ML18053A730
| ML18053A730 | |
| Person / Time | |
|---|---|
| Site: | Lee  |
| Issue date: | 12/19/2017 |
| From: | Donahue J Duke Energy Carolinas |
| To: | Office of New Reactors |
| Hughes B | |
| References | |
| DUKE, DUKE.SUBMISSION.15, LEE.NP, LEE.NP.1 | |
| Download: ML18053A730 (91) | |
Text
UFSAR Table of Contents 1 Introduction and General Description of the Plant 2 Site Characteristics 3 Design of Structures, Components, Equipment and Systems 4 Reactor 5 Reactor Coolant System and Connected Systems 6 Engineered Safety Features 7 Instrumentation and Controls 8 Electric Power 9 Auxiliary Systems 10 Steam and Power Conversion 11 Radioactive Waste Management 12 Radiation Protection 13 Conduct of Operation 14 Initial Test Program 15 Accident Analyses 16 Technical Specifications 17 Quality Assurance 18 Human Factors Engineering 19 Probabilistic Risk Assessment UFSAR Formatting Legend Description Original Westinghouse AP1000 DCD Revision 19 content Departures from AP1000 DCD Revision 19 content Standard FSAR content Site-specific FSAR content Linked cross-references (chapters, appendices, sections, subsections, tables, figures, and references)
8.1 Introduction ................................................................................................... 8.1-1 8.1.1 Utility Grid Description .................................................................. 8.1-1 8.1.2 Onsite Power System Description ................................................ 8.1-1 8.1.3 Safety-Related Loads ................................................................... 8.1-2 8.1.4 Design Basis ................................................................................. 8.1-3 8.1.4.1 Offsite Power System ................................................. 8.1-3 8.1.4.2 Onsite Power System ................................................. 8.1-3 8.1.4.3 Design Criteria, Regulatory Guides, and IEEE Standards .................................................................... 8.1-4 8.1.5 Combined License Information ..................................................... 8.1-5 8.2 Offsite Power System .................................................................................... 8.2-1 8.2.1 System Description ....................................................................... 8.2-1 8.2.1.1 Transmission Switchyard ............................................ 8.2-2 8.2.1.2 Transformer Area ........................................................ 8.2-6 8.2.1.3 Switchyard Relay House ............................................. 8.2-7 8.2.1.4 Switchyard & Transmission Lines Testing &
Inspection .................................................................... 8.2-8 8.2.2 Grid Stability ................................................................................. 8.2-9 8.2.3 Conformance to Criteria ............................................................. 8.2-11 8.2.4 Standards and Guides ................................................................ 8.2-12 8.2.5 Combined License Information for Offsite Electrical Power ........ 8.2-12 8.2.6 References ................................................................................. 8.2-12 8.3 Onsite Power Systems .................................................................................. 8.3-1 8.3.1 AC Power Systems ....................................................................... 8.3-1 8.3.1.1 Description .................................................................. 8.3-1 8.3.1.2 Analysis ..................................................................... 8.3-12 8.3.1.3 Raceway/Cable ......................................................... 8.3-12 8.3.1.4 Inspection and Testing .............................................. 8.3-13 8.3.2 DC Power Systems .................................................................... 8.3-14 8.3.2.1 Description ................................................................ 8.3-14 8.3.2.2 Analysis ..................................................................... 8.3-18 8.3.2.3 Physical Identification of Safety-Related Equipment ................................................................. 8.3-19 8.3.2.4 Independence of Redundant Systems ...................... 8.3-20 8.3.2.5 Inspection and Testing .............................................. 8.3-22 8.3.3 Combined License Information for Onsite Electrical Power ........ 8.3-23 8.3.4 References ................................................................................. 8.3-24 8-i Revision 1
201 Not Used ...................................................................................................... 8.1-11 1-1 Onsite Standby Diesel Generator ZOS MG 02A Nominal Loads ................. 8.3-26 1-2 Onsite Standby Diesel Generator ZOS MG 02B Nominal Loads ................. 8.3-31 1-3 Component Data - Main AC Power System (Nominal Values) .................... 8.3-36 1-4 Post-72 Hours Nominal Load Requirements ................................................ 8.3-37 1-5 Indication and Alarm Points Standby Diesel Generators ............................. 8.3-38 2-1 250V DC Class 1E Division A Battery Nominal Load Requirements ........... 8.3-39 2-2 250V DC Class 1E Division B Battery Nominal Load Requirements ........... 8.3-40 2-3 250V DC Class 1E Division C Battery Nominal Load Requirements ........... 8.3-41 2-4 250V DC Class 1E Division D Battery Nominal Load Requirements ........... 8.3-42 2-5 Component Data - Class 1E DC System (Nominal Values) ......................... 8.3-43 2-6 Component Data - Non-Class 1E DC System EDS1 - EDS4 (Nominal Values) .......................................................................................... 8.3-44 2-7 Class 1E 250V DC and Class 1E Uninterruptible Power Supplies Failure Modes and Effects Analysis ......................................................................... 8.3-46 8-ii Revision 1
202 Switchyard General Arrangement ................................................................. 8.2-14 1-1 AC Power Station One Line Diagram........................................................... 8.3-50 1-2 Onsite Standby Diesel Generator Initiating Circuit Logic Diagram............... 8.3-51 1-3 Post-72-Hour Temporary Electric Power One Line Diagram ....................... 8.3-52 1-4 Diesel Generator System Piping and Instrumentation Diagram (Sheet 1 of 2) ................................................................................................ 8.3-53 1-4 Diesel Generator System Piping and Instrumentation Diagram (Sheet 2 of 2) ................................................................................................ 8.3-54 1-5 Diesel Engine Skid Mounted System (Sheet 1 of 2) .................................... 8.3-55 1-5 Diesel Engine Skid Mounted System (Sheet 2 of 2) .................................... 8.3-56 2-1 Class 1E DC System One Line Diagram (Sheet 1 of 2)............................... 8.3-57 2-1 Class 1E DC System One Line Diagram (Sheet 2 of 2)............................... 8.3-58 2-2 Class 1E 208y/120V UPS One Line Diagram .............................................. 8.3-59 2-3 Non-Class 1E DC & UPS System One Line Diagram (Sheet 1 of 3) ........... 8.3-60 2-3 Non-Class 1E DC & UPS System One Line Diagram (Sheet 2 of 3) .......... 8.3-61 2-3 Non-Class 1E DC & UPS System One Line Diagram (Sheet 3 of 3) .......... 8.3-62 8-iii Revision 1
1 Utility Grid Description e Energy is an investor-owned utility serving the Piedmont region of North Carolina and South olina. The Duke Energy transmission system consists of interconnected hydro plants, fossil-ed plants, combustion turbine units and nuclear plants supplying energy to the service area at ous voltages up to 525 kV. The transmission system is interconnected with neighboring utilities, together, they form the Virginia-Carolina Subregion of the Southeastern Electric Reliability ncil.
Nuclear Station Units 1 and 2 are located in the eastern portion of Cherokee County in north tral South Carolina, approximately 35 miles southwest of Charlotte, North Carolina, approximately miles northeast of Spartanburg, South Carolina and approximately 7.5 miles southeast of Gaffney, th Carolina. The power from Unit 1 is transmitted via an overhead transmission line to a 230 kV chyard. Similarly, the power from Unit 2 is transmitted via an overhead transmission line to a kV switchyard.
230 kV switchyard is located south of Unit 1 and is tied to the Duke Energy Carolinas 230 kV work by two double circuit overhead lines, namely Roddey East (northeast to Catawba) and dey West (southwest to Pacolet).
525 kV switchyard is located east of the 230 kV switchyard and is tied to the Duke Energy kV network by two single circuit overhead lines, namely Asbury East (northeast to Newport) and ury West (southwest to Oconee). The 525 kV switchyard is also connected to the 230 kV chyard through autotransformers.
2 Onsite Power System Description onsite power system is comprised of the main ac power system and the dc power system. The n ac power system is a non-Class 1E system. The dc power system consists of two independent ems: Class 1E dc system and non-Class 1E dc system. The ac and dc onsite power system figurations are shown on Figures 8.3.1-1 and 8.3.2-1, 8.3.2-2 and 8.3.2-3, respectively.
normal ac power supply to the main ac power system is provided from the station main erator. When the main generator is not available, plant auxiliary power is provided from the chyard by backfeeding through the main stepup and unit auxiliary transformers. This is the erred power supply. When neither the normal or the preferred power supply is available due to an trical fault at either the main stepup transformer, unit auxiliary transformer, isophase bus, or kv nonsegregated bus duct, fast bus transfer will be initiated to transfer the loads to the reserve iliary transformers powered by maintenance sources of power. In addition, two non-Class 1E ite standby diesel generators supply power to selected loads in the event of loss of the normal, erred, and maintenance power sources. The reserve auxiliary transformers also serve as a rce of maintenance power. The maintenance sources are as described.
main generator is connected to the offsite power system by three single-phase stepup sformers. The normal power source for the plant auxiliary ac loads comes from the generator bus ugh two unit auxiliary transformers of identical rating. In the event of a loss of the main generator, power is maintained without interruption from the preferred power supply by an autotrip of the 8.1-1 Revision 1
are single-phase main stepup transformer is provided in the transformer area. The spare can be ed in service upon failure of one phase of the main stepup transformers.
onsite standby power system, powered by the two onsite standby diesel generators, supplies er to selected loads in the event of loss of other ac power sources. Loads that are priority loads nvestment protection due to their specific functions (permanent nonsafety loads) are selected for ess to the onsite standby power supply. Availability of the standby power source is not required to omplish any safety function.
maintenance power supplies are provided at the medium voltage (6.9 kV) buses through mally open circuit breakers. Bus transfer to maintenance source either is automatic under fast bus sfer logic or may be initiated manually.
r independent divisions of Class 1E 250 Vdc battery systems are provided for the Class 1E dc UPS system. Divisions B and C have two battery banks; one battery bank is sized to supply er to safety-related loads for at least 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and the other battery bank is sized to supply power second set of safety-related loads for at least 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> following a design basis event (including loss of all ac power). Divisions A and D have one 24-hour battery bank. The loads are assigned to h battery bank, depending on their required function, during the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> coping period so that no ual or automatic load shedding is required for the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Two ancillary diesel generators provided for power for Class 1E post-accident monitoring, MCR lighting, MCR and I&C room tilation, and power to refill the PCS water storage tank and spent fuel pool if no other sources of ower are available.
ngle spare Class 1E battery bank is provided for both Class 1E and non-Class 1E battery ems and a separate spare charger is provided for each of the systems. In order to preserve pendence of each Class 1E dc system division, plug-in locking type disconnects are permanently alled to prevent connection of more than one battery bank to the spare. In addition, kirk-key rlock switches are provided to prevent transfer operation of more than one switchboard at a time.
spare battery bank is located in a separate room and is capable of supplying power to the uired loads on any battery being temporarily replaced with the spare.
non-Class 1E 125 Vdc power system provides continuous, reliable power to the plant nonsafety-ted dc loads. Operation of the non-Class 1E dc system is not required to accomplish any safety tion.
nterruptible power supplies (UPS) to the four independent divisions of the Class 1E 120 Vac rument buses are included in the Class 1E dc system. The normal power to the uninterruptible er supply comes from the respective Class 1E 250 Vdc bus. The backup power comes from the n ac power system through Class 1E 480-208Y/120V voltage regulating transformers. The same figuration applies for the uninterruptible power to the non-divisional, non-Class 1E 120 Vac rument buses. The normal power to the non-Class 1E uninterruptible power supply comes from non-Class 1E 125 Vdc bus and the backup power comes from the main ac power system through ltage regulating transformer.
3 Safety-Related Loads safety-related loads requiring Class 1E power are listed in Tables 8.3.2-1, 8.3.2-2, 8.3.2-3 and 2-4. Safety-related loads are powered from the Class 1E 250 Vdc batteries and the associated ss 1E 120 Vac instrument buses.
8.1-2 Revision 1
ite power has no safety-related function due to the passive design of the AP1000. Therefore, undant offsite power supplies are not required. The design provides a reliable offsite power em that minimizes challenges to the passive safety system.
4.2 Onsite Power System 4.2.1 Safety Design Basis The Class 1E dc and UPS power system meets the single failure criterion (GDC 17).
The Class 1E dc and UPS system has sufficient capacity to achieve and maintain safe shutdown of the plant for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> following a complete loss of all ac power sources without requiring load shedding for the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The Class 1E dc and UPS system is divided into four independent divisions. Any three-out-of-four divisions can shut down the plant safely and maintain it in a safe shutdown condition.
Separation criteria preserve the independence of redundant Class 1E circuits as described in Subsection 8.3.2.4 and no single credible event is capable of disabling redundant safety-related systems.
Special identification criteria are applied for Class 1E equipment, cabling, and raceways as described in Subsection 8.3.2.3.
The Class 1E systems and equipment are designed to permit periodic inspection and testing (GDC-18).
The Class 1E dc and UPS power system permits connection of any one 250 Vdc switchboard at a time to the spare battery and the spare battery charger. The spare battery and charger have sufficient capacity to permit continuous plant operation at 100-percent power in case of a failure or unavailability of one Class 1E battery bank and the associated battery charger.
Two ancillary diesel generators provide ac power for Class 1E post-accident monitoring, MCR lighting, MCR and I&C room ventilation, and power to refill the PCS water storage tank and spent fuel pool if no other sources of power are available. The equipment used to perform this function is not safety-related because it is not needed for a prolonged period following a loss of ac and it is easily replaced with transportable generators.
4.2.2 Power Generation Design Basis The main ac power system is a non-Class 1E system and nonsafety-related. The normal power supply to the main ac power system comes from the station main generator through two identically rated unit auxiliary transformers and an additional unit auxiliary transformer for the electric auxiliary boiler and as described site-specific loads.
The onsite standby power system supplies ac power to the selected permanent nonsafety loads in the event of a main generator trip concurrent with the loss of preferred power source and maintenance power source when under fast bus transfer conditions. The onsite standby diesel generators are automatically connected to the associated 6.9 kV buses upon loss of 8.1-3 Revision 1
The permanent nonsafety loads are not required for the plant safe shutdown; therefore, the onsite standby power system is a nonsafety-related system and non-Class 1E.
For continued operation of the plant, a spare single-phase main transformer can be placed in service upon failure of one phase of the main stepup transformers.
4.3 Design Criteria, Regulatory Guides, and IEEE Standards er to Table 8.1-1 for guidelines, and their applicability to Chapter 8.
offsite and onsite ac power systems have no safety function and, therefore, their conformance to eral Design Criteria, Regulatory Guides and IEEE Standards is not required, except as indicated able 8.1-1.
Class 1E dc power system design is based on the following:
General Design Criteria (GDC)
See Section 3.1 for a discussion of conformance to the General Design Criterion.
Nuclear Regulatory Commission (NRC) Regulatory Guides See Section 1.9 for the list and details of conformance to the regulatory guides.
IEEE Standards.
The Class 1E dc power system design is based on the following IEEE Standards that are generally acceptable to the NRC as stated in the referenced Regulatory Guides:
- IEEE 308-1991, IEEE Standard Criteria for Class 1E Power Systems for Nuclear Power Generating Stations. Refer to Regulatory Guide 1.32.
- IEEE 317-1983, IEEE Standard for Electrical Penetration Assemblies in Containment Structures for Nuclear Power Generating Stations. Refer to Regulatory Guide 1.63.
- IEEE 323-1974, IEEE Standard for Qualifying Class 1E Equipment for Nuclear Power Generating Stations. Refer to Regulatory Guide 1.89.
- IEEE 338-1987, IEEE Standard Criteria for the Periodic Surveillance Testing of Nuclear Power Generating Station Safety Systems. Refer to Regulatory Guide 1.118.
- IEEE 344-1987, IEEE Recommended Practice for Seismic Qualification of Class 1E Equipment for Nuclear Power Generating Stations. Refer to Regulatory Guide 1.100.
- IEEE 379-2000, IEEE Standard Application of the Single Failure Criterion to Nuclear Power Generating Station Safety Systems. Refer to Regulatory Guide 1.53.
8.1-4 Revision 1
- IEEE 383-1974, IEEE Standard for Type Test of Class 1E Electric Cables, Field Splices, and Connections for Nuclear Power Generating Stations. Refer to Regulatory Guide 1.131.
- IEEE 384-1981, IEEE Standard Criteria for Independence of Class 1E Equipment and Circuits. Refer to Regulatory Guide 1.75.
- IEEE 450-1995, IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries for Stationary Applications. Refer to Regulatory Guide 1.32.
- IEEE 484-1996, IEEE Recommended Practice for Installation Design and Installation of Vented Lead-Acid Batteries for Stationary Applications. Refer to Regulatory Guide 1.128.
- IEEE 741-1997, IEEE Standard Criteria for the Protection of Class 1E Power Systems and Equipment in Nuclear Power Generating Stations. Refer to Regulatory Guide 1.63.
- IEEE 1202-1991, IEEE Standard for Flame Testing of Cables for Use in Cable Tray in Industrial and Commercial Occupancies.
5 Combined License Information section contained no requirement for information.
8.1-5 Revision 1
Applicability(a)
(Section/Subsection)
Criteria 8.2 8.3.1 8.3.2 Remarks 10CFR50 Appendix A -
General Design Criteria (GDC) (See Section 3.1 for a discussion of conformance to each of the GDC).
. GDC 2 Design Bases for Protection A Against Natural Phenomena
. GDC 4 Environmental and Missile Design A Basis GDC 5 Sharing of Structures, Systems, not applicable and Components
. GDC 17 Electric Power Systems A
. GDC 18 Inspection and Testing of Electric A Power Systems GDC 50 Containment Design Basis A A applicable to penetration design "A" denotes applicable to AP1000, and "G" denotes guidelines as defined in NUREG-0800, Rev. 3, Table 8-1 (SRP). No letter denotes "Not Applicable."
8.1-6 Revision 1
Applicability(a)
(Section/Subsection)
Criteria 8.2 8.3.1 8.3.2 Remarks Regulatory Guide (See Section 1.9 for list and discussion of conformance to the Regulatory Guides).
. RG 1.6 Independence Between G Redundant Standby (Onsite)
Power Sources and Between Their Distribution Systems
. RG 1.9 Selection, Design, and not applicable Qualification of Diesel Generator Units Used as Stand-by (Onsite)
Electric Power Systems at Nuclear Power Plants RG 1.32 Criteria for Safety-Related Electric G Power Systems for Nuclear Power Generating Stations
. RG 1.47 Bypassed and Inoperable Status G Indication for Nuclear Power Plant Safety Systems
. RG 1.63 Electric Penetration Assemblies in G G Containment Structures for Nuclear Power Plants RG 1.75 Physical Independence of Electric G Systems
. RG 1.81 Shared Emergency and Shutdown not applicable Electric Systems for Multi-Unit Nuclear Power Plants "A" denotes applicable to AP1000, and "G" denotes guidelines as defined in NUREG-0800, Rev. 3, Table 8-1 (SRP). No letter denotes "Not Applicable."
