves as one onsite source for the unit Class 1E a-c power system (Figure 8.1-3).

The main components of the unit non-Cla ss 1E auxiliary power system for Unit 1 (2) include the unit auxiliary transforme r 141 (241), two 6900-volt switchgear buses 151 (251) and 152 (252), two 4160-volt swit chgear buses 141X (241X) and 142X (242X), 18 480-volt unit substations, 39 48 0-volt motor-control centers, 22 480-/120-Vac lighting distribution cabinets, and 30 208-volt/120-Vac distribution panels.

LSCS-UFSAR 8.3-2 REV. 13 The normal 6900-volt and 4160-volt powe r source for the unit non-Class 1E auxiliary power system is unit auxiliary tr ansformer (UAT) 141. The transformer is sized to carry the total full-load au xiliary power required by the unit.

The UAT 141 primary is connected to the main generator bus via an isolated phase bus duct tap; the transformer 6900-volt winding is connected by nonsegregated

phase bus duct to 6900-volt switchge ar buses 151 and 152; the transformer 4160-volt winding is connected by nonsegregate d phase bus duct to 4160-volt switchgear buses 141X and 142X. The isolated phase bu s duct tap is sized to carry the full rating of UAT 141. The nonsegregated ph ase bus ducts are sized to carry the full load of the switchgear buses to which they are connected.

The reserve 6900-volt and 4160-volt powe r source for the unit non-Class 1E auxiliary power system is the system auxiliary transformer (SAT) 142. The transformer is sized to carry the total full-load auxiliary power required by the unit plus the ESF auxiliary power for the other unit.

The SAT 142 6900-volt winding is connected by nonsegregated phase bus duct to 6900-volt switchgear buses 151 and 152; the transformer 4160-volt winding is connected by nonsegregated phase bus duct to 4160-volt ESF switchgear buses

141Y, 142Y, and 143. Buses 141Y and 142Y can be connected by nonsegregated phase bus duct and the breakers ACB 1415 and ACB 1425, to 4160-volt switchgear buses 141X and 142X respectively. The nons egregated phase bus ducts are sized to carry the full load of the switchgear buses to which they are connected.

When the unit is synchronized to the sy stem, the preferred co nfiguration is as follows:

a. 6900-volt bus 151 (251) is fed from UAT 141 (241), and 6900-volt bus 152 (252) is fed from SAT 142 (242).

b. The 4160-volt buses 141X (241X) are fed from UAT 141 (241).

c. The 4160-volt buses 141Y, 142X, 142Y, and 143 (241Y, 242X, 242Y, and 243) are fed from SAT 142 (242).

d. 4160-volt bus tie breaker ACB 1415 (2415) is open, and ACB 1425 (2425) is closed.

e. 4160-volt unit tie breakers ACB 1414 and ACB 1424 (ACB 2414 and ACB 2424) remain open.

Upon a tripout of the main generator those switch groups which, at that time, are fed from the UAT are automatically transferre d to the SAT if it is available so that LSCS-UFSAR 8.3-3 REV. 14, APRIL 2002 all seven switch groups will continue to be energized and available for operating auxiliaries as required for a safe and orderly shutdown.

In the event of loss of the SAT, those switch groups which at that time are fed from the SAT--with the exception of 4160-volt bu s 143 (243), which transfers directly to its associated diesel generator, 1B (2B)--automatically transfer to the UAT, if it is available, so that all seven switch groups continue to be energized and available for operating auxiliaries as required.

In the event of loss of both the UAT and SAT, undervoltage relays will automatically trip (open) all SAT 4160-volt f eed breakers and trip (open) the bus tie breakers connecting buses 141X and 142X (241X and 242X) to buses 141Y and 142Y (241Y and 242Y) respectively, thus complete ly severing the unit non-Class 1E and the unit Class 1E auxiliary a-c powe r systems from each other.

Figure 8.3-3 shows, as a typical exampl e, the logic associated with UAT 141 (ACB 1511) and SAT 142 (ACB 1512) feeds to 6900 Volt Bus 151.

8.3.1.1.2 Unit Clas s 1E A-C Power System

The loads served by the unit Class 1E a-c power system include all Class 1E a-c loads of that unit. The sy stem also provides 4160-volt power sources to the non-safety-related 4160-volt buses 141X (241X) and 142X (242X) via bus tie breakers ACB 1415 (ACB 2415) and ACB 1425 (ACB 2425).

The connected loads, their ratings, bus assignments, division assignments, and locations are shown on Tables 8.1-7 through 8.1-10.

The coincidental loads for shutdown and LOCA operation (including maximum load sequencing times for a coincident loss of a ll offsite power) are shown in Table 8.3-1.

The main components of the unit Class 1E a-c power system for Unit 1 (or Unit 2) are three diesel generators, one of which is common to Unit 1 and Unit 2, three 4160-volt switchgear buses, four 480-volt unit substations, five 4160-/480-volt transformers, eleven 480-volt motor cont rol centers (MCC's), and nine 208-/120-Vac distribution panels.

Components of the unit Class 1E a-c power system are assigned to three electrically and physically independent divisions as shown in Tables 8.1-1 and 8.3-1.

Class 1E loads with redundant safety functions are assigned to different divisions.

LSCS-UFSAR 8.3-4 REV. 13 For each ESF unit, each Division 1 and 2 4160-volt bus, 141Y (241Y) and 142Y (242Y) is provided with four independ ent sources of a-c power as follows:

a. a normal (#1 offsite) source which is provided from the 345-kV system through the system au xiliary transformer (SAT) 142 (242) directly to buses 141Y (241Y) and 142Y (242Y);

b. a reserve (#1 onsite) source, available during unit operation, which is provided from the unit through the unit auxiliary transformer 141 (241) to buses 141Y (241Y) and 142Y (242Y) via bus tie breakers ACB 1415 (ACB 2415) and ACB 1425 (ACB 2425) with buses 141X (241X) and 142X (242X) respectively;

c. a standby (#2 onsite) source wh ich is provided from the onsite diesel generators: 0 to buses 141Y or 241Y and 1A (2A) to bus 142Y (242Y); and

d. an emergency (#2 offsite) source (in accordance with NRC General Design Criterion 17) which is provided from the 345-kV system through the system auxiliary transformer (SAT) of the

opposite unit to buses 141Y (241 Y) and 142Y (242Y) via unit tie breakers ACB 1414 and ACB 2414 with bus 241Y (141Y) and ACB 1424 and ACB 2424 with bus 242Y (142Y).

(NOTE: The two unit ties listed in item d above each consist of 1200-ampere, 3-phase, 4160-volt nonsegregated phase bus duct provided with current differential relay protection. Each unit tie is provided with a circuit breaker at each end. The capacity of each unit tie is adequate for the ESF loads on the opposite unit bus.) In addition to the four independent so urces discussed above, a fifth source (#3 offsite available to both units) is available by virtue of removable links in the main generator isolated phase bus, which, when removed, allow backfeeding of the unit auxiliary transformer from th e 345-kV system through the main power transformer. This source is similar to items b and d disc ussed above; however, it is available only when the unit is shut down and the generator disconnected.

For each unit, ESF Division 3 4160-volt bus 143 (243) is provided with two independent sources of a-c power as follows:

a. a normal (offsite) source wh ich is provided from the 345-kV system through system auxilia ry transformer (SAT) 142 (242), and LSCS-UFSAR 8.3-5 REV. 13

b. a standby (onsite) source which is provided from onsite diesel generator 1B (2B).

ESF electrical equipment is fed from 4160-volt buses 141Y (241Y), 142Y(242Y), and 143 (243), divided into three divisions, Divisi ons 1, 2, and 3, respectively, for each unit (Table 8.1-1).

The 4160-volt ESF buses can be fed from any of the sources described in the preceding; however, the normal source of power for ESF buses 141Y (241Y), 142Y (242Y), and 143 (243) is the 345-kV sy stem (offsite) through SAT #142 (242).

When no offsite power is available through SAT 142 (242), the preferred configuration is ESF buses 141Y (241Y) an d 142Y (242Y) fed from the unit (onsite) through UAT 141 (241) via bus tie breakers ACB 1415 (ACB 2415) and ACB 1425 (ACB 2425) with buses 141X (241X) and 142X (242X), respectively, with ESF bus 143 (243) fed from diesel generator 1B (2B).

Alternate configurations are (a) ESF buse s 141Y (241Y) and 142Y (242Y) fed from diesel generators O (O) and 1A (2A), re spectively, and (b) ESF buses 141Y (241Y) and 142Y (242Y) fed from the 345-kV sy stem through SAT 242 (142) via unit tie breakers ACB 1414 and ACB 2414 with bus 241Y (141Y) and via unit tie breakers ACB 1424 and ACB 2424 with bus 242Y (142Y), respectively.

Power is required at all times to operate the various auxiliary systems. Some of these systems are required when the unit is operating; some are required only when the unit is shut down, and others are required only for abnormal conditions. Since engineered safety features fall into each of these categories it is essential to have auxiliary power at all times. Depending on the condition of the unit at any given time some power sources may not be avail able, therefore, a reliable power transfer scheme is furnished.

The transfer of a 4160-volt bus from one so urce to another can occur by: (a) manual transfer, (b) automatic fast transfer (approximately 8 cycles), or (c) automatic slow transfer (after motor lo ads have been shed).

Manual source transfers are accomplished by paralleling the incoming supply with the running supply, and then tripping th e running supply. Once the incoming breaker is closed the outgoing breaker is tripped manually. This prevents continuous operation with two sources in parallel.

Automatic fast source transfer (i.e., automatic fast closing of a source breaker) of a bus occurs when the following conditions are fulfilled:

a. All source breakers to the bus are open.

LSCS-UFSAR 8.3-6 REV. 13

b. At least one source is available to the bus at the instant all source breakers become open.

If more than one source is available to the bus, a source breaker is selected for automatic closure according to the following order of priority: unit or system auxiliary transformer source; diesel generator source.

Automatic slow source transfer of a bus occurs when the following conditions are fulfilled:

a. All source breakers are open.

b. Fast transfer has not resulted due to all sources being not "available to the bus." c. A source becomes "available to the bus" after the bus undervoltage relays have tripped all bus breakers feeding motor services (e.g., a diesel generator becomes ready to accept the load). If several sources become "available to the bus" after the motor loads are shed due to bus undervoltage, the breaker for the diesel generator source is closed.

Figure 8.3-1 shows, as a typical example, the logic for all the source breakers available to 4160 Volt ESF Bus 142Y. This fi gure also identifies several functions and components of the system which are no t safety related. In particular, the manual and automatic (fast) closure of breaker ACB 1425 and the automatic (fast) closure of breaker ACB 1422 are non-safety-rel ated functions; their sole purpose is to maintain continuity of electrical service to the power production plant components during auxiliary power system disturbances. The operation of these non-safety-related functions will in no way affect the performance of the engineered safety features of the Unit Class 1E A-C Power System. In all cases, power will be supplied to the 4160 Volt ESF buses either through manual transfer to one of the

offsite sources, if available, or through automatic starting and loading of the diesel generators (as described later in the section).

LSCS-UFSAR 8.3-7 REV. 14, APRIL 2002 Typical interlocking and permissives for manual and automatic circuit breaker operations are shown on the figure s as designated in the following:

4160-V SWITCH GROUPS DG 1A ACB 1423 to BUS 142Y Fig. 8.3-1

BUS TIE ACB 1424-BUS 142Y to UNIT 2 BUS 242Y Fig. 8.3-1 SAT 142 ACB 1422 to BUS 142Y Fig. 8.3-1

BUS TIE ACB 1425-BUS 142Y to BUS 142X Fig. 8.3-1 DG 1B CONTROL (START/STOP)

Fig. 8.3-2 DG 1B ACB 1433 to BUS 143 Fig. 8.3-2

SAT 142 ACB 1432 to BUS 143 Fig. 8.3-2

480-V ESF BUSES BUS 135X LOAD SHED Fig. 8.3-4 BUS 135Y LOAD SHED Fig. 8.3-4 BUS 136X LOAD SHED Fig. 8.3-4

BUS 136Y LOAD SHED Fig. 8.3-4 BUS 143-1 ALARM Fig. 8.3-4 The power supply circuits are designed with fault protection devices to disconnect circuit faults from power sources; to disconnect the faulted component with minimum disturbance to the unfaulted portions of the system; and to secure the system from false disconnecting operations for any anticipated normal event.

Table 8.3-2 lists the 4160-volt circuit protec tive devices and their actions for various faults (Figures 8.3-1, 8.3-2, and 8.3-3). These figures and table apply to Unit 1 but are directly analogous for Unit 2.

LSCS-UFSAR 8.3-8 REV. 13 Equipment fed from 480-volt switchgear has instantaneous and time overcurrent protection that is applied in accordance with latest engineering design practice.

Each 480-volt bus is supplied with under voltage relays which shed appropriate loads on the buses when low voltage occurs (Figure 8.3-4). This figure applies to Unit 1 but is directly analogous to load shedding for Unit 2 480-volt ESF buses.

All MCC cubicles, except those with 120-Vac distribution equipment panels, are provided with manually-operated supply circuit breakers furnished with short circuit protection or combination starters. Each starter that is provided with an overload relay is also provided with an au xiliary relay to monitor the status of the overload relay contacts. This auxiliary relay is connected in the starter circuit so

that, in addition to monitoring the status of the overload relay contacts, it also directly monitors the status of the control transformer and control circuit fuse and indirectly monitors the supply circuit brea ker. As such, this auxiliary relay will detect the most frequent causes of starter control circuit non-operation.

The design of Class 1E motor-operated valv e thermal overload protection circuits is discussed in Subsection 6.3.2.2.13.

All incoming 480-volt feeders from the 480-vo lt buses are bolted solidly to the main buses of their respective motor control centers.

The standby a-c power system consists of five diesel-generator sets for both reactor/turbine-generator units. One of the diesel sets is shared between Unit 1 and Unit 2 (Figures 8.1-2 and 8.1-3).

Each ESF Division has a diesel generator that serves as an independent onsite power source in the unlikely event of the simultaneous occurrence of a total loss of offsite power and a loss of the unit auxiliary power system.

The diesel-generator sets have ample capacity to supply all power required for the safe shutdown of both units in the event of a total loss of offsite power. Ample capacity is provided for the condition in which one unit may be involved in a loss-of-coolant accident while the remaining unit is being shut down without loss of coolant, as well as for the condition in wh ich both units are concurrently being shut down without loss-of-coolant accidents.

The diesel generators are rated as indicate d in Table 8.3-3. The continuous ratings of the diesel generators are based on the maximum coincidental LOCA or shutdown load expected. The starting systems are described in Subsection 9.5.6.

Control power for each diesel generator is supplied from the 125-Vdc battery within its associated division. The 125-Vdc control power for diesel-generator "O" is LSCS-UFSAR 8.3-9 REV. 14, APRIL 2002 supplied from either Unit 1 Division 1 or Unit 2 Division 1 as determined by the position of an automatic transfer switch located in the diesel generator "O" control panel. The automatic transfer switch seeks Unit 1 Division 1.

In the event of loss of all normal sources of power (onsite and offsite) to the Class 1E power system, each diesel generator set is automatically started and loaded.

Controls and circuitry used to start and load the redundant units are independent of each other. The starting circuitry an d control power is provided by a 125-Vdc battery for each division load group. Th e diesel generator automatic starting and loading proceeds as follows:

a. Each diesel generator is automatically started by one of the following events (Figure 8.3-2):

1. Undervoltage develops on the associated 4-kV bus.

2. Low water level develops in the reactor vessel.

3. High pressure develops in the primary containment.

b. Should automatic fast source transfer fail to occur upon loss of voltage in the 4160-volt divisional buses, all 4-kV motor loads on the Division 1 and Division 2 buses are shed. Division 3 loads are not shed following a loss of bus voltage, since the total connected bus load is within the capacity of the diesel-generator set. c. After each diesel-generator se t has attained a normal frequency and voltage, its breaker closes if normal a-c power has been lost in the manner described above. This constitutes the automatic slow transfer scheme.

d. If normal a-c power is still present and the diesel generator was started by signals a.2 or a.3 preceding, the diesel-generator breaker does not close, and the set remains at full frequency and voltage until manually shut down. The diesel generators are not loaded for 15 minutes out of every 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months during accident standby operation. Diesel Engine maintenance and operation practices ensure they are capable of operating at less than full load for extended periods without degradation of performance or reliability.

LSCS-UFSAR 8.3-9a REV. 14, APRIL 2002

e. If normal a-c power is lost and signals a.2 and a.3 are not present, only the loads needed for safe shutdown are connected automatically or manually by the operator's action as station conditions require.

f. If, while operating as per item e, signal a.2 or a.3 appears, the Division 1 and Division 2 diesel- generator breakers are tripped LSCS-UFSAR 8.3-10 REV. 13 causing all 4-kV motor loads to be shed from these buses. The Division 1 and Division 2 diesel-g enerator breakers then reclose and the required Class 1E load s are started automatically.

Division 3 does not require load shedding and, therefore, upon appearance of signal a.2 or a.3 the diesel-generator breaker remains closed and the required Class 1E loads are started

automatically.

g. If, while the diesel generator is connected to the bus during routine periodic load testing, signal a.2 or a.3 appears, the Division 1 and Division 2 diesel-generator breakers are tripped. If normal a-c power is still pres ent the diesel-generator breakers do not reclose and the sets remain at full frequency and voltage

until manually shut down. If normal a-c power is coincidentally or subsequently lost, all 4-kV motor loads are shed, the diesel-generator breakers are reclosed and the required Class 1E loads are started automatically. Division 3 does not require load shedding and, therefore, upon appe arance of signal a.2 or a.3 the diesel-generator breaker remains closed and the required Class 1E loads are started automatically.

Electrical interlocks, consisting of mechanically actuated auxiliary breaker position switches, are provided to prevent an op erator from paralleling, through the unit ties, two standby diesel generators without an offsite source connected to one of the associated ESF buses.

Additional interlocks prevent automatic closure of a standby diesel-generator breaker to its associated 4160-volt bus (supplying ESF loads), unless the normal (#1 offsite) source, the unit tie (#2 offsite) source, the bus tie (#1 onsite) source breakers are all open, the lockout relays for the no rmal (#1 offsite) source breaker or the diesel itself have not tripped, and an undervoltage condition exists on the bus.

All control circuits and their components including the bus transfer system are provided with means for manual testing du ring normal station operation and meet IEEE 279-1971 criteria. Means are provided to permit connecting selected non-1E loads in the station to the diesel-generator set within its capability. However, this is a strictly manual operation under the operator's full control.

Each diesel generator can be started manually either by a control switch located on the main control board or by a control switch located on the separate local control panel of the diesel generator (NOTE: diesel generator "O" has a control switch on both U-1 MCB and U-2 MCB). Diesel generators 1B and 2B are each furnished with a two-position selector switch ("remote" and "local") located at the remote control station in the control room.

LSCS-UFSAR 8.3-11 REV. 14, APRIL 2002 The fuel oil system, air starting system, and generator output and excitation systems of each diesel engine are equipped with instrumentation to monitor all important parameters and to annunciate abnormal conditions.

Table 8.3-4 shows the protective and supervisory functions for each diesel generator. Instrumentation for diesel generator 1A is shown on Figure 8.3-5. The instrumentation for the other diesel generators is directly analogous.

The fuel oil storage and transfer system s are described in Subsection 9.5.4, lubrication systems in Subsection 9.5.7, and cooling systems in Subsection 9.5.5.

In addition to the periodic testing, each diesel generator undergoes a comprehensive functional test during refueling outages. This functional testing checks diesel starting, closure of the diesel breakers, and sequencing of loads on the diesel. During testing the diesel is started by a si gnal simulating a loss-of-coolant accident. In addition, an undervoltage condition is imposed to simulate a loss of offsite power. The timing sequence is checked to assure proper loading in the time required as indicated in Table 8.3-1. Periodic testing of the diesel and its various components plus a functional test at refueling intervals is used to demonstrate adequate reliability.

If a Division 1 or 2 diesel generator is automatically connected to its associated bus after the bus motor loads have been shed, the bus loads (if required) are sequentially started to keep the diesel-g enerator voltage and frequency above 75%

and 95% of nominal rating respectively.

The maximum sequence times between diesel-generator breaker closure and service breaker closures are shown on Table 8.3-1. Division 3 loads are not shed following a loss of bus voltage, nor are they sequenced following a restoration of bus voltage.

