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| number = ML17226A144
| number = ML17226A144
| issue date = 07/28/2017
| issue date = 07/28/2017
| title = River Bend Station, Unit 1, Revision 25 to the Updated Safety Analysis Report, Chapter 8, Section 8.1 Through 8.3
| title = 5 to the Updated Safety Analysis Report, Chapter 8, Section 8.1 Through 8.3
| author name =  
| author name =  
| author affiliation = Entergy Operations, Inc
| author affiliation = Entergy Operations, Inc
Line 20: Line 20:


==8.1 INTRODUCTION==
==8.1 INTRODUCTION==
 
8.1.1 Utility Grid Description The Gulf States Utilities Company (GSU) electrical system consists of interconnected fossil fuel plants and future plants supplying electric energy over a 500/230/138-kV transmission system (Fig. 8.1-1 through 8.1-3).  
====8.1.1 Utility====
11 GSU, a member of the Southeastern Electric Reliability Council, is interconnected with Arkansas Power and Light Company (AP&L),
Grid Description The Gulf States Utilities Company (GSU) electrical system consists of interconnected fossil fuel plants and future plants  
Mississippi Power and Light Company (MP&L), Louisiana Power and Light Company (LP&L), and Central Louisiana Electric Company (CLECo). Prior to January 1, 1998, GSU was a member of the Southwest Power Pool.
 
11
supplying electric energy over a 500/230/138-kV transmission  
The River Bend Station Unit 1 main generator is rated 1,151 MVA, 0.9 pf, 22-kV, 1,800 rpm, three-phase, 60 Hz.
 
system (Fig. 8.1-1 through 8.1-3). 11GSU, a member of the Southeastern Electric Reliability Council, is interconnected with Arkansas Power and Light Company (AP&L),
Mississippi Power and Light Company (MP&L), Louisiana Power and Light Company (LP&L), and Central Louisiana Electric Company (CLECo). Prior to January 1, 1998, GSU was a member of the  
 
Southwest Power Pool.
11The River Bend Station Unit 1 main generator is rated 1,151 MVA, 0.9 pf, 22-kV, 1,800 rpm, three-phase, 60 Hz.
The output of the station is delivered to Fancy Point Substation, a 230/500-kV substation (Fig. 8.1-4 and 8.1-5) via a 230-kV line.
The output of the station is delivered to Fancy Point Substation, a 230/500-kV substation (Fig. 8.1-4 and 8.1-5) via a 230-kV line.
This substation consists of 230-kV bays and 500-kV bays.
This substation consists of 230-kV bays and 500-kV bays.
 
Transmission lines at 230-kV feed power to the GSU 230-kV system, the central part of Baton Rouge area by connecting to the Enjay Substation, the eastern part by connecting to the Coly Substation, and the northern part by connecting to the Port Hudson Substation. Power is also fed at 500-kV to the GSU system and to the power pool. The 500-kV, 230-kV, and 138-kV systems are interconnected at various locations.
Transmission lines at 230-kV feed power to the GSU 230-kV system, the central part of Baton Rouge area by connecting to the Enjay Substation, the eastern part by connecting to the Coly Substation, and the northern part by connecting to the Port Hudson Substation. Power is also fed at 500-kV to the GSU system and to the power pool. The 500-kV, 230-kV, and 138-kV systems  
8.1.2 Interconnections  
 
11 The transmission system from GSU's generation facilities is closely integrated with those of other utilities in the Southwest Power Pool and the Southeastern Electric Reliability Council. As of the year 1984, GSU expects to have 11 interconnections to CLECo at 138-kV and 230-kV; 8 interconnections to Middle South System (MSS) at 115-kV, 138-kV, 230-kV, and 500-kV voltage levels; 1 interconnection at 345-kV to the Southwestern Electric Power Company (SWEPCo); and 3 interconnections at 230-kV and 500-kV to the Cajun Electric Power Cooperative, Incorporated (CEPCo).
are interconnected at various locations.
Table 8.1-1 is a listing of the tie lines, voltage levels of interconnected buses, and utilities, which are projected for the year 1984.
 
In 11
====8.1.2 Interconnections====
11The transmission system from GSU's generation facilities is closely integrated with those of other utilities in the Southwest Power Pool and the Southeastern Electric Reliability Council. As of the year 1984, GSU expects to have 11 interconnections to CLECo at 138-kV and 230-kV; 8 interconnections to Middle South System (MSS) at 115-kV, 138-kV, 230-kV, and 500-kV voltage  
 
levels; 1 interconnection at 345-kV to the Southwestern Electric Power Company (SWEPCo); and 3 interconnections at 230-kV and 500-kV to the Cajun Electric Power Cooperative, Incorporated (CEPCo).
Table 8.1-1 is a listing of the tie lines, voltage levels of  
 
interconnected buses, and utilities, which are projected for the year 1984. In 11 RBS USAR Revision 22 8.1-2 addition to the listed