8.1-7 Revision 1
Applicability(a)
(Section/Subsection)
Criteria 8.2 8.3.1 8.3.2 Remarks
. RG 1.106 Thermal Overload Protection for G Electric Motors on Motor-Operated Valves RG 1.108 Periodic Testing of Diesel not applicable Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants RG 1.118 Periodic Testing of Electric Power G and Protection Systems RG 1.128 Installation Design and Installation G of Large Lead Storage Batteries for Nuclear Power Plants RG 1.129 Maintenance, Testing, and G Battery Service tests are performed Replacement of Vented Lead-Acid in accordance with the requirements Storage Batteries for Nuclear of the Regulatory Guide.
Power Plants
. RG 1.131 Qualification Tests of Electric G The insulating and jacketing Cables, Field Splices, and material for electrical cables are Connections for Light-Water- selected to meet the fire and flame Cooled Nuclear Power Plants test requirements of IEEE Standard 1202 or IEEE Standard 383 excluding the option to use the alternate flame source, oil or burlap.
RG 1.155 Station Blackout Not applicable(b)
RG 1.204 Guidelines for Lightning Protection G Implemented via IEEE 665.
of Nuclear Power Plants RG 1.206 Combined License Applications for G G G Nuclear Power Plants (LWR Edition)
"A" denotes applicable to AP1000, and "G" denotes guidelines as defined in NUREG-0800, Rev. 3, Table 8-1 (SRP). No letter denotes "Not Applicable."
Station Blackout, and the associated guidelines, was addressed as a design issue in Subsection 1.9.5.1.5.
8.1-8 Revision 1
Applicability(a)
(Section/Subsection)
Criteria 8.2 8.3.1 8.3.2 Remarks Branch Technical Position (BTP)
. BTP Requirements on Motor-Operated G see 1.9.2 ICSB 4 Valves in the ECCS Accumulator (PSB) Lines
. BTP Use of Diesel-Generator Sets for not applicable ICSB 8 Peaking (PSB)
BTP Stability of Offsite Power Systems G Stability Analysis of the Offsite 8-3 Power System is performed in ICSB 11 accordance with the BTP.
(PSB)
. BTP Application of the Single Failure G see 1.9.2 ICSB 18 Criterion to Manually Controlled (PSB) Electrically-Operated Valves
. BTP Guidance for Application of G see also 7.5 ICSB 21 RG 1.47 BTP Adequacy of Station Electric not applicable PSB 1 Distribution System Voltages
. BTP Criteria for Alarms and Indications not applicable PSB 2 Associated with Diesel-Generator Unit Bypassed and Inoperable Status "A" denotes applicable to AP1000, and "G" denotes guidelines as defined in NUREG-0800, Rev. 3, Table 8-1 (SRP). No letter denotes "Not Applicable."
8.1-9 Revision 1
Applicability(a)
(Section/Subsection)
Criteria 8.2 8.3.1 8.3.2 Remarks NUREG Reports
. NUREG Enhancement of Onsite Diesel not applicable CR0660 Generator Reliability "A" denotes applicable to AP1000, and "G" denotes guidelines as defined in NUREG-0800, Rev. 3, Table 8-1 (SRP). No letter denotes "Not Applicable."
8.1-10 Revision 1
Not Used 8.1-11 Revision 1
normal ac power supply to the main ac power system is provided from the main generator. When main generator is not available, plant auxiliary power is provided from the switchyard by kfeeding through the main stepup and unit auxiliary transformers. This is the preferred power ply. When neither the normal or the preferred power supply is available due to an electrical fault at er the main stepup transformer, unit auxiliary transformer, isophase bus, or 6.9 kv nonsegregated duct, fast bus transfer will be automatically initiated to transfer the loads to the reserve auxiliary sformers powered by maintenance sources of power. In addition, two non-Class 1E onsite dby diesel generators supply power to selected plant loads in the event of loss of the normal, erred, and maintenance power sources. The reserve auxiliary transformers also serve as a rce of maintenance power.
ntenance power is provided at the medium voltage level (6.9 kV) through normally open circuit akers. Bus transfer to the maintenance source is automatic under fast bus transfer logic or may nitiated manually.
Nuclear Station is connected into an interconnection switchyard designed to operate at a inal voltage of 230 kV and 525 kV.
1 is connected to the 230 kV switchyard, and Unit 2 is connected to the 525 kV switchyard.
re are four transmission lines connected to the 230 kV switchyard, and two transmission lines nected to the 525 kV switchyard. As shown below, each transmission line is tied into a Duke smission line or switchyard located between 19 and 95 miles from the station. The rconnection of Units 1 and 2, the switchyard, and the 230 and 525 kV transmission systems is wn in Figures 8.2-201 and 8.2-202.
Length Thermal Rating Transmission Line Termination Point (miles) (MVA) dey West WH (230 kV) Pacolet Tie 19 916 dey West BL (230 kV) Pacolet Tie 19 916 dey East WH (230 kV) Catawba Nuclear Station 34 1114 dey East BL (230 kV) Catawba Nuclear Station 34 1114 ry East (525 kV) Newport Tie 41 3910 ry West (525 kV) Oconee Tie 95 3910 1 is connected to the Duke Transmission System via the Roddey East and Roddey West 230 kV
- s. The Roddey lines consist of a section of line, 34 miles in length, from Lee Nuclear Station to awba Nuclear Station and a section of line, 19 miles in length, from Lee Nuclear Station to Pacolet 230 kV line is constructed on a 150 ft. wide right-of-way with double circuit lattice steel towers, ing in height from 120 ft. to 190 ft. with a nominal height of 150 ft. Conductors are two per phase horizontal bundle. The vertical phase spacing is 19.5 ft. to 22.5 ft. The lines are designed to meet 8.2-1 Revision 1
2 is connected to the Duke Transmission System via the Asbury 525 kV line. This line consists of ction of line, 41 miles in length, from Lee Nuclear Station to Newport Tie and a section of line, miles in length, from Lee Nuclear Station to Oconee Nuclear Station. The 525 kV line is structed on a 200 ft. wide right-of-way with single circuit lattice steel towers, varying in height from ft. to 150 ft. with a nominal height of 140 ft. Conductors are two per phase in a horizontal bundle.
lines are designed to meet or exceed the requirements of the ANSI C2 National Electric Safety e (Subsection 8.2.6 Reference 1). The 525 kV lines are designed to keep the electric field at the ductor surface significantly below corona inception.
ansformer area containing generator step-up (GSU) transformers, unit auxiliary transformers Ts), and reserve auxiliary transformers (RATs) is located next to each turbine building.
main generator is connected to the offsite power system via three single-phase main stepup sformers. The normal power source for the plant auxiliary ac loads is provided from the isophase erator bus through the two unit auxiliary transformers of identical ratings. In the event of a loss of main generator, the power is maintained without interruption from the preferred power supply by uto-trip of the main generator breaker. Power then flows from the transformer area to the iliary loads through the main and unit auxiliary transformers.
transmission line structures associated with the plant are designed to withstand standard loading ditions for the specific-site as provided in Reference 1.
omatic load dispatch is not used at the plant and does not interface with safety-related action uired of the reactor protection system.
1.1 Transmission Switchyard 230 kV switchyard connects Unit 1 to the 230 kV transmission system. The 525 kV switchyard nects Unit 2 to the 525 kV transmission system. Both switchyards utilize a breaker and a half configuration with a red and yellow bus. All breakers are in the closed position with red and ow buses energized under normal operation. The two switchyards are connected by two 230 kV 25 kV autotransformers.
230 kV switchyard is configured to accept a maximum of four 230 kV lines interconnecting the smission grid by two 230 kV double circuit lines. There are two terminals dedicated to ommodate the two autotransformers, one terminal for the Unit 1 GSU connection, one terminal for nection to the Unit 1 RATs, one terminal for connection to the Unit 2 RATs, and three spare circuit itions.
525 kV switchyard is configured to accommodate two incoming transmission lines, two transformer connections, the Unit 2 GSU, and three spare circuit positions.
configuration of the switchyard is shown in Figure 8.2-201. The switchyard structure is tubular l design with all power circuit breakers and switches fully rated for the ultimate load and fault ent levels to which the switchyard might be exposed. The nominal continuous current ratings of installed equipment (based on a nominal operating temperature of key elements at 90 Deg C) is 8.2-2 Revision 1
ure Analysis design of the offsite power system provides for a robust system that supports reliable power duction. Offsite power is not required to meet any safety function and physical independence is iated by this lack of safety function and by the AP1000s partial exemption to General Design eria (GDC) 17 granted by the NRC during design certification. Nevertheless, multiple, reliable smission circuits are provided to support operation of the facility. Neither the accident analysis the Probabilistic Risk Assessment has identified the nonsafety-related offsite power system as significant for normal plant operation.
230 kV switchyard is connected to four transmission lines and the 525 kV switchyard is nected to two transmission lines. No single transmission line to either switchyard is designated as preferred circuit, but each line has sufficient capacity and capability from the transmission work to power the safety-related systems and other auxiliary systems under normal, abnormal, accident conditions.
ilure modes and effect analysis (FMEA) of the Lee Nuclear Station switchyard confirms that a le initiating event, such as an offsite transmission line fault, plus a single breaker failure still ides the availability of at least one off-site transmission source to the switchyards. This luation recognizes that a single failure of some switchyard components could directly cause the of switchyard feed to the GSU, such as a fault on the main busline feed.
luated events in the FMEA include a breaker not operating during a fault on an offsite smission line; fault on a switchyard bus; fault on an autobank; a spurious relay trip; and a loss of trol power supply. Some possible component outage combinations that can occur as a result of a le faulted zone and a breaker failure to trip are: 1 line and a bus, 1 line and a units RATs, 1 bus an autobank or 2 autobanks. In summary:
In the event of a fault on a 230kV or 525kV transmission line, the line protection relays sense the fault and cause the associated breakers to trip. The four busses, two autobanks, and the unaffected transmission lines remain energized. Both units continue operation.
In the event of a fault on a transmission line concurrent with a stuck bus breaker, breaker failure protection causes circuit breakers on the associated bus to trip and isolate the fault.
The three unaffected busses, the two autobanks, and the unaffected transmission lines remain energized. Both units continue operation.
In the event of a fault on a transmission line concurrent with a stuck middle breaker, breaker failure protection causes circuit breakers on the associated Unit RAT busline to trip and isolate the fault. The four busses, the two autobanks, and the unaffected transmission lines remain energized. The affected unit's RATs are de-energized, and both units continue operation.
In the event of a fault on a Unit RAT busline line concurrent with a stuck bus breaker, breaker failure protection causes circuit breakers on the associated bus to trip and isolate the fault.
The three unaffected busses, the two autobanks, and the transmission lines remain energized. The affected unit's RATs are de-energized, and both units continue operation.
8.2-3 Revision 1
energized. The affected unit's RATs are de-energized, and both units continue operation.
In the event of a fault on a 230kV/525kV autobank, transformer protective relays sense the fault and trip the associated autobank breakers. The four busses, one autobank, and the transmission lines remain energized. Both units continue operation.
In the event of a fault on a 230kV/525kV autobank concurrent with a stuck bus breaker, breaker failure protection causes circuit breakers on the associated bus to trip and isolate the fault. The three unaffected busses, one autobank, and the transmission lines remain energized. Both units continue operation.
In the event of a fault on a 230kV/525kV autobank concurrent with a stuck middle breaker, breaker failure protection causes the circuit breakers associated with both autobanks to trip and isolate the fault. The four busses and the transmission lines remain energized. Both units continue operation.
In the event of a fault on a bus, the bus differential relays sense the fault and trip the associated bus breakers. The three unaffected busses, the two autobanks, and the transmission lines remain energized. Both units continue operation.
In the event of a fault on a bus concurrent with a stuck breaker associated with a transmission line, breaker failure protection causes the associated transmission line breakers to trip and isolate the fault. The three unaffected busses, the two autobanks, and the unaffected transmission lines remain energized. Both units continue operation.
In the event of a fault on a bus concurrent with a stuck breaker associated with an autobank, breaker failure protection causes the associated autobank breakers to trip and isolate the fault. The three unaffected busses, one autobank, and the transmission lines remain energized. Both units continue operation.
In the event of a bus fault concurrent with a stuck breaker associated with a Unit RAT busline, breaker failure protection causes the associated RAT busline middle breaker to trip and isolate the fault. The three unaffected busses, the two autobanks, and the transmission lines remain energized. The affected unit's RATs are de-energized, and both units continue operation.
In the event of a fault on a bus concurrent with a stuck unit busline breaker, breaker failure protection causes the adjacent busline breaker to trip, interrupting power to the associated GSU and UATs resulting in a reactor trip. The three unfaulted busses, the two autobanks, and the transmission lines remain energized. In this event, both units' RATs remain energized and the unaffected unit continues operation. The affected unit's auxiliary systems are powered through the associated RATs.
In the case of a loss of DC control power, the loss of control power to a breaker or switchyard primary protective relay is compensated for by redundant trip coils powered from a different source which allows the protective function to occur. Both units continue operation.
In the case of a spurious trip output of a single protective relay providing line, autobank, or bus protection; the associated switchyard breakers trip, isolating the one affected line, autobank, or bus. The unaffected busses, autobank(s), and transmission lines remain energized. Both units continue operation.
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results of the analysis confirm that in each scenario, the power source for the unit auxiliary ems remains available, either to the GSU or the RATs. No combination results in an outage on a U and the associated unit's RATs. While continued operation of the unit is not a success criterion, fact that the units continue operation through most failure scenarios is an indication of the ustness of the switchyard design.
nsmission System Provider/Operator:
e Energy is a regulated, vertically integrated utility with regards to its electric generation and smission operations. Duke Energys Nuclear Generation Department (NGD) has a formal eement titled Nuclear Switchyard Interface Agreement with the transmission system operator O), which is Duke Energys Power Delivery (PD) department. The PD department includes the nsmission Control Center (TCC), transmission System Operation Center, and transmission nning and Grid Operations. The Nuclear Switchyard Interface Agreement and associated artment Directives serve as the communications protocol with the TSO. These documents itate adequate and prompt communications between the TSO and the plant operators.
e Energy is also the transmission system provider (TSP). The TSP/TSO establishes a voltage edule for the 230 kV & 525 kV switchyard. The nuclear power plant, while generating, is expected upply or absorb reactive power to help regulate voltage in the 230/525 kV switchyard in ordance with TSP/TSO voltage schedule criteria. The TSP/TSO also maintains switchyard age such that voltage on the 26 kV isophase bus is within 0.95 - 1.05 pu of its nominal value.
plants operator workstations monitor switchyard voltage, frequency, and other offsite power em parameters. The operator workstations are set to alert the nuclear plant operator if the grid not be able to supply offsite power of sufficient voltage. Procedures direct the plant operators to tact the TSO and request a status of the most current contingency analysis for existing grid ditions. If the results of the contingency analysis indicate that insufficient voltage would exist in switchyard, the procedures direct the plant operators to take appropriate actions.
Nuclear Switchyard Interface Agreement between NGD and PD sets the requirements for smission system studies and analyses. These analyses demonstrate the capability of the offsite ider of supporting plant start up and normal shutdown.
is the approving grid organization for reliability studies performed on the area bulk electric em. PD conducts planning studies of the transmission grid on an ongoing basis. Model data used erform simulation studies of projected future conditions is maintained and updated as load casts and future generation / transmission changes evolve. Studies are performed annually to ess future system performance in accordance with North American Electric Reliability Corporation RC) reliability standards. These studies form a basis for identifying future transmission expansion ds.
large generating units requesting to connect to the area bulk electric system are required to plete the Large Generator Interconnection Procedure (LGIP). The studies performed by Duke rgy TSO as part of this procedure, examine the generating unit (combined turbine-generator-ter) and the main step-up transformer(s).
Nuclear Switchyard Interface Agreement between NGD and PD demonstrates protocols in place he plant to remain cognizant of grid vulnerabilities and make informed decisions regarding ntenance activities critical to the electrical system.
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smission topology patterns.
1.2 Transformer Area transformer area contains the main stepup transformers, the unit auxiliary transformers, and the rve auxiliary transformers. Protective relaying and metering required for this equipment is ted in the turbine building. The necessary power sources (480 Vac, 120 Vac, and 125 Vdc) to the ipment are supplied from the turbine building. See Subsection 9.5.1 for a discussion of fire ection associated with plant transformers.
feeder connects the transformer area with the switchyard to supply power to/from the main up transformers for the unit. An arrangement is shown in Figure 8.3.1-1.
transformer area for each unit contains the GSU (3 single phase transformers plus one spare),
e UATs, and two RATs. The two RATs per unit are connected to the 230 kV switchyard. The ondary (high voltage side) windings of the three single-phase generator step-up (GSU) sformers are connected in wye configuration and connect to the 230 kV switchyard and 525 kV chyard for Units 1 and 2, respectively.
1.2.1 Switchyard Transformer Ratings autotransformers connect the 230 kV and 525 kV switchyards. Each autotransformer is rated kV to 230 kV, 750/810 MVA @ 55°C/65°C with a tertiary winding rated 13 kV, 54.2/60.7 MVA @
C/65°C.
1.2.2 Switchyard Protection Relay Scheme 230 kV and 525 kV switchyards each have two main buses for their respective voltage level. All e 230 kV and 525 kV lines and each of the GSUs are normally connected to both buses in their ective switchyard. This switchyard scheme is referred to as a breaker and a half scheme. This ngement is used for reliability and flexibility, and allows for isolation of components and buses, e preserving the plants connection to the grid.
er normal operating conditions, all circuit breakers and all bus sectionalizing motor operated onnects are closed, and all bus sections are energized.
transmission line relay protection circuits continuously monitor the conditions of the offsite power em and are designed to detect and isolate the faults with maximum speed and minimum urbance to the system. The principal features of these schemes are described below:
h of the 230 kV and 525 kV lines are protected by two independent pilot systems to clear for a t anywhere on the line. The two autotransformers each have primary and secondary protective ying.The primary and secondary relaying use separate instrument current transformers for itoring, and separate DC power supplies.
breaker failure relays operate after a preset time delay. Should a breaker fail to trip within the setting, the associated breaker failure trip relay will trip and lock out all breakers necessary to ate the failed breaker from all local sources. A breaker failure relay operation for 230 kV and/or kV switchyard breakers that are connected to GSU, RAT, and Autobank transformers will also ate the appropriate remote sources through a direct transfer trip operation.