One and only one diesel generator may be operated at any one time in parallel with another source for the purpose of testing. The diesel generators are used only for emergencies and testing. They are not used for peaking during normal operation of the station.

8.3.1.1.3 Unit Reactor Protection System (RPS) Power System The reactor protection system is an electrical subsystem. It includes the motor-generator power supplies and distribution panels with associated control and indicating equipment, sensors, relays, bypass circuitry, and switches that cause rapid insertion of control rods (scram) to shut down the reactor. The reactor protection system is designed to meet the intent of the Institute of Electrical and Electronic Engineers (IEEE) Proposed Crit eria for Nuclear Power Plant Protection Systems (IEEE 279) (see Subsection 7.2.3.

2). The process computer system and LSCS-UFSAR 8.3-12 REV. 16, APRIL 2006 annunciators are not part of the reactor pr otection system. Although scram signals are received from the neutron-monitoring sy stem, this neutron monitoring system is treated as a separate nuclear safety system.

The nuclear safety functions provided by th e RPS system loads are actuated on loss of power (fail-safe); therefore, the system is not Class 1E.

The loads served by the system are (a) control power requiremen ts of the RPS, (b) nuclear steam supply shutoff system, (c) average power range monitor subsystem of the neutron-monitoring system, and (d) process radiation monitoring system.

Power to each of the two reactor protection trip systems is supplied, via a separate bus, by its own high inertia a-c motor-generator set. Each generator has a voltage regulator which is designed to respond to a step load change of 50% of rated load with an output voltage change of not greate r than 15%. High inertia is provided by a flywheel. The inertia is sufficient to maintain voltage and frequency within 5% of rated values for at least 1 second following a total loss of power to drive the motor.

The electrical protective assembly (EPA), consisting of Class 1E protective circuitry is installed between the RPS and each of the power sources. The EPA provides redundant protection to the RPS and other systems which receive power from the RPS buses by acting to disconnect the RPS from the power source circuits.

The EPA consists of a circuit breaker with a trip coil driven by logic circuitry. The logic circuitry which senses line voltage an d frequency and trips the circuit breaker open, within a preset time delay, on the conditions of overvoltage, undervoltage, and underfrequency. Provision is made for setpoint verification, calibration and adjustment under administrative control. After tripping, the circuit breaker must be reset manually. Trip setpoints are based on providing 120-Vac, 60 Hz power at the RPS logic cabinets. The protective circuit functional range is

+/-10% of nominal a-c voltage and -5% of nominal frequency.

If the RPS bus voltage or frequency remain s outside of the functional range for a period greater than the preset time delay, the EPA logic circuitry trips the circuit breaker. The EPA trip time delay is current ly set at a nominal value of 3 seconds.

Electrical Protective Assembly trip time delays of 0.1 to 4.0 seconds have been evaluated and found to have no adverse effect on loads powered from the RPS busses (Section 8.3.1.5, References 1 and 2).

The EPA trip setpoints are established in accordance with the following design limits: Over-voltage 132 Vac Under-voltage 108 Vac Under-frequency 57 Hz LSCS-UFSAR 8.3-13 REV. 13 The EPA assemblies are packaged in an enclosure designed to be wall mounted.

The enclosures are mounted on a Seismic Category I structure separately from the motor generator sets and separate from each other. Two EPAs are installed in series between each of the two RPS motor-generator sets and the RPS buses and between the auxiliary power source and the RPS buses. Six EPAs are normally installed in each plant. The block diagram in Figure 7.2-8 provides an overview of the six EPA units and their connections between the power sources and the RPS buses. The EPA is designed as a Class 1E electrical component to meet the qualification requirements of IEEE 323-1974 and IEEE 344-1975. It is designed and fabricated to meet the quality assurance requirements of 10 CFR 50, Appendix B.

The enclosures containing the EPA assemb lies are located in an area where the ambient temperature is between 40° F and 122° F. The ci rcuits within the enclosure are qualified to operate under acci dent conditions from 40° F to 137° F, at 10% to 95% relative humidity and survive a total integrated radiation dose of 2 x 10 5 rads. The assemblies are seismically qualified per IEEE 344-1975, to the safe shutdown earthquake (SSE) and operating base earthquake acceleration response spectra and environmentally qualified to the requirement of IEEE 323-1974. The enclosure dimensions are approximately 16 x 20 x 8 inches and accommodate power cable sizes from 6 AWG to 250 MCM.

Alternate power is available to either reactor protection system bus from a transformer connected to a bus fed from the standby electrical power system. An interlock prevents feeding both reactor protection system buses simultaneously from this transformer. Additional interlocks prevent paralleling a motor-generator set with the alternate supply. The backup scram valve solenoids receive d-c power from the 125-volt battery system.

Each MG set normally feeds one bus of the distribution panel. Manual transfer of one bus to the regulated transformer source is possible to permit servicing and maintenance of the MG set.

8.3.1.1.4 Instrument Power System The objective of the instrument power supply and distribution system is to provide a reliable source of 120-Vac or 24-Vdc power to the instrument and computer systems. The 24-Vdc portion of the system is also presented here for completeness.

The 24-Vdc system is designed to provide power to the neutron-monitoring systems and process radiation monitors and has complete redundancy for each unit.

LSCS-UFSAR 8.3-14 REV. 14, APRIL 2002 24-Vdc System The system consists of two duplicate 24-volt, three-wire, grounded-neutral subsystems (Figure 8.3-6). This figure app lies to Unit 1 but is directly analogous to the Unit 2 system. Each subsystem consists of two 24-volt batteries in series, center grounded at the control room, and connected to a d-c distribution panel. There are two 24-volt battery chargers for ea ch subsystem. Each one is separately connected to a 24-volt battery. Power supplies for the battery chargers are from buses having a backup supply from the stan dby diesel-generator system. Each 24-Vdc subsystem is equipped with und ervoltage and overvoltage alarms.

120-Vac Systems

The 120-Vac continuous power supply is desi gned to supply continuous power to the station computer and to those instrument systems which must remain in operation during a momentary loss of a-c power. It also provides a reliable source of power to these instrument systems which are not vital to plant operation and safety.

The 120-Vac continuous power supply (inverte r) provides a reliable source of power which satisfies the voltage and frequency- variation limits of the station computer.

Reliability is enhanced by the ability to transfer automatically from the normal 480-Vac source to the alternate 250-Vdc source with automatic return to the a-c source when power is restored. The 120-Vac continuous power supply is provided with a backup transformer capable of being fed from the standby diesel-generator system so that the inverter can be deenergized periodically for maintenance purposes.

The 120-Vac nonvital instrument power system consists of a series of distribution

panels, each of which has a source of power from one 3-phase 480/120-208-Vac transformer. The feed from each transformer terminates in a distribution panel located in the 480-volt motor control ce nter which supplies the transformer.

The 120-/208-volt instrument power supply and distribution load centers are fed from 480-volt breakers located in motor control centers. Load centers serving engineered safety feature Class 1E instru mentation and indication loads and other essential loads are Class 1E and are fed from Class 1E power system motor control centers. 8.3.1.2 Analysis The following analysis demonstrates compli ance with NRC General Design Criteria 17 and 18 and IEEE Standard 308.

Each unit of the station has available to it three separate diesel-driven power sources to provide electric power to three independent and redundant trains of LSCS-UFSAR 8.3-15 REV. 13 engineered safety features. Each unit also has separate battery power sources to provide power to the separate and redundant vital d-c loads.

The offsite electric power system connections to the station are designed to provide a diversity of reliable power sources which are physically and electrically isolated so that any single failure can affect only on e source of supply and will not propagate to alternate sources (Section 8.2).

The station's auxiliary electric power system is designed to provide electrical isolation and physical separation of the redundant power supplies for station requirements which are important to nuclear safety. Means are provided for rapid location and isolation of system faults. Each separate power source, diesel-generator and offsite, is physically and electrically independent up to the point of connection to the ESF power buses. Redundant loads important to plant safety are split between the ESF switchge ar groups (Figure 8.1-3). The ESF electrical systems are designed in accordance with IEEE Standards 279-1971 and 308-1971.

Provisions have been made in the design of offsite and onsite power systems for the inspection and testing of appropriate parts of the systems. Periodic tests can be made of major portions of the power system s under conditions simulating the design conditions.

The ESF equipment are tested to provide assurance that the systems operate as designed and are available to function properly in the unlikely event of an accident.

The Class 1E power systems important to safety also meet the testability requirements of General Design Criterion 18.

Functional testing of ESF electrical auxiliary power equipment is done periodically.

Whenever one of the components of an ESF system requires maintenance, the necessary correction is made, the component is retested, and the main channel or subsystem of which the faulty component was a part is retested to confirm that the channel or subsystem has been restored to serviceable condition following the maintenance.

Prototype qualification of one diesel generator, consisting of 300 valid start and sequential load tests with no more than three failures, is performed to demonstrate type reliability. In addition, a start test, a load test, a voltage stability and transient response test, and a test of the safety trips and alarms are conducted on each of the three non-GE-furnished diesel generators by the vendor.

Subsequent to site installation, preoperat ional testing was conducted on all diesel generators to demonstrate performance reliability. The tests consist of:

a. starting LSCS-UFSAR 8.3-16 REV. 17, APRIL 2008

b. load acceptance

c. design load

d. load rejection, and

e. diesel generator electric and subsystem capability.

Data acquired from preoperational testing were used to provide a basis for taking any corrective action needed and to develop an in-service periodic test program that will maintain high diesel generator reliability.

To ensure the operational readiness of each diesel generator, tests and inspections are conducted periodically. Each diesel generator is started and loaded for a period of time long enough to bring all the components of the diesel-generator system into thermal equilibrium. Should one of th e components require maintenance, the necessary corrections are made and the component retested. The operational readiness test is then continued to completion.

The station batteries and other equipment associated with the d-c system are serviced and tested periodically. Typica l battery tests are specific gravity and voltage of the pilot cell, temperature of the pilot cell, battery float current and overall battery voltage. Periodically, ea ch battery is subjected to a rated load discharge test.

All electric system components supplying power to Class 1E electric equipment are designed to meet their functional requirements under the conditions produced by the design-basis events. All redundant equipment is physically separated to maintain independence and to minimize the possibility of common-mode failure. All Class 1E equipment is located in Seismic Category I structures.

The standby a-c power system provides a self-contained source of electrical power which is not dependent on auxiliary transformer sources of supply and which is capable of supplying sufficient power for th ose electrical loads which are required for the simultaneous safe shutdown of both units, including the load in one unit, which is required to combat a loss-of-coolant accident. The standby a-c power system produces a-c power at a voltage and frequency compatible with normal bus requirements. The standby diesel generato rs are applied to the various plant buses so that the loss of any one of the diesel generators will not prevent the safe shutdown of either unit. The total system satisfies single-failure criteria.

In the event that both sources of auxiliary power (system and unit auxiliary transformers) are lost for either one or both units, the auxiliaries essential to safe shutdown will be supplied by the corresp onding diesel-driven generators. One LSCS-UFSAR 8.3-16a REV. 17, APRIL 2008 diesel generator is permanently assigned to each of the three engineered safety features electrical system 4160-volt buses for each unit.

LSCS-UFSAR 8.3-17 REV. 13 Each diesel-generator system is housed in a separate room which is provided with an independent source of ventilation air. The design of the rooms prevents the possibility that missiles, explosion, and fire from one diesel generator might affect its redundant counterpart.

Each diesel-generator is designed and installed to provide a reliable source of redundant onsite-generated auxiliary powe

r. It is capable of supplying the engineered safety features loads assign ed to the engineered safety features electrical system bus which it feeds.

Each diesel generator and its associated auxiliaries are designed to meet the station Seismic Category I design criteria.

The diesel generators are so applied to their respective buses that the loss of one diesel generator cannot affect both of an y two redundant buses. Therefore, safe shutdown capability will not be affe cted by such a diesel failure.

Criteria for Class 1E systems do not apply to the RPS power cables. The system is fail-safe and its power supplies are not necessary for scram. A total loss of power will cause a scram. Loss of one power source will cause a system trip.

8.3.1.3 Physical Identification of Safety-Related Equipment 8.3.1.3.1 General Two methods of identification, color code an d segregation code, are generally used to distinguish between Class 1E and non-Class 1E components, and between components of different divisions. Class 1E equipment is uniquely identified by color coding of all components according to the division to which they are assigned, as shown in Table 8.3-6. Segregation coding assignment is indicated in Table 8.3-5.

8.3.1.3.2 Raceway Identification

Each cable tray routing point is assigned a colored alphanumeric code shown on Table 8.3-6, which is applied to the side s of the cable tray at locations on the installation drawings. This identification number reflects the segregation code of the tray section and the unit of the station in which the tray is installed. A cable can only be routed and installed in a tray with the appropriate segregation code as specified in Table 8.3-5.

Exposed conduits are identified using the codes shown on Table 8.3-6 at the beginning and the end of the run, on both sides of a wall through which the conduit passes, and at both sides of junction boxes.

LSCS-UFSAR 8.3-18 REV. 13 8.3.1.3.3 Cable Identification Each cable listed in the cable tabulation is assigned a number for identification purposes. The number denotes the system to which the cable is assigned and the unit of the station to which the cable is assigned. This cable number appears on the electrical installation drawings and the wi ring diagrams on which the terminations of the cable are shown. A cable identification tag made of a permanent material and displaying the assigned cable number and segregation code is affixed to each end of the cable. These tags also are co lored to identify the applicable segregation code. Unit 1 and Unit 2 cables are identified as such by their assigned segregation codes. The segregation code and tag color are determined from Table 8.3-6.

8.3.1.4 Physical Independence of Redundant Systems This subsection presents: (a) the criteria used to design and evaluate the physical independence of all station Class 1E components, including Class 1E control and instrumentation components as noted in Subsection 8.1.3; (b) the control procedures used to assure design and installation compliance with these criteria; and (c) the general arrangement of station Class 1E components.

8.3.1.4.1 General Criteria The simultaneous occurrence of: (a) a single failure, (b) a loss of all offsite power, and (c) a design-basis event cannot disable any nuclear safety function.

Each Class 1E component is assigned to an ESF division.

Class 1E components with redundant safety functions are assigned to separate divisions unless specifically noted otherwise (IEEE 308/5.2.1, 5.

3.1; IEEE 279/4.6). Assignments are made in acco rdance with Table 8.3-1.

Non-Class 1E non-division-associated components are electrically isolated from the Class 1E system by an acceptable isolation device.

8.3.1.4.2 Physical Separation Criteria Class 1E components of an ESF division are physically separated from the Class 1E components of any other ESF division. Cl ass 1E components are also physically separated from non-Class 1E or non-Seis mic Category I, high-energy components that could cause loss of redundancy as th e result of a design-basis event effecting failure of these components.

A test (of the most limiting separation configuration) was performed to demonstrate that faults induced in non-safety-related cable will not cause the failure of adjacent safety-related cables. Wyle Test Report No. 46511-3,"Test Report on Verification Te sting of Separation Between Class 1E and Non-class IE Power Cables in Race ways" was submitted by CECO to NRC by LSCS-UFSAR 8.3-19 REV. 13 letter dated May 3, 1983. Based on this report, the NRC staff have concluded that LaSalle separation configuration (depicted in the report) meets the objectives of IEEE Standard 384-1974 as augmented by Re gulatory Guide 1.75 for separation of instrumentation, control and power cables; and the independance requirement of criterion 17 of Appendix A to 10 CFR 50.

Raceway Assignments The design and installation of cable trays/conduit for power and control cables provides three separate, redundant paths (divisions) for the installation of engineered safety feature (ESF) cables both in and between the reactor building, auxiliary building, turbine building, and th e diesel-generator rooms. This cable tray scheme satisfies the criterion set fort h in Subsection 8.3.1.4.2.1 by meeting the following requirements:

a. All cable trays (power, control and instrumentation) in the reactor building and those containing cables between the reactor building and the auxiliary building, except those trays which must meet the requirements in Su bsection 8.3.1.4.2.2 for reactor protection system cables, are as signed to one of the three ESF divisions. Since Division 3 contains only cables related to the HPCS system, it has considerabl y fewer cable trays than the other two divisions. Theref ore, the reactor building and auxiliary building areas containing ESF cable trays are essentially divided into Division 1 and Division 2 areas.

b. All cable trays in the turbine building and those containing cables between the turbine building and the auxiliary building are designated as non-safety- related (NSR) trays and are not utilized for any RPS or ESF cables in this area. Those few RPS and ESF cables required in the turbine building are separately installed in conduit.

c. Cables associated with the ESF equipment are routed only in cable trays assigned to their respective divisions. A cable associated with the ESF equipment of one division has no

portion of its run in any cable tray assigned to another division.

d. NSR cables in the reactor building can be installed in ESF trays. However, once committed to a tr ay of one division, that cable cannot be run in any trays of the other divisions, nor is it permitted to cross from an ESF to an NSR tray. Likewise, NSR cables in turbine building NSR trays are not permitted to cross

into ESF trays from the reactor building. Subsection 8.3.1.3 describes the segregation codes which have been established to LSCS-UFSAR 8.3-20 REV. 13 ensure compliance with this re quirement (Table 8.3-6). Reactor building auxiliaries which are not safety related, but which share power supplies with safety-related equipment, can have their cables installed only in ESF trays assigned to the same division as the power supply. For example, a reactor building closed cooling water pump motor fed from a 480-volt substation which is connected to 4-kV Bus 141Y (ESF Division 1) has its cables installed only in ESF Division 1 trays.

e. Cables associated with ESF systems whose sole function is to transmit indication and/or alarm signals are not designated as ESF cables. However, the location of their terminations and the design of the cable tray system re sult in their placement in trays assigned to the divisions of their respective systems.

8.3.1.4.2.1 Raceway Separation Criteria Division Raceways A raceway that carries a division cable is a division tray or conduit. Each division tray or conduit is restrictively assigned to a single division.

In Protected Zones In areas having a low probability of being subject to damage from missiles and/or conflagration, cable trays and conduit of different ESF divisions are separated by a minimum horizontal distance of 3 feet side of tray to side of tray. Where a 3-foot separation between such cable trays is im practicable, exceptions are noted, and a barrier of 1-inch transite and a 6-inch total air space are provided to inhibit tray-to-tray fires. Vertical stacking is avoided for runs longer than 10 feet for trays or conduit assigned to different engineered safeguards divisions,but where this is impractical, a minimum vertical separation of 5 feet is maintained between the top of the lower tray or conduit and the bottom of the upper tray or conduit. In such cases the lower tray has a solid metal cover, which is raised if power cables are contained in the tray.

Cable trays and conduit of different engineered safeguards divisions may cross each other with a minimum vertical separation of 12 inches (metal to metal, not including the cover or the tray support).

A crossing is defined as the intersection of two paths of cable trays or conduit in which the acute angle between the centerlines of the converging paths is 45° or greater. In this case, where two cable trays cross, the lower tray must have a solid metal cover extending 5 feet on each side of the centerlines of the intersection. This cover must be raised if the lower tray carries power cables.

LSCS-UFSAR 8.3-21 REV. 13 The clearance between the top of the lower cover and the bottom of the upper tray must be 8 inches or more.

The separation requirements for cable trays located in the cable spreading room are identified in UFSAR Section 7.1.3.4.3.d.

In Hazard Zones Cable trays or conduit for only one ESF division are allowed in areas where they may be subjected to damage from large missiles or conflagration. A minimum tray separation of 20 feet or a 6-inch reinforced concrete wall must intervene between cable trays or conduit of redundant ESF divisions if they occupy such areas. The following LSCS areas are defined as hazard zones because of potential damage from large missiles or conflagration per the intent of this criterion:

Missiles Fire (Conflagration)

Turbine Building Main Floor Oil Storage Room

Reactor Feed Pump Turbines Turbine Oil Tanks Reactor Building Operating Floor Inside turbine shield walls beneath main floor Diesel Fuel Oil Storage

Generator Hydrogen System

In General Plant Zones Open trays assigned to different divisions are separated by at least (a) 3 feet of horizontal free air space, (b) 5 feet of vertic al free air space, or (c) a fire-resistant barrier with dimensions sufficient to maintain the minimum free air spacing of (a) and (b). This spacing applies to open trays.

If the horizontal or vertical spacings are not possible, the limitations outlined in preceding paragraph "In Protected Zones" will apply.

8.3.1.4.2.2 Cable Routing Criteria

Electrical cable routing in LSCS is in accordance with the design criteria enumerated in the following. These criteria fulfill the following objectives:

LSCS-UFSAR 8.3-22 REV. 13

a. to preserve the independence of redundant reactor protection system trip channels (subchannels), reactor vessel and primary containment isolation valves, emergency core cooling systems, and Class 1E electrical systems;

b. to prevent possible adverse influence of a non- safety-related cable on more than one of several redundant cables associated with any nuclear safety feature;

c. to reduce the noise level on instrument signal cables to a level suitable for reliable operation of instrument systems;

d. to withstand the environmental conditions in plant areas through which cables must pass without functional impairment; and e. to retain a thermal margin (bel ow design rating) over the heat generated in cable trays by current-carrying conductors.

Each safety-related cable is as signed to a Division 1, 2, or 3, according to Table 8.3-

1. Each non-safety-related cable which has any part of its length in a Division 1, 2, or 3 tray, or which connects to a Class 1E power system, or which shares an enclosure with a Class 1E circuit, or which is not physically separated from safety-related cables by acceptable distance or barriers is defined as a "division-associated cable."

A division-associated cable is given a cabl e code of 11, 12, or 13 (see Tables 8.3-5 and 8.3-6). All division, division-associated and non-safety-related cables routed in their respective cable trays or that may interact with division, or division associated cables are fully qualified to th e requirements of IEEE-383-1974.

Not all cables are qualified to IEEE-383-1974.

Non-qualified cables do not have any impact on safety related cables. For exam ple, non-safety related cables that are routed in enclosed raceways that are dedicated exclusively for their use, have limited free air routing, have no interaction with plant general safety related or division associated cables, and present an acceptable fire hazards/combustible loading risk may not be qualified to IEEE-383-1974.

For example, lighting and communication circuit cables installed in dedicated lighting and communication conduits need not be qualified to the requirements of IEEE-383-1974 (i.e., they are not safety re lated, are not installed in divisional, divisional-associated or non-safety-related raceways, do not interact with other plant cables and are acceptable fire hazard/combustible loading risk).

LSCS-UFSAR 8.3-23 REV. 13 Each non-safety-related cable which is no t a division-associated cable is given a cable code of W (Tables 8.3-5 and 8.3-6).

Division cables and division-associated cables are routed only in trays dedicated to that division.

Reactor Protection System (RPS) Cables Separation of reactor protection system cables is in accordance with NSSS specifications which require that the re actor protection system logic cables conveying digital inputs from pressure, leve l, and valve limit switches to the scram contactors be divided into four groups of cables, each group being associated with one of the four trip system subchannels, A1, A2, B1, or B2. Each of these groups is routed in its own conduit, with groups A1 and B1 separated from their redundant counterparts A2 and B2 by a minimum distance of 3 feet horizontally and 5 feet vertically in areas where damage from fire is determined to be the most serious potential hazard. The conduits containing cables of groups A1 and B1 (as well as those containing A2 and B2 cables) need not be separated from each other by minimum physical distances, since these cables are not redundant.

Reactor protection system cables from the input sensors to the scram contactors are not routed in areas where a potential missile hazard could affect the redundant input circuits.

Cables containing bypass switch circuits and cables associated with manual scram circuits from the reactor control panel to each of the input subchannels A1, A2, B1, and B2 are routed in accordance with the requirements of this subsection.

The majority of the RPS low-level inputs are in the 172 LPRM cables from the power range neutron-monitoring (PRM) detectors to the PRM monitor cabinet in the control room. These cables in the neutron-monitoring system are treated differently from the above requirements for digital inputs because some but not all of them are averaged into 6 APRM outputs, two of which are then subdivided to provide 8 inputs to the reactor protection system, two to each subchannel. Therefore, the following special requirements apply:

a. LPRM cables beneath the reactor vessel and inside the support pedestal are neither grouped nor separated, because this location is a distribution area fo r these cables to their respective detectors, and because this location provides an adequate degree of protection from external elements during plant operating and shutdown periods.

b. LPRM cables are grouped at the inner end of the pedestal penetrations through which they pass and routed inside the LSCS-UFSAR 8.3-24 REV. 13 containment in four separate conduits and/or cable trays to their respective containment electrical penetrations. The makeup of each of these groups of LPRM cables is such that the loss of a single group cannot prevent a high neutron flux scram.

c. The four groupings of LPRM cables are maintained through the containment electrical penetrat ion and are installed in four separate cable trays and/or conduit which carries them to the power range monitoring cabinet in the control room where the LPRM signals are averaged to form APRM's.

d. LPRM cables whose signals are not averaged may be routed in the same trays/conduit with the LPRM cables that provide inputs to the APRM's and hence to the reactor protection system. e. These four groups of LPRM inpu ts are designated as groups NA, NB, NC, and ND. From the point where these cables are divided just inside the reactor support pedestal to their termination in the PRM cabinet, the trays and conduit containing each group are separated from each other by a minimum distance of three feet horizontally and five feet vertically unless analysis shows that more separation is required because of a potential missile hazard inside the primary containment. Outside the containment, the same restriction cited in the preceding discussion on routing cables through potential missile-hazardous areas applies.

f. The cables connecting the APRM digital trip outputs to the RPS trip channels are routed in accordance with the requirements of the preceding discussion.

The remaining low-level RPS inputs are the SRM and IRM inputs from the incore detectors to the startup range monitor cabinet, and the main steamline high radiation inputs from the detectors in the reactor building to the control room monitor cabinet. Although these inputs can be grouped similar to the digital inputs and need meet only the preceding requirements for separation of RPS digital inputs, for ease in routing they are grouped with and meet the more stringent requirements outlined above for LPRM inputs. Digital trip outputs from the SRM, IRM, and the steamline radiation monitors are routed in accordance with the requirements in the preceding discussion.

Cables from the scram contactors to the scram pilot valve solenoids are also separated into four divisions. Each of these divisions of cables is associated with the A and B solenoids of one of the four groups of control rods, G1 through G4, LSCS-UFSAR 8.3-25 REV. 13 regardless of the side of the reactor vessel on which the hydraulic unit is located.

Cables of more than one of the four divisions were not installed in the same cable tray or conduit. These cable division s are designated as G1, G2, G3, and G4.

Cables for the A and B solenoids of each HCU are run in the same conduit. Because the deenergization of both solenoids is requ ired to scram each rod, the exposure of these cables to external hazardous events is reduced.

Since the HCU's are almost equally di vided on both sides of the reactor containment, cables for each group of solenoid pilots must be divided as they leave the control room relay panel and then separately routed to their respective sides of the reactor. To further reduce the exposure of these cables to unspecified hazardous events, the G1 and G4 cables on each side are routed separately from the G2 and G3 cables between the control room relay panels and the local termination cabinets at the HCU's. Scram solenoid cables (G1 th rough G4) from these termination cabinets to the individual HCU's are routed in four separate conduits to each assemblage of HCU's. Power cables for the reactor protection MG set power supplies to channels A and B are treated as non-safety-related cables and are routed in cable trays provided for those cables. Cables for one RPS MG set are not installed in the same trays/conduit as those for the other redundant MG set. This requirement applies: (a) to the feeder cables for the MG set motors, (b) to the cables from the generators to the distribution panels, and (c) to the MG set control cables. Minimum distances between conduits/cable trays for reactor protection syst em MG set cables are not stipulated because this system is designed to be "fail-safe", that is, loss or malfunction of these cables and components initiates rather than prevents a reactor scram. Cables from the RPS distribution panels to the trip channels A and B are installed in accordance with the requir ements of the preceding discussion on separation of RPS digital inputs.

Primary Containment Isolation Valve The primary containment isolation valve subsystems consist of the nuclear steam supply shutoff system (NSSS) and the primary containment isolation system (PCIS). The NSSS subsystem includes thos e valves on pipes which penetrate the primary containment and which connect to the reactor primary boundary. The PCIS subsytem includes those valves on pipes which penetrate the primary containment and are either open to the drywell or connect to closed piping systems other than the primary reactor boundary.

These valves are divided into two categories, inboard and outboard. Where two power-operated valves are furnished for isolation of a single pipeline with at least one of the valves located inside the pr imary containment, the valve inside the containment is the inboard valve. Where two power-operated isolation valves are LSCS-UFSAR 8.3-26 REV. 13 furnished, both outside the containment, th e valve closer to the pipe penetration is the inboard valve. Where only one power-operated isolation valve is installed, it is assigned to either the inboard or outboard category, whichever is more suitable to its physical location.

The design of the input circuits, sometimes known as the incident detection circuitry, which automatically actuate the NSSS is such that it lends itself more toward the separation criteria established for the reactor protection system than for those associated with ESF. This circuitry is a logic arrangement with ESF. This circuitry is a logic arrangement with two trip systems, both of which must trip to initiate the isolation functions. Each of these trip systems has two trip logics, each of which receives an input signal from an independent sensor for each monitored variable. The design principle is therefore identical to that for the reactor protection system logic circuitry, which is commonly referred to as the "one-out-of-two taken twice" arrangement. In fact, many of the sensors and relays which actuate isolation valve logic channels also actuate the reactor protection system.

In order to ensure that no single credi ble event can prevent the reactor isolation valve system logic circuitry from performing the functions for which it is designed, the four trip logics are separated in accordance with the criteria established for the separation of reactor protection system digital inputs. The cables associated with the sensors, relays, and other components whose functions are shared between the NSSS/PCIS and the reactor protection system are routed with and identified as reactor protection system (RPS) cables.

Those cables associated only with the NSSS/PCIS input circuitry are routed and identified as ESF cables.

The cables associated with the outputs from the NSSS/PCIS logic circuitry which automatically close isolation valves are separated in accordance with the provisions for ESF systems cables. All such cables for outboard valves are assigned to ESF Division 1. Cables for inboard isolation valves are assigned to ESF Division 2.

Those valve cables associated with the manual control of isolation valves (between the control room switches and the relay panels or motor control centers) are also separated in accordance with the provisions for ESF cables. Likewise, cables between local pushbutton and motor control centers for local manual operation of NSSS/PCIS valves are similarly treated.

The cables between NSSS/PCIS valves and their motive power supplies are also separated in accordance with the provisions for cables for the ESF systems. Power cables for outboard valves are assigned to ESF Division 1 and those for inboard valves to ESF Division 2.

The thermocouple cables and associated circuitry for the Main Steam Tunnel Leak Detection Delta T MSIV isolation are assigned to divisions in a way to prevent spurious unit trips due to a loss of division power. This assignment results in LSCS-UFSAR 8.3-27 REV. 13 functionally redundant components assigned to the same division. However, the circuits are designed such that a credible single failure, a loss of all offsite power and a main steam line leak will not prevent the MSIV isolation. The credible single failures considered include short circuits (including hot shorts), missiles, and the effect of the steam leak on the conduit in cluding physical damage to the conduit and the temperature effect on the cable. The circuit is designed to detect a limited range of small main steam leaks within the Main Steam Tunnel.

8.3.1.4.2.3 Panel Criteria In Protected Zones ESF systems cables entering control room and auxiliary equipment room panels from the protected cable-spreading areas directly beneath these rooms must meet the following separation requirements, whic h modify those contained in Subsection 8.3.1.4.2.2:

a. Control room and auxiliary equipment room panels are generally designed and located so that cables for redundant ESF systems entering panel sections are separated by a minimum distance of 3 feet horizontally, in which case the criteria of Subsection 8.3.1.4.2.2 apply.

b. In those few situations where a minimum separation of three feet horizontally between cables of redundant divisions cannot be attained, the cables of one of the redundant divisions are installed in conduit from a point inside the panel where the fire barrier between divisions is effective to that point where a minimum separation of th ree feet is attained.

c. Non-safety cables routed with cables of one of the redundant ESF divisions are treated as engineered safeguards cables where they enter panels containing engineered safeguards components and thus meet the above criteria in these areas.

In Hazard Zones Class 1E panels are not located in hazard zones where the hazard(s) originate(s) from Class 1E or Seismic Category I equipment of or asssociated with another division.

In General Plant Zones Panels do not contain more than one division. Panels of different divisions are separated as required for enclosed raceways.

LSCS-UFSAR 8.3-28 REV. 13 8.3.1.4.2.4 Containment Electrical Penetration Criteria The electrical characteristics of all cables which enter the containment and their required separation distances are maintained through the electrical penetrations in the containment boundary. Containment electrical penetrations are installed in separate locations to ensure that the se gregation and separation requirements of the succeeding sections of these design criteria can be met.

The required physical separation for penetrations serving Class 1E circuits is the same as that required for covered trays.

Penetrations are assigned to equipment according to Table 8.3-1.

The electrical penetrations through the containment boundary are arranged in four quadrant groups on two levels as shown in Figures 8.3-7 and 8.3-8.

The cables for ESF Division 1 equipment are routed through penetrations on the two north quadrants, and the cables fo r ESF Division 2 equipment are routed through penetrations on the two south quadrants.

8.3.1.4.3 Cable Tray Criteria All trays in Seismic Category I structures are Seismic Category I. The nuclear safety function of Division 1, 2, and 3 trays in Seismic Category I structures is to carry Class 1E cables without damage or functional degradation during a safe shutdown earthquake. The nuclear safety f unction of non-Class 1E trays in Seismic Category I structures is to preclude trays from becoming missiles during a safe shutdown earthquake.

Cable trays are made of galvanized steel wi th solid bottoms and sides. Ladder type trays of the same material ar e also used at switchgear motor centers and in certain locations where cable routing changes from one tray to another of the same category in the same tier. Solid covers are installe d on each top tray for all horizontal tray runs under gratings and stairways and in open areas where cable damage from falling objects or collections of dirt and debris is likely. Cable trays for instrument cables with low-level signals have solid bo ttom sections as well as solid covers to provide adequate electromagnetic shielding. All cable trays are a maximum of 30 inches wide. Power cable trays are 4 inches deep. Control and instrument cable trays are 6 inches deep.

Solid covers are provided for all instrument ation cable trays. Solid covers are also provided where required to meet physical separation requirements.

LSCS-UFSAR 8.3-29 REV. 13 Unless otherwise limited, the minimum vertical distance between stacked trays of the same division or between stacked trays of a non-safety-related system is 1 foot from the bottom of the upper tray to the top rail of the lower tray.

Administrative responsibility and control are provided to assure that the installation of electrical Class 1E equipment is in accordance with the design

criteria.

8.3.1.4.4 Cable Criteria Cables are designed for a plant life of 40 years under the following conditions:

a. Instrumentation, Control and Low Voltage Power Normal operating and accident environments as presented in Section 3.11.

b. Medium Voltage Power (5- and 8-kV)

Similar to Section 3.11 except:

0-6 hours 212° F, 7 in. H 2 O gauge, all steam 6-12 hours 150° F, 7 in. H 2 O gauge, 100% relative humidity 12-hours- 150° F, 0 in. H 2 O 100 days gauge, 90% relative humidity.

Cable installation types installed at LSCS are listed in Table 8.3-10. Where possible, cables are not routed throug h a normally or potentially adverse environmental area if neither end of the cable terminates in that area.

Except for those cables required for lightin g, heating, and ventilation, power cables are not routed into and through the control room, the computer room, the auxiliary equipment room, or the cable-spreading room beneath the control room. Power cables for heating, lighting, and ventilation in these areas are installed in conduit.

Class 1E cables must perform their safety functions during the worst-case design-basis event environment (usually LOCA), following 40 years of the worst-case normal environment.

The normal and LOCA environments for stat ion areas are given in Section 3.11.

The locations of Class 1E loads are given in Tables 8.1-4 through 8.1-10.

LSCS-UFSAR 8.3-30 REV. 13 Power cables are installed in a separate tray system and are not intermixed with any other cable types. Power cables instal led in stacked trays are, where practical, located in the highest-level tray. Power cables of different voltage ratings are installed in the same cable trays and/or conduit.

Control cables are not separated by voltage levels, since all control cables are insulated for 600 volts.

Control cables are run in a tray system separate from power and instrumentation cables. Instrument cables of different voltage rati ngs are installed in the same trays and/or conduit provided their signals do not interfere with each other.

Instrumentation cables are installed in separate conduit or in separate nonventilated solid trays with covers to provide electromagnetic shielding. In general, instrumentation trays will occupy the lowest level of a stack of cable trays.

8.3.1.4.5 Control Proc edures - Independence Procedures have been established to implement design and construction compliance with the foregoing physical independence criteria.

The design procedures include those which (1) assure adequate physical separation between redundant Class 1E components, and (2) assure the proper assignment of cables to raceways.

In the station electrical physical design, areas of the plant are identified on electrical layout drawings as being either potentially hazardous ("hazard"), "protected", or "general" plant zones.

The segregation codes for raceways and the electrical equipment division assignments also are identified on electrical layout drawings.

The station electrical physical design is re viewed periodically to determine (1) if the area zone classification should be changed because of the introduction or removal of a potential hazard, and (2) if the equipment and raceway locations in the zones are separated to the extent required by the detailed physical independence criteria.

The primary design document showing cable routing is the cable tabulation. In

addition to routing information, the cable tabulation contains the following information for each cable:

a. Cable identification number.

b. Cable service.

LSCS-UFSAR 8.3-31 REV. 13

c. Segregation code - an alphanumeric code to designate segregation where applicable.

d. Routing - an identifying number denoting a specific point in the cable tray installation through which the cable is routed.

The data contained in the cable tabulation as well as the raceway identification numbers are contained in a computer program. The program checks the cable routing for compliance as shown in Table 8.3-5 (cable tray segregation), and Table 8.3-6 (cable segregation).

Reactor protection system cables are assigned a three-character code. The RPS cable codes do not reflect the unit of the station, since all RPS cables are installed in a conduit system which is not interco nnected between units. The first two characters of the RPS codes reflect the applicable segregation division, and the third character denotes the type of c able (P, C, or K) (Table 8.3-6).

There are six safety-related systems which have special separation requirements. Two of them, the reactor core isolation cooling (RCIC) system and the standby liquid control (SLC) system, are not ESF systems. But, because of system requirements, their interconnecting cables are separated and routed with ESF cables. The RCIC system cables are separated from the high- pressure core spray (HPCS) system cables (Division 3) by routing them with ESF Division 1 cables. The standby liquid control system cannot be vuln erable to a single electrical failure, so its redundant cables are routed with ESF Divisions 1 and 2.

Three additional systems with special separation requirements are the standby gas treatment (SBGT) system, the control room HVAC system and the auxiliary electric equipment room HVAC system, all of which are ESF systems. Redundant components and power supplies for these systems are, however, located in each of the two units. To ensure that the c ables for these redundant subsystems are separated and that each subsystem is fed from separate offsite and onsite power supplies, the redundant subsystem cables are routed with ESF Division 2 of Unit 1 and ESF Division 2 of Unit 2, respectively. Interconnections between the two subsystems are routed in conduit in the opposite unit and separated in accordance with the requirements of Su bsection 8.3.1.4.2. The pr ovisions of the following paragraphs ensure that redundant cables are not routed in the same cable tray or trays in close proximity.

A pull card for each cable pulled is signed by a contractor's representative as verification that the cable actually was pulled over the route specified in the cable tabulation.

LSCS-UFSAR 8.3-32 REV. 14, APRIL 2002 Unit 1 cables are routed only in Unit 1 cable trays and are not permitted in Unit 2 trays. Likewise, Unit 2 cables are routed only in Unit 2 trays and are not permitted in Unit 1 trays.

Visual inspections of the cable and raceway color codes are used to verify that proper separation of redundant Cla ss 1E cables has been maintained.

The final system with special requirements is the combustible gas control system, which is also an ESF system. This system has redundant components and power supplies located in each of the two units.

Cables for these redundant subsystems are treated in exactly the same manner as indicated above for those in the SBGT, control room HVAC and auxiliary electric equipment room HVAC systems, with the exception of the divisional assignments of those for the Unit 1 and Unit 2 crosstie valves. Cables for the crosstie valves allowing the Unit 2 hydrogen recombiner to serve the Unit 1 containment are designated as electrical Division 1 and routed exclusively within Unit 1. (See Drawing No. M-130.) Like wise, crosstie valve cables allowing Unit 1 hydrogen recombiner to serve the Unit 2 containment are designated as electrical Division 1 and rout ed exclusively within Unit 2. Physical separation is in accordance with the requirements of Subsection 8.3.1.4.2.

8.3.1.4.6 General Arrangement of Class 1E Components Physical independence of redundant Class 1E components is maintained primarily by the reservation of building segm ents for exclusive division use.

Major electrical equipment locations are indicated in general arrangement drawings listed in the Table of Contents of Chapter 1.