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1.2.3 Plant Response to High Voltage Open Phase Condition onitoring system is installed on the credited GDC 17 offsite power circuit that provides continuous n phase condition monitoring of the MSU transformer HV input power supply (see erence 201). The system detects an open phase condition (with or without a concurrent high edance ground on the HV side of the transformer) on one or more phases under all transformer ing conditions. The open phase condition monitoring system provides an alarm to the operators e control room should an open phase condition occur on the HV source to the MSU transformers.
system design utilizes commercially available components including state of the art digital ying equipment and input parameters as required to provide loss of phase detection and alarm ability.
itionally, a high-voltage open phase condition with or without a ground fault can manifest itself as nacceptable voltage on the 6.9 kV medium voltage ES-1 and ES-2 buses during normal loading ditions. The presence of unacceptable voltages on the ES-1 and ES-2 buses results in isolation of affected medium voltage bus from the offsite power supply and enables the onsite standby diesel erators to start and restore AC power to the ES-1 and ES-2 buses and associated defense-in-th loads. The onsite AC power system is described in Subsection 8.3.1 or management relays for the medium voltage motors on ES-1 and ES-2 provide detection of cceptably high negative sequence currents. High negative sequence current motor trips or other ning load trips provide alarms in the MCR, which can assist in the detection of a high-voltage open se condition with or without a ground fault. Electric circuit protection for the medium voltage em and equipment is described in Subsection 8.3.1.1.1.1 gh-voltage open phase condition with or without a ground fault can also manifest itself as an cceptable voltage on the 480 VAC low-voltage buses powered from ES-1 and ES-2. The safety-ted IDS battery chargers are powered from the low-voltage buses and continue to charge the IDS eries unless the battery charger input or output monitored electrical parameters are cceptable. If the monitored electrical parameters degrade to the point that the battery charger no er provides sufficient DC bus voltage, the Class 1E electrical system DC bus receives power the applicable IDS battery and the battery charger maintains isolation between the
-Class 1E AC and Class 1E DC power systems which generates alarms in the MCR. The onsite power system is described in Subsection 8.3.1 and the Class 1E DC power system is described ubsection 8.3.2.1.1.
rator actions and maintenance and testing activities are addressed in procedures, as described ection 13.5. Plant operating procedures, including off-normal operating procedures associated the monitoring system will be developed prior to fuel load. Maintenance and testing procedures, uding calibration, surveillance testing, setpoint determination and troubleshooting procedures ociated with the monitoring system will be developed prior to fuel load.
trol Room operator and maintenance technician training associated with the operation and ntenance of the monitoring system will be conducted in accordance with the milestones for Non nsed Plant Staff and Reactor Operator Training Programs in Table 13.4-201.
1.3 Switchyard Relay House elay House is erected to serve the needs of the switchyard. The size of this building is roximately 40 ft. x 60 ft. The Relay House contains the switchyard batteries (redundant battery ems are contained in separate battery rooms and appropriately ventilated) and is capable of 8.2-7 Revision 1
kV and 525 kV breakers associated with the GSUs (yellow bus and mid-tie breakers) are under rational control of the plant. Engineering and maintenance is the responsibility of PD. The trols for these breakers will be located inside the plant. Manual controls will be duplicated in the chyard Relay House as well.
will have operational control over all the other breakers in the 230 kV and 525 kV switchyards luding those associated with the RATs) with manual controls located in the switchyard Relay se.
1.4 Switchyard & Transmission Lines Testing & Inspection as owner of the interconnection facilities, has ongoing inspection and maintenance programs to ide for the continuous reliable operation of those facilities and others under the charge of the smission owner. The maintenance and inspection programs leverage a combination of best utility tices, operating experience and equipment manufacturers recommendations to determine the uency and type of maintenance.
performance of maintenance, testing, calibration and inspection, PD follows its own field test uals, vendor manuals and drawings, industrys maintenance practices to comply with applicable RC Reliability Standards.
al inspection of transmission lines in the Duke Energy system are performed twice per year. The ection has a specific focus on right-of-way encroachments, vegetation management, conductor line hardware condition assessment, and supporting structures. Herbicides are used to control etation within the boundaries of the transmission line rights-of-way. Where herbicides cannot be lied, vegetation is cut and removed. This cutting and removal effort is extended beyond the formal t-of-way limit to address the presence of any danger trees which may adversely impact the ration of the transmission line.
interconnecting switchyard as well as other switchyard facilities have multiple levels of inspection maintenance. These include the following:
Walk through and visual inspection of the entire switchyard facility.
Relay functional tests.
Oil sampling of large power transformers. Oil samples are evaluated through the use of gas chromatography and dielectric breakdown analysis.
Power circuit breakers are subjected to three levels of inspection and maintenance. The frequency of each is a function of number of operations and time. Maintenance leverages the use of external visual inspection of all functional systems, an external test, and an internal inspection. Frequency of the various maintenance/inspection efforts is based on a combination of operating history of the type of breaker, industry practice and manufacturers recommended maintenance requirements.
A power test (Doble Test) is typically performed on oil filled equipment.
Thermography is used to identify potential thermal heating issues on bus, conductors, connectors and switches.
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grity and, therefore, does not depend on the electric power grid for safe operation. This feature of AP1000 significantly reduces the importance of the grid connection and the requirement for grid ility. The AP1000 safety analyses assume that the reactor coolant pumps can receive power from er the main generator or the grid for a minimum of 3 seconds following a turbine trip.
AP1000 main generator is connected to the generator bus through the generator circuit breaker.
grid is connected to the generator bus through the main step-up transformers and the grid akers. The reactor coolant pumps are connected to the generator bus through the reactor coolant p breakers, the 6.9 kV switchgear, and the unit auxiliary transformers. During normal plant ration the main generator supplies power to the generator bus. Some of this power is used by the t auxiliary systems (including the reactor coolant pumps); the rest of the power is supplied to the uring power operation of the plant, a turbine trip occurs, the motive power (steam) to the turbine be removed. The generator will attempt to keep the shaft rotating at synchronous speed erned by the grid frequency) by acting like a synchronous motor. The reverse-power relay itoring generator power will sense this condition and, after a time delay of at least 15 seconds, n the generator breaker. During this delay time the generator will be able to provide voltage port to the grid if needed. The reactor coolant pumps will receive power from the grid for at least conds following the turbine trip. A grid stability analysis to show that, with no electrical system res, the grid will remain stable and the reactor coolant pump bus voltage will remain above the age required to maintain the flow assumed in the Chapter 15 analyses for a minimum of conds following a turbine trip is as addressed in Subsection 8.2.5. In the Chapter 15 analyses, if initiating event is an electrical system failure (such as failure of the isophase bus), the analyses ot assume operation of the reactor coolant pumps following the turbine trip. The responsibility for ing the protective devices controlling the switchyard breakers with consideration given to erving the plant grid connection following a turbine trip is discussed in Subsection 8.2.5.
e turbine trip occurs when the grid is not connected (generator supplying plant house loads only),
main turbine-generator shaft will begin to slow down as the energy stored in the rotational inertia e shaft is used to supply the house loads (including reactor coolant pumps). The system will st down until the generator exciter can no longer maintain generator terminal voltage and the erator breaker is tripped on either generator under-voltage or exciter over-current. This coast n will last at least 3 seconds before the generator breaker trips.
sequence of events following a loss-of-offsite-power event is the same as those described for
-disconnected operation.
Duke transmission system is designed to conform to transmission planning standards blished by the NERC. The NERC transmission planning standards are written such that each mbers system is designed to avoid system cascading upon the occurrence of several categories vents, including loss of generation, loss of transmission, and loss of load.
dies are made periodically to verify that the transmission facilities conform to the NERC dards.
id stability study of the offsite power system was performed, and is updated as necessary for ificant system changes. In order to maintain reactor coolant pump (RCP) operation for three onds following a turbine trip as specified in Subsection 8.2.2, the grid voltage at the high-side of GSU and RATs cannot drop below a level that provides less than 80 percent of the nominal age at the RCP.
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The inrush kVA for motors is 56,712 kVA1; The nominal voltage is 1.00 pu for both the 525 kV and 230 kV switchyards; The allowable voltage regulation is 0.95 1.05 pu (steady state);
The nominal frequency is 60 Hz; The allowable frequency fluctuation is +/-0.5 Hz (steady state);
The maximum frequency decay rate is 5 Hz/sec; and The limiting under frequency value for RCP is greater than 57.7 Hz.
study analyzes cases for load flow and transient stability using the Duke Energy system summer k case. In order to complete the forward-looking study, the following assumptions are made:
Grid voltage is 230 kV and 525 kV.
GSU tap settings selected are 235 kV (+2.5%) for 230 kV System and 525 kV (nominal) for the 525 kV system.
GSU output voltage is 1.00 pu for Unit 1 and 1.01 pu for Unit 2.
Autotransformer (230/525 kV) tap setting is 240/537.5 kV.
computer analysis is performed using the Siemens Power Technology International
/E software. The analysis examines three conditions:
- 1. Normal Running
- 2. Turbine Trip
- 3. Not in Service/Shutdown h condition is modeled both with and without the other Lee Nuclear Station unit running. Other ditions (i.e. startup, normal shutdown) are bounded by these analyses.
results of the study conclude that the transmission system remains stable preserving the grid nection, and supports RCP operation for at least three seconds following a turbine trip under the eled conditions. The 80 percent voltage requirement is also met when there is another smission element out of service, including the largest generator or most critical transmission line.
study finds that both Lee Nuclear Station units are transiently stable and meet voltage uirements for the evaluated contingencies.
Based on the inrush of a single 10,000 HP feedwater pump, assuming efficiency = 0.95, pf = 0.9, inrush = 6.5 X FLA, and locked rotor power factor = 0.15.
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stability analysis has confirmed that the interface requirements for steady state load, nominal age, allowable voltage regulation, nominal frequency, allowable frequency fluctuation, and imum frequency decay rate have been met.
lve years of average outage data available on the Duke transmission system can be summarized ollows:
- 1. The Momentary Average Interruption Frequency Index is 0.28 for the 230 kV system and 0.78 for the 525 kV system.
- 2. The Transmission System Average Interruption Frequency Index for sustained
(>1 minute) outages is 0.08 for the 230 kV system and 0.37 for the 525 kV system.
- 3. The Transmission System Average Interruption Duration Index (Minutes) is 31.8 for the 230 kV system and 210 for the 525 kV system.
3 Conformance to Criteria offsite sources are not Class 1E. Commercial equipment is manufactured to the industrial dards listed in Subsection 8.2.6. The design meets General Design Criterion 1. Unit trips occur at generator breaker and do not cause the loss of the preferred power source to the plant electrical ems. The AP1000 does not require ac power sources for mitigating design basis events; pter 15 describes the design bases assumptions utilized for analysis of these events.
AP1000 plant design supports an exemption to the requirement of GDC 17 for two physically pendent offsite circuits by providing safety-related passive systems for core cooling and tainment integrity, and multiple nonsafety-related onsite and offsite electric power sources for r functions. See Section 6.3 for additional information on the systems for core cooling.
liable dc power source supplied by batteries provides power for the safety-related valves and rumentation during transient and accident conditions.
Class 1E dc and UPS system is the only safety-related power source required to monitor and ate the safety-related passive systems. Otherwise, the plant is designed to maintain core cooling containment integrity, independent of nonsafety-related ac power sources indefinitely. The only tric power source necessary to accomplish these safety-related functions is the Class 1E dc and S power system which includes the associated safety-related 120V ac distribution switchgear.
ough the AP1000 is designed with reliable nonsafety-related offsite and onsite ac power that are mally expected to be available for important plant functions, nonsafety-related ac power is not d upon to maintain the core cooling or containment integrity.
nonsafety-related ac power system is designed such that plant auxiliaries can be powered from grid under all modes of operation. During loss of offsite power, the ac power is supplied by the ite standby diesel-generators. Preassigned loads and equipment are automatically loaded on the el-generators in a predetermined sequence. Additional loads can be manually added as uired. The onsite standby power system is not required for safe shutdown of the plant.
formance with General Design Criterion 18 is provided by the test and inspection capability of the em.
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ugh 4 are used as guides in the design and procurement of the offsite power system.
5 Combined License Information for Offsite Electrical Power design of the ac power transmission system and its testing and inspection plan is addressed in sections 8.2.1, 8.2.1.1, 8.2.1.2, 8.2.1.3, and 8.2.1.4.
technical interfaces for ac power requirements from offsite and the analysis of the offsite smission system and the setting of protective devices are addressed in Subsections 8.2.1.2.2 8.2.2.
6 References ANSI C2-1997, National Electrical Safety Code.
ANSI C37.010-1999, IEEE Application Guide for AC High-Voltage Circuit Breakers Rated on a Symmetrical Current Basis.
ANSI C37.90-1989, IEEE Standard for Relays and Relay Systems Associated with Electric Power Apparatus.
ANSI C57.12.00-2000, IEEE Standard General Requirements for Liquid-Immersed Distribution, Power and Regulating Transformers.
. NRC Bulletin 2012-01, "Design Vulnerability in Electric Power System," July 27, 2012.
8.2-12 Revision 1
RAT 1A RAT 1B RAT 2A RAT 2B 70 MVA 70 MVA 70 MVA 70 MVA UNIT 1 UNIT 2 825/1375 MVA 825/1375 MVA 230-26kV 525-26kV 230kV 525kV YELLOW BUS YELLOW BUS 56 55 54 53 52 51 24 23 22 21 45 42 41 14 36 35 34 33 32 31 4 3 2 1 750MVA PER BANK 230kV 525kV RED BUS RED BUS WH. BL. BL. WH. 525-230 AUTOBANKS RODDEY WEST RODDEY EAST ASBURY WEST LINE ASBURY EAST LINE 230kV LINES 230kV LINES TO OCONEE TO NEWPORT TO PACOLET TO CATAWBA 2 CONDUCTOR BUNDLED 2 CONDUCTOR BUNDLED 2515 KCMIL ACSR 2515 KCMIL ACSR Figure 8.2-201 Offsite Power System One-Line Diagram 8.2-13 Revision 1
Figure 8.2-202 Switchyard General Arrangement 8.2-14 Revision 1
1.1 Description onsite ac power system is a non-Class 1E system comprised of a normal, preferred, ntenance and standby power supplies. The normal, preferred, and maintenance power supplies included in the main ac power system. The standby power is included in the onsite standby er system. The Class 1E and non-Class 1E 208/120 Vac instrumentation power supplies are cribed in Subsection 8.3.2 as a part of uninterruptible power supply in the dc power systems.
1.1.1 Onsite AC Power System main ac power system is a non-Class 1E system and does not perform any safety-related tions. It has nominal bus voltage ratings of 6.9 kV, 480 V, 277 V, 208 V, and 120 V.
re 8.3.1-1 shows the main generator, transformers, feeders, buses, and their connections. The gs of major ac equipment are listed in Table 8.3.1-3.
ing power generation mode, the turbine generator normally supplies electric power to the plant iliary loads through the unit auxiliary transformers. The plant is designed to sustain a load ction from 100 percent power with the turbine generator continuing stable operation while plying the plant house loads. The load rejection feature does not perform any safety function.
ing plant startup, shutdown, and maintenance the generator breaker remains open. The main ac er is provided by the preferred power supply from the high-voltage switchyard (switchyard age is site-specific) through the plant main stepup transformers and two unit auxiliary sformers. Each unit auxiliary transformer supplies power to about 50 percent of the plant loads.
aintenance source is provided to supply power through two reserve auxiliary transformers. The ntenance source and the associated reserve auxiliary transformers primary voltage are site cific. The reserve auxiliary transformers are sized so that it can be used in place of the unit iliary transformers.
two unit auxiliary transformers have two identically rated 6.9 kV secondary windings. The third auxiliary transformer is a two winding transformer sized to accommodate the electric boiler and
-specific loads. Secondaries of the auxiliary transformers are connected to the 6.9 kV switchgear es by nonsegregated phase buses. The primary of the unit auxiliary transformer is connected to main generator isolated phase bus duct tap. The 6.9 kV switchgear designation, location, nection, and connected loads are shown in Figure 8.3.1-1. The buses tagged with odd numbers 1, ES3, etc.) are connected to one unit auxiliary transformer and the buses tagged with even bers (ES2, ES4, etc.) are connected to the other unit auxiliary transformer. ES7 is connected to third unit auxiliary transformer. 6.9 kV buses ES1-ES6 are provided with an access to the ntenance source through normally open circuit breakers connecting the bus to the reserve iliary transformer. ES7 is not connected to the maintenance source. Bus transfer to the ntenance source is manual or automatic through a fast bus transfer scheme.
arrangement of the 6.9 kV buses permits feeding functionally redundant pumps or groups of s from separate buses and enhances the plant operational flexibility. The 6.9 kV switchgear ers large motors and the load center transformers. There are two switchgear (ES1 and ES2) ted in the annex building, and five (ES3, ES4, ES5, ES6, and ES7) in the turbine building.
8.3-1 Revision 1
ection. If these devices sense a fault condition the following actions will be automatically taken:
Trip high-side (grid) breaker Trip generator breaker Trip exciter field breaker Trip the 6.9 kV buses connected to the faulted transformer Initiate a fast bus transfer of ES1-ES6 6.9kV buses ES1-ES6.
reserve auxiliary transformers have protective devices for sudden pressure, overcurrent, rential current and neutral overcurrent. The reserve auxiliary transformers protective devices trip reserve supply breaker and any 6.9 kV buses connected to the reserve auxiliary transformers.
onsite standby power system powered by the two onsite standby diesel generators supplies er to selected loads in the event of loss of normal, and preferred ac power supplies followed by a bus transfer to the reserve auxiliary transformers. Those loads that are priority loads for defense-epth functions based on their specific functions (permanent nonsafety loads) are assigned to es ES1 and ES2. These plant permanent nonsafety loads are divided into two functionally undant load groups (degree of redundancy for each load is described in the sections for the ective systems). Each load group is connected to either bus ES1 or ES2. Each bus is backed by n-Class 1E onsite standby diesel generator. In the event of a loss of voltage on these buses, the el generators are automatically started and connected to the respective buses. In the event re a fast bus transfer initiates but fails to complete, the diesel generator will start on an ervoltage signal; however, if a successful residual voltage transfer occurs, the diesel generator not be connected to the bus because the successful residual voltage transfer will provide power e bus before the diesel connection time of 2 minutes. The source incoming breakers on chgear ES1 and ES2 are interlocked to prevent inadvertent connection of the onsite standby el generator and preferred/maintenance ac power sources to the 6.9 kV buses at the same time.
diesel generator, however, is capable of being manually paralleled with the preferred or reserve er supply for periodic testing. Design provisions protect the diesel generators from excessive ing beyond the design maximum rating, should the preferred power be lost during periodic ing. The control scheme, while protecting the diesel generators from excessive loading, does not promise the onsite power supply capabilities to support the defense-in-depth loads. See section 8.3.1.1.2 for starting and load sequencing of standby diesel generators.
reactor coolant pumps (RCPs) are powered from the four switchgear buses located in the turbine ding, one RCP per bus. Variable-speed drives are provided for RCP startup and for RCP ration when the reactor trip breakers are open. During normal power operation (reactor trip akers are closed), 60 Hz power is provided directly to the RCPs and the variable-speed drives are connected.
h RCP is powered through two Class 1E circuit breakers connected in series. These are the only ss 1E circuit breakers used in the main ac power system for the specific purpose of satisfying the ty-related tripping requirement of these pumps. The reactor coolant pumps connected to a mon steam generator are powered from two different unit auxiliary transformers. The bus gnments for the reactor coolant pumps are shown in Figure 8.3.1-1.