Class 1E equipment in the containment building generally is allocated to building quadrants as follows:

ESF Division Quadrants 1 Northeast and Northwest 2 Southeast and Southwest 3 Northeast, at elevation 761 feet Redundant Class 1E equipment in the auxiliary building generally is assigned to separate areas of the building.

LSCS-UFSAR 8.3-33 REV. 15, APRIL 2004 8.3.1.5 References

1. Letter from Mr. H. R. Peffer (Gen eral Electric) to Mr. T. E. Watts (Commonwealth Edison Co.), Dated February 22, 1983.

2. Letter from Mr. H. R. Peffer (Gen eral Electric) to Mr. T. E. Watts (Commonwealth Edison Co.), Dated March 1, 1983.

8.3.2 D-C Power Systems 8.3.2.1 Description

The d-c power-distribution system and bat teries are designed to provide control power for switchgear groups, diesel generators, relays, solenoid valves, and other electric devices and components.

Batteries are provided as a source of power for vital loads in case of emergencies such as loss of a-c power.

The d-c system and batteries are designed to provide control power for both normal and emergency operation of plant equipm ent and to provide power for automatic operation of the engineered safety feature protection systems during abnormal and accident conditions (LOCA).

The d-c power system of each unit includes the unit Class 1E d-c power system and the non-Class 1E 24-Vdc power system. The d-c system is shown in single-line form in Figures 8.3-6 and 8.3-9 through 8.3-12. These figures apply to Unit 1 but are directly analogous to the Unit 2 d-c system.

8.3.2.1.1 Unit Class 1E D-C Power System Each unit has one 250-volt power battery and three 125-volt control batteries located in ventilated rooms having concrete walls. The 250-volt battery is adequately sized to supply its loads until a-c power sources to redundant loads are restored (Figure 8.3-9). Each 125-volt battery is sized to supply control power requirements of the switchgear and logic circuitry of one of the three engineered LSCS-UFSAR 8.3-34 REV. 16, APRIL 2006 safety features divisions (Figure 8.3-10).

The redundancy and independence of these load groups is the same as that described for the 4160-volt and 480-Vac Class 1E load groups. Each battery has its own charger with a capa city for restoring it to full charge under normal load in a time commensurate with the recommendations of the battery vendor.

Each Division 1 and 2 125Vdc battery has tw o fully redundant battery chargers capable of supplying at least 200 amperes at a minimu m of 130 volts for at least 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . The Division 3 battery charger will supply at le ast 50 amperes at a mi nimum of 130 volts for at least 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . Battery chargers are powered from a-c sources, and in case of loss of normal a-c power from both on-site and off-site sources, can be supplied from the standby diesel generators associated with their respective engineered safeguards divisions.

Each battery subsystem is complete with its main distribution center, battery charger, and accessory equipment. Each battery subsystem is physically separated from its redundant system so that any failure involving one system cannot jeopardize the other system. During an actual failure of normal power, the diesel-generator power supply establishes battery charger input and thereby reduces th e drain on the battery subsystem. The ampere-hour capacity of each battery is size d to supply all essential loads until a-c power is restored to power its battery chargers (T ables 8.3-11, 8.3-12, 8.

3-13, and 8.3-14). See section 15.9.3.2 for battery requirements concerning station blackout capability.

The battery charger associated with each Divi sion 1 or 2 battery is rated to supply the normal plant d-c loads while its battery is re turned to or maintained in a fully charged state. The battery equipment is designed and rated for operation for a 40-year plant life with reasonable maintenance and replacement of parts. The ESF portion of the equipment covered by this design criterion is design ed (Seismic Category I) to withstand all postulated design-basis accidents without loss of operating capability under seismic and accident environmental conditions.

The d-c loads served by the battery subs ystems include all the 125-Vdc and 250-Vdc loads of the station, both Class 1E and non-Class 1E.

The system-connected loads are identifi ed in Table 8.3-1 and Figure 8.1-3.

The d-c loads of ESF Divisions 1, 2, and 3 are supplied from three independent d-c systems. Table 8.3-11 lists al l the 250- Vdc loads of both Class 1E and non-Class 1E of Division 1. Tables 8.3-12, 8.3-13, and 8.3-14 list all the 125-Vdc loads both Class 1E and non-Class 1E of Divisions 1, 2, and 3, respectively.

LSCS-UFSAR 8.3-35 REV. 13 Components Each battery has its own independent inst rumentation. The following monitoring features are provided for continuous supervision of each 125-Vdc and 250-Vdc subsystem:

a. for ESF Divisions 1 and 2, a local d-c voltmeter with a selector switch to indicate the d-c output voltage at the distribution panels or bus; for ESF Division 3, a local d-c voltmeter to indicate the bus voltage;

b. local and remote d-c voltmeter to indicate the d-c output voltage of the battery charger;

c. local and remote d-c ammeter to indicate the d-c output current of the battery charger;

d. except for ESF Division 3, power failure alarm relay which indicates a loss of a-c power to the battery charger;

e. local and remote d-c ammeter to indicate the output or input current of each battery;

f. except for ESF Division 3, charger low d-c voltage alarm relay;

g. charger high d-c voltage shutdown relay;

h. recording ground-detector voltmeter and alarm;

i. except for ESF Division 3, breaker trip alarms on the battery, battery charger, breakers, and alarms when bus tie breakers are closed; j. d-c bus undervoltage alarm;

k. battery high discharge rate alarm;

l. battery charger high current output alarm;

m. battery instrumentation failure alarm;

n. remote d-c voltmeter in control room to indicate the bus voltage; and LSCS-UFSAR 8.3-36 REV. 17, APRIL 2008 The following overcharging protection is provided:

a. A high-voltage shutdown relay opens the main supply breaker to the charger when the d-c output voltage of the charger rises to approximately 15% over the battery float voltage.

b. A d-c-indicating voltmeter provides a visual check on battery voltage. Local instruments are located on either the d-c distribution panel, d-c instrumentation panel, or battery charger. Remote instruments are located in the control room. The alarms are annunciate d in the main control room. This instrumentation and the related alarms prov ide reliable supervision of the condition of the overall d-c system bu t do not by themselves prov ide detailed information on the condition of each battery as a component.

Batteries and battery chargers distribution centers and control feeds have the following characteristics except for Division 3:

a. Battery Design 24-Volt Div I 125-Volt Div II 125-Volt 250-Volt Number of cells 12 58 58 116 Normal drop in specific gravity (discharge level) 0.064 0.126* 0.126* 0.139* Normal average voltage range per cell - Unit 1: - Unit 2:

2.17 - 2.25 2.17 - 2.25

Normal specific

gravity at 77

°F 1.215 1.215 1.215 1.215

Normal drop in specific gravity for an 8-hour discharge to 1.81 volts per cell.

b. Battery Chargers

1. Overload protection: circuit breaker LSCS-UFSAR 8.3-37 REV. 13

2. Transient voltage protection: surge suppressors

3. Regulation:

+/-1% from zero to 100%

and/or: a-c line voltage changes of

+/-10% and/or, a-c line frequency changes of

+/-3% for the 24-volt chargers (battery disconnected), and

+/-5% for all other chargers.

4. The battery charger limits d-c current output to 125% of rated level at about 80% of float voltage.

The 480-volt, 3-phase input of each battery charger is supplied from its respective 480-volt ESF motor control center through a manually operated breaker. This breaker is furnished with instantaneous and thermal magnetic overload trips.

At the charger cubicle, the a-c supply to the battery charger is controlled by a manually operated 3-pole circuit breaker. This breaker is tripped by operation of a high-voltage sensing d-c relay which monitors the d-c output voltage of the battery charger.

c. 125-volt and 250-Vdc distribution centers Service: 125-Vdc and 250-Vdc.

Circuit breakers (two-pole): All circuit breakers have an interrupting capacity of

20,000 amperes at 250 Vdc.

The following d-c breakers on the d-c main bus are provided

with breaker alarms:

1. charger to battery bus breaker (on trip), and

2. bus tie to d-c bus on opposite unit (non-redundant bus on close).

A 6-position, maintained-contact type control switch installed on each d-c bus provides readout of d-c voltages of charger output or

bus voltage at the voltmeter on the same panel. This voltage reading facilitates paralleling operations between the bus, battery, and charger.

LSCS-UFSAR 8.3-38 REV. 15, APRIL 2004 A recording and contact-making ground-detector voltmeter is installed on each battery. This d-c voltmeter has a range of -150 to 0 to +150 volts for the 125-Vdc system and range of -300 to 0 to +300 volts for the 250-volt system.

d. Control Feeds to Equipment Circuit breakers are used to isolate the control feeds supplying the following equipment:

1. 6900-volt, 4160-volt and 480-volt switchgear groups;

2. main control board;

3. hydrogen and stator cooling panel;

4. annunciator input relay logic cabinet;

5. annunciator input cabinet;

6. generator and transformer relay and metering panel; and

7. control panels for diesel generators.

125-Vdc buses 1A, 1B and 1C (for Unit 1) are mutually redundant for Unit 1.

Similarly, buses 2A, 2B, and 2C are mutua lly redundant for Unit 2. This design allows for the single failure or loss of one redundant d-c bus on each unit during simultaneous accident and loss-of-offsite-power conditions without adversely affecting the safe shutdown capability of the plant.

The tie between panels 111Y and 211Y, th e tie between panels 112Y and 212Y, and the tie between panels 113 and 213 (ESF d-c buses for Unit 1 and Unit 2) are each provided with two normally open, manually operated circuit breakers as indicated on Figures 8.3-10, 8.3-11, and 8.3-12 respectively. These bus ties are provided so that the nonredundant d-c buses of Unit 1 and Unit 2 can be interconnected during maintenance and testing operations for the battery and/or battery charger associated with either bus 111Y or 211Y, bus 112Y or 212Y, and bus 113 or 213. No interlocks are provided, however, because the interconnected buses are not redundant. Since no crosstie current is assumed for battery loading, the associated Division is considered inoperable when crosstied. Administrative control must be provided for operation of these bus ties.

Battery bus tie-closed alarms are provided in the control room by the annunciator.

During normal operation, the batteries are kept fully charged by the battery chargers. The voltage is raised periodically for equalization of the charge on the LSCS-UFSAR 8.3-39 REV. 13 individual battery cells. Readings are recorded for the battery voltage level during charge equalization.

Divisions The d-c battery system is divided into three electrically and physically independent divisions as follows:

LSCS-UFSAR 8.3-40 REV. 16, APRIL 2006 ENGINEERED SAFETY FEATURES EQUIPMENT Unit No. ESF Div. No. 125-V Batt. No. 125-V Pnl. No. 250-V Batt. No. 250-V Bus No. 250-V MCC No. Diesel Gen. No. 4-kV Bus No.

1 1 1A 111Y 1 1 121Y 0 141Y 1 2 1B 112Y 1A 142Y 1 3 1C 113 1B 143 2 1 2A 211Y 2 2 221Y 0 241Y 2 2 2B 212Y 2A 242Y 2 3 2C 213 2B 243 The system design satisfies the single-failure criteria in that any one of the three 4160-volt ESF buses (141Y, 142Y, 143) on Unit 1 along with its control power can be lost and still provide operation of sufficient engineered safety features system auxiliaries to control the plant safely under all modes of operation.

Sources The primary sources of d-c power for the system loads of each unit are a combination of the 250-Vdc battery chargers (ESF Division 1) and the 125-Vdc battery chargers (ESF Division 1, 2 and 3). Each battery charger is fed from a 480-volt ESF motor control center of the same ESF division and is sized to carry the following loads:

a. normal load on the associated d-c distribution panel, and b. battery-charging load required to fully charge the battery following a discharge.

If the battery chargers are out of service, the secondary d-c power sources for the associated d-c system loads of each unit are the 250-volt and the 125-volt batteries themselves. The Division 1 and 2 batteries are sized to start and carry the

LSCS-UFSAR 8.3-41 REV. 16, APRIL 2006 normal d-c loads plus all d-c loads required for safe shutdown and for switching operations required to limit the consequences of a design-basis event for a period of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months following loss of all a-c sources. The Division 3 on-line battery charger will carry all nonaccident shutdown loads; the principal one being the starting load of the HPCS diesel. These primary and secondary sources (battery chargers and batteries) meet, for their size and instru mentation, the requirements of IEEE 308-1971. The chargers alone are capable of su pplying station normal d-c steady-state requirements while restoring the batteries to full charge.

Operating Configurations The 250-Vdc motor-control center (Division

1) and each of the 125-Vdc distribution panels (Divisions 1, 2, and 3) are normally fed from their primary source (charger) and their secondary source (battery) operating in parallel in a "float-charger" configuration. Loss of either source does not interrupt power flow to the bus. The battery system is provided with a recording ground - detection voltmeter and alarm (alarm at the main control room. Figure 8.3-9 shows the essential electrical connections for the 250-Vdc ESF Division 1 (Unit 1). Figures 8.3-10, 8.3-11, and 8.3-12 show the essential electrical connect ions for the 125-Vdc ESF Divisions 1, 2, and 3 respectively for Unit 1. These figures are directly analogous to the Unit 2 d-c system. Battery load requirements are gi ven in Tables 8.3-11, 8.3-12, 8.3-13, and 8.3-14. Batteries The ampere-hour capacity of each battery is adequate to supply expected essential loads following station trip and loss of all a-c power without battery terminal voltage falling below 105-Vdc / 210 Vdc term inal voltage, the minimum discharge level. The 8-hour, 77° F ampere-hour capacity to 105-Vdc / 210 Vdc terminal voltage for each battery is as follows:

a. Unit 1/2 250-volt battery, 1832 A-hr;

b. Unit 1/2, Division 1 125-volt battery, 1128 A-hr;

c. Unit 1/2, Division 2 125-volt battery, 1128 A-hr;

d. Division 3 125-volt battery, 308 A-hr.

The station batteries are designed to operate with the specified capacities in the worst expected temperature and humidity co nditions in the battery room following a design-basis accident.

LSCS-UFSAR 8.3-42 REV. 14, APRIL 2002 The batteries and the battery chargers of ESF Divisions 1, 2, and 3 are located outside the primary containment in area s where the environment is essentially normal following a design-basis accident.

They are housed in a Safety Class 1 structure in separate battery rooms having concrete walls.

In addition to normally expected environmental conditions, Class 1E d-c cables or devices located inside the containment are designed to operate in the post-accident environment for the period of time during which they would be needed to limit the consequences of the accident. The batteries are designed to withstand the pressure, temperature, humidity, and radiation levels for the applicable design-basis accident for that period of time without loss of function.

Sufficient ventilation is provided in the battery rooms for the following purposes:

a. To purge the room of gaseous hydrogen liberated from the batteries at an air change rate of greater than 6 air changes per hour. This limits the hydrogen concentration to a level below 2% of total volume.

b. To limit each battery room temperature at 104° F maximum and maintain a minimum electrolyte temperature of 60

°F for the 125 VDC batteries and 65

°F for the 250 VDC batteries.

c. To maintain each battery r oom at normal plant pressure.

The conditions of the battery are monitored in accordance with IEEE 308-1974. Battery testing is performed in accordance with IEEE 450-1995 per Regulatory Guide 1.32 C.1.c.

The 125-Vdc and 250-Vdc control batteries, rack s, chargers, distribution panels, and battery room ventilation equipment are classified as Seismic Category I.

The 125-volt and 250-volt batteries are hous ed in separately ventilated rooms and are provided with seismically qualified battery racks.

The ESF portion of the d-c equipment is installed in a Seismic Category I Structure.

The engineered safety feature portions of the 125-Vdc system and the 250-Vdc systems are classified as Class 1E.

Fire detectors and fire extinguishers are installed in the areas where the 125-volt and 250-volt batteries and distri bution buses are installed.

LSCS-UFSAR 8.3-43 REV. 14, APRIL 2002 8.3.2.2 Analysis Each division of the Class 1E a-c power system is provided with control and d-c motive power from a corresponding division of the Class 1E d-c power system. The 480-Vac feed to each battery charger is supp lied from an a-c source in the individual division to which the particular charger belongs. In this way, separation between the independent divisions is maintained, and the power provided to the chargers can be from either offsite or onsite sources.

Alarms are provided to monitor the status of the battery-charger supply. Such alarms include loss of a-c power to the charger, d-c output failure, low output voltage, high current output, battery ground, and breaker trip. Battery chargers are provided with disconnecting means, feedback protection and high d-c voltage shutdown. Each d-c subsystem has re mote and local status monitoring instruments. Remote display instruments are located in the control room.

All the status-monitoring instruments for the Division 1, Division 2, and Division 3 125-Vdc power systems are mounted on the d-c distribution/instrumentation panels or battery charger of the respective divisions located outside the battery rooms. The status-monitoring instruments for the Division 1 250-Vdc power system are mounted on the respective battery charger panel located outside the battery room.

All alarms are annunciated in the main cont rol room. Periodic functional tests are performed to ensure the readiness of the system to deliver the required d-c power.

8.3.3 Fire Protection for Cable Systems 8.3.3.1 Cable Derating and Cable Tray Fill Power cables are selected such that the cable insulation thermal rating is not exceeded. Cable ampacities are analyzed using a computerized cable engineering program to ensure that cables are applied within their therma l rating. Original construction design cable ampacities for LSCS were limited to the values shown in Tables 8.3-7 through 8.3-9. The values in these tables apply to cables that have some part of their length in solid bottom trays with derating factors applied for ambient, tray fill, tray covers, sh ields, and direct current service.

The thermal ampacity of power and control cables with no part of their length in solid-bottom trays conform to IPCE A P-46-426-1962 (AIEES-135-1), with appropriate derating factors applied for ambient, shields, and direct current service.

Cables are classified as power (P), control (C), or instrumentation (K), as follows:

a. Power Cables Power cables are defined as those cables which provide electrical energy for motive power or he ating to all 6600-Vac, 4000-Vac, 460-Vac, 208-Vac, 250-Vdc, and 125-Vdc loads. Cables which transmit power from electrical energy sources to power distribution panels, regardless of voltage, are included in this LSCS-UFSAR 8.3-44 REV. 15, APRIL 2004 definition. Generally, all 8-kV and 4-kV cables and all 600-volt cables with #6 AWG and larger co nductors are included in this category. Some 600-volt, #10 and #14 AWG conductor cables are also included in this category, e.g., power feeds to valve motor operators.

b. Control Cables For purposes of this criterion, co ntrol cables are defined as those circuits up to and including 120-Vac and up to and including 125-Vdc between components responsible for the automatic or manual initiation of auxiliary electrical functions and the electrical indication of the state (posit ion) of auxiliary components.

When applying these criteria, cables which supply electrical energy from distribution panels to 120-Vac, 125-Vdc, and 24-Vdc instrument, control, and alarm circuits are treated as cont rol cables. Generally, all 600-volt cables with #10 and #14 AWG conductors, except those three conductor cables which are power cables, are included in this category. Some motor operated valves and the 480-volt feed for the standby gas treatment system stack monitoring subsystem have their power circuit categorized as control due to their small size, low current and/or intermittent use.

c. Instrumentation Cables Instrumentation (signal) cables are defined as those cables conducting low-level instrumentation and control signals. These

signals can be analog or digital. Typically, those cables which carry signals from thermocouples, resistance temperature detectors, transducers, neutron monitors, etc. to E/P converters, indicators, recorders, and computer input circuits which carry signals of less than 50 mA are included in this category. Generally, instrumentation cables are one of the following types:

1. #16 AWG, twisted, shie lded conductor pairs;

2. #20 AWG, chromel-constantan conductor pairs; or

3. coaxial or triaxial.

The cable ampacities are based on an approximate 2-inch design depth of fill for 4-inch deep power cable trays and an approximate 3-inch design depth of fill for the 6-inch deep control and instrumentation trays. De sign indexes are calculated for all cable pan routing points.

LSCS-UFSAR 8.3-45 REV. 13 Design Index = Sum of (Cable Diameters) 2 Tray width x Design Depth of Fill If the design index exceeds 1.25 for a powe r cable tray, that routing point will be analyzed by calculation to determine if thermal loading limitations have been exceeded. If the design index exceeds 1.4 for a power, control, or instrumentation cable tray that routing point will be analyzed by calculation to determine if static loading limitations have been exceeded.

8.3.3.2 Fire Detection and Protection in the Areas where Cables are Installed Fire Detection The fire-detection system utilizes ionization type fire detectors for detecting incipient fires and products of combustion in various plant zones. Each unit's fire detection system is divided into two groups as follows:

a. a first group which provides warning alarm only (warning zones), and

b. a second group which supplies warning and initiates the operation of a fire-protection system, depending on zone (protection zones).

Groups of fire detectors are installed in areas of high cable concentration, including the following:

a. control room;

b. auxiliary equipment room;

c. ESF electrical switchgear room s (ESF Divisions 1, 2, and 3);

d. 250-volt 125-volt battery rooms;

e. reactor protection equipment area;

f. major switchgear rooms (four areas for each unit);

g. computer room;

h. radwaste control room;

i. lake screen house; LSCS-UFSAR 8.3-46 REV. 13

j. off-gas switchgear room;

k. concentrated cable areas in the following locations:

1. reactor building - elevations 740 feet, 673 feet 4 inches, 710 feet 6 inches, 694 feet 6 inches, 761 feet and 786 feet 6 inches.

2. auxiliary building - elevation 749 feet;

3. primary containment - elevations 740 feet,, 749 feet 1 inch, 761 feet and 777 feet 11 inches;

4. turbine building;

5. diesel generator building - elevations 674 feet and 736 feet 6 inches; and

l. river screen house (heat detectors).

The design and configuration of each area determine the number and actual location of fire detectors.

The fire detectors are installed in return air ducts where possible. Otherwise, they are placed as near as possible to the potential fire hazard. The sensitivity of each fire detector is individually adjustable and is set by the factory-trained technician at the time of installation.

The fire detectors alert the operators in the main control room through the main control board annunciator and a separate li ght indicating panel for fire-detection systems and sound an alarm locally upon detection of fire in any of the above mentioned areas.

The fire-detection systems are electrically supervised and energize alarms both in the auxiliary electric equipment room (AEER) and in the control room upon loss of supply voltage or similar failure.

Automatic Fire Protection for the Cable Spreading Room The cable spreading rooms for LSCS are each equipped with automatic preaction deluge systems actuated by ionization detectors. Ionization smoke detectors are located in the ceilings. These detectors ar e sensitive enough to alarm at the very inception of a fire when combustion produc ts are first being released. Actuation of one detector trips the deluge valve to charge the system with water.

LSCS-UFSAR 8.3-47 REV. 14, APRIL 2002 Fusible link sprinkler heads are located adjacent to each cable tray. A heat source, such as from a fire, is then required for the sprinkler head to actuate and flood the tray. This system is also air supervised. Damage to the system or actuation of a fusible link sprinkler head actuates an alarm both locally and in the control room. If for some reason the ionization smoke detection system was not in service or failed to function, the heat of a fire would cause a supervisiory alarm, and the deluge valve could be tripped manually.

The system is electrically supervised an d alarms both locally and in the control room upon any failure. If there is a fire and the detectors do not function for any reason, the melting of the fusible links en ergizes an alarm both in the AEER and in the control room by releasing the air pressure maintained in the dry pipe.

Fire hose stations and portable fire extinguishers are readily available to

switchgear rooms.

8.3.3.3 Fire Barriers and Separation Between Redundant Cable Trays

For information on installation of fire barriers and separation between redundant cable trays, see Subsection 8.3.1.4.2.

8.3.3.4 Fire Stops Fire stops are installed in the cable trays at all riser openings in floors. When it penetrates a floor, the tray section is comp letely enclosed for a distance of 6 feet above the floor surface.

Within the tray section, fire stops are provided that satisfy the fire-resistance requirements for the application.

In areas where pressure integrity between walls is required, a sleeve penetration filled with a nonflowing, fire-resistant material or other suitable fi re stop is used.

In other walls, cable tray penetrations utilize seals similar to risers.

All cables (Class 1E and non-Class 1E) are flame retardant. These cables have passed flame tests specified by IEEE 383.

8.3.3.5 Integrity of the Essential (ESF) Electrical Auxiliary Power and Controls See Subsections 8.3.1.1.2 and 8.3.2.1.1. Se e also Tables 8.3-1, 8.3-11, 8.3-12, and 8.3-13 for separation of redundant ESF loads, which ensures integrity of ESF equipment during fires or other accident conditions.

To maintain the integrity of ESF equipment needed during fires for safe shutdown and for fire fighting, the following provisions are made:

LSCS-UFSAR 8.3-48 REV. 13 1. Physical separation is provided be tween redundant divisions of electrical auxiliary power equipment, with fi reproof walls separating redundant equipment.

2. ESF equipment is located only in protected zones having a low probability of being subject to damage from missiles or fire.

3. Independent sources of power and controls are provided for each redundant ESF division.

4. Fire barriers are used wherever th ere is a possibility of fires occurring.

5. ESF equipment is installed in Seis mic Category I buildings for protection against earthquakes (which can cause fires).

8.3.3.6 Provisions for Protection of ESF Auxiliary Power from Effects of Fire-Suppressing Agents

1. The cabling that is installed in the c able spreading room is waterproof and is not subjected to water damage. There are only two penetrations through the floor of the cable spreading room. These penetrations have been specially curbed. Floor drains are provided, and there is no problem of water leakage into the auxiliary equipment room.

2. Use of fireproof walls and barriers for separating redundant ESF equipment prevents spread of fire-suppressing agents such as water, CO 2, as fire-extinguishing chemicals.

3. See Subsecton 8.3.3.3 for description of fire barriers and separation between redundant ESF cable trays.

LSCS-UFSAR TABLE 8.3-1 (SHEET 1 OF 7) TABLE 8.3-1 REV. 17, APRIL 2008 LOADING ON 4160-VOLT BUSES**

EQUIPMENT U NIT #1 LOCA D ELAY T IME A FTER ESF BUS I S ENERGIZED (S EC)1 U NIT #2 SS NUMBER INSTALLED R EQUIRED B HP EACH MINIMUM IMMEDIATE REQUIREMENTS ESF BUSES (Note 9) U NIT 1 U NIT 2 U NIT 1 U NIT 2 U NIT 1 U NIT 2 BUS 141Y BUS 142Y BUS 143 BUS 241Y BUS 242Y BUS 243 HPCS pump X* 0 - 1 1 3050 1 0 ---- ---- 3050 ---- ---- ---- LPCS pump X 0 - 1 1 1490 1 0 1490 ---- ---- ---- ---- ---- RHR pump 1C X 0 X 1 1 765 1 0 ---- 765 ---- ---- ---- ---- RHR pumps 1A &

1B XX 5 XX 2 2 765 2 1 765 765 ---- ---- 765 ---- RHR service water pump X<> - X<> 4 4 200 2 2 400 400 ---- ---- 400 ---- Diesel-generator

auxiliaries: (a) Water pumps X 0 X 3 2 125/75/77.5 3 2 125 75 77.5 ---- 75 77.5 (b) Starting air comp. XXXX 0 XXXX 4 4 12.2/10.7/7.5 4 3 12.2 22.9 7.5 ---- 22.9 7.5 (c) DG rm. exh. fan X 0 X 3 2 40/30.2 3 2 40 40 30.2 ---- 40 30.2 (d) Fuel oil rm. fan X 0 X 3 2 3 3 2 3 3 3 ---- 3 3 (e) Fuel oil trans.

pump XXXX 0 XXXX 3 2 5 3 2 5 5 5 ---- 5 5 (f) Lube oil soak back pump X - X 2 1 0.75 2 1 0.75 0.75 ---- ---- 0.75 ---- (g) Engine oil circ pump X - X 2 1 1 2 1 1 1 ---- ---- 1 ----

The 250 V Div. 1 and 125 V Div 1 battery charger data above are revised for record.

LSCS-UFSAR TABLE 8.3-1 (SHEET 2 OF 7) TABLE 8.3-1 REV. 17, APRIL 2008 LOADING ON 4160-VOLT BUSES**

EQUIPMENT U NIT #1 LOCA D ELAY T IME A FTER ESF BUS I S ENERGIZED (S EC)1 U NIT #2 SS NUMBER INSTALLED R EQUIRED B HP EACH MINIMUM IMMEDIATE REQUIREMENTS ESF BUSES (Note 9) U NIT 1 U NIT 2 U NIT 1 U NIT 2 U NIT 1 U NIT 2 BUS 141Y BUS 142Y BUS 143 BUS 241Y BUS 242Y BUS 243 Battery charger - 250 Vdc X 0 - 1 1 89.8kVA 1 0 102.3 ---- ---- ---- ---- ---- Battery charger - 125 Vdc X 0 X 3 3 44.1kVA 2 1 50.3 50.3 ---- ---- 50.3 ---- Essential lighting X 0 X 3 3 27.3kW/ 46kW/

5kVA/ 22.7kW 3 2 36.6 61.7 6 ---- 30.5 6 Computer power supply X 0 X 1 (Note 4) 1 (Note 4) 25kVA 1 0 57 ---- ---- ---- ---- ---- Aux. equipment room: Sup. sys. refrig. comp. XXXXXX - - 1 1 115.1 1 1 ---- 115.1 ---- ---- 115.1 ---- Air cooled cond. fan XX Note 5 - 1 1 100 1 1 ---- 100 ---- ---- 100 ---- Supply fan XX Note 5 - 1 1 78/76 1 1 ---- 78 ---- ---- 76 ---- Return fan XX Note 5 - 1 1 50/46 1 1 ---- 50 ---- ---- 46 ----

Cont. rm. refrig. comp. XXXXXX - - 1 1 90.7 1 1 ---- 90.7 ---- ---- 90.7 ---- Cont. rm. air-cooled cond. fan XX Note 5 - 1 1 85.2/71 1 1 ---- 85.2 ---- ---- 71 ---- Hydrogen recombiner power cabinet XXX - - 1 1 100kVA 1 1 --- 134 --- --- 114 ---

Post LOCA containment monitor sample panel X - - 2 2 1 2 0 1 1 --- --- --- ---

The 250 V Div. 1 and 125 V Div 1 battery charger data above are revised for record.

LSCS-UFSAR TABLE 8.3-1 (SHEET 3 OF 7) TABLE 8.3-1 REV. 17, APRIL 2008 LOADING ON 4160-VOLT BUSES**

EQUIPMENT U NIT #1 LOCA D ELAY T IME A FTER ESF BUS I S ENERGIZED (S EC)1 U NIT #2 SS NUMBER INSTALLED R EQUIRED B HP EACH MINIMUM IMMEDIATE REQUIREMENTS ESF BUSES (Note 9) U NIT 1 U NIT 2 U NIT 1 U NIT 2 U NIT 1 U NIT 2 BUS 141Y BUS 142Y BUS 143 BUS 241Y BUS 242Y BUS 243 SLCS tank heater XXXX - XXXX 1 1 10kW 1 0 13 ---- ---- ---- ---- ---- SLCS pump XXX - XXX 2 2 40kW 0 0 ---- ---- ----

---- ---- SLCS mixing heater XXX - XXX 1 1 40kW 0 1 ---- ---- ---- ---- 54 ---- Battery room exhaust fans X - X 6 6 1 6 4 2 3 1 ---- 3 1 Standby gas treatment blower X - X 1 1 20 1 1 ---- 20 ---- ---- 20 ---- Standby gas elect. duct heater XX Note 5 XX 1 1 23 1 1 ---- 30.8 ---- ---- 30.8 ---- Standby gas cooling fan XXXX - XXXX 1 1 1.5 1 0 ---- 1.5 ---- ---- ---- ---- RX protection MG set XXX - XXX 2 2 25 0 1 ---- ---- ---- ---- 25 ---- Primary containment vent. sup. fan XXX - XXX 2 2 100 0 1 ---- ---- ---- ---- 100 ---- RX protection MG room supply fan X - X 1 1 20 1 1 ---- 20 ---- ---- 20 ---- Control room supply fan XX Note 5 - 1 1 50 1 1 ---- 50 ---- ---- 50 ---- Control room return fan XX Note 5 - 1 1 25 1 1 ---- 25 ---- ---- 25 ---- Control room emergency makeup fan XX Note 5 - 1 1 15 1 1 ---- 15 ---- ---- 15 ---- Fuel pool emergency makeup pump XXX - XXX 2 2 75 0 0 ---- ---- ---- ---- ---- ----

The 250 V Div. 1 and 125 V Div 1 battery charger data above are revised for record.

LSCS-UFSAR TABLE 8.3-1 (SHEET 4 OF 7) TABLE 8.3-1 REV. 17, APRIL 2008 EQUIPMENT U NIT #1 LOCA D ELAY T IME A FTER ESF BUS I S ENERGIZED (S EC)1 U NIT #2 SS NUMBER INSTALLED R EQUIRED B HP EACH MINIMUM IMMEDIATE REQUIREMENTS ESF BUSES (Note 9) U NIT 1 U NIT 2 U NIT 1 U NIT 2 U NIT 1 U NIT 2 BUS 141Y BUS 142Y BUS 143 BUS 241Y BUS 242Y BUS 243 Cleanup recirc. pump XXX - XXX 2 (NOTE 2) 2 (NOTE 2) 55.3 0 1 ---- ---- ---- ---- 55.3 ---- Switchgear heat removal fan X - X 2 2 25 2 1 25 25 ---- ---- 25 ---- LPCS & RCIC pumps cub. cooler fan XXXX - XXXX 1 1 25 1 0 25 ---- ---- ---- ---- ---- RHR pump cubicle cooler fan XXXX - XXXX 2 2 20/25 2 1 20 25 ---- ---- 25 ---- LPCS & RHR "A" water leg pump X - X 1 1 7.5 1 0 7.5 ---- ---- ---- ---- ---- RCIC water leg pump X - X 1 1 7.5 1 0 7.5 ---- ---- ---- ---- ---- RHR B/C water leg pump X - X 1 1 7.5 1 1 ---- 7.5 ---- ---- 7.5 ---- RHR service water pump cub. fan XXXX - XXXX 2 2 5 2 1 5 5 ---- ---- 5 ---- Annunciator supply X - X 2 2 5kVA 2 1 6 6 ---- ---- 6 ---- 120/208-V dist. pnl. on MCC X - X 9 9 10.5kVA/

15kVA 8 5 48 68 ---- ---- 85.5 ---- Primary containment water chiller XXX - XXX 2 2 600kW 0 0 ---- ---- ---- ---- ---- ---- Control rod drive feed pump XXX - XXX 2 2 300 0 0 ---- ---- ---- ---- ---- ---- HPCS water leg pump X - X 1 1 7.5 1 1 ---- ---- 7.5 ---- ---- 7.5 HPCS - pump cubicle cooler fan XXXX - XXXX 1 1 17 1 0 ---- ---- 17 ---- ---- 17

LSCS-UFSAR TABLE 8.3-1 (SHEET 5 OF 7) TABLE 8.3-1 REV. 17, APRIL 2008 EQUIPMENT U NIT #1 LOCA D ELAY T IME A FTER ESF BUS I S ENERGIZED (S EC)1 U NIT #2 SS NUMBER INSTALLED R EQUIRED B HP EACH MINIMUM IMMEDIATE REQUIREMENTS ESF BUSES (Note 9) U NIT 1 U NIT 2 U NIT 1 U NIT 2 U NIT 1 U NIT 2 BUS 141Y BUS 142Y BUS 143 BUS 241Y BUS 242Y BUS 243 Control room emergency makeup air heaters XX Note 5 - 1 1 20kW 1 1 ---- 27 ---- ---- 27 ---- Primary containment water chiller pump XXX - XXX 2 (Note 2) 2 (Note 2) 50 0 0 ---- ---- ---- ---- ---- ---- Carbon dioxide refrig.

unit XXXX - XXXX 1 0 3 1 0 3 ---- ---- ---- ---- ---- Laboratory receptacles transformer XXXXXX - XXXXXX 3 0 15.6/12kW 3 0 Note 7 Note 7 ---- ---- ---- ---- Fire evacuation sirens transformer X - X 1 1 7.5kVA 1 1 ---- 10 ---- ---- 10 ----

HPCS switchgear room supply fan X - X 1 1 13 1 1 ---- ---- 13 ---- ---- 13 HPCS switchgear room exh. fan X - X 1 1 13 1 1 ---- ---- 13 ---- ---- 13 HPCS diesel auxiliaries(Note 6) XXXX - XXXX 1 1 11kW 1 1 ---- ---- 14.7 ---- ---- 14.7 Turbine turning gear XXXXX - XXXXX 1 (Note 2) 1 (Note 2) 60 0 1 ---- ---- ---- ---- 60 ----

Turbine turning gear oil pump XXXXX - XXXXX 1 (Note 2) 1 (Note 2) 50 0 1 ---- ---- ---- ---- 50 ----

Turbine bearing lift pumps XXXXX - XXXXX 8 (Note 2) 8 (Note 2) 5 0 8 ---- ---- ---- ---- 40 ---- Reactor feed pump turb. turbine gear XXXXX - XXXXX 2 (Note 2) 2 (Note 2) 1.5 0 2 ---- ---- ---- ---- 3 ---- Reactor feed pump turb. aux. oil pump XXXXX - XXXXX 1 (Note 2) 1 (Note 2) 2 0 1 ---- ---- ---- ---- 2 ----

LSCS-UFSAR TABLE 8.3-1 (SHEET 6 OF 7) TABLE 8.3-1 REV. 17, APRIL 2008 EQUIPMENT U NIT #1 LOCA D ELAY T IME A FTER ESF BUS I S ENERGIZED (S EC)1 U NIT #2 SS NUMBER INSTALLED R EQUIRED B HP EACH MINIMUM IMMEDIATE REQUIREMENTS ESF BUSES (Note 9) U NIT 1 U NIT 2 U NIT 1 U NIT 2 U NIT 1 U NIT 2 BUS 141Y BUS 142Y BUS 143 BUS 241Y BUS 242Y BUS 243 Generator main seal oil pump XXXXX - XXXXX 1 (Note 2) 1 (Note 2) 20 0 1 ---- ---- ---- ---- 20 ---- Generator recirc. seal oil pump XXXXX - XXXXX 1 (Note 2) 1 (Note 2) 7.5 0 1 ---- ---- ---- ---- 7.5 ---- Generator seal oil vac. pump XXXXX - XXXXX 1 (Note 2) 1 (Note 2) 2 0 1 ---- ---- ---- ---- 2 ---- Reactor Bldg. closed cooling water pump XXX - XXX 2 (Note 2) 2 (Note 2) 150 0 0 ---- ---- ---- ---- ---- ----

Key to symbols used in this table:

X Loads are energized immediately upon restoration of bus voltage. Total Coincidental BHP on Each Bus 3251 3182 3244 ---- 3354 195 XX Loads are applied automatically in sequence listed above. Total Motor Output kW = (.746) (BHP) 2425 2374 2420 ---- 2502 146 XXX Loads are applied manually by operator as required within diesel-generator rating. # Total Motor Input kW Based on actual efficiencies for individual loads and includes electrical losses. 2594.1 2580.3 2587 ---- 2717 166 XXXX Loads cycle automatically, as required. Diesel-Generator Rating (kW) (8760-hour maintenance interval) 2600 2600 2600 ---- 2600 2600 XXXXX Bus must be manually reenergized by operator before loads can automatically start. Diesel-Generator Rating-kVA @ 80% PF 3250 3250 3250 ---- 3250 3250 XXXXXX Loads must be manually reset locally upon restoration of bus voltage. Diesel-Generator Rating (kW) (2000-hour maintenance Interval) 2860 2860 2860 ---- 2860 2860 X<> Manually started when required.

LSCS-UFSAR TABLE 8.3-1 (SHEET 7 OF 7) TABLE 8.3-1 REV. 17, APRIL 2008 **Assumptions:

A. Total loss of plant normal ac auxiliary power B. Unit 1 in LOCA condition (Note 8) C. Unit 2 in hot shutdown condition D. Five diesel-generator sets start E. Intermittent loads expected to operate for very short periods of time, such as motor-operated valves and sump pumps, are not included in the tabulation since inherent conservatism already contained in the tabulated values more than accounts for these loads.

Notes: 1Delay times may exceed those indicated by 2 seconds except for RHR pumps 1A and 1B. The delay time for RHR pumps 1A and 1B may exceed that indicated by 1 second.

2Loads have access to ESF buses (manual) 4Computer power supplies can be powered from either unit 5Delay time is dependent on system component operating times 6The following loads are fed from a common source of power: starting air compressor, air compressor dryer, lube oil soak back pump, engine oil circulating pump and 125 Vdc battery charger.