480 V load centers supply power to selected 460 V motor loads and to motor control centers.
tie breakers are provided between two 480 V load centers each serving predominantly undant loads. This intertie allows restoration of power to selected loads in the event of a failure or ntenance of a single load center transformer. The bus tie breakers are interlocked with the esponding bus source incoming breakers so that one of the two bus source incoming breakers 8.3-2 Revision 1
480 V motor control centers supply power to 460 V motors not powered directly from load ters, while the 480/277 V, and 208/120 V distribution panels provide power for miscellaneous s such as unit heaters, space heaters, and lighting system. The motor control centers also ide ac power to the Class 1E battery chargers for the Class 1E dc power system as described in section 8.3.2.
ancillary ac diesel generators, located in the annex building, provide ac power for Class 1E post-dent monitoring, MCR lighting, MCR and I&C room ventilation, and pump power to refill the PCS er storage tank and the spent fuel pool, when all other sources of power are not available.
h ancillary ac generator output is connected to a distribution panel. The distribution panel is ted in the room housing the diesel generators. The distribution panel has incoming and outgoing er circuit breakers as shown on Figure 8.3.1-3. The outgoing feeder circuit breakers are nected to cables which are routed to the divisions B and C voltage regulating transformers and to PCS pumps. Each distribution panel has the following outgoing connections:
Connection for Class 1E voltage regulating transformer to power the post-accident monitoring loads, the lighting in the main control room, and ventilation in the main control room and divisions B and C I&C rooms.
Connection for PCS recirculation pump to refill the PCS water storage tank and the spent fuel pool.
Connection for local loads to support operation of the ancillary generator (lighting and fuel tank heating).
Temporary connection for a test load device (e.g., load resistor).
See Figure 8.3.1-3 for connections to post-72-hour loads.
1.1.1.1 Electric Circuit Protection ective relay schemes and direct acting trip devices on circuit breakers:
Provide safety of personnel Minimize damage to equipment Minimize system disturbances Isolate faulted equipment and circuits from unfaulted equipment and circuits Maintain (selected) continuity of the power supply or types of protection systems employed for AP1000 include the following:
dium Voltage Switchgear erential Relaying h medium voltage switchgear bus is provided with a bus differential relay (device 87B) to protect inst a bus fault. The actuation of this relay initiates tripping of the source incoming circuit breaker all branch circuit load breakers. The differential protection scheme employs high-speed relays.
ors rated 1500 hp and above are generally provided with a high dropout overcurrent relay ice 50D) for differential protection.
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und overcurrent protection.
h medium voltage motor feeder breaker is equipped with a motor protection relay which provides ection against various types of faults (phase and ground) and abnormal conditions such as ed rotor and phase unbalance. Motor overload condition is annunciated in the main control room.
h medium voltage power feeder to a 480 V load center has a multifunction relay. The relay ides overcurrent protection on each phase for short circuit and overload, and an instantaneous rcurrent protection for ground fault.
dervoltage Relaying ium voltage buses are provided with a set of three undervoltage relays (device 27B) which trip or feeder circuit breakers connected to the bus upon loss of bus voltage using two-out-of-three c to prevent spurious actuation. In addition, a protective device is provided on the line side of ming supply breakers of buses ES1 and ES2 to initiate an alarm in the main control room if a ained low or high voltage condition occurs on the utility supply system. The alarm is provided so the operator can take appropriate corrective measures.
-V Load Centers h motor-feeder breaker in load centers is equipped with a trip unit which has long time, antaneous, and ground fault tripping features. Overload condition of motors is annunciated in the n control room.
circuit breakers feeding the 480V motor control centers and other non-motor loads have long
, short time, and ground fault tripping features.
h load center bus has an undervoltage relay which initiates an alarm in the main control room n loss of bus voltage.
d center transformers have transformer winding temperature relays (device 49T) which give an m on transformer overload.
-V Motor Control Center or control center feeders for low-voltage (460 V) motors have molded case circuit breakers gnetic or motor circuit protectors) and motor starters. Motor starters are provided with thermal s (overload heaters) or current sensors. Other feeders have molded case circuit breakers with mal and magnetic trip elements for overload and short circuit protection.
-Class 1E ac motor-operated valves are protected by thermal overload devices. Thermal rload devices are selected and sized so as to provide the necessary protection while minimizing probability of spurious interruptions of valve actuation.
1.1.2 Standby AC Power Supply 1.1.2.1 Onsite Standby Diesel Generators onsite standby diesel generator units, each furnished with its own support subsystems, provide er to the selected plant nonsafety-related ac loads. Power supplies to each diesel generator system components are provided from separate sources to maintain reliability and operability of 8.3-4 Revision 1
onsite standby diesel generator function to provide a backup source of electrical power to onsite ipment needed to support decay heat removal operation during reduced reactor coolant system ntory, midloop, operation is identified as an important nonsafety-related function. The standby el generators are included in the Investment Protection Short-Term Availability Controls cribed in Section 16.3 and the Design Reliability Assurance Program described in Section 17.4.
h of the generators is directly coupled to the diesel engine. Each diesel generator unit is an pendent self-contained system complete with necessary support subsystems that include:
Diesel engine starting subsystem Combustion air intake and engine exhaust subsystem Engine cooling subsystem Engine lubricating oil subsystem Engine speed control subsystem Generator, exciter, generator protection, monitoring instruments, and controls subsystems diesel-generator starting air subsystem consists of an ac motor-driven, air-cooled compressor, a pressor inlet air filter, an air-cooled aftercooler, an in-line air filter, refrigerant dryer (with dew t at least 10°F less than the lowest normal diesel generator room temperature), and an air iver with sufficient storage capacity for three diesel engine starts. The starting air subsystem will onsistent with manufacturer's recommendations regarding the devices to crank the engine, ation of the cranking cycle, the number of engine revolutions per start attempt, volume and design sure of the air receivers, and compressor size. The interconnecting stainless steel piping from compressor to the diesel engine dual air starter system includes air filters, moisture drainers, and sure regulators to provide clean dry compressed air at normal diesel generator room perature for engine starting.
diesel-generator combustion air intake and engine exhaust subsystem provides combustion air ctly from the outside to the diesel engine while protecting it from dust, rain, snow and other ironmental particulates. It then discharges exhaust gases from the engine to the outside of the el generator building more than 20 feet higher than the air intake. The combustion air circuit is arate from the ventilation subsystems and includes weather protected dry type inlet air filters d directly to the inlet connections of the diesel engine-mounted turbochargers. The combustion ilters are capable of reducing airborne particulate material, assuming the maximum expected orne particulate concentration at the combustion air intake. Each engine is provided with two rs as shown in Figure 8.3.1-4. A differential pressure gauge is installed across each filter to rmine the need for filter replacement. The engine exhaust gas circuit consists of the engine aust gas discharge pipes from the turbocharger outlets to a single vertically mounted outdoor ncer which discharges to the atmosphere. Manufacturer's recommendations are considered in design of features to protect the silencer module and other system components from possible ging due to adverse atmospheric conditions, such as dust storms, rain, ice, and snow.
diesel-generator engine cooling system is an independent closed loop cooling system, rejecting ine heat through two separate roof-mounted, fan-cooled radiators. The system consists of two arate cooling loops each maintained at a temperature required for optimum engine performance eparate engine-driven coolant water circulating pumps. One circuit cools the engine cylinder 8.3-5 Revision 1
er temperature. The temperature control valve has an expanding wax-type temperature-sensitive ment or equivalent. The cooling circuit, which cools the engine cylinder blocks, jacket, and head as, includes a keep-warm circuit consisting of a temperature controlled electric heater and an ac or-driven water circulating pump.
diesel-generator engine lubrication system is contained on the engine skid and includes an ine oil sump, a main engine driven oil pump and a continuous engine prelube system consisting n ac and dc motor driven prelube pump and electric heater. The prelube system maintains the ine lubrication system in service when the diesel engine is in standby mode. The lube oil is ulated through the engine and various filters and coolers to maintain the lube oil properties able for engine lubrication.
diesel generator engine fuel oil system consists of an engine-mounted, engine-driven fuel oil p that takes fuel from the fuel oil day tank, and pumps through inline oil filters to the engine fuel ctors and a separate recirculation circuit with a fuel oil cooler. The recirculation circuit discharges k to the fuel oil day tank that is maintained at the proper fuel level by the diesel fuel oil storage transfer system.
onsite standby diesel generators are provided with necessary controls and indicators for local or ote monitoring of the operation of the units. Essential parameters are monitored and alarmed in main control room via the plant data display and processing system as described in Chapter 7.
cations and alarms that are available locally and in the main control room are listed in le 8.3.1-5.
design of the onsite standby diesel generators does not ensure functional operability or ntenance access or support plant recovery following design basis events. Maintenance essibility is provided consistent with the system nonsafety-related functions and plant availability ls.
piping and instrumentation diagrams for the onsite standby diesel generator units and the ociated subsystems are shown on Figures 8.3.1-4 and 8.3.1-5.
onsite standby power supply system is shown schematically on one line diagram, Figure 8.3.1-1.
onsite diesel generators will be procured in accordance with an equipment specification which include requirements based upon the manufacturer's standards and applicable recommendations documents such as NUREG/CR-0660 (Reference 15). Capability to detect system leakage and revent crankcase explosions will be based upon manufacturer's recommendations. Control of sture in the starting air system by the equipment described above will be based upon ufacturer's recommendations. Dust and dirt in the diesel generator room is controlled by the el generator building ventilation system described in Subsection 9.4.10. Personnel training is ressed as part of overall plant training in Subsection 13.2.6. Automatic engine prelube by the ipment described above will be based upon manufacturer's recommendations. Testing, test ing and preventive maintenance is addressed as part of overall plant testing and maintenance in pter 13. Instrumentation to support diagnostics during operation is shown on Figure 8.3.1-4. The rall diesel building ventilation design is described in Subsection 9.4.10 and the combustion air ems are described above. The fuel oil storage and handling system is described in section 9.5.4. High temperature insulation will be based upon manufacturer's recommendations.
ponse to the effects of engine vibration will be based upon manufacturer's recommendations.
sel building floor coatings are described in Subsections 6.1.2.1.4 and 6.1.3.2. The diesel 8.3-6 Revision 1
1.1.2.2 Generator h generator is a direct-shaft driven, air-cooled self ventilated machine. The generator enclosure is n drip-proof type that facilitates free movement of ventilation air. The generator component ign is in compliance with the NEMA MG-1 (Reference 1) requirements.
h generator produces its rated power at 6900 V, 60 Hz. Each generator continuous rating is ed on supplying the electrical ac loads listed in Tables 8.3.1-1 or 8.3.1-2. The loads shown on les 8.3.1-1 and 8.3.1-2 represent a set of nonsafety-related loads which provide shutdown ability using nonsafety-related systems. The generators can also provide power for additional stment protection ac loads. The plant operator would normally provide power to these loads by energizing one of those system components that are redundantly supplied by both the diesel erators. The diesel generator design is compatible with the step loading requirements identified in les 8.3.1-1 and 8.3.1-2. The generator exciter and voltage regulator systems are capable of iding full voltage control during operating conditions including postulated fault conditions.
h generator has a set of potential and current transformers for protective relaying and metering poses.
following generator protection functions are provided via relays that are mounted on the local erator control panel:
Differential (87), overcurrent (50/51), reverse power (32), underfrequency (81), under/over voltage (27/59), loss of excitation (40), ground fault (51g), negative sequence (46),
synchronization check (25), voltage balance (60).
Note: The number in the parentheses identifies the ANSI device designation.
1.1.2.3 Onsite Standby Power System Performance onsite standby power system provides reliable ac power to the various plant system electrical s shown on Tables 8.3.1-1 and 8.3.1-2. These loads represent system components that enhance rderly plant shutdown under emergency conditions. Additional loads that are for investment ection can be manually loaded on the standby power supply after the loads required for orderly tdown have been satisfied. The values listed in the "Operating Load (kW)" column of les 8.3.1-1 and 8.3.1-2 represent nominal values of the actual plant loads.
h the diesel engine and the associated generator are rated based on 104°F ambient temperature 000 ft elevation as standard site conditions. The selected unit rating has a design margin to ommodate possible derating resulting from other site conditions.
Lee Nuclear Station site conditions provided in Sections 2.1 and 2.3 are bounded by the dard site conditions used to rate both the diesel engine and the associated generator in section 8.3.1.1.2.3.
diesel generator unit is able to reach the rated speed and voltage and be ready to accept trical loads within 120 seconds after a start signal.
h generator has an automatic load sequencer to enable controlled loading on the generator. The matic load sequencer connects selected loads at predetermined intervals. This feature allows 8.3-7 Revision 1
sequential and manual loading of the onsite standby diesel generator, see Tables 8.3.1-1 and 1-2.
nable periodic testing, each generator has synchronizing equipment at a local panel as well as in main control room.
logic diagram for diesel generator initiating circuit is shown in Figure 8.3.1-2.
1.1.2.4 Operation, Inspection, and Maintenance ration, inspection and maintenance (including preventive, corrective, and predictive ntenance) procedures consider both the diesel generator manufacturers recommendations and stry diesel working group recommendations.
1.1.3 Ancillary ac Diesel Generators er for Class 1E post-accident monitoring, MCR lighting, MCR and divisions B and C I&C room tilation and for refilling the PCS water storage tank and the spent fuel pool when no other sources ower are available is provided by two ancillary ac diesel generators located in the annex building.
ancillary generators are not needed for refilling the PCS water storage tank, spent fuel pool eup, post-accident monitoring or lighting for the first 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> following a loss of all other ac rces.
generators are classified as AP1000 Class D. The generators are commercial, skid-mounted, kaged units and can be easily replaced in the event of a failure. Generator control is manual from ntrol integral with the diesel skid package. These generators are located in the portion of the ex Building that is a seismic Category II structure.
these systems and components, the design of equipment anchorages is consistent with the SSE ign of equipment anchorages of seismic Category I items and there should be no spatial raction with any other non-seismic SSC that could adversely interact to prevent the functioning of post-72 hour SSCs following an SSE; no dynamic qualification of the active equipment is essary. Features of this structure which protect the function of the ancillary generators are lyzed and designed for Category 5 hurricanes, including the effects of sustained winds, maximum ts, and associated wind-borne missiles.
fuel for the ancillary generators is stored in a tank located in the same room as the generators.
fuel tank, piping, and valves are analyzed to show that they withstand an SSE. The tank includes isions for venting to the outside atmosphere and for refilling from a truck or other mobile source el. The tank is seismic Category II and holds sufficient fuel for 4 days of operation.
h ancillary generator output is connected to a distribution panel located in the same room as the erators. Each distribution panel has an incoming circuit breaker and outgoing feeder circuit akers. The outgoing feeder circuit breakers are connected to cables that are routed to the sions B and C voltage regulating transformers and to the passive containment cooling system rculation pumps (see Figure 8.3.1-3).
1.1.4 Electrical Equipment Layout main ac power system distributes ac power to the reactor, turbine, and balance of plant (BOP) iliary electrical loads for startup, normal operation, and normal/emergency shutdown.
8.3-8 Revision 1
sformer yard to the annex building in the most direct path practical.
switchgear ES3, ES4, ES5, and ES6 are located in the turbine building electrical switchgear ms. The incoming power is supplied from the unit auxiliary transformers ET2A and ET2B indings) via nonsegregated buses to ES3 and ES4 and from ET2A and ET2B (X windings) to and ES6. Switchgear ES7 is located in the auxiliary boiler room in the turbine building.
Class 1E medium voltage circuit breakers, ES31, ES32, ES41, ES42, ES51, ES52, ES61, and 2, for four reactor coolant pumps are located in the auxiliary building.
480 V load centers are located in the turbine building electrical switchgear rooms 1 and 2 and in annex building electrical switchgear rooms 1 and 2 based on the proximity of loads and the ociated 6.9 kV switchgear. Load center 71 is located in the auxiliary boiler room in the turbine ding.
480 V motor control centers are located throughout the plant to effectively distribute power to trical loads. The load centers and motor control centers are free standing with top or bottom le entry and front access. The number of stacks/cubicles varies for each location.
1.1.5 Heat Tracing System electric heat tracing system is nonsafety-related and provides electrical heating where perature above ambient is required for system operation and freeze protection.
electric heat tracing system is part of the AP1000 permanent nonsafety-related loads and is ered from the diesel backed 480 V ac motor control centers through 480 V - 208Y/120V sformers and distribution panels.
1.1.6 Containment Building Electrical Penetrations electrical penetrations are in accordance with IEEE 317 (Reference 2).
penetrations conform to the same functional service level as the cables, (for example, low-level rumentation is in a separate nozzle from power and control). The same service class separation uirements apply within inboard/outboard terminal boxes.
vidual electrical penetrations are provided for each electrical service level and follow the same way voltage grouping described in Subsection 8.3.1.3.4. Optical fibers are installed in rumentation and control or low voltage power electric penetrations.
electrical penetrations conductor modules are in penetrations of the same Service Class.
ules for instrumentation signals will be in instrumentation penetrations; modules for control er (e.g., 120/125/250V) will be in control power penetrations; modules for low voltage power
., 600 Vac) will be in low voltage power penetrations.
possible to combine low voltage power with control power in the same electrical penetration embly.
etrations carrying medium voltage power cables have thermocouples to monitor the temperature in the assembly at the spot expected to have the hottest temperature.
8.3-9 Revision 1
er continuously without exceeding their thermal limit, or at least longer than the field cables of the uits so that the fault or overload currents are interrupted by the protective devices prior to a ntial failure of a penetration. Penetrations are protected for the full range of currents up to the imum short circuit current available.
ary and backup protective devices protecting Class 1E circuits are Class 1E in accordance with E 741 (Reference 10). Primary and backup protective devices protecting non-Class 1E circuits non-Class 1E.
etration overcurrent protection coordination curves are generated based on the protection uirements specified by the penetration equipment manufacturer. When necessary, penetrations protected for instantaneous overcurrent by current limiting devices such as current-limiting fuses, ent-limiting breakers, or reactors.
cedures implement periodic testing of protective devices that provide penetration overcurrent ection. A sample of each different type of overcurrent device is selected for periodic testing ng refueling outages. Testing includes:
Verification of thermal and instantaneous trip characteristics of molded case circuit breakers.
Verification of long time, short time, and instantaneous trips of medium voltage vacuum circuit breakers.
Verification of long time, short time, and instantaneous trips of low voltage air circuit breakers.
Verification of Class 1E and non-Class 1E dc protective device characteristics (except fuses) per manufacturer recommendations, including testing for overcurrent interruption and/or fault current limiting.
etration protective devices are maintained and controlled under the plant configuration control gram. A fuse control program, including a master fuse list, is established based on industry rating experience.