7Each laboratory receptacle circuit powered by Regular Lighting Cabinets 27A, 27B and 28 must be individually reset prior to use after a loss of power. The use of these receptacle circuits is expected to be limited after a LOOP/LOCA event and considered intermittent a nd therefore are not included in the EDG loading Tabulation.

8A detailed analysis was completed for the condition where Unit 2 is in LOCA and Unit 1 is in Hot shutdown, coincident with a Lo ss of Offsite Power (LOOP). The analysis showed minor differences in the ESF bus electrical loadings between Units 1 and 2. However , these differences were a very small percentage of the diesel generator continuous rating, an d in all cases the to tal electrical loadi ng on any given ESF bus never exceeded the continuous rati ng of the applicable diesel generator.

9The numerical electric loading values in this Table are historical. Refer to the most recent version of the DG Loading Calculations for the Current Load values.

LSCS-UFSAR TABLE 8.3-2 (SHEET 1 of 4) TABLE 8.3-2 REV. 17, APRIL 2008

SUMMARY

OF RELAY PROTECTION FOR ESF 4160-VOLT EQUIPMENT RELAYS ITEM NO. EQUIPMENT DEVICE TYPE RELAY FUNCTION RELAY FUNCTION 1a Bus Tie ACB1415 (1425) 1451 CO-6 Phase overcurrent Trip: ACB1415 (1425) (BusTie) & Alarm Block Reclosure: ACB1411 (1421) (Tr. 141 feed);

ACB1412 (1422) (Tr. 142 feed); ACB1415 (1425) (bus tie) 1b Bus Tie ACB1415 (1425) 1415N CO-6 Ground overcurrent (Same as in Item 1a) 2a Bus 141Y (142Y) 1427 ITE-27 Bus undervoltage Shed loads on bus 141Y (142Y) Trip ACB1412 (1422) (Tr. 142 feed) Trip ACB1414 (1424) (tie to Unit 2) Trip ACB1415 (1425) (bus tie) Start D.G. "0" (D.G. 1A) & Alarm Interlock Auto Close ACB1413 (1423) 2b Bus 141Y (142Y) 1427 ITE-27N Degraded Voltage Trip ACB1412(1422)(Tr. 142 feed) Trip ACB1414(1424)(Tie to Unit

2) Trip ACB1415(1415)(Bus tie) Trip ACB2413(DG-0 feed to 241Y) concurrent with LOCA Start DG-0 (DG-1A) Prevent Start of LPCS and A RHR Pumps (B and C RHR Pumps)

Alarm 3a D.G. 0 (D.G. 1A) 1427 ITE-59N Generator output voltage Alarm Interlock Close ACB1413 (1423) 3b D.G. 0 (D.G. 1A) 1459 NOTE 1 Generator* neutral ground Alarm, Trip & block reclosure ACB1413 (1423)

Stop DG-0 (1A) 3c D.G. 0 (D.G. 1A) 1487 NOTE 1 Generator differential Trip & block reclosure ACB1413 (1423) (D.G. feed) Stop D.G. 0 (D.G. 1A) & Alarm 3d D.G. 0 (D.G. 1A) 1432 NOTE 1 Reverse* power Same as in Item 3c 3e D.G. 0 (D.G. 1A) 1451 1JCV51 Phase* overcurrent Same as in Item 3c

Blocked by Safeguard Actuation Signal Note 1: See the LaSalle controlled computer database for Relay Type LSCS-UFSAR TABLE 8.3-2 (SHEET 2 of 4) TABLE 8.3-2 REV. 14, APRIL 2002

SUMMARY

OF RELAY PROTECTI ON FOR ESF 4160-VOLT EQUIPMENT RELAYS ITEM NO. EQUIPMENT DEVICE TYPE RELAY FUNCTION RELAY FUNCTION 3f D.G. 0 (D.G. 1A) 1440 CEH51A Loss of* field Trip if ACB1413 (1423) initially closed, then same as Item 3c 3g D.G. 0 (D.G. 1A) 1481 NOTE 1 Underfrequency* Same as in Item 3f 3h D.G.-0, 1A 1451 NOTE 1 Phase overcurrent Alarm 3i D.G.-1B 1432 NOTE 1 Reverse power* Trip ACB1433 (D.G. Feed)

Stop D.G.-1B D.G.-2B 2432 NOTE 1 Reverse power* Trip ACB2433 (D.G. Feed), if 2433 initially closed Stop D.G. 2B 3j D.G.-1B 1440 CEH11A Loss of field* Same as 3i with ACB1433 closed. 3k D.G.-1B 1451 IJCV51 Phase overcurrent*

Note 2 Alarm 3l D.G.-1B 1459 IAV51K Generator Neutral Ground Alarm 3m D.G.-1B 1487 PVD Generator differential Trip ACB1433 Stop D.G.-1B 3n D.G.-1B 1451 IAC51 Phase Overcurrent Note 3 Alarm Note 1: See Section B of Q-Listthe LaSalle c ontrolled computer database for Relay Type Note 2: Overcurrent with voltage rest raint protection for the 1B HPCS Dies el Generator and bus 143 is provided by relays 1451V-DG1B (K35A, K35B, and K35C). To ensure proper relay coordination, the overcurrent with voltage restraint protection logic is arranged so that an overcurrent condition will result in tripping of the preferred source supply from the Station Auxiliary Transformer (i.e., ACB 1432), and then after an approximate 1/2 second time delay, the diesel output breaker (i.e., ACB 1433) will also trip if the fault has not cleared. During a loss of coolant accident condition, this protective feature is blocked from tripping the diesel output breaker. Note 3: Overcurrent protection for the 1B HPCS Diesel Generator and bus 143 is provided by relays 1451-DG1B (K33A, K33B). The overcurrent protection logic is arranged so that if the diesel is operating in parallel with the Station Auxiliary Transformer (i.e., ACB 1432 and ACB 1433 are closed), an overcurrent condition will result in tripping of the preferred source supply from the SAT (i.e., ACB 1432).

Blocked by Safeguard Actuation Signal LSCS-UFSAR TABLE 8.3-2 (SHEET 3 of 4) TABLE 8.3-2 REV. 15, APRIL 2004

SUMMARY

OF RELAY PROTECTI ON FOR ESF 4160-VOLT EQUIPMENT RELAYS RELAY FUNCTION RELAY FUNCTION ITEM NO. EQUIPMENT DEVICE TYPE 4a ACB1412 (1422) (1432) Tr. 142 feed to Bus 141Y (142Y) (143) 1451 Co-6 (Co-6) (IAC-51)

Phase overcurrent Trip ACB1415 (1425)(bus tie) Trip ACB1413 (1423) (1433) (DG feed) Trip ACB1412 (1422)(1432) (Tr. 142 feed) Trip ACB1414 (1424) (cross-tie feed to Unit 2) & Alarm Block Reclosure: ACB1413 (1423) (1433) (DG feed)

Block Reclosure: ACB1412 (14222) (1432) (Tr. 142 feed)

Block Reclosure: ACB1414 (1424) (cross-tie to Unit 2) 4b ACB1412 (1422) 1451N Co-6 (Co-6) (IAC-51) Ground overcurrent Same as in Item 4a 4c ACB1412 (1422) (1432) Tr. 142 feed to Bus 141Y (142Y) 143 1887T 142 HU-1 Transformer differential Trip ACB1412 (1422) (1432) (Tr. 142 feed) Block Reclosure: ACB1412 (1422)

(1432) 4d ACB1412 (1422) (1432) Tr. 142 feed to Bus 141Y (142Y) 1427 ITE-27 Tr. 142 under voltage ("Y" winding) Block Reclosure: ACB1412 (1422) (1432) Trip ACB1412 (1422) 5a 345kV Bus 13 1887 PVD Bus differenital Trip ACB1412 (1422) (1432) (Tr. 142 feed) 5b 345kV Bus 13 1850 LBB-1 S1/ARS/ TD5 Backup trip (OCB 1-13) Trip ACB1412 (1422) (1432) (Tr. 142 feed) 5c 345kV Bus 13 1850 LBB-2 S1/ARS/ TD5 Backup trip (OCB 11-13) Trip ACB1412 (1422) (1432) (Tr. 142 feed) 6a Bus 143 1427 NGV13A Bus undervoltage Trip ACB1432 (Tr. 142 feed) Start D.G.

1B Intlck. close ACB1433 (D.G. 1B feed) 6b Bus 143 1427 ITE-27N Degraded Voltage Trip ACB1432(Tr. 142 feed) Alarm 7a ACB1414 (1424) Cross-tie to Unit 2 1487BT IJD Bus tie diferential Trip ACB1414 (2414) (tie to bus 241Y) Trip ACB1424 (2424) (tie to bus 242Y) Block Reclosure: ACB1414 (2414) Block Reclosure: ACB1424 (2424)

LSCS-UFSAR TABLE 8.3-2 (SHEET 4 of 4) TABLE 8.3-2 REV. 15, APRIL 2004

SUMMARY

OF RELAY PROTECTI ON FOR ESF 4160-VOLT EQUIPMENT RELAYS RELAY FUNCTION ITEM NO. EQUIPMENT DEVICE TYPE RELAY FUNCTION 7b ACB2414 (2424) Cross-tie to Unit 1 2451BT CO-9 Phase overcurrent Trip ACB1414 (2414) (tie to bus 241Y) Trip ACB 1424 (2424) (tie to bus 242Y) Block Reclosure: ACB1414 (2414) Block Reclosure: ACB1424 (2424) 8a Feeds to motors:

Buses 141Y (142Y) (143) 1450/1451 CO-5 Phase time overcurrent with inst. Element Trip breaker supplying motor 8b Feeds to motors:

Buses 141Y (142Y) 1451N GR-5 Ground overcurrent instantaneous with time delay Trip breaker supplying motor 8c Feeds to motors: Bus 143 1450/1451 IAC66 Phase time overcurrent with inst. element Trip breaker supplying motor 8d Feeds to motors: Bus 143 1451N PJC Ground overcurrent instantaneous Alarm 9a Feeds to 480-volt transformers Buses 141Y & 142Y 1450/1451 CO-4 Phase time overcurrent with inst. element Trip 4160-volt and 480-volt breakers on transformer 9b Feeds to 480-volt transformers Buses 141Y & 142Y 1451N GR-5 Ground overcurrent instantaneous with time delay Trip 4160-volt and 480-volt breakers on transformer 9c (480-volt neutral) (on transformer)

Buses 141Y & 142Y 1350N IAC-60B Ground time overcurrent with instantaneous element Trip 4160-volt and 480-volt breakers on transformer 9d Feeds to 480-volt transformers: Bus 143 1450/1451 IAC51 Phase tme overcurrent with inst. element Trip 4160-volt breaker supplying transformer 9e Feeds to 480volt transformers: Bus 143 1450N PJC Ground overcurrent instantaneous Alarm 9f 480-volt neutral on transformer: Bus 143 1359N IAV Ground overcurrent instantaneous Alarm NOTE 1: SEE THE LASALLE CONTROLLED COMPUTER DATABASE FOR RELAY TYPE.

LSCS-UFSAR TABLE 8.3-3 TABLE 8.3-3 REV. 0 - APRIL 1984 DIESEL-GENERA TOR RATINGS ITEM DIESEL GENERATOR O (DIVISION 1)

DIESEL GENERATORS 1A AND 2A (DIVISION 2)

DIESEL GENERATORS 1B AND 2B (DIVISION 3)

Continuous rating, kW (8760-hour maintenance interval) 2600 2600 2600 2000-hour rating, kW (2000-hour maintenance interval) 2860 2860 2860 7-day rating, kW (7-day maintenance interval) 2987 2987 2987 30-minute rating, kW (30-minute maintenance interval) 3040 3040 3040 2-hour 10% overload, out of each 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 2860 2860 2860 LSCS-UFSAR TABLE 8.3-4 TABLE 8.3-4 REV. 0 - APRIL 1984 TABULATION OF DIESEL-GENERATOR PROTECTIVE AND SUPERVISORY FUNCTIONS

TROUBLE EVENT FUNCTION FOR TESTING (MANUAL START) FUNCTION FOR EMERGENCY (AUTOMATIC START) OPERATION DUE TO LOSS OF ALL OFFSITE POWER (LOOP)

FUNCTION FOR EMERGENCY (AUTOMATIC START) OPERATION DUE TO ACCIDENT (LOCA) Overspeed Alarm, trip Alarm, trip Alarm, trip Loss of control power Alarm Alarm Alarm Low lube oil pressure Alarm, trip Alarm, trip Alarm High jacket coolant temperature Alarm, trip Alarm, trip Alarm Generator reverse power Alarm**, trip Alarm**, trip Alarm** Generator internal fault (differential) Alarm**, trip Alarm**, trip Alarm**, trip Generator overcurrent (voltage restrained) Alarm, trip Alarm, trip Alarm Generator overcurrent Alarm, trip ACB1432* Alarm, trip ACB1432* Alarm, trip ACB1432* Generator loss of field Alarm, trip Alarm, trip Alarm Generator Neutral Ground Alarm, trip** Alarm, trip** Alarm Generator Under Frequency** Alarm, trip Alarm, trip Alarm Generator Under Voltage** Alarm Alarm Alarm

On Diesel Generators 1B and 2B onlu.

- On Diesel Generators 0, 1A and 2A only.

LSCS-UFSAR TABLE 8.3-5 TABLE 8.3-5 REV. 0 - APRIL 1984 CABLE TRAY SEGREGATION CODES

DIVISION 1 DIVISION 2 DIVISION 3 BOP CATEGORY TYPE TRAY CODE PERMISSIBLE CABLE CODES TRAY CODE PERMISSIBLE CABLE CODES TRAY CODE PERMISSIBLE CABLE CODES TRAY CODE PERMISSIBL E CABLE CODES Power (P) 1YP 1YP, 11P 1BP 1BP, 12P 1GP 1GP, 13P 1WP 1WP Control (C) 1YC 1YC, 11C 1BC 1BC, 12C 1GC 1GC, 13C 1WC 1WC Instrument (K) 1YK 1YK, 11K 1BK 1BK, 12K 1GK 1GK, 13K 1WK 1WK

These codes apply to Unit 1. For Unit 2 codes, replace the first digit with the numeral "2" (2YP, 2YC, 2YK, etc.)

LSCS-UFSAR TABLE 8.3-6 TABLE 8.3-6 REV. 0 - APRIL 1984 CABLE SEGREGATION CODES

(NON-RPS CABLES)

ESF DIV. COLOR CODE POWER CONTROL INSTRUMENTATI ON 1 Yellow 1YP 1YC 1YK 2 Blue 1BP 1BC 1BK 3 Green 1GP 1GC 1GK NSR White 1WP 1WC 1WK NSR in ESF 1 Yellow on white 11P 11C 11K NSR in ESF 2 Blue on white 12P 12C 12K NSR in ESF 3 Green on white 13P 13C 13K (RPS CABLES)

RPS DIV. COLOR CODE POWER CONTROL INSTRUMENTATI ON A1 Black on orange** - A1C NAK A2 Black on orange** - A2C NCK B1 Black on orange** - B1C NBK B2 Black on orange** - B2C NDK G1 Black on orange** - G1C - G2 Black on orange** - G2C - G3 Black on orange** - G3C - G4 Black on orange** - G4C -

These codes apply to Unit 1. For Unit 2 codes, replace the first digit with the numeral "2" (2YP, 2YC, 2YK, etc.) Black characters, denoting RPS Division, on an orange field. N - Neutron monitoring cable.

G - Scram solenoid cables.

LSCS-UFSAR TABLE 8.3-7 TABLE 8.3-7 REV. 14 - APRIL 2002 CABLE AMPACITIES kV CABLES 1/C CABLE - KERITE

SIZE OUTER DIAMETER (in.) AMPACITIES

KERITE IPCEA STANDARD KERITE IPCEA STANDARD 40° C AMBIENT 50° C AMBIENT #750 MCM 1.39 1.867 495 664 598 3/C CABLE - KERITE SIZE OUTER DIAMETER (in.) AMPACITIES*

KERITE IPCEA STANDARD KERITE IPCEA STANDARD 40° C AMBIENT 50° C AMBIENT #750 MCM 3.00 4.041 582 582 524 #500 MCM 2.60 3.508 443 462 416 #4/0 AWG 1.99 2.817 221 273 246 #1/0 AWG 1.56 2.440 122 178 160

Based on maximum pan fill of 2 inches LSCS-UFSAR TABLE 8.3-8 TABLE 8.3-8 REV. 14 - APRIL 2002 CABLE AMPACITIES kV CABLES 1/C CABLE* SIZE OUTER DIAMETER (in.) AMPACITIES

3/C CABLE SIZE OUTER DIAMETER (in.) AMPACITIES**

KERITE IPCEA STANDARD KERITE IPCEA STANDARD 40° C AMBIENT 50° C AMBIENT #2 1.36 1.84 84 113 101 #1/0 1.54 2.08 120 162 145

250 MCM 2.16 2.70 259 284 256 #500 MCM 2.60 2.92 443 462 416

No 5-kV 1/C Cables are used

- Based on maximum pan fill of 2 inches LSCS-UFSAR TABLE 8.3-9 TABLE 8.3-9 REV. 14 - APRIL 2002 CABLE AMPACITIES - 600-VOLT CABLES 1/C CABLE SIZE OUTER DIAMETER (in.) AMPACITIES

OKONITE IPCEA STANDARD OKONITE IPCEA STANDARD 40° C AMBIENT 50° C AMBIENT #14 0.17 0.172 5 5 4.5 #10 0.21 0.215 9 9 8

6 0.34 0.342 23 23 20 #2 0.45 0.448 48 48 43 #1/0 0.58 0.581 78 78 70

4/0 0.74 0.735 142 142 127 #250 MCM 0.85 - 176 - - #350 MCM 0.96 0.950 235 232 208 #500 MCM 1.09 1.081 320 317 285 #750 MCM 1.31 1.294 467 461 414 #1000 MCM 1.47 1.447 598 588 529

1500 MCM -- 1.820 -- -- --

3/C CABLE SIZE OUTER DIAMETER (in.) AMPACITIES*

OKONITE IPCEA STANDARD OKONITE IPCEA STANDARD 40° C AMBIENT 50° C AMBIENT #14 0.45 0.487 7 7.5 6.7

10 0.57 0.611 14 15 13.5 #6 0.90 0.928 35 36 32

2 1.13 1.157 70 71 64 #1/0 1.42 1.455 111 113 101 #4/0 1.82 1.851 202 205 184

350 MCM 2.29 2.319 315 315 284 #500 MCM 2.59 2.602 390 390 351

Based on maximum pan fill of 2 inches LSCS-UFSAR TABLE 8.3-10 TABLE 8.3-10 REV. 0 - APRIL 1984 CABLE INSULATION VOLT CLASS APPLICATION MANUFACTURER INSULATION TYPE 5 kV Power Kerite HTK (High Temp.)

N98 600 V Power and Control Okonite Okonite (EPR Base 1) 1000-600 Instrument Raychem Flamtrol (Radiation Cross-Linked Polyolefin) 600-300 Instrument Samuel Moore EPDM (rubber based compound 600 Instrument Cerro Ethylene Propylene Rubber

LSCS-UFSAR TABLE 8.3-11 (SHEET 1 OF 2) TABLE 8.3-11 REV. 17 - APRIL 2008 250 - VOLT BATTERY 1 (ESF DIVISION 1) LOAD REQUIREMENTS AMPERAGE REQUIREMENTS PER TIME INTERVAL AFTER A-C POWER LOSS UNIT 1 - BATTERY 1DC01E LOAD (AMPERES)

(Note): The numerical electrical loading values and interim time frames in this table are historical. Refer to the most recent revision of the DC battery sizing calculation for the current load profile.