1.1.7 Grounding System AP1000 grounding system will comply with the guidelines provided in IEEE 665 (Reference 18)
IEEE 1050 (Reference 20). The grounding system consists of the following four subsystems:
Station grounding grid System grounding Equipment grounding Instrument/computer grounding station grounding grid subsystem consists of buried, interconnected bare copper conductors and und rods (Copperweld) forming a plant ground grid matrix. The subsystem will maintain a uniform und potential and limit the step-and-touch potentials to safe values under all fault conditions.
system grounding subsystem provides grounding of the neutral points of the main generator, n step-up transformers, auxiliary transformers, load center transformers, and onsite standby el generators. The main and diesel generator neutrals will be grounded through grounding sformers providing high-impedance grounding. The main step-up and load center transformer 8.3-10 Revision 1
equipment grounding subsystem provides grounding of the equipment enclosures, metal ctures, metallic tanks, ground bus of switchgear assemblies, load centers, MCCs, and control inets with two ground connections to the station ground grid.
instrument/computer grounding subsystem provides plant instrument/computer grounding ugh separate radial grounding systems consisting of isolated instrumentation ground buses and lated cables. The radial grounding systems are connected to the station grounding grid at one t only and are insulated from all other grounding circuits.
ounding system calculation was performed to establish a ground grid design within the plant ndary resulting in step and touch potentials near equipment that are within the acceptable limit for onnel safety. Computer analysis utilized actual resistivity measurements from soil samples taken e plant site, and were used to create a soil model for the plant site. The ground grid conductor was then determined using the methodology outlined in IEEE 80, "IEEE Guide for Safety in AC station Grounding" (Reference 201), and a grid configuration for the site was created. The grid figuration was modeled in conjunction with the soil model. The resulting step and touch potentials e calculated, and are within the acceptable limit.
1.1.8 Lightning Protection lightning protection system, consisting of air terminals and ground conductors, will be provided he protection of exposed structures and buildings housing safety-related and fire protection ipment in accordance with NFPA 780 (Reference 19). Also, lightning arresters are provided in h phase of the transmission lines and at the high-voltage terminals of the outdoor transformers.
isophase bus connecting the main generator and the main transformer and the medium-voltage chgear is provided with lightning arresters. In addition, surge suppressors are provided to protect plant instrumentation and monitoring system from lightning-induced surges in the signal and er cables connected to devices located outside.
ct-stroke lightning protection for facilities is accomplished by providing a low-impedance path by ch the lightning stroke discharge can enter the earth directly. The direct-stroke lightning protection em, consisting of air terminals, interconnecting cables, and down conductors to ground, are ided external to the facility in accordance with the guidelines included in NFPA 780. The system onnected directly to the station ground to facilitate dissipation of the large current of a direct ning stroke. The lightning arresters and the surge suppressors connected directly to ground ide a low-impedance path to ground for the surges caused or induced by lightning. Thus, fire or age to facilities and equipment resulting from a lightning stroke is avoided.
ccordance with IEEE 665, IEEE Standard for Generating Station Grounding, a lightning ection risk assessment for the buildings comprising the Lee Nuclear Station was performed ed on the methodology in NFPA 780. The tolerable lightning frequency for each of the buildings determined to be less than the expected lightning frequency; therefore, lightning protection is uired for Lee Nuclear Station buildings in accordance with NFPA 780 and IEEE C.62.23 ference 202). The zone of protection is based on the elevations and geometry of the structures. It udes the space covered by a rolling sphere having a radius sufficient enough to cover the building e protected. The zone of protection method is based on the use of ground masts, air terminals shield wires. Either copper or aluminum is used for lightning protection. Lightning protection unding is interconnected with the station or switchyard grounding system.
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ac power system is non-Class 1E and is not required for safe shutdown. Compliance with ting regulatory guides and General Design Criteria is covered in Table 8.1-1 of Section 8.1.
1.3 Raceway/Cable 1.3.1 General raceway system for non-Class 1E ac circuits complies with IEEE 422 (Reference 3) in respect to allation and support of cable runs between electrical equipment including physical protection.
eway systems consist primarily of cable tray and wireway.
1.3.2 Load Groups Segregation re are two nonsafety-related load groups associated with different transformers, buses, and ite standby diesel generators. No physical separation is required as these two ac load groups are
-Class 1E and nonsafety-related.
1.3.3 Cable Derating and Cable Tray Fill le Derating power and control cable insulation is designed for a conductor temperature of 90°C. The wable current carrying capacity of the cable is based on the insulation design temperature while surrounding air is at an ambient temperature of 65°C for the containment and 40 to 50°C for other as. Power cables, feeding loads from switchgear, load centers, motor control centers, and ribution panels are sized at 125 percent of the full-load current at a 100-percent load factor.
power cable ampacities are in accordance with the Insulated Cable Engineers Association lications (References 4 and 11), and National Electric Code (Reference 5). The derating is based he type of installation, the conductor and ambient temperature, the number of cables in a way, and the grouping of the raceways. A further derating of the cables is applied for those les which pass through a fire barrier. The method of calculating these derating factors is rmined from the Insulated Cable Engineers Association publications and other applicable dards.
rumentation cable insulation is also designed for a conductor temperature of 90°C. The operating er of these cables is low (usually mV or mA) and does not cause cable overheating at the imum design ambient temperature.
circuits that are routed partly through conduit and partly through trays or underground ducts, the le size is based on the ampacity in that portion of the circuit with the lowest indicated current ying capacity.
le Tray Fill le tray design is based on random cable fill of 40 percent of usable tray depth. If tray fill exceeds above stated maximum fill, tray fill will be analyzed and the acceptability documented.
duit fill design is in compliance with Tables 1, 2, 3, and 4 of Chapter 9, National Electrical Code ference 5).
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ordance with the function and voltage class of the cables as follows:
Medium voltage power (6.9 kV)
Low voltage power (480 Vac, 208Y/120 Vac, 125 Vdc/250 Vdc) 120 Vac/125 Vdc/250 Vdc signal and control (if used)
Instrumentation (analog and digital)
Vac, 208Y/120 Vac, 125 Vdc/250 Vdc power cables may be mixed with 120 Vac/125 Vdc/
Vdc signal and control cables.
arate raceways are provided for medium voltage power, low voltage power and control, as well nstrumentation cables.
-Class 1E raceways and supports installed in seismic Category I structures are designed and/or sically arranged so that the safe shutdown earthquake could not cause unacceptable structural raction or failure of seismic Category I components.
eways are kept at a reasonable distance from heat sources such as steam piping, steam erators, boilers, high and low pressure heaters, and any other actual or potential heat source.
es of heat source crossings are evaluated and supplemental heat shielding is used if necessary.
Class 1E raceway and cable routing see Subsection 8.3.2.
1.4 Inspection and Testing operational tests are conducted to verify proper operation of the ac power system. The operational tests include operational testing of the diesel load sequencer and diesel generator acity testing.
cedures are established for periodic verification of proper operation of the Onsite AC Power tem capability for automatic and manual transfer from the preferred power supply to the ntenance power supply and return from the maintenance power supply to the preferred power ply.
1.4.1 Diesel Load Sequencer Operational Testing load sequencer for each standby diesel generator is tested to verify that it produces the ropriate sequencing signals within five (5) seconds of the times specified in Tables 8.3.1-1 and 1-2. The five second margin is sufficient for proper diesel generator transient response.
1.4.2 Standby Diesel Generator Capacity Testing h standby diesel generator is tested to verify the capability to provide 4000 kW while maintaining output voltage and frequency within the design tolerances of 6900+/-10% Vac and 60+/-5% Hz. The 0 kW capacity is sufficient to meet the loads listed in Tables 8.3.1-1 and 8.3.1-2. The test duration be the time required to reach engine temperature equilibrium plus 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. This duration is cient to demonstrate long-term capability.
8.3-13 Revision 1
output voltage and frequency within the design tolerances of 480+/-10% Vac and 60+/-5% Hz. The W capacity is sufficient to meet the loads listed in Table 8.3.1-4. The test duration will be the time uired to reach engine temperature equilibrium plus 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. This duration is sufficient to onstrate long-term capability.
2 DC Power Systems 2.1 Description plant dc power system is comprised of independent Class 1E and non-Class 1E dc power ems. Each system consists of ungrounded stationary batteries, dc distribution equipment, and terruptible power supply (UPS).
Class 1E dc and UPS system provides reliable power for the safety-related equipment required he plant instrumentation, control, monitoring, and other vital functions needed for shutdown of the
- t. In addition, the Class 1E dc and UPS system provides power to the normal and emergency ing in the main control room and at the remote shutdown workstation.
Class 1E dc and UPS system is capable of providing reliable power for the safe shutdown of the t without the support of battery chargers during a loss of all ac power sources coincident with a ign basis accident (DBA). The system is designed so that no single failure will result in a condition will prevent the safe shutdown of the plant.
non-Class 1E dc and UPS system provides continuous, reliable electric power to the plant non-ss 1E control and instrumentation loads and equipment that are required for plant operation and stment protection and to the hydrogen igniters located inside containment. Operation of the non-ss 1E dc and UPS system is not required for nuclear safety. See Subsection 8.3.2.1.2.
batteries for the Class 1E and non-Class 1E dc and UPS systems are sized in accordance with E 485 (Reference 6). The operating voltage range of the Class 1E batteries and of the EDS5 ine generator motor load support batteries is 210 to 280 Vdc. The maximum equalizing charge age for the Class 1E and EDS5 batteries is 280 Vdc. The nominal system voltage is 250 Vdc. The rating voltage range of non-Class 1E EDS1 through EDS4 batteries is 105 to 140 Vdc. The imum equalizing charge voltage for non-Class 1E EDS1 through EDS4 batteries is 140 Vdc. The inal system voltage is 125 Vdc for non-Class 1E EDS1 through EDS4.
qualification test program for AP1000 24-hour and 72-hour class 1E batteries meets or exceeds requirements of IEEE Standard 323, IEEE Standard 344, and IEEE Standard 535, including uired and recommended margins, and it is in regulatory compliance with Regulatory Guides 1.89, 0, and 1.158. The test program requires that the battery be subjected to accelerated thermal g and discharge cycling (wear aging) in accordance with IEEE Standard 323 and IEEE ndard 535 over its qualified life objective followed by the DBE seismic event performed in ordance with IEEE Standard 344. In addition, following the aging process, the test specimens ll be subjected to environmental testing to verify the equipments ability to operate in postulated ormal environmental conditions during plant operation. Discharge cycling will be performed as a ntial aging mechanism prior to seismic testing using Type 3 modified performance test method in ordance with IEEE Standard 450-2002 at intervals representative of the AP1000 surveillance test uirements of the batteries with 10% margin in the number of discharge cycles, which establishes gin for the expected life of the battery. Thus, magnitude/duration (modified performance test us service and performance tests) and test interval envelop the AP1000 and industry cycling uirements. If new battery failure modes are detected during the qualification testing, these failure 8.3-14 Revision 1
ess, a report that uniquely describes step-by-step the tests performed and results, and resses any deficiencies and repairs, including photographs, drawings, and other materials, will be ntained for records.
2.1.1 Class 1E DC and UPS System 2.1.1.1 Class 1E DC Distribution Class 1E dc distribution is in compliance with applicable General Design Criteria, IEEE dards, and Regulatory Guides listed in Subsection 8.1.4.3. The scope of compliance ompasses physical separation, electrical isolation, equipment qualification, effects of single active ponent failure, capacity of battery and battery charger, instrumentation and protective devices, surveillance test requirements. The Class 1E dc components are housed in seismic Category I ctures. For system configuration and equipment rating, see Class 1E dc one-line diagram, re 8.3.2-1. Nominal ratings of major Class 1E dc equipment are listed in Table 8.3.2-5.
re are four independent, Class 1E 250 Vdc divisions, A, B, C, and D. Divisions A and D are each prising one battery bank, one switchboard, and one battery charger. The battery bank is nected to Class 1E dc switchboard through a set of fuses and a disconnect switch. Divisions B C are each composed of two battery banks, two switchboards, and two battery chargers. The battery bank in the four divisions, designated as 24-hour battery bank, provides power to the s required for the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following an event of loss of all ac power sources concurrent with sign basis accident (DBA). The second battery bank in divisions B and C, designated as 72-hour ery bank, is used for those loads requiring power for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> following the same event. Each chboard connected with a 24-hour battery bank supplies power to an inverter, a 250 Vdc ribution panel, and a 250 Vdc motor control center. Each switchboard connected with a 72-hour ery bank supplies power to an inverter. No load shedding or load management program is ded to maintain power during the required 24-hour safety actuation period.
ngle spare battery bank with a spare battery charger is provided for the Class 1E dc and UPS em. In the case of a failure or unavailability of the normal battery bank and the battery charger, manently installed cable connections allow the spare to be connected to the affected bus by plug-cking type disconnect along with kirk-key interlock switches. The plug-in locking type disconnect kirk-key interlock switches permit connection of only one battery bank and battery charger at a so that the independence of each battery division is preserved. The spare battery and the ery charger can also be utilized as a substitute when offline testing, maintenance, and alization of an operational battery bank are desired.
h 250 Vdc Class 1E battery division and the spare battery bank are separately housed as cribed in Subsection 8.3.2.1.3.
h battery bank, including the spare, has a battery monitor system that detects battery open-circuit ditions and monitors battery voltage. The battery monitor provides a trouble alarm in the main trol room. The battery monitors are not required to support any safety-related function. Monitoring alarming of dc current and voltages are through the plant control system which includes a battery harge rate alarm. AP1000 generally uses fusible disconnect switches in the Class 1E dc system.
olded-case circuit breakers are used for dc applications, they will be sized to meet the dc rrupting rating requirements.
Class 1E dc switchboards employ fusible disconnect switches and have adequate short circuit continuous-current ratings. The main bus bars are braced to withstand mechanical forces 8.3-15 Revision 1
ery chargers are connected to dc switchboard buses. The input ac power for the Class 1E dc ery chargers is supplied from non-Class 1E 480 Vac diesel generator backed motor control ters. The battery chargers provide the required isolation between the non-1E ac and the Class 1E lectrical systems. The battery chargers are qualified as isolation devices in accordance with E 384 (Reference 7) and Regulatory Guide 1.75. Each battery charger has an input ac and output ircuit breaker for the purpose of power source isolation and required protection. Each battery rger prevents the ac supply from becoming a load on the battery due to a power feedback as a lt of the loss of ac power to the chargers. Each battery charger has a built-in current limiting uit, adjustable between 110 to 125 percent of its rating to hold down the output current in the nt of a short circuit or overload on the dc side. The output of the charger is ungrounded and red. The output float and equalizing voltages are adjustable. The battery chargers have an alizing timer and a manual bypass switch to permit periodic equalizing charges. Each charger is able of providing the continuous demand on its associated dc system while providing sufficient er to charge a fully discharged battery (as indicated by the nominal load requirements in les 8.3.2-1 through 8.3.2-4) within a 24-hour period. The battery chargers are provided with a mon failure/trouble alarm.
Class 1E dc motor control centers operate at 250 Vdc nominal two wire, ungrounded system.
dc motor control centers provide branch circuit protection for the dc motor-operated valves.
or-operated valves are protected by thermal overload devices in accordance with Regulatory de 1.106. Motor overload condition is annunciated in the main control room. The loads fed from motor control centers are protected against a short-circuit fault by fusible disconnect switches.
uced-voltage motor controllers limit the starting current to approximately 500 percent of rated ent for motors equal to or larger than 5 HP.
Class 1E dc distribution panels provide power distribution and tripping capability between the Vdc power sources and the assigned safeguard loads indicated on Figure 8.3.2-1.
site-specific non-Class 1E dc loads are connected to the Class 1E dc system.
2.1.1.2 Class 1E Uninterruptible Power Supplies Class 1E UPS provides power at 208 Y/120 Vac to four independent divisions of Class 1E rument and control power buses. Divisions A and D each consist of one Class 1E inverter ociated with an instrument and control distribution panel and a backup voltage regulating sformer with a distribution panel. The inverter is powered from the respective 24-hour battery k switchboard. Divisions B and C each consist of two inverters, two instrument and control ribution panels, and a voltage regulating transformer with a distribution panel. One inverter is ered by the 24-hour battery bank switchboard and the other, by the 72-hour battery bank chboard. For system configuration and equipment rating, see Figures 8.3.2-1 and 8.3.2-2. The inal ratings of the Class 1E inverters and the voltage regulating transformers are listed in le 8.3.2-5. Under normal operation, the Class 1E inverters receive power from the associated ery bank. If an inverter is inoperable or the Class 1E 250 Vdc input to the inverter is unavailable, power is transferred automatically to the backup ac source by a static transfer switch featuring a e-before-break contact arrangement. The backup power is received from the diesel generator ked non-Class 1E 480 Vac bus through the Class 1E voltage regulating transformer. In addition, a ual mechanical bypass switch is provided to allow connection of backup power source when the rter is removed from service for maintenance.
rder to supply power during the post-72-hour period following a design basis accident, provisions made to connect a ancillary ac generator to the Class 1E voltage regulating transformers 8.3-16 Revision 1
tilation, and Subsection 9.5.3 for post-72-hour lighting details respectively.
2.1.2 Non-Class 1E DC and UPS System non-Class 1E dc and UPS system consists of the electric power supply and distribution ipment that provide dc and uninterruptible ac power to the plant non-Class 1E dc and ac loads are critical for plant operation and investment protection and to the hydrogen igniters located de containment. The non-class 1E dc and UPS system is comprised of two subsystems esenting two separate power supply trains. The subsystems are located in separate rooms in the ex building. Figure 8.3.2-3, non-Class 1E dc and UPS system one line diagram represents the ribution configuration.
h of the EDS1 and 3, and 2 and 4 subsystems consists of separate dc distribution buses. These buses can be connected by a normally open circuit breaker to enhance the power supply source ilability.
h dc subsystem includes battery chargers, stationary batteries, dc distribution equipment, and ociated monitoring and protection devices.
buses 1, 2, 3, and 4 (See Figure 8.3.2-3) provide 125 Vdc power to the associated inverter units supply the ac power to the non-Class 1E uninterruptible power supply ac system. An alternate ulated ac power source for the UPS buses is supplied from the associated regulating sformers. DC bus 5 supplies large dc motors. This configuration isolates the large motors.
onsite standby diesel generator backed 480 Vac distribution system provides the normal ac er to the battery chargers. Industry standard stationary batteries that are similar to the Class 1E ign are provided to supply the dc power source in case the battery chargers fail to supply the dc ribution bus system loads. The batteries are sized to supply the system loads for a period of at t two hours after loss of all ac power sources.
dc distribution switchboard houses the dc feeder protection device, dc bus ground fault ction, and appropriate metering. The component design and the current interrupting device ction follow the circuit coordination principles.
non-Class 1E dc and UPS system is designed to meet the quality guidelines established by eric Letter 85-06, "Quality Assurance Guidance for ATWS Equipment that is not Safety-Related."
h of the EDS1 through 4 non-Class 1E dc distribution subsystem bus has provisions to allow the nection of a spare non-Class 1E battery charger should its non-Class 1E battery charger be vailable due to maintenance, testing, or failure. EDS5 does not require this capability because the load on the charger is the battery.
non-Class 1E dc system uses the Class 1E spare battery bank (Figure 8.3.2-1) as a temporary acement for any primary non-Class 1E battery bank. In this design configuration, the spare ss 1E battery bank would be connected to the non-Class 1E dc bus, but could not simultaneously ply Class 1E safety loads nor perform safety-related functions. For EDS1 through EDS4, this is omplished by opening the disconnect switch between the two 125 Vdc battery cell strings, which ther, comprise the 250 Vdc spare battery. Additionally, the design includes two current rrupting devices placed in series with the main feed from the spare battery that are fault-current vated. This will preserve the spare Class 1E battery integrity should the non-Class 1E bus 8.3-17 Revision 1
2.1.3 Separation and Ventilation the Class 1E dc system, the 24-hour and the 72-hour battery banks are housed in the auxiliary ding in ventilated rooms apart from chargers and distribution equipment. The battery rooms are tilated to limit hydrogen accumulation. Subsection 9.4.1 describes the ventilation system in the ery rooms. Each of the four divisions of dc systems are electrically isolated and physically arated to prevent an event from causing the loss of more than one division.