LOAD NAME RATING HP(KVA) 0-1 MIN 1-2 MIN 2-30 MIN 30-45 MIN 45-170 MIN 170-240 MIN 1EBOP (Load 1) 40.000 0.00 729.00 138.00 138.00 138.00 138.00 1EBOP (Load 2) ------ 2.00 2.00 2.00 2.00 2.00 2.00 GEN H2 1ES0P 15.000 120.00 32.10 32.10 32.10 32.10 32.10 UPS 1IP01E (25.00) 100.00 100.00 100.00 0.00 0.00 0.00 RCIC BAR CD VAC PUMP 3.000 22.40 14.90 14.90 14.90 14.90 14.90 RCIC BAR CD VC TK PU 3.000 37.00 11.00 11.00 11.00 11.00 11.00 RCIC VALVE 1E51-F080 0.360 10.10 0.10 0.10 0.10 0.10 0.10 RCIC VALVE 1E51-F045 1.800 51.10 0.10 0.10 0.10 0.10 0.10 RCIC VALVE 1E51-F010 0.361 11.80 0.10 0.10 0.10 0.10 0.10 RCIC VALVE 1E51-F013 4.180 105.10 0.10 0.10 0.10 0.10 0.10 RCIC VALVE 1E51-F022(1) 0.360 10.10 6.80 0.00 0.00 0.00 0.00 RCIC VALVE 1E51-F022(2) 0.100 0.10 0.10 0.10 0.10 0.10 0.10 RCIC VALVE 1E51-F046 0.360 10.10 0.10 0.10 0.10 0.10 0.10 RCIC VALVE 1E51-F019 1.000 25.10 0.10 0.10 0.10 0.10 0.10 RSP 1C61-P001 ------ 0.00 0.00 0.00 0.00 0.00 0.00 RCIC VALVE 1E51-F031 0.330 9.10 0.10 0.10 0.10 0.10 0.10 RCIC VALVE 1E51-F059 0.542 18.90 0.10 0.10 0.10 0.10 0.10 RCIC VALVE 1E51-F360 0.144 8.50 0.10 0.10 0.10 0.10 0.10 RCIC VALVE 1E51-F068 0.361 11.80 0.10 0.10 0.10 0.10 0.10 RCIC VALVE 1E51-F069 0.145 8.50 0.10 0.10 0.10 0.10 0.10 TOTAL 561.70 897.00 299.20 199.20 199.20 199.20

LSCS-UFSAR TABLE 8.3-11 (SHEET 2 OF 2) TABLE 8.3-11 REV. 17 - APRIL 2008 250 - VOLT BATTERY 2 (ESF DIVISION 1) LOAD REQUIREMENTS AMPERAGE REQUIREMENTS PER TIME INTERVAL AFTER A-C POWER LOSS UNIT 2 - BATTERY 2DC01E LOAD (AMPERES) (Note): The numerical electrical loading values and interim time frames in this table are historical. Refer to the most recent revision of the DC battery sizing calculation for the current load profile.

LOAD NAME RATING HP(KVA) 0-1 MIN 1-2 MIN 2-30 MIN 30-45 MIN 45-170 MIN 170-240 MIN 2EBOP (Load 1) 40.000 0.00 729.00 138.00 138.00 138.00 138.00 2EBOP (Load 2) ------ 2.00 2.00 2.00 2.00 2.00 2.00 GEN H2 2ESOP 15.000 120.00 32.10 32.10 32.10 32.10 32.10 UPS 2IP01E (25.00) 100 00 100.00 100.00 0.00 0.00 0.00 RCIC BAR CD VAC PUMP 3.000 44.00 11.00 11.00 11.00 11.00 11.00 RCIC BAR CD VC TK CND 3.000 17.30 11.50 11.50 11.50 11.50 11.50 RCIC VALVE 2E51-F080 0.360 10.10 0.10 0.10 0.10 0.10 0.10 RCIC VALVE 2E51-F045 4.180 41.10 0.10 0.10 0.10 0.10 0.10 RCIC VALVE 2E51-F013 4.180 105.100 0.10 0.10 0.10 0.10 0.10 RCIC VALVE 2E51-F022(1) 0.360 10.10 6.80 0.00 0.00 0.00 0.00 RCIC VALVE 2E51-F022(2) 0.10 0.10 0.10 0.10 0.10 0.10 0.10 RCIC VALVE 2E51-F046 0.360 10.10 0.10 0.10 0.10 0.10 0.10 RCIC VALVE 2E51-F019 1.100 25.10 0.10 0.10 0.10 0.10 0 10 RSP 2C61-P001 ------ 0.00 0.00 0.00 0.00 0.00 0.00 RCIC VALVE 2E51-F360 0.144 9.75 0.10 0.10 0.10 0.10 0.10 RCIC VALVE 2E51-F069 0.145 8.50 0.10 0.10 0.10 0.10 0.10 RCIC VALVE 2E51-F010 0.360 11.80 0.10 0.10 0.10 0.10 0.10 RCIC VALVE 2E51-F031 0.361 11.80 0.10 0.10 0.10 0.10 0.10 RCIC VALVE 2E51-F059 0.542 16.100 0.10 0.10 0.10 0.10 0.10 RCIC VALVE 2E51-F068 0.361 11.80 0.10 0.10 0.10 0.10 0.10 TOTAL 554.75 893.60 295.80 195.80 195.80 195.80

LSCS-UFSAR TABLE 8.3-12 (SHEET 1 OF 4) TABLE 8.3-12 REV. 17 - APRIL 2008 125 - VOLT BATTERY 1A (ESF DIVISION 1) LOAD REQUIREMENTS AMPERAGE REQUIREMENTS PER TIME INTERVAL AFTER A-C POWER LOSS UNIT 1 - BATTERY 1DC07E LOAD (AMPERES) (Note): The numerical electrical loading values and interim time frames in this table are historical. Refer to the most recent revision of the DC battery sizing calculation for the current load profile.

LOAD NAME LOAD (AMPS) 0-1 MIN 1-15 MIN 15-30 MIN 30-60 MIN 60-240 MIN RB LTG CAB #140 16.800 16.80 16.80 16.80 16.80 0.00 ANN INPUT CAB 1PA03J 19.2 19.2 19.2 19.2 0.00 0.00 480 SWGR 135X 12.380 12.38 0.58 0.58 0.58 0.58 D/G 0 CONT. PNL 8.560 8.56 0.46 0.46 0.46 0.46 ANN VIS PNL 1PA08J 36.000 36.00 36.00 36.00 0.00 0.00 480V SWGR 135Y 16.800 16.80 1.20 1.20 1.20 1.20 4 KV SWGR 141Y 64.260 64.26 3.96 3.96 3.96 3.96 ADS 1 PNL 1H13-P628 6.880 6.88 6.88 6.88 6.88 6.88 RCIC INTLK 1H13-P621 2.010 2.01 2.01 2.01 2.01 2.01 RHR INTLK 1H13-P601 2.000 2.00 2.00 2.00 2.00 2.00 RCIC INTLK 1H13-P601 1.050 1.05 1.05 1.05 1.05 1.05 LPCS INTLK 1H13-P629 2.962 2.96 2.96 2.96 2.96 2.96 PCI PNL 1PA13J 0.960 0.96 0.96 0.96 0.96 0.96 RI & FW INT 1H13-P612 3.700 3.70 3.70 3.70 3.70 3.70 RPS DIV A2 1H13-P609 0.770 0.77 0.77 0.77 0.77 0.77 RSP 1C61-P001 3.700 3.70 3.70 3.70 3.70 3.70 RR SWGR 151-1 0.570 0.57 0.57 0.57 0.57 0.57 LFMG PNL 1B33-P001A 2.063 2.06 2.06 2.06 2.06 2.06 PR RAD MON 1H13-P604 6.000 6.00 6.00 6.00 6.00 6.00 480V SWGR 131X 6.230 6.23 0.53 0.53 0.53 0.53 FW PUMP TURB 1A 2.400 2.40 2.40 2.40 2.40 2.40 EXC SWGR CUB 1PL18J 10.000 10.00 0.00 0.00 0.00 0.00 480V SWGR 137X 0.000 0.00 0.00 0.00 0.00 0.00 480V SWGR 137Y 0.000 0.00 0.00 0.00 0.00 0.00 480V SWGR 133 4.420 4.42 0.62 0.62 0.62 0.62 DAC PNL 0PA04J 5.000 5.00 5.00 5.00 5.00 5.00 480V SWGR 131A 10.450 10.45 0.95 0.95 0.95 0.95 480V SWGR 131B 0.000 0.00 0.00 0.00 0.00 0.00 480V SWGR 133A 6.330 6.33 0.63 0.63 0.63 0.63 480V SWGR 133B 8.350 8.35 0.75 0.75 0.75 0.75 480V SWGR 131Y 4.250 4.25 0.45 0.45 0.45 0.45 4KV SWGR 141X 43.750 43.75 3.55 3.55 3.55 3.55 6.9 KV SWGR 151 42.990 42.99 2.79 2.79 2.79 2.79 MP & AP PNL 1PA02J 1.500 1.50 1.50 1.50 1.50 1.50 MAIN GEN EXC HOUSING 0.000 0.00 0.00 0.00 0.00 0.00 SWGR ACB TEST CAB 0.000 0.00 0.00 0.00 0.00 0.00 FP CAB 1FP02E LD1 16.000 16.00 16.00 0.00 0.00 0.00 FP CAB 1FP02E LD2 16.000 16.00 16.00 16.00 0.00 0.00 FP CAB 1FP02E LD3 5.000 5.00 5.00 5.00 5.00 5.00 TURB LTG CAB #141 47.600 47.60 47.60 47.60 47.60 0.00 RW PNL OPL60J ANN 4.200 4.20 4.20 4.20 4.20 4.20 VQ HVAC PNL 1PL71J 0.420 0.42 0.42 0.42 0.42 0.42

LSCS-UFSAR TABLE 8.3-12 (SHEET 2 OF 4) TABLE 8.3-12 REV. 17 - APRIL 2008 125 - VOLT BATTERY 1A (ESF DIVISION 1) LOAD REQUIREMENTS AMPERAGE REQUIREMENTS PER TIME INTERVAL AFTER A-C POWER LOSS UNIT 1 - BATTERY 1DC07E LOAD (AMPERES)

(Note): The numerical electrical loading values and interim time frames in this table are historical. Refer to the most recent revision of the DC battery sizing calculation for the current load profile.

LOAD NAME LOAD (AMPS) 0-1 MIN 1-15 MIN 15-30 MIN 30-60 MIN 60-240 MIN SUP MASTER OPM08J L1 10.500 10.50 10.50 0.00 0.00 0.00 SUP MASTER OPM08J L2 0.000 0.00 0.00 3.00 3.00 3.00 RW PNL OPL01J ANN 12.500 12.50 12.50 12.50 12.50 12.50 ARI PNL 1H13-P800 7.250 7.25 4.55 4.55 4.55 4.55

DC INST 1JY-DC040 1.600 1.60 1.60 1.60 1.60 1.60 DC INST 1JY-DC041 1.600 1.60 1.60 1.60 1.60 1.60

TOTAL 475.005 475.01 250.00 226.50 155.31 90.91

LSCS-UFSAR TABLE 8.3-12 (SHEET 3 OF 4) TABLE 8.3-12 REV. 17 - APRIL 2008 125 - VOLT BATTERY 2A (ESF DIVISION 1) LOAD REQUIREMENTS AMPERAGE REQUIREMENTS PER TIME INTERVAL AFTER A-C POWER LOSS UNIT 2 - BATTERY 2DC07E LOAD (AMPERES) (Note): The numerical electrical loading values and interim time frames in this table are historical. Refer to the most recent revision of the DC battery sizing calculation for the current load profile.

LOAD NAME LOAD (AMPS) 0-1 MIN 1-15 MIN 15-30 MIN 30-60 MIN 60-240 MIN LPCS INTLK 2H13-P629 2.940 2.94 2.94 2.94 2.94 2.94 DC INS PWR 2JY-DC040 1.600 1.60 1.60 1.60 1.60 1.60 RCIC INTLK 2H13-P621 2.310 2.31 2.31 2.31 2.31 2.31 RHR INTLK 2H13-P601 2.000 2.00 2.00 2.00 2.00 2.00 RCIC INTLK 2H13-P601 1.070 1.07 1.07 1.07 1.07 1.07 PCI PNL 2PA13J 0.96 0.96 0.96 0.96 0.96 0.96 RCIC INTLK 2H13-P612 3.700 3.70 3.70 3.70 3.70 3.70 DC INS PWR 2JY-DC041 1.600 1.60 1.60 1.60 1.60 1.60 RPS DIV A2 2H13-P609 0.760 0.76 0.76 0.76 0.76 0.76 RB LTG CAB #240 12.800 12.80 12.80 12.80 12.80 0.00 RP RAD MON 2H13-P604 6.000 6.00 6.00 6.00 6.00 6.00 D/G O CONT PNL 8.560 8.56 0.46 0.46 0.46 0.46 LMFG PNL 2B33-P001A 2.063 2.06 2.06 2.06 2.06 2.06 6.9 KV SWGR 251-1 0.570 0.57 0.57 0.57 0.57 0.57 ANN VIS PNL 2PA08J 36.000 36.00 36.00 36.00 0.00 0.00 480V SWGR 235X 12.380 12.38 0.58 0.58 0.58 0.58 AN INPUT CAB 2PA03J 19.2 19.2 19.2 19.2 0.00 0.00 480V SWGR 235Y 18.720 18.72 1.22 1.22 1.22 1.22 SET PT VER DEVICE 5.000 5.00 5.00 5.00 5.00 5.00 4KV SWGR 241Y 84.750 84.75 4.35 4.35 4.35 4.35 RSP 2C61-P001 3.700 3.70 3.70 3.70 3.70 3.70 FW PUMP TURB 2A 2.400 2.40 2.40 2.40 2.40 2.40 MAIN GEN EXC HSG 0.000 0.00 0.00 0.00 0.00 0.00 VQ HVAC PNL 2PL71J 0.420 0.42 0.42 0.42 0.42 0.42 FP CAB 2FP02E LD1 16.000 16.00 16.00 0.00 0.00 0.00 FP CAB 2FPO2E LD2 16.000 16.00 16.00 16.00 0.00 0.00 FP CAB 2FP02E LD3 5.000 5.00 5.00 5.00 5.00 5.00 EXC SWGR CUB 2PL18J 10.000 10.00 0.00 0.00 0.00 0.00 480 SWGR 233 6.470 6.47 0.76 0.76 0.76 0.76 TURB LTG CAB #241 44.400 44.40 44.40 44.40 44.40 0.00 480V SWGR 237X 0.000 0.00 0.00 0.00 0.00 0.00 480V SWGR 237Y 0.000 0.00 0.00 0.00 0.00 0.00 480V SWGR 231A 10.460 10.46 0.98 0.98 0.98 0.98 480V SWGR 231B 0.000 0.00 0.00 0.00 0.00 0.00 480V SWGR 233A 6.380 6.38 0.68 0.68 0.68 0.68 480V SWGR 233B 6.340 6.34 0.64 0.64 0.64 0.64 480V SWGR 231Y 2.210 2.21 0.31 0.31 0.31 0.31 480V SWGR 231X 6.480 6.48 0.78 0.78 0.78 0.78 4KV SWGR 241X 57.460 57.46 3.86 3.86 3.86 3.86 SWGR ACB TEST CAB 0.000 0.00 0.00 0.00 0.00 0.00 6.9KV SWGR 251 43.770 43.77 3.57 3.57 3.57 3-57

LSCS-UFSAR TABLE 8.3-12 (SHEET 4 OF 4)

TABLE 8.3-12 REV. 17 - APRIL 2008 125 - VOLT BATTERY 2A (ESF DIVISION 1) LOAD REQUIREMENTS AMPERAGE REQUIREMENTS PER TIME INTERVAL AFTER A-C POWER LOSS UNIT 2 - BATTERY 2DC07E LOAD (AMPERES) (Note): The numerical electrical loading values and interim time frames in this table are historical. Refer to the most recent revision of the DC battery sizing calculation for the current load profile.

LOAD NAME LOAD (AMPS) 0-1 MIN 1-15 MIN 15-30 MIN 30-60 MIN 60-240 MIN ARI PNL 2H13-P800 L1 9.300 9.30 9.30 0.00 0.00 0.00 ARI PNL 2H13-P800 L2 0.000 0.00 0.00 5.60 5.60 5.60 ADS 1 PNL 2H13-P628 6.600 6.60 6.60 6.60 6.60 6.60 MP & AP PNL 2PA02J 1.500 1.50 1.50 1.50 1.50 1.50 TOTAL 477.87 477.87 222.09 202.39 131.19 73.99

LSCS-UFSAR TABLE 8.3-13 (SHEET 1 OF 4) TABLE 8.3-13 REV. 17 - APRIL 2008 125 - VOLT BATTERY 1B (ESF DIVISION 2) LOAD REQUIREMENTS AMPERAGE REQUIREMENTS PER TIME INTERVAL AFTER A-C POWER LOSS UNIT 1 - BATTERY 1DC14E LOAD (AMPERES) (Note): The numerical electrical loading values and interim time frames in this table are historical. Refer to the most recent revision of the DC battery sizing calculation for the current load profile.

LOAD NAME LOAD (AMPS) 0-1 MIN 1-15 MIN 15-30 MIN 30-60 MIN 60-240 MIN ANN VIS PNL 1PA08J 36.000 36.00 36.00 36.00 0.00 0.00 480V SWGR 136X 24.610 24.61 1.01 1.01 1.01 1.01 RB LTG CAB #142 14.800 14.80 14.80 14.80 14.80 0.00 RR SWGR 152-1 0.550 0.55 0.55 0.55 0.55 0.55 D/G 1A CONT PNL 8.560 8.56 0.46 0.46 0.46 0.46 RSP 1C61-P001 0.000 0.00 0.00 0.00 0.00 0.00 480V SWGR 136Y 20.590 20.59 0.99 0.99 0.99 0.99 4KV SWGR 142Y 71.560 71.56 4.56 4.56 4.56 4.56 ADS 2 PNL 1H13-P645 0.642 0.64 0.64 0.64 0.64 0.64 ADS 2 PNL 1H13-P631 5.812 5.81 5.81 5.81 5.81 5.81 RHR INTLK 1H13-P601 2.000 2.00 2.00 2.00 2.00 2.00 AB LTG CAB #40 24.400 24.40 24.40 24.40 24.40 0.00 RCIC INTLK 1H13-P601 0.550 0.55 0.55 0.55 0.55 0.55 RCIC INTLK 1H13-P618 3.130 3.13 3.13 3.13 3.13 3.13 RPS DIV B2 1H13-P611 0.760 0.76 0.76 0.76 0.76 0.76 CR HVAC PNL OPL15J 0.790 0.79 0.79 0.79 0.79 0.79 ARI PNL 1H13-P801 7.500 7.50 4.60 4.60 4.60 4.60

PCI PNL 1PA14J 0.960 0.96 0.96 0.96 0.96 0.96 STGS PNL 1PL17J 0.700 0.70 0.70 0.70 0.70 0.70 AEER HVAC OPL42J 0.410 0.41 0.41 0.41 0.41 0.41 LFMG PNL 1B33-P001B 2.063 2.06 2.06 2.06 2.06 2.06 PR RAD MON 1H13-P604 6.000 6.00 6.00 6.00 6.00 6.00 DC INST 1JY-DC042 1.600 1.60 1.60 1.60 1.60 1.60 480V SWGR 134A 8.380 8.38 0.78 0.78 0.78 0.78 480V SWGR 134B 0.000 0.00 0.00 0.00 0.00 0.00 480V SWGR 138 0.000 0.00 0.00 0.00 0.00 0.00 TIP PNL 1H13-P607 0.800 0.80 0.00 0.00 0.00 0.00 FP INVERTER 1FP01E 60.000 60.00 60.00 0.00 0.00 0.00 EHC CAB 1PA01J 3.000 3.00 3.00 3.00 3.00 3.00 FW CONT PN 1H13-P613 3.000 3.00 3.00 3.00 3.00 3.00 FW PUMP TURB 1B CONT 2.400 2.40 2.40 2.40 2.40 2.40 EXC SWGR CUB 1PL18J 10.000 10.00 0.00 0.00 0.00 0.00 MP & AP PNL 1PA02J 1.604 1.60 1.60 1.60 1.60 1.60 480V SWGR 134Y 0.000 0.00 0.00 0.00 0.00 0.00 480V SWGR 134X 8.620 8.62 1.02 1.02 1.02 1.02 480V SWGR 132A 10.480 10.48 0.98 0.98 0.98 0.98 480V SWGR 132X 8.480 8.48 0.88 0.88 0.88 0.88 480V SWGR 132Y 2.200 2.20 0.30 0.30 0.30 0.30 480V SWGR 132B 2.130 2.13 0.23 0.23 0.23 0.23 4KV SWGR 142X 43.340 43.34 3.14 3.14 3.14 3.14 6.9 KV SWGR 152 43.870 43.87 3.67 3.67 3.67 3.67

LSCS-UFSAR TABLE 8.3-13 (SHEET 2 OF 4) TABLE 8.3-13 REV. 17 - APRIL 2008 125 - VOLT BATTERY 1B (ESF DIVISION 2) LOAD REQUIREMENTS AMPERAGE REQUIREMENTS PER TIME INTERVAL AFTER A-C POWER LOSS UNIT 1 - BATTERY 1DC14E LOAD (AMPERES)

(Note): The numerical electrical loading values and interim time frames in this table are historical. Refer to the most recent revision of the DC battery sizing calculation for the current load profile.