2.1.4 Maintenance and Testing ponents of the 125 Vdc and 250 Vdc systems undergo periodic maintenance tests to determine condition of the system. Batteries are checked for electrolyte level, specific gravity, and cell age, and are visually inspected.
surveillance testing of the Class 1E 250 Vdc system is performed as required by the Technical cifications.
inverter DC input protection will be set at least 10% higher than the battery charger trip setpoints revent the inverter tripping before the battery charger. The time delay for the inverter high dc input age trip will be set higher than the time delay for the battery charger to prevent the inverter ing before the battery charger.
cedures are established for inspection and maintenance of Class 1E and non-Class 1E batteries.
ss 1E battery maintenance and service testing are performed in conformance with Regulatory de 1.129. Batteries are inspected periodically to verify proper electrolyte levels, specific gravity, temperature and battery float voltage. Cells are inspected in conformance with IEEE 450 and dor recommendations.
clearing of ground faults on the Class 1E dc system is also addressed by procedure. The battery ing procedures are written in conformance with IEEE 450 and the Technical Specifications.
cedures are established for periodic testing of the Class 1E battery chargers and Class 1E age regulating transformers in accordance with the manufacturer recommendations.
Circuit breakers in the Class 1E battery chargers and Class 1E voltage regulating transformers that are credited for an isolation function are tested through the use of breaker test equipment. This verification confirms the ability of the circuit to perform the designed coordination and corresponding isolation function between Class 1E and non-Class 1E components. Circuit breaker testing is done as part of the Maintenance Rule program and testing frequency is determined by that program.
Fuses / fuse holders that are included in the isolation circuit are visually inspected.
Class 1E battery chargers are tested to verify current limiting characteristic utilizing manufacturer recommendation and industry practices. Testing frequency is in accordance with that of the associated battery.
2.2 Analysis pliance with General Design Criteria (GDC) and Regulatory Guides is discussed in Sections 3.1 1.9, respectively. Refer to Table 8.1-1 of Section 8.1 for guidelines and applicability of GDC, 8.3-18 Revision 1
e event of a loss of offsite power coincident with a main generator trip, ac power to the battery rger is provided from two separate non-Class 1E onsite standby diesel generators. Divisions A C chargers receive their ac power from one diesel generator, ZOS MG 02A, and division B and D rgers from the second diesel generator, ZOS MG 02B. Provisions are also made to power the t accident monitoring systems and the main control room lighting loads in divisions B and C from illary ac generators during the post 72-hour period as described in Subsection 8.3.2.1.1.2.
Class 1E battery chargers are designed to limit the input (ac) current to an acceptable value er faulted conditions on the output side. Fault current in the Class 1E voltage regulating sformers is limited by the impedance of the transformer. The Class 1E battery chargers and ss 1E voltage regulating transformers have built-in circuit breakers at the input and output s for protection and isolation. The circuit breakers are coordinated and periodically tested as of the Maintenance Rule program. The Class 1E battery chargers and Class 1E voltage ulating transformers are qualified as isolation devices between Class 1E and non-Class 1E uits in accordance with IEEE 384 and Regulatory Guide 1.75.
four divisions are independent, located in separate rooms, cannot be interconnected, and their uits are routed in dedicated, physically separated raceways. This level of electrical and physical aration prevents the failure or unavailability of a single battery, battery charger, or inverter from cting adversely a redundant division.
Class 1E dc and UPS system is designed in accordance with IEEE 308 (Reference 8) and E 946 (Reference 9). Important system component failures are annunciated. The battery itoring system detects battery open circuit condition and monitors battery voltage. The Class 1E Y/120Vac distribution panels are equipped with undervoltage protection. The set of fuses located e 250 Vdc switchboards provide selective tripping of circuits for a fault to limit the effects of the ormal condition, minimize system disturbance and protect the battery from complete accidental harge through a short circuit fault. The Class 1E dc system is ungrounded, thus, a single ground t does not cause immediate loss of the faulted system. Ground detections with alarms are ided for each division of power so that ground faults can be located and removed before a ond ground fault could disable the affected circuit. A spare battery bank and charger enables ing, maintenance, and equalization of battery banks offline. This configuration provides the ability for each battery bank or battery charger to be separately tested and maintained (including ery discharge tests, battery cell replacement, battery charger replacement) without limiting tinuous plant operation at 100-percent power.
rt circuit analyses will be performed in accordance with IEEE 946 (Reference 9) and/or other eptable industry standards or practices to determine fault currents. Circuit interrupting device rdination analyses will be performed in accordance with IEEE 141, 242 (References 16 and 17),
/or other acceptable industry standards or practices.
2.3 Physical Identification of Safety-Related Equipment h safety-related circuit and raceway is given a unique identification number to distinguish ween circuits and raceways of different voltage level or separation groups. Each raceway is color ed with indelible ink, paint, or adhesive markers (adhesive markers are not used in the tainment) at intervals of 15 feet or less along the length of the raceway and on both sides of floor all penetrations. Each cable is color coded at a maximum of 5 feet intervals along the length of cable and cable markers showing the cable identification number are applied at each end of the le.
8.3-19 Revision 1
A Brown B Green C Blue D Yellow 2.4 Independence of Redundant Systems 2.4.1 General routing of cable and the design of raceways prevents a single credible event from disabling a undant safety-related plant function.
2.4.2 Raceway and Cable Routing re are five separation groups for the cable and raceway system: group A, B, C, D, and N.
aration group A contains safety-related circuits from division A. Similarly, separation group B tains safety-related circuits from division B; group C from division C; group D from division D; and up N from nonsafety-related circuits.
les of one separation group are run in separate raceway and physically separated from cables of r separation groups. Group N raceways are separated from safety-related groups A, B, C and D.
eways from group N are routed in the same areas as the safety-related groups according to tial separation stipulated in Regulatory Guide 1.75 and IEEE 384 with the following exceptions:
Within the main control room and remote shutdown room (nonhazard areas), the minimum vertical separation for open top cable tray is 3 inches and the minimum horizontal separation is 1 inch.
Within general plant areas (limited hazard areas), the minimum vertical separation is 12 inches, and the minimum horizontal separation is 6 inches for open top cable trays with low-voltage power circuits for cable sizes <2/0 AWG. For configurations that involve exclusively limited energy content cables (instrumentation and control), these minimum distances are reduced to 3 inches and 1 inch respectively.
Within panels and control switchboards, the minimum horizontal separation between components or cables of different separation groups (both field-routed and vendor-supplied internal wiring) is 1 inch, and the minimum vertical separation distance is 6 inches.
For configurations involving an enclosed raceway and an open raceway, the minimum vertical separation is 1 inch if the enclosed raceway is below the open raceway.
exceptions to the guidance in Regulatory Guide 1.75 are based on test results used to support eptions to the separation guidance for operating nuclear power plants. A summary of test results ten electrical separation test programs is documented in Reference 13. These test programs port the AP1000 exceptions.
-Class 1E circuits are electrically isolated from Class 1E circuits, and Class 1E circuits from rent separation groups are electrically isolated by isolation devices, shielding and wiring 8.3-20 Revision 1
en isolation devices are used to isolate Class 1E circuits from non-Class 1E circuits, the circuits in or from the Class 1E equipment or devices are identified as Class 1E and are treated as such.
ond the isolation device(s) these circuits are identified as non-Class 1E and are separated from ss 1E circuits in accordance with the above separation criteria.
er and control cables are installed in conduits, solid bottom trays, or ventilated bottom trays der-type). Solid tray covers are used in outdoor locations and indoors where trays run in areas re falling debris is a problem. Instrumentation cables are routed in conduit or solid bottom cable with solid tray covers as required. The cables are derated for specific application in the location re they are installed as stated in Subsection 8.3.1.3.3. The environmental design of electrical ipment including Class 1E cables under normal and abnormal operating conditions is discussed ection 3.11.
arate trays are provided for each voltage service level: 6.9 kV, low voltage power (480 Vac, 208Y/
Vac, 125 Vdc, 250 Vdc), high-level signal and control (120 Vac, 125 Vdc, 250 Vdc), and low level al (instrumentation). A tray designed for a single class of cables shall contain only cables of the e class except that low voltage power cables may be routed in raceways with high level signal control cables if their respective sizes do not differ greatly and if they have compatible operating peratures. When this is done in trays, the power cable ampacity is calculated as if all cables in the are power cable. Low voltage power cable and high level signal and control cable will not be ed in common raceways if the fault current, within the breaker or fuse clearing time, is sufficient to t the insulation to the ignition point. Vertically stacked trays are arranged from top to bottom as ed in Subsection 8.3.1.3.4. In general, a minimum of 12 inches vertical spacing is maintained ween trays of different service levels within the stack.
electrical penetrations are in accordance with IEEE 317 (Reference 2). Class 1E and non-ss 1E electrical penetration assemblies are maintained in a separate nozzle. The physical aration of the Class 1E electrical penetration assemblies are in accordance with Regulatory de 1.75. The containment building penetrations are described in Subsection 8.3.1.1.6.
eways installed in seismic Category I structures have seismically designed supports or are wn not to affect safety-related equipment should they fail. Trays are not attached rigidly to seismic egory I equipment. Conduits may be attached to seismic Category I equipment with flexible type nections.
2.4.3 Hazard Protection ere redundant safety-related and nonsafety-related raceway systems traverse each other, aration in accordance with Regulatory Guide 1.75 and IEEE 384 is maintained.
ere hazards to safety-related raceways are identified, a predetermined minimum separation is ntained between the break and/or missile source and any safety-related raceway, or a barrier igned to withstand the effects of the hazard is placed to prevent damage to raceway of redundant ems. For details of missile protection and high-energy line break protection, see Sections 3.5 3.6, respectively.
ere redundant circuits, devices, or equipment (different separation groups) are exposed to the e external hazard(s), predetermined spatial separation is provided. Where the spatial separation not be met, qualified barriers are installed. For details on fire protection, see Subsection 9.5.1.
Section 3.4 for protection of raceways and the associated equipment against flooding.
8.3-21 Revision 1
separation group identification described in Subsection 8.3.2.3 provides for the maintenance of aration in the routing of cables and the connection of control boards and panels. The separation up designation on the cable or raceway is assigned to maintain compatibility with a single line ram channel designation and other cables or raceways routed. The routing is verified during allation. Color identification of equipment and cabling (discussed in Subsection 8.3.2.3) assist personnel in this effort.
2.5 Inspection and Testing operational tests are conducted to verify proper operation of the dc power systems. The operational tests include MOV terminal voltage testing and capacity testing of the batteries, rgers, inverters, and regulating transformers.
2.5.1 Class 1E 24-Hour Battery Capacity Testing h Class 1E 24-hour battery is tested to verify the capability to provide its load for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> while ntaining the battery terminal voltage above the minimum voltage specified in Table 8.3.2-5.
lysis will be performed based on the design duty cycle, and testing will be performed with loads ch envelope the analyzed battery bank design duty cycle. Each battery is connected to a charger ntained at 270+/-2 V for a period of at least 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to the test to assure the battery is fully rged.
2.5.2 Class 1E 72-Hour Battery Capacity Testing h Class 1E 72-hour battery is tested to verify the capability to provide its load for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> while ntaining the battery terminal voltage above the minimum voltage specified in Table 8.3.2-5.
lysis will be performed based on the design duty cycle, and testing will be performed with loads ch envelope the analyzed battery bank design duty cycle. Each battery is connected to a charger ntained at 270+/-2 V for a period of at least 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to the test to assure the battery is fully rged.
2.5.3 Class 1E Spare Battery Capacity Testing Class 1E spare battery is tested to the same requirements as the most severe of the six division eries.
2.5.4 Class 1E 24-Hour Inverter Capacity Testing h Class 1E 24-hour inverter is tested to verify the capability to provide 12 kW while maintaining output voltage and frequency within the tolerances specified in Table 8.3.2-5. The 12 kW capacity ufficient to meet the 24-hour inverter loads listed in Tables 8.3.2-1, 8.3.2-2, 8.3.2-3, and 8.3.2-4.
inverter input voltage will be no more than 210 Vdc during the test to represent the conditions at battery end of life.
2.5.5 Class 1E 72-Hour Inverter Capacity Testing h Class 1E 72-hour inverter is tested to verify the capability to provide 7 kW while maintaining the ut voltage and frequency within the tolerances specified in Table 8.3.2-5. The 7 kW capacity is cient to meet the 72-hour inverter loads listed in Tables 8.3.2-2 and 8.3.2-3. The inverter input age will be no more than 210 Vdc during the test to represent the conditions at the battery end of 8.3-22 Revision 1
output voltage within the range specified in Table 8.3.2-5. The 150 A is sufficient to meet the hour loads listed in Tables 8.3.2-1, 8.3.2-2, 8.3.2-3, and 8.3.2-4 while maintaining the esponding battery charged.
2.5.7 Class 1E 72-Hour Charger Capacity Testing h Class 1E 72-hour charger is tested to verify the capability to provide 125 A while maintaining output voltage within the range specified in Table 8.3.2-5. The 125 A is sufficient to meet the hour loads listed in Tables 8.3.2-2 and 8.3.2-3 while maintaining the corresponding battery rged.
2.5.8 Class 1E Regulating Transformer Capacity Testing h Class 1E regulating transformer is tested to verify the capability to provide 30 kW while ntaining the output voltage within the tolerance specified in Table 8.3.2-5. The 30 kW capacity is cient to meet the inverter loads listed in Tables 8.3.2-1, 8.3.2-2, 8.3.2-3 and 8.3.2-4.
2.5.9 Motor-Operated Valves Terminal Voltage Testing operating voltage supplied to Class 1E motor-operated valves is measured to verify the motor ter input terminal voltage is above the minimum design value of 200 Vdc. The battery terminal age will be no more than 210 Vdc during the test to represent the conditions at the battery end of 2.5.10 Non-Class 1E Battery Capacity Testing h load group 1, 2, 3, and 4 non-Class 1E battery is tested to verify the capability to provide 500 A wo hours while maintaining the battery terminal voltage above the minimum voltage specified in le 8.3.2-6. The 500 A is sufficient to meet the loads described in Subsection 8.3.2.1.2. Each ery is connected to a charger maintained at 135+/-1 V for a period of at least 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to the to assure the battery is fully charged.
2.5.11 Non-Class 1E Inverter Capacity Testing h load group 1, 2, 3, and 4 non-Class 1E inverter is tested to verify the capability to provide W while maintaining the output voltage and frequency within the tolerances specified in le 8.3.2-6. The 35 kW capacity is sufficient to meet the loads described in Subsection 8.3.2.1.2.
2.5.12 Non-Class 1E Charger Capacity Testing h load group 1, 2, 3, and 4 non-Class 1E charger is tested to verify the capability to provide 550 A e maintaining the output voltage within the range specified in Table 8.3.2-6. The 550 A is cient to meet the loads described in Subsection 8.3.2.1.2 while maintaining the corresponding ery charged.
3 Combined License Information for Onsite Electrical Power design of grounding and lightning protection is addressed in Subsections 8.3.1.1.7 and 8.3.1.1.8.
plant procedures for the following are addressed in Subsections 8.3.1.1.2.4, 8.3.1.1.6 and 2.1.4.
8.3-23 Revision 1
Battery maintenance and surveillance (for battery surveillance requirements, refer to Chapter 16, Section 3.8)
Periodic testing of penetration protective devices Diesel generator operation, inspection, and maintenance in accordance with manufacturers' recommendations.
Periodic testing on the battery chargers and voltage regulating transformers.
4 References NEMA MG-1, "Motors and Generators," 1998.
IEEE Standard 317, "Electric Penetration Assemblies in Containment Structures for Nuclear Power Generating Stations," 1983.
IEEE Standard 422, "Guide for the Design and Installation of Cable Systems in Power Generating Stations," 1986.
ICEA Standard Publication P-54-440, "Ampacities of Cables in Open-Top Cable Trays,"
1986.
NFPA 70, "National Electrical Code (NEC)," 1999.
IEEE Standard 485, "IEEE Recommended Practice for Sizing Lead-Acid Batteries for Stationary Applications," 1997.
IEEE Standard 384, "IEEE Standard Criteria for Independence of Class 1E Equipment and Circuits," 1981.
IEEE Standard 308, "IEEE Standard Criteria for Class 1E Power Systems for Nuclear Power Generating Stations," 1991.
IEEE Standard 946, "IEEE Recommended Practice for the Design of dc Auxiliary Power Systems for Generating Stations," 1992.
IEEE Standard 741, "IEEE Standard Criteria for the Protection of Class 1E Power Systems and Equipment in Nuclear Power Generating Stations," 1997.
IPCEA Standard Publication P-46-426-1962, "Power Cable Ampacities, Volume I -
Copper Conductors."
IEEE Standard 450, "IEEE Recommended Practice for Maintenance, Testing and Replacement of Vented Lead-Acid Batteries for Stationary Applications," 1995.
Young, G. L. et al., "Cable Separation - What Do Industry Programs Show?," IEEE Transactions of Energy Conversion, September 1990, Volume 5, Number 3, pp 585-602.
Not used.
8.3-24 Revision 1
IEEE Standard 141, "IEEE Recommended Practice for Electric Power Distribution for Industrial Plants" (IEEE Red Book), 1993.
IEEE Standard 242, "IEEE Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems" (IEEE Buff Book), 1986.
IEEE Standard 665, "IEEE Guide for Generating Station Grounding," 1995.
NFPA 780, "Standard for the Installation of Lightning Protection Systems," 2000.
IEEE Standard 1050, "IEEE Guide for Instrumentation and Control Equipment Grounding in Generating Stations," 1996
. Institute of Electrical and Electronics Engineers (IEEE), IEEE Guide for Safety in AC Substation Grounding, IEEE Std 80-2000, August 4, 2000.