LOAD NAME LOAD (AMPS) 0-1 MIN 1-15 MIN 15-30 MIN 30-60 MIN 60-240 MIN H2 & STATOR CAB 1PL19J 2.500 2.50 2.50 2.50 2.50 2.50 SWGR ACB TEST CAB 0.000 0.00 0.00 0.00 0.00 0.00 TURB LTG CAB #143 51.200 51.20 51.20 51.20 51.20 0.00 FP PANEL OFP17J 5.000 5.00 5.00 5.00 5.00 5.00 RELAY TEST PANEL 0.000 0.00 0.00 0.00 0.00 0.00 125 VDC CONTROL RELAY 0.144 0.14 0.14 0.14 0.14 0.14

TOTAL 501.135 501.13 252.63 192.63 156.63 66.23

LSCS-UFSAR TABLE 8.3-13 (SHEET 3 OF 4) TABLE 8.3-13 REV. 17, APRIL 2008 125 - VOLT BATTERY 2B (ESF DIVISION 2) LOAD REQUIREMENTS AMPERAGE REQUIREMENTS PER TIME INTERVAL AFTER A-C POWER LOSS UNIT 2 - BATTERY 2DC14E LOAD (AMPERES) (Note): The numerical electrical loading values and interim time frames in this table are historical. Refer to the most recent revision of the DC battery sizing calculation for the current load profile.

LOAD NAME LOAD (AMPS) 0-1 MIN 1-15 MIN 15-30 MIN 30-60 MIN 60-240 MIN RPS DIV B2 2H13-P611 0.760 0.760 0.760 0.760 0.760 0.760 RCIC INTLK 2H13-P601 0.550 0.550 0.550 0.550 0.550 0.550 RCIC INTLK 2H13-P618 3.290 3.290 3.290 3.290 3.290 3.290 RHR INTLK 2H13-P601 2.000 2.000 2.000 2.000 2.000 2.000 ADS 2 PNL 2H13-P645 0.642 0.642 0.642 0.642 0.642 0.642 CR HVAC PNL 0PL16J 0.794 0.794 0.794 0.794 0.794 0.794 STGS PNL 2PL17J 0.700 0.700 0.700 0.700 0.700 0.700 LMFG PNL 2B33-P001B 2.063 2.063 2.063 2.063 2.063 2.063 AEER HVAC PNL 0PL43J 0.420 0.420 0.420 0.420 0.420 0.420 AB LTG CAB NO 41 13.200 13.200 13.200 13.200 13.200 0.000 PR RAD MON 2H13-P604 6.000 6.000 6.000 6.000 6.000 6.000 RB LTG CAB NO 242 35.00 35.00 35.00 35.00 35.00 0.000 D/G 2A CONT PNL 8.560 8.560 0.460 0.460 0.460 0.460 ANN VIS PNL 2PA08J 36.000 36.000 36.000 36.000 0.000 0.000 480V SWGR 236X 24.700 24.700 1.100 1.100 1.100 1.100 RR SWGR 252-1 0.550 0.550 0.550 0.550 0.550 0.550 480V SWGR 236Y 20.780 20.780 1.180 1.180 1.180 1.180 DC INST 2JY-DC042 1.600 1.600 1.600 1.600 1.600 1.600 PCI PNL 2PA14J 0.960 0.960 0.960 0.960 0.960 0.960 4KV SWGR 242Y 78.130 78.130 4.430 4.430 4.430 4.430 RSP 2C61-P6001 0.000 0.000 0.000 0.000 0.000 0.000 FW PUMP TURB 2B CONT 2.400 2.400 2.400 2.400 2.400 2.400 FW CON PNL 2H13-P613 3.000 3.000 3.000 3.000 3.000 3.000

RELAY TEST PANEL 0.000 0.000 0.000 0.000 0.000 0.000 TIP PNL 2H13-P607 0.800 0.800 0.000 0.000 0.000 0.000 EXC SWGR CUB 2PL18J 10.000 10.000 0.000 0.000 0.000 0.000 FP INVERTER 2FP01E 60.000 60.000 60.000 0.000 0.000 0.000 480V SWGR 234A 8.450 8.450 0.850 0.850 0.850 0.850 480V SWGR 234B 0.000 0.000 0.000 0.000 0.000 0.000 480V SWGR 238 2.180 2.180 0.280 0.280 0.280 0.280 480V SWGR 234Y 0.000 0.000 0.000 0.000 0.000 0.000 480V SWGR 234X 6.620 6.620 0.920 0.920 0.920 0.920 480V SWGR 232A 10.560 10.560 1.060 1.060 1.060 1.060 480V SWGR 232X 8.550 8.550 0.950 0.950 0.950 0.950 480V SWGR 232B 0.000 0.000 0.000 0.000 0.000 0.000 480V SWGR 232Y 4.280 4.280 0.480 0.480 0.480 0.480 TURB LTG CAB NO 243 43.200 43.200 43.200 43.200 43.200 0.000 4KV SWGR 242X 50.150 50.150 3.250 3.250 3.250 3.250 SWGR ACB TEST CAB 0.000 0.000 0.000 0.000 0.000 0.000 6.9 KV SWGR 252 44.030 44.030 3.830 3.830 3.830 3.830 ARI PNL 2H13-P801 L1 9.300 9.300 9.300 0.000 0.000 0.000

LSCS-UFSAR TABLE 8.3-13 (SHEET 4 OF 4)

TABLE 8.3-13 REV. 17, APRIL 2008 125 - VOLT BATTERY 2B (ESF DIVISION 2) LOAD REQUIREMENTS AMPERAGE REQUIREMENTS PER TIME INTERVAL AFTER A-C POWER LOSS UNIT 2 - BATTERY 2DC14E LOAD (AMPERES) (Note): The numerical electrical loading values and interim time frames in this table are historical. Refer to the most recent revision of the DC battery sizing calculation for the current load profile.

LOAD NAME LOAD (AMPS) 0-1 MIN 1-15 MIN 15-30 MIN 30-60 MIN 60-240 MIN ARI PNL 2H13-P801 L2 0.000 0.000 0.000 5.600 5.600 5.600 ADS 2 PNL 2H13-P631 5.512 5.512 5.512 5.512 5.512 5.512 H2 & STATOR CAB 2PL19 J 2.500 2.500 2.500 2.500 2.500 2.500 MP & AP PNL 2PA02J 1.704 1.704 1.704 1.704 1.704 1.704 125 VDC Control Relay 0.144 0.144 0.144 0.144 0.144 0.144 TOTAL 513.079 513.079 254.079 190.379 154.379 62.979

LSCS-UFSAR TABLE 8.3-14 TABLE 8.3-14 REV. 16 - APRIL 2006 ESF DIVISION 3 (HPCS) 125-VDC BATTERY LOAD REQUIREMENTS UNIT 1 - BATTERY BATT 1C LOAD (AMPERES)

(1DC18E) LOAD NAME LOAD (AMPS) 0-1 MIN 1-240 MIN 4KV SWGR 143 30.110 30.110 2.110 D/G FLD FLASHING 1.900 1.900 0.000 D/G CAB 1H22-P028 1.000 1.000 0.500 D/G CAB 1E22-P301B 2.000 2.000 1.562 GEN CONT CAB S001 44.800 44.800 12.800 HPCS PANEL 1H13-P625 3.850 3.850 3.850 PWR SUPPLY 1E22-K500 1.600 1.600 1.600 DIESEL AIR COMP CONT 2.000 2.000 0.000 TOTAL 87.260 87.260 22.422 ESF DIVISION 3 (HPCS) 125-VDC BATTERY LOAD REQUIREMENTS UNIT 2 - BATTERY BATT 2C LOAD (AMPERES) 2DC18E LOAD NAME LOAD (AMPS) 0-1 MIN 1-240 MIN 4KV SWGR 243 30.270 30.270 2.270 D/G CAB 2E22-P301B 2.000 2.000 1.562 D/G CAB 2H22-P028 1.000 1.000 0.500 GEN CONT CAB S001 44.800 44.800 12.800 D/G FLD FLASHING 1.900 1.900 0.000 HPCS PANEL 2H13-P625 3.850 3.850 3.850 PWR SUPPLY 2E22-K500 1.600 1.600 1.600 DIESEL AIR COMP CONT 2.000 2.000 0.000 TOTAL 87.420 87.420 22.582 LSCS-UFSAR 8.4-1 REV. 13 8.4 OTHER ELECTRICAL FEATURES AND REQUIREMENTS FOR SAFETY This section presents other electrical fe atures and requirements for safety which deal with distinct aspects of the alternating current power systems and the direct current onsite emergency power systems, as well as selected items which are associated with these areas.

The other electrical features, requirements, and related matters for safety addressed in this se ction is as follows:

a. Containment electrical penetrations.

8.4.1 Containment Electrical Penetrations Containment electrical penetrations are designed to meet Regulatory Guide 1.63.

Each primary containment medium and high voltage (6.9 kV, 4.16 kV, and 480 volt) electrical penetration circuit is provided with primary and backup primary containment penetration conductor overcurrent protective devices for those circuits that are required to be energized during reactor operation. Other circuits, which are not required during reactor operation are maintained deenergized. Table 8.4-1 (Unit 1) and 8.4-2 (Unit 2) list the pr imary containment conductor overcurrent protective devices that provide the required primary and backup overcurrent protection for circuits energized during reactor operation. The A.C. circuits inside primary containment that are deenergized during reactor operation are:

a. Installed welding grid systems 1A and 1B (Unit 1); 2A and 2B (Unit 2).

b. All drywell lighting circuits.

c. All drywell hoists and crane circuits.

LSCS-UFSAR TABLE 8.4-1 (SHEET 1 of 3) TABLE 8.4-1 REV. 9 UNIT 1 PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES DEVICE NUMBER AND LOCATION SYSTEM/COMPONENT POWERED

a. 6.9 kV Circuit Breakers 1. Swgr. 151 (Cub. 4, Bkr. 3A) RR Pump 1A, Primary - fast speed 2. Swgr. 152 (Cub. 4, Bkr. 3B) RR Pump 1B, Primary - fast speed 3. Swgr. 151-1 (Cub. 3, Bkr. 2A) RR Pump 1A, Primary - low speed 4. Swgr. 152-1 (Cub. 3, Bkr. 2B) RR Pump 1B, Primary - low speed 5. Swgr. 151-1 (Cub. 2, Bkr, 4A) RR Pump 1A, Backup - fast speed 6. Swgr. 152-1 (Cub. 2, Bkr. 4B) RR Pump 1B, Backup - fast speed b. 4.16 kV Circuit Breakers 1. Swgr. 141Y (Cub. 13, Bkr. 1A) RR Pump 1A, Backup - low speed 2. Swgr. 142Y (Cub. 14, Bkr. 1B) RR Pump 1B, Backup - low speed c. 480 VAC Circuit Breakers 1. Swgr. 136Y (Compt. 403C) VP/Pri. Cont. Vent Supply Fan 1B 2. Swgr. 135Y (Compt. 203A) VP/Pri. Cont. Vent Supply Fan 1A d. 480 VAC (Molded Case) Circuit Breakers 1. Backup breakers are located in the back of the respective MCC. a) MCC 136Y-2 (Compt. C4) RR/MOV 1B33-F067B b) MCC 136Y-2 (Compt. A3) RR/MOV 1B33-F023B c) MCC 134X-1 (Compt. B3) NB/MOV 1B21-F001 LSCS-UFSAR TABLE 8.4-1 (SHEET 2 of 3) TABLE 8.4-1 REV. 9 UNIT 1 PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES DEVICE NUMBER AND LOCATION SYSTEM/COMPONENT POWERED d) MCC 134X-1 (Compt. B4) NB/MOV 1B21-F002 e) MCC 136Y-1 (Compt. B2) (Normal) RH/MOV 1E12-F009 f) MCC 136Y-2 (Compt. C5) RI/MOV 1E51-F063 g) MCC 135Y-1 (Compt. A1) RR/MOV 1B33-F023A h) MCC 135Y-1 (Compt. A4) RR/MOV 1B33-F067A i) MCC 133-1 (Compt. C2) RT/MOV 1G33-F102 j) MCC 133-1 (Compt. E1) NB/MOV 1B21-F005 k) MCC 136Y-2 (Compt. B1) NB/MOV 1B21-F016 l) MCC 136Y-2 (Compt. E1) RH/MOV 1E12-F099A m) MCC 136Y-1 (Compt. E4) RT/MOV 1G33-F001 n) MCC 136Y-2 (Compt. A5) WR/MOV 1WR180 o) MCC 136Y-2 (Compt. D6) RH/MOV 1E12-F099B p) MCC 136Y-1 (Compt. H5) VP/MOV 1VP113B q) MCC 136Y-1 (Compt. H4) VP/MOV 1VP114A r) MCC 136Y-1 (Compt. H3) VP/MOV 1VP113A s) MCC 136Y-1 (Compt. H6) VP/MOV 1VP114B t) MCC 136Y-2 (Compt. A4) WR/MOV 1WR179 u) MCC 135Y-1 (Compt. D3) RT/MOV 1G33-F101 v) MCC 135Y-1 (Compt. D4) RT/MOV 1G33-F100 w) MCC 133-1 (Compt. C3) RT/MOV 1G33-F106 x) MCC 136Y-2 (Compt. D5) RI/MOV 1E51-F076 y) MCC 135X-1 (Compt. C2/C3) (Emerg) RH/MOV 1E12-F009 z) MCC 133-2 (Compt. AC1) VP/Drywell Cooler, 1VP15SA

LSCS-UFSAR TABLE 8.4-1 (SHEET 3 of 3) TABLE 8.4-1 REV. 9 UNIT 1 PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES

DEVICE NUMBER AND LOCATION SYSTEM/COMPONENT POWERED aa) MCC 133-2 (Compt. AB1)

VP/Drywell Cooler, 1VP15SE ab) MCC 133-2 (Compt. AB2)

VP/Drywell Cooler, 1VP15SD ac) MCC 134X-2 (Compt. H1)

VP/Drywell Cooler, 1VP15SB ad) MCC 134X-2 (Compt. H2)

VP/Drywell Cooler, 1VP15SC ae) MCC 134X-2 (Compt. J1)

VP/Drywell Cooler, 1VP15SF 2 Backup breakers are located in the front of the respective MCC. a) MCC 135X-2 (Compt. E4) VP/Pri. Cont. Vent Supply Fan 1A Backup b) MCC 136X-2 (Compt. G4) VP/Pri. Cont. Vent Supply Fan 1B Backup

LSCS-UFSAR TABLE 8.4-2 (SHEET 1 of 3) TABLE 8.4-2 REV. 9 UNIT 2 PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES DEVICE NUMBER AND LOCATION SYSTEM/COMPONENT POWERED

a. 6.9 kV Circuit Breakers 1. Swgr. 251 (Cub. 8, Bkr. 3A) RR Pump 2A, Primary - fast speed

2. Swgr. 252 (Cub. 7, Bkr. 3B) RR Pump 2B, Primary - fast speed

3. Swgr. 251-1 (Cub. 3, Bkr. 2A) RR Pump 2A, Primary - low speed

4. Swgr. 252-1 (Cub. 3, Bkr. 2B) RR Pump 2B, Primary - low speed 5. Swgr. 251-1 (Cub. 2, Bkr. 4A) RR Pump 2A, Backup - fast speed 6. Swgr. 252-1 (Cub. 2, Bkr. 4B) RR Pump 2B, Backup - fast speed

b. 4.16 kV Circuit Breakers 1. Swgr. 241Y (Cub. 1, Bkr. 1A) RR Pump 2A, Backup - low speed

2. Swgr. 242Y (Cub. 1, Bkr. 1B) RR Pump 2B, Backup - low speed

c. 480 VAC Circuit Breakers 1. Swgr. 236Y (Compt. 400A) VP/Pri. Cont. Vent Supply Fan 2B

2. Swgr. 235Y (Compt. 202C) VP/Pri. Cont. Vent Supply Fan 2A

d. 480 VAC (Molded Case) Circuit Breakers 1. Backup breakers are located in the back of the respective MCC. a) MCC 236Y-2 (Compt. C4) RR/MOV 2B33-F067B b) MCC 236Y-2 (Compt. A3) RR/MOV 2B33-F023B c) MCC 234X-1 (Compt. B3) NB/MOV 2B21-F001

LSCS-UFSAR TABLE 8.4-2 (SHEET 2 of 3) TABLE 8.4-2 REV. 9 UNIT 2 PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES DEVICE NUMBER AND LOCATION SYSTEM/COMPONENT POWERED d) MCC 234X-1 (Compt. B4) NB/MOV 2B21-F002 e) MCC 236Y-1 (Compt. B2) (Normal) RH/MOV 2E12-F009 f) MCC 236Y-2 (Compt. E4) RI/MOV 2E51-F063 g) MCC 235Y-1 (Compt. A1) RR/MOV 2B33-F023A h) MCC 235Y-1 (Compt. A4) RR/MOV 2B33-F067A i) MCC 233-1 (Compt. C2) RT/MOV 2G33-F102 j) MCC 233-1 (Compt. E1) NB/MOV 2B21-F005 k) MCC 236Y-2 (Compt. B1) NB/MOV 2B21-F016 l) MCC 236Y-2 (Compt. E1) RH/MOV 2E12-F099A m) MCC 236Y-1 (Compt. E4) RT/MOV 2G33-F001 n) MCC 236Y-2 (Compt. A5) WR/MOV 2WR180 o) MCC 236Y-2 (Compt. D6) RH/MOV 2E12-F099B p) MCC 236Y-1 (Compt. H5) VP/MOV 2VP113B q) MCC 236Y-1 (Compt. H4) VP/MOV 2VP114A r) MCC 236Y-1 (Compt. H3) VP/MOV 2VP113A s) MCC 236Y-1 (Compt. H6) VP/MOV 2VP114B t) MCC 236Y-2 (Compt. A4) WR/MOV 2WR179 u) MCC 235Y-1 (Compt. D3) RT/MOV 2G33-F101 v) MCC 235Y-1 (Compt. D4) RT/MOV 2G33-F100 w) MCC 233-1 (Compt. C3) RT/MOV 2G33-F106 x) MCC 236Y-2 (Compt. D5) RI/MOV 2E51-F076 y) MCC 235X-1 (Compt. C2/C3) (Emerg) RH/MOV 2E12-F009 z) MCC 233-2 (Compt. AC1)

VP/Drywell Cooler, 2VP15SA LSCS-UFSAR TABLE 8.4-2 (SHEET 3 of 3) TABLE 8.4-2 REV. 9 UNIT 2 PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES DEVICE NUMBER AND LOCATION SYSTEM/COMPONENT POWERED aa) MCC 233-2 (Compt. AB1) VP/Drywell Cooler, 2VP15SE ab) MCC 233-2 (Compt. AB2) VP/Drywell Cooler, 2VP15SD ac) MCC 234X-2 (Compt. H1) VP/Drywell Cooler, 2VP15SB ad) MCC 234X-2 (Compt. H2) VP/Drywell Cooler, 2VP15SC ae) MCC 234X-2 (Compt. J1) VP/Drywell Cooler, 2VP15SF

2. Backup breakers are located in the front of the respective MCC. a) MCC 235X-2 (Compt. AA4) VP/Pri. Cont. Vent Supply Fan 2A Backup b) MCC 236X-2 (Compt. AA4) VP/Pri. Cont. Vent Supply Fan 2B Backup

RS-08-045, LaSalle, Units 1 and 2, Updated Final Safety Analysis Report (Ufsar), Revision 17, Chapter 8.0 - Electric Power

Contents

Text

8.1 INTRODUCTION

8.1 INTRODUCTION

8.2.1 Description

8.2.2 Analysis

8.2.4 References

SUMMARY

SUMMARY

SUMMARY

SUMMARY

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RS-08-045, LaSalle, Units 1 and 2, Updated Final Safety Analysis Report (Ufsar), Revision 17, Chapter 8.0 - Electric Power

Text

8.1 INTRODUCTION

8.1 INTRODUCTION

8.2.1 Description

8.2.2 Analysis

8.2.4 References

SUMMARY

SUMMARY

SUMMARY

SUMMARY

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