. Institute of Electrical and Electronics Engineers (IEEE), Application Guide for Surge Protection of Electric Generating Plants: Document Number IEEE C.62.23-1995 (R2001).
8.3-25 Revision 1
Automatic Loads (Note 2)
Operating Load (kW)
(Note 4)
Time em Seq. Event or Rating At Power Shutdown
- o. (sec) Load Description (hp/kW) (Note 10) (Note 10)
- 1. 0 D/G Start Signal is Initiated - - -
- 2. TBD D/G Reaches IDLE Speed (Note 6) - - -
- 3. TBD D/G Reaches Full Speed (Note 6) - - -
- 4. 120 D/G Breaker Closes, Load - - -
Sequencer Starts
- 5. 120 Load Center Transformer EK11 2500 kVA 7.5 7.5 (Note 7)
- 6. 120 Load Center Transformer EK12 2500 kVA 7.5 7.5 (Note 7)
- 7. 120 Annex Bldg Lighting Panel (Note 8) 30 kVA 10 10
- 8. 120 Annex Bldg Lighting Panel (Note 8) 30 kVA 10 10
- 9. 120 Aux Bldg Lighting Panel (Note 8) 60 kVA 15 15
- 0. 120 Aux Bldg Lighting Panel (Note 8) 60 kVA 15 15
- 1. 120 Turbine Bldg Lighting Panel 40 kVA 7 7 (Note 8)
- 2. 120 Turbine Bldg Lighting Panel 40 kVA 7 7 (Note 8)
- 3. 120 Turbine Bldg Lighting Panel 40 kVA 7 7 (Note 8)
- 4. 120 D/G Bldg Lighting Panel (Note 8) 30 kVA 3 3
- 5. 120 D/G 2A AC/OC Radiator Fan 25 hp 21 21
- 6. 120 Diesel Oil Transfer Module Unit 15 kW 15 15 Heater A 8.3-26 Revision 1
Automatic Loads (Note 2)
Operating Load (kW)
(Note 4)
Time em Seq. Event or Rating At Power Shutdown
- o. (sec) Load Description (hp/kW) (Note 10) (Note 10)
- 7. 120 Diesel Oil Transfer Module Exhaust 0.5 hp 0.5 0.5 Fan A
- 8. 120 D/G A Jacket Water Radiator Fan 25 hp 21 21
- 9. 120 Class 1E Div. A Regulating XFMR 1 45 kVA 15 15
- 0. 120 Class 1E Div. C Regulating XFMR 1 45 kVA 15 15
- 1. 120 Motor-Operated Valves (Note 5) - - -
- 2. 120 D/G A Fuel Oil Transfer Pump 3 hp 3 3
- 3. 120 D/G A Bldg Stdby Exhaust Fan 1A 3 hp 3 3
- 4. 120 D/G A Bldg Stdby Exhaust Fan 2A 3 hp 3 3
- 5. 120 D/G A Bldg Primary AHU MS 01A 3 hp 3 3 Fan
- 6. 120 D/G A Fuel Oil Cooler Fan 2 hp 2 2
- 7. 140 Start-up Feed Water Pump A 800 hp 665 0
- 8. 160 Load Center Transformer EK13 2500 kVA 7.5 7.5 (Note 9)
- 9. 160 Aux Bldg Lighting Panel (Note 8) 60 kVA 15 15
- 0. 160 Fuel Oil Day Tank Vault Exhaust 0.5 hp 0.5 0.5 Fan A
- 1. 160 Diesel Fuel Oil Transfer Heater A 90 kW 90 90
- 2. 160 Service Water Pump A 500 hp 350 350
- 3. 180 Service Water Cooling Tower Cell 175 hp 120 120 Fan A
- 4. 200 Component Cooling Water Pump A 700 hp 500 500 8.3-27 Revision 1
Automatic Loads (Note 2)
Operating Load (kW)
(Note 4)
Time em Seq. Event or Rating At Power Shutdown
- o. (sec) Load Description (hp/kW) (Note 10) (Note 10)
- 5. 240 Normal Residual Heat Removal 250 hp 0 207 Pump A
- 6. 240 RNS Pump Room Fan A 1.5 hp 0 1.5
- 7. 240 Annex Bldg Equipment Room 20 hp 17 17 Return/Exhaust Fan A (Note 12)
- 8. 240 Annex Bldg Equipment Room AHU 50 hp 42 42 MS02A Fan (Note 12)
- 9. 240 Annex Bldg Swgr Rm AHU MS 05A 50 hp 42 42 Fan (Note 12)
- 0. 240 Annex Bldg Swgr Rm Ret/Exhaust 25 hp 21 21 Fan 06A (Note 12)
- 1. 240 Instrument Air Compressor A 200 hp 166 166
- 2. 300 Non-1E Battery Charger 117 kVA 88 88 EDS1-DC-1
- 3. 300 Non 1E Battery Room A Exhaust 0.5 hp 0.5 0.5 Fan
- 4. 300 Containment Recirculation Fan A 200 hp 149 149
- 5. 360 Containment Recirculation Fan D 200 hp 149 149
- 6. 360 Non-1E Battery Charger 117 kVA 88 88 EDS3-DC-1
- 7. 420 Div. A/C Class 1E Battery Room 5 hp 5 5 Exhaust Fan A Total Automatically Sequenced 2706 2249.5 Loads (kW) 8.3-28 Revision 1
Manual Loads (Note 2)
Time Operating m Seq. Event or Rating Load
- o. (sec) Load Description (hp/kW) (kW)
- 8. Class 1E Div. A Battery Charger 1 78 kVA 26 (Note 13)
- 9. -- Class 1E Div. C Battery Charger 1 78 kVA 26 (Note 13)
- 0. -- Class 1E Div. C Battery Charger 2 78 kVA 15
- 1. -- Supplemental Air Filtration System 15 hp 15 Fan A
- 2. -- Supplemental Air Filtration System 20 kW 20 Electric Heater A
- 3. -- Backup Group 4A Pressurizer 246 kW 246 Heaters
- 4. -- CRDM Fan 01A 75 hp 62
- 5. -- CRDM Fan 01B 75 hp 62
- 6. -- Spent Fuel Cooling Pump A 250 hp 200
- 7. -- Make-Up Pump A 600 hp 498
- 8. -- Non-1E Regulating XFMR 75 kVA 25 EDS1-DT-1
- 9. -- Non-1E Regulating XFMR 75 kVA 25 EDS3-DT-1
- 0. -- Main Control Room 40 hp 34 AHU Supply Fan A (Note 11)
- 1. -- Main Control Room 25 hp 21 AHU Return Fan A (Note 11)
- 2. -- Div A/C Class 1E Electrical Room 40 hp 34 AHU Supply Fan A (Note 11)
- 3. -- Div A/C Class 1E Electrical Room 25 hp 21 Return Fan A (Note 11) 8.3-29 Revision 1
Manual Loads (Note 2)
Time Operating em Seq. Event or Rating Load
- o. (sec) Load Description (hp/kW) (kW)
- 4. -- Div B/D Class 1E Electrical Room 25 hp 21 AHU Supply Fan D (Note 11)
- 5. -- Div B/D Class 1E Electrical Room 25 hp 21 Return Fan D (Note 11)
- 6. -- Air Cooled Chiller Pump 2 (Note 11) 20 hp 17
- 7. -- Air Cooled Chiller 2 (Note 11) 375 kW 375
- 8. -- CVS Pump Room Fan A (Note 11) 1.5 hp 1.5 Total Manually Sequenced Loads 1765.5 (kW) s:
Loads listed are for diesel generator ZOS MG 02A.
Loads identified in the first portion of the table (AUTOMATIC LOADS) will be loaded without operator action. Loads identified in the second portion of the table (MANUAL LOADS) will be energized at operator discretion based on system needs. Automatic loads may not be started until there is a system need. Not all manually sequenced loads will be operated simultaneously.
Time Sequence is counted from the time a diesel generator receives the start signal.
The "Operating Load" column shows the load input power requirement from the diesel generator.
Motor-operated valves (MOVs) pertaining to various systems will be energized on closure of the diesel generator breaker.
Normally the MOV power requirement is for a very short duration (a few seconds); hence, the MOV load will not affect the diesel generator capacity rating.
On receipt of the diesel generator start signal, the engine accelerates to a set idle speed. The engine operates at the idle speed for a time to allow bearing oil pressure buildup, proper lubrication of the moving parts, and engine warmup. After a set time delay (to be determined based on vendor selection), the engine will ramp up to the rated operating speed.
On restoring the power supply to the diesel backed bus ES1 by closing the diesel generator incoming breaker, the associated unit substation ECS EK 11 and 12 load center transformers are energized. The transformers draw magnetizing current and the no load losses (approx. 0.3 percent of the rating) from the bus.
Only a part of the building lighting load is automatically connected to the diesel generator bus. The remaining lighting load is connected via manual action at the operator's discretion.
Load Center ECS EK 13 transformer no load losses and magnetizing current is approximately 0.3 percent of the transformer rating.
The At Power loads are those loads that would be automatically sequenced on the diesel generator following a loss of offsite power and reactor trip from power; i.e., reactor coolant pressure above the residual heat removal system operating pressure.
The Shutdown loads are those loads that would be automatically sequenced on the diesel generator following a loss of offsite power during a plant shutdown; i.e., reactor coolant pressure below the residual heat removal system operating pressure and the RNS isolation valves open.
Air cooled chiller VWS MS 03 is automatically loaded on diesel generator ZOS MG 02B along with the VAS and VBS fans associated with the cooling coils served by this chiller. The redundant air cooled chiller VWS MS 02 and its associated VAS and VBS fans can be manually loaded on diesel generator ZOS MG 02A in case of failures of VWS MS 03 or ZOS MG 02B.
Annex building ventilation fans are automatically loaded on diesel generator ZOS MG 02A. The redundant fans can be manually loaded on diesel generator ZOS MG 02B in case of diesel generator or fan failures.
To prevent spurious ADS actuation, the 24-hour Class 1E battery chargers should be manually loaded on the diesel generator within 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br />; before the Automatic Depressurization Actuation (ADS) timer in the Protection and Safety Monitoring System actuates ADS on low battery charger input voltage.
8.3-30 Revision 1
Automatic Loads (Note 2)
Operating Load (kW)
Time em Seq. Event or Rating At Power Shutdown
- o. (sec) Load Description (hp/kW) (Note 10) (Note 10)
- 1. 0 D/G Start Signal is Initiated - - -
- 2. TBD D/G Reaches IDLE Speed (Note 6) - - -
- 3. TBD D/G Reaches Full Speed (Note 6) - - -
- 4. 120 D/G Breaker Closes, Load - - -
Sequencer Starts
- 5. 120 Load Center Transformer EK21 2500 kVA 7.5 7.5 (Note 7)
- 6. 120 Load Center Transformer EK22 2500 kVA 7.5 7.5 (Note 7)
- 7. 120 Annex Bldg Lighting Panel (Note 8) 30 kVA 10 10
- 8. 120 Annex Bldg Lighting Panel (Note 8) 30 kVA 10 10
- 9. 120 Aux Bldg Lighting Panel (Note 8) 60 kVA 15 15
- 0. 120 Aux Bldg Lighting Panel (Note 8) 60 kVA 15 15
- 1. 120 Turbine Bldg Lighting Panel 40 kVA 7 7 (Note 8)
- 2. 120 Turbine Bldg Lighting Panel 40 kVA 7 7 (Note 8)
- 3. 120 Turbine Bldg Lighting Panel 40 kVA 7 7 (Note 8)
- 4. 120 D/G Bldg Lighting Panel (Note 8) 30 kVA 3 3
- 5. 120 D/G 2B AC/OC Radiator Fan 25 hp 21 21
- 6. 120 Diesel Oil Transfer Module Unit 15 kW 15 15 Heater B
- 7. 120 Diesel Oil Transfer Module Exhaust 0.5 hp 0.5 0.5 Fan B
- 8. 120 D/G B Jacket Water Radiator Fan 25 hp 21 21 8.3-31 Revision 1
Automatic Loads (Note 2)
Operating Load (kW)
Time em Seq. Event or Rating At Power Shutdown
- o. (sec) Load Description (hp/kW) (Note 10) (Note 10)
- 9. 120 Class 1E Div. B Regulating XFMR 1 45 kVA 15 15
- 0. 120 Class 1E Div. D Regulating XFMR 1 45 kVA 15 15
- 1. 120 Motor-Operated Valves (Note 5) - - -
- 2. 120 D/G B Fuel Oil Transfer Pump 3 hp 3 3
- 3. 120 D/G B Bldg Stdby Exhaust Fan 1B 3 hp 3 3
- 4. 120 D/G B Bldg Stdby Exhaust Fan 2B 3 hp 3 3
- 5. 120 D/G B Bldg. Primary AHU MS 01B 3 hp 3 3 Fan
- 6. 120 D/G B Fuel Oil Cooler Fan 2 hp 2 2
- 7. 140 Start-up Feed Water Pump B 800 hp 665 0
- 8. 160 Load Center Transformer EK23 2500 kVA 7.5 7.5 (Note 9)
- 9. 160 Aux Bldg Lighting Panel (Note 8) 60 kVA 15 15
- 0. 160 Fuel Oil Day Tank Vault Exhaust 0.5 hp 0.5 0.5 Fan B
- 1. 160 Diesel Fuel Oil Transfer Heater B 90 kW 90 90
- 2. 160 Service Water Pump B 500 hp 350 350
- 3. 180 Service Water Cooling Tower Cell 175 hp 120 120 Fan B
- 4. 180 Main Control Room 40 hp 34 34 AHU Supply Fan B
- 5. 180 Main Control Room 25 hp 21 21 AHU Return Fan B
- 6. 180 Div. B/D Class 1E Electrical Room 25 hp 21 21 AHU Supply Fan B 8.3-32 Revision 1
Automatic Loads (Note 2)
Operating Load (kW)
Time em Seq. Event or Rating At Power Shutdown
- o. (sec) Load Description (hp/kW) (Note 10) (Note 10)
- 7. 180 Div B/D Class 1E Electrical Room 25 hp 21 21 Return Fan B
- 8. 180 Div A/C Class 1E Electrical Room 40 hp 34 34 AHU Supply Fan C
- 9. 180 Div A/C Class 1E Electrical Room 25 hp 21 21 Return Fan C
- 0. 180 Air Cooled Chiller Pump 3 20 hp 17 17
- 1. 200 Component Cooling Water Pump B 700 hp 500 500
- 2. 220 Air Cooled Chiller 3 375 kW 375 375
- 3. 240 CVS Pump Room Fan B 1.5 hp 1.5 1.5
- 4. 240 Instrument Air Compressor B 200 hp 166 166
- 5. 300 Normal Residual Heat Removal 250 hp 0 207 Pump B
- 6. 300 RNS Pump Room Fan B 1.5 hp 0 1.5
- 7. 300 Non-1E Battery Charger 117 kVA 88 88 EDS2-DC-1
- 8. 300 Non-1E Battery Room B Exhaust 0.5 hp 0.5 0.5 Fan 09B
- 9. 360 Containment Recirculation Fan B 200 hp 149 149
- 0. 360 Containment Recirculation Fan C 200 hp 149 149
- 1. 360 Non-1E Battery Charger 117 kVA 88 88 EDS4-DC-1
- 2. 420 Div. B/D Class 1E Battery Room 1.5 hp 1.5 1.5 Exhaust Fan B Total Automatically Sequenced 3126 2669.5 Loads (kW) 8.3-33 Revision 1
Manual Loads (Note 2)
Time Operating em Seq. Event or Rating Load
- o. (sec) Load Description (hp/kW) (kW)
- 3. -- Class 1E Div. B Battery Charger 1 78 kVA 26
- 4. -- Class 1E Div. B Battery Charger 2 78 kVA 15
- 5. -- Class 1E Div. D Battery Charger 1 78 kVA 26
- 6. -- Supplemental Air Filtration System 15 hp 15 Fan B
- 7. -- Supplemental Air Filtration System 20 kW 20 Electric Heater B
- 8. -- Backup Group 4B Pressurizer 246 kW 246 Heaters
- 9. -- CRDM Fan 01C 75 hp 62
- 0. -- CRDM Fan 01D 75 hp 62
- 1. -- Spent Fuel Cooling Pump B 250 hp 200
- 2. -- Make-Up Pump B 600 hp 498
- 3. -- Non-1E Regulating XFMR 75 kVA 25 EDS2-DT-1
- 4. -- Annex Bldg Equipment Room 20 hp 17 Return/Exhaust Fan B
- 5. -- Annex Bldg Equipment Room AHU 50 hp 42 MS02B Fan
- 6. -- Annex Bldg Swgr Rm AHU MS 05B 50 hp 42 Fan
- 7. -- Annex Bldg Swgr Rm Ret/Exhaust 25 hp 21 Fan 06B Total Manually Sequenced Loads 1317 (kW) 8.3-34 Revision 1
the second portion of the table (MANUAL LOADS) will be energized at operator discretion based on system needs. Automatic loads may not be started until there is a system need. Not all manually sequenced loads will be operated simultaneously.
Time Sequence is counted from the time a diesel generator receives the start signal.
The "Operating Load" column shows the load input power requirement from diesel generator.
Motor-operated valves (MOVs) pertaining to various systems will be energized on closure of the diesel generator breaker.
Normally the MOV power requirement is for a very short duration (few seconds); hence the MOV load will not affect the diesel generator capacity rating.
On receipt of the diesel generator start signal, the engine accelerates to a set idle speed. Engine operates at the idle speed for a time period to allow bearing oil pressure build up, proper lubrication of the moving parts, and engine warmup. After a set time delay (to be determined based on vendor selection), the engine will ramp up to the rated operating speed.
On restoring the power supply to the diesel backed bus ES2 by closing diesel generator incoming breaker, the associated unit substation ECS EK 21 and 22 load center transformers are energized. The transformers draw magnetizing current and the no load losses (approx. 0.3 percent of the rating) from the bus.
Only a part of the building lighting load is automatically connected to the diesel generator bus. The remaining lighting load is connected via manual action at the operator's discretion.
Load Center ECS EK 23 transformer no load losses and magnetizing current is approximately 0.3 percent of the transformer rating.
The At Power loads are those loads that would be automatically sequenced on the diesel generator following a loss of offsite power and reactor trip from power; i.e., reactor coolant pressure above the residual heat removal system operating pressure.
The Shutdown loads are those loads that would be automatically sequenced on the diesel generator following a loss of offsite power during a plant shutdown; i.e., reactor coolant pressure below the residual heat removal system operating pressure and the RNS isolation valves open.
Air cooled chiller VWS MS 03 is automatically loaded on diesel generator ZOS MG 02B along with the VAS and VBS fans associated with the cooling coils served by this chiller. The redundant air cooled chiller VWS MS 02 and its associated VAS and VBS fans can be manually loaded on diesel generator ZOS MG 02A in case of failures of VWS MS 03 or ZOS MG 02B.
Annex building ventilation fans are automatically loaded on diesel generator ZOS MG 02A. The redundant fans can be manually loaded on diesel generator ZOS MG 02B in case of diesel generator or fan failures.
To prevent spurious ADS actuation, the 24-hour Class 1E battery chargers should be manually loaded on the diesel generator within 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br />, before the Automatic Depressurization Actuation (ADS) timer in the Protection and Safety Monitoring System actuates ADS on low battery charger input voltage.
8.3-35 Revision 1
(Nominal Values)
Main Stepup Transformer 3 single phase, FOA, 65°C rise, liquid filled Unit Auxiliary Transformers (UAT 2A/2B) 3 phase, 3 winding H = 70 MVA, OA, 65°C X = 35 MVA, OA, 65°C Y = 35 MVA, OA, 65°C Unit Auxiliary Transformer (UAT 2C) 3 phase, 2 winding 33 MVA, OA, 65°C Reserve Auxiliary Transformers (RAT) 3 phase, 3 winding H = 70 MVA, OA, 65°C X = 35 MVA, OA, 65°C Y = 35 MVA, OA, 65°C 6.9 kV Switchgear medium voltage metal-clad switchgear Interrupting current rating - 63kA vacuum-type circuit breaker 480 V Load Centers Transformers - Indoor, Air-Cooled 2500 kVA, AA Ventilated Dry-Type, Fire Retardant: 3 phase, 60 Hz 6900 - 480 V 1000 kVA, AA (Load Center 71) 3 phase, 60 Hz 6900 - 480 V Main Bus Ampacity 4000 amperes continuous 2000 amperes continuous (Load Center 71) 480V Breakers metal enclosed draw-out circuit breaker or motor-starter (contactor) 65,000 A RMS symmetrical interrupting rating 480 V Motor Control Centers Horizontal Bus 800 A continuous rating 65,000 A RMS symmetrical bracing Vertical Bus 300 A continuous rating 65,000 A RMS symmetrical bracing Breakers (molded case) 65,000 A RMS symmetrical interrupting rating 8.3-36 Revision 1
Post-72 Hours Nominal Load Requirements Ancillary Ancillary AC Generator 1 AC Generator 2 em
- o. Description of Loads Load (kW) Load (kW)
Post-Accident Monitoring (PAM) Emergency and Panel 6.5 Lighting (Division B) in Main Control Room and ancillary fans Post-Accident Monitoring (PAM) Emergency and Panel 6.5 Lighting (Division C) in Main Control Room and ancillary fans
) PCS Recirculation Pumps 19.3 19.3 Ancillary Generator Room Lights 0.5 0.5 Ancillary Generator Fuel Tank Heater 1.25 kW 1.25 kW Total 27.55 kW 27.55 kW There are two PCS pumps; however, only one pump will be operating at any point in time on each generator. In case of fire fighting, two pumps (one on each generator) may be used.
8.3-37 Revision 1
Standby Diesel Generators Indication Alarm Parameter Control Room Local Control Room Local e Oil Pressure Low No Yes Yes Yes e Oil Temperature High No Yes Yes Yes e Oil Sump Level Low No Yes No Yes oling Water Temperature High Yes Yes Yes Yes oling Water Pressure Low No Yes Yes Yes Starting Air Pressure Low Yes Yes Yes Yes 8.3-38 Revision 1
Nominal Load Requirements Power Required (kW)
Load Description Momentary Continuous Bus IDSA DS 1 (24 hr Battery Bank) nverter Protection and Safety Monitoring System 0 10.6 Emergency Lighting 0 0.3 Containment High Range Monitor 0 0.1 Subtotal 0 11.0 250 Vdc Panel Reactor Trip Swgr & Solenoid Valves 7 0.5 250 Vdc MCC Motor-operated Valves 453 Total 460 11.5 8.3-39 Revision 1
Nominal Load Requirements Power Required (kW)
Load Description Momentary Continuous Bus IDSB DS 1 (24 hr Battery Bank) verter Protection and Safety Monitoring System 0 10.1 Emergency Lighting and Panel Lighting 0 0.5 Subtotal 0 10.6 250 Vdc Panel Reactor Trip Swgr, RCP Trip & Solenoid Valves 12 0.8 250 Vdc MCC Motor-operated Valves 290 Total 302 11.4 BUS IDSB DS 2 (72 hr Battery Bank) verter Protection and Safety Monitoring System 0 3.15 Emergency Lighting and Panel Lighting 0 0.63 Containment High Range Monitor 0 0.12 MCR Supply Duct Radiation Monitor 1.8 0.24 Total 1.8 4.14 8.3-40 Revision 1
Nominal Load Requirements Power Required (kW)
Load Description Momentary Continuous Bus IDSC DS 1 (24 hr Battery Bank) verter Protection and Safety Monitoring System 0 10.1 Emergency Lighting and Panel Lighting 0 0.5 Subtotal 0 10.6 250 Vdc Panel Reactor Trip Swgr, RCP Trip & Solenoid Valves 12 0.5 250 Vdc MCC Motor-operated Valves 173 Total 185 11.1 BUS IDSC DS 2 (72 hr Battery Bank) verter Protection and Safety Monitoring System 0 3.15 Emergency Lighting and Panel Lighting 0 0.63 Containment High Range Monitor 0 0.12 MCR Supply Duct Radiation Monitor 1.8 0.24 Total 1.8 4.14 8.3-41 Revision 1
Nominal Load Requirements Power Required (kW)
Load Description Momentary Continuous Bus IDSD DS 1 (24 hr Battery Bank) nverter Protection and Safety Monitoring System 0 10.6 Emergency Lighting 0 0.3 Containment High Range Monitor 0 0.1 Subtotal 0 11.0 250 Vdc Panel Reactor Trip Swgr & Solenoid Valves 6 0.8 250 Vdc MCC Motor-operated Valves 380 Total 386 11.8 8.3-42 Revision 1
(Nominal Values)
Battery Bank 250 Vdc (2 - 125 Vdc) 60 lead calcium cells, 2400 Ah. (8 hrs to 1.75 V per cell @ 77°F).
Charger AC input - 480 V, 3-phase, 60 Hz; dc output - 250 Vdc, 200 A continuous; float voltage 2.20 to 2.25 V/cell; equalizing charge voltage 2.33 V/cell.
Switchboard Main bus 600 A continuous, 50,000 A short circuit bracing; fuse disconnect switch 50,000 A interrupting rating, ontinuous ratings 200 and 400 A.
Spare Switchboard Main bus 1200 A continuous, 50,000 A short circuit bracing; fuse disconnect switch, 50,000 A interrupting rating, ontinuous rating 1200 A.
Motor Control Center Main bus 300 A continuous, vertical bus 300 A continuous, 50,000 A short circuit bracing.
Spare Battery Bank 2-125V dc 60 lead calcium cells, 2400 Ah. (8 hrs to 1.75 V per cell @ 77°F).
Spare Charger AC input - 480 V, 3-phase, 60 Hz; dc output - 250 Vdc, 200 A continuous; float voltage 2.20 to 2.25 V/cell; equalizing charge voltage - 2.33 V/cell.
Uninterruptible Power Supply (UPS)
- i. Inverter 15 kVA with 250 Vdc input and 208Y/120 Vac, 3-phase, 4-wire, 60 Hz output; ac output voltage regulation of +/-2% steady state; output frequency variation within 0.5% of nominal 60 Hz.
ii. Voltage Regulating Transformer 45 kVA, 480 V - 208Y/120V, 3-phase, 4-wire.
r to Figures 8.3.2-1 and 8.3.2-2 for the system component configuration.
8.3-43 Revision 1
(Nominal Values)
Battery Bank 125 Vdc 60 lead calcium cells, 2400 Ah. (8 hrs to 1.75 V per cell @ 77°F).
Charger AC input - 480 V, 3-phase, 60 Hz; dc output - 125 Vdc, 600 A continuous; float voltage - 2.20 to 2.25 V/cell; equalizing charge voltage - 2.33 V/cell.
Switchgear Main bus 1200 A continuous, 50,000 A short circuit bracing; breaker 1000A frame size.
Spare Charger AC input - 480 V, 3-phase, 60 Hz; dc output - 125 Vdc, 600 A continuous; float voltage - 2.20 to 2.25 V/cell; equalizing charge voltage - 2.33 V/cell.
Uninterruptible Power Supply (UPS)
- i. Inverter 50 kVA with 125 Vdc input and 208 Y/120 Vac, 3-phase, 4-wire, 60 Hz output; ac output voltage regulation of +/-2% steady state; output frequency variation within 0.5% of nominal 60 Hz.
ii. Voltage Regulating Transformer 75 kVA, 480 V - 208 Y/120 V, 3-phase, 4-wire.
r to Figure 8.3.2-3 for the system component configuration.
8.3-44 Revision 1
(Nominal Values)
Battery Bank 250 Vdc (2 - 125 Vdc) 60 lead calcium cells, 2400 Ah. (8 hrs to 1.75 V per cell @ 77°F).
Charger AC input - 480 V, 3-phase, 60 Hz; dc output - 250 Vdc, 200 A continuous; float voltage - 2.20 to 2.25 V/cell; equalizing charge voltage - 2.33 V/cell.
Switchgear Main bus 600 A continuous, 50,000 A short circuit bracing; breaker 1200 A frame size.
r to Figure 8.3.2-3 for the system component configuration.
8.3-45 Revision 1
Failure Modes and Effects Analysis Plant Failure Effect on Description of Operating Failure Method of Failure System Safety Components Safety Function Mode Mode(s) Detection Function Capability General Remarks Battery Charger Provide dc power A,B No output Annunciator in main None; Failure of only one Division A, IDSA DC 1 when ac power control room; battery Battery can provide div. chgr. falls into Division B, IDSB DC 1, 2 available and charger failure alarm for power for 24 and single failure criteria Division C, IDSC DC 1, 2 maintain battery in a ac power failure, 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> without and the other three Division D, IDSD DC 1 charged condition. dc output under/ over charger; other div. are still voltage, dc no charge, divisions available. available.
and input/output breaker Spare battery charger open. available for connection.
C No input Same as above. None; This component Battery can provide inoperable during power for 24 and blackout.
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> without charger.
Battery Backup to battery A,B No output Battery monitor provides None; Power still available Division A, IDSA DB 1A,1B charger during load or low annunciation in main Battery chargers with a single Division B, IDSB cycling (in-rush voltage control room; (item 1) available; ground. Loss of DB 1A,1B,2A,2B current) and provide switchboard failure alarm other divisions entire battery Division C, IDSC dc power for 24 and in main control room for available. Spare function is single DB 1A,1B,2A,2B 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> without ground detection and battery available for failure and the other Division D, IDSD DB 1A,1B battery charger. bus undervoltage. connection. divisions are available.
C No output Same as above. None; or low Other divisions voltage available; spare battery available.
Fused transfer switch box Provide circuit A,B,C Inadvertent Switchboard failure None; Division A, IDSA DF 1 continuity and opening alarm in main control Other divisions Division B, IDSB DF 1,2 protection between (blown room for ground available.
Division C, IDSC DF 1,2 Item 2 battery and fuse) detection and bus Division D, IDSD DF 1 Item 4 switchboard. undervoltage.
8.3-46 Revision 1
Class 1E 250V DC and Class 1E Uninterruptible Power Supplies Failure Modes and Effects Analysis Plant Failure Effect on m Description of Operating Failure Method of Failure System Safety
. Components Safety Function Mode Mode(s) Detection Function Capability General Remarks
. 250V DC Switchboard Distribute power via A,B,C Bus ground Switchboard failure None; Division A, IDSA DS 1 fusible disconnects fault alarm in main control Other divisions Division B, IDSB DS 1,2 to loads from room for ground available.
Division C, IDSC DS 1,2 chargers and detection and bus Division D, IDSD DS 1 battery. undervoltage.
. Fusible disconnect Provide circuit A,B Inadvertent Alarm in main control None; Division A, for Charger 1 continuity and opening room for charger failure Battery can provide Division B, for protection between (blown (dc no charge). power for 24 and Charger 1,2 Item 1 and 4. fuse) 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> without Division C, for chargers. Other Charger 1,2 divisions available.
Division D, for Charger 1 C Inadvertent Same as above. None; opening Battery can provide (blown power for 24 and fuse) 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> without chargers.
. Fusible disconnect Provide circuit A,B,C Inadvertent Inverter trouble alarm in None; Division A, for Inverter 1 continuity and opening main control room for System safety Division B, for Inverter 1,2 protection between (blown loss of dc input, loss of function can be met Division C, for Inverter 1,2 Item 4 switchboard fuse) ac output, input, output with loss of one Division D, for Inverter 1 and Item 9 inverters. and backup power division.
supply breaker open.
. Fusible disconnect for Provide circuit A,B,C Inadvertent DC MCC trouble alarm in None; DC MCC continuity and opening main control room for Other divisions Division A protection between (blown bus undervoltage. available.
Division B Item 4 switchboard fuse)
Division C and Item 13 DC Division D MCC.
8.3-47 Revision 1
Failure Modes and Effects Analysis Plant Failure Effect on m Description of Operating Failure Method of Failure System Safety
. Components Safety Function Mode Mode(s) Detection Function Capability General Remarks
. Fusible disconnect for Provide circuit A,B,C Inadvertent DC dist. panel trouble None; DC dist panel continuity and opening alarm in main control Other divisions Division A protection between (blown room for bus available.
Division B Item 4 switchboard fuse) undervoltage.
Division C and Item 14 dc Division D panel.
. Inverter Convert 250V DC to A,B,C No output Alarm in main control None; Division A, IDSA DU 1 208Y/120V AC and room for common UPS System safety Division B, IDSB DU 1,2 provide 120V AC trouble, for loss of dc function can be met Division C, IDSC DU 1,2 power. input, loss of ac output; with loss of one Division D, IDSD DU 1 input, output and backup division.
power supply breakers open.
. Voltage regulating Backup to inverter A,B No output Alarm in main control None; For single failure transformer (Item 9) when it is room for input and output Other divisions analysis: These Division A, IDSA DT 1 bypassed for power supply breakers available. components are Division B, IDSB DT 1 maintenance or open. And bus redundant to Item 1.
Division C, IDSC DT 1 malfunction (local undervoltage. These components Division D, IDSD DT 1 manual switching at are redundant to inverter). Item 9.
C No input Bus undervoltage. None This component cannot function during blackout.
. 208Y/120V AC distr. Distribute power via A,B,C Ground and Alarm in main control None; panel breakers to loads bus fault room for undervoltage. System safety Division A, IDSA EA 1 function can be met Division B, IDSB EA 1,3 with loss of one Division C, IDSC EA 1,3 division.
Division D, IDSD EA 1 8.3-48 Revision 1
Failure Modes and Effects Analysis Plant Failure Effect on m Description of Operating Failure Method of Failure System Safety
. Components Safety Function Mode Mode(s) Detection Function Capability General Remarks
. 208Y/120V AC Distr. Backup to invertor A,B Ground and Alarm in main control None; Panel (Item 9) when it is bus fault room for bus Other divisions Div. A, IDSA EA 2 bypassed for undervoltage. available.
Div. B, IDSB EA 2 maintenance or Div. C, IDSC EA 2 malfunction (local C No input Bus under voltage. None This component Div. D, IDSD EA 2 manual switching at cannot function inverter). during blackout.
. DC MCC Distribute power via A,B,C Ground and MCC trouble alarm per None; Power still available DIV. A, IDSA DK 1 fusible disconnect to bus fault MCC in main control Other divisions with a single DIV. B, IDSB DK 1 loads. room for bus available. ground.
DIV. C, IDSC DK 1 undervoltage and ground DIV. D, IDSD DK 1 detection.
. DC Distr. Panel Distribute power via A,B,C Ground and Panel trouble alarm per None; Power still available Div. A, IDSA DD1 fusible disconnect to bus fault panel in main control Other divisions with a single Div. B, IDSB DD1 loads. room for bus available. ground.
Div. C, IDSC DD1 undervoltage and ground Div. D, IDSD DD1 detection.
Plant operating modes are represented as follows:
A - Normal or preferred power available.
B - Loss of normal power and loss of preferred power and onsite standby diesel generator available.
C - Blackout (loss of all ac systems, except 208Y/120-V AC UPS system).
System success criteria are as follows:
250-V DC System - Three out of four (Division A, B, C or D) divisions required.
208Y/120-V AC UPS System - Three out of four divisions required.
The failure of any one fusible disconnect or opening of one circuit breaker under a fault condition results in only the loss of the associated division. The other redundant divisions still remain available.
8.3-49 Revision 1
WLS 1&2 - UFSAR Figure 8.3.1-1 AC Power Station One Line Diagram 8.3-50 Revision 1
WLS 1&2 - UFSAR Figure 8.3.1-2 Onsite Standby Diesel Generator Initiating Circuit Logic Diagram 8.3-51 Revision 1
WLS 1&2 - UFSAR Figure 8.3.1-3 Post-72-Hour Temporary Electric Power One Line Diagram 8.3-52 Revision 1
WLS 1&2 - UFSAR Inside Diesel Generator Building Figure 8.3.1-4 (Sheet 1 of 2)
Diesel Generator System Piping and Instrumentation Diagram (REF) ZOS 001 8.3-53 Revision 1
WLS 1&2 - UFSAR Inside Diesel Generator Building Figure 8.3.1-4 (Sheet 2 of 2)
Diesel Generator System Piping and Instrumentation Diagram (REF) ZOS 002 8.3-54 Revision 1
WLS 1&2 - UFSAR Inside Diesel Generator Building Figure 8.3.1-5 (Sheet 1 of 2)
Diesel Engine Skid Mounted System (REF) ZOS K001 8.3-55 Revision 1
WLS 1&2 - UFSAR Inside Diesel Generator Building Figure 8.3.1-5 (Sheet 2 of 2)
Diesel Engine Skid Mounted System (REF) ZOS K002 8.3-56 Revision 1
WLS 1&2 - UFSAR Figure 8.3.2-1 (Sheet 1 of 2)
Class 1E DC System One Line Diagram 8.3-57 Revision 1
WLS 1&2 - UFSAR Figure 8.3.2-1 (Sheet 2 of 2)
Class 1E DC System One Line Diagram 8.3-58 Revision 1
WLS 1&2 - UFSAR Figure 8.3.2-2 Class 1E 208y/120V UPS One Line Diagram 8.3-59 Revision 1
WLS 1&2 - UFSAR Figure 8.3.2-3 (Sheet 1 of 3)
Non-Class 1E DC & UPS System One Line Diagram 8.3-60 Revision 1
WLS 1&2 - UFSAR Figure 8.3.2-3 (Sheet 2 of 3)
Non-Class 1E DC & UPS System One Line Diagram 8.3-61 Revision 1
WLS 1&2 - UFSAR Figure 8.3.2-3 (Sheet 3 of 3)
Non-Class 1E DC & UPS System One Line Diagram 8.3-62 Revision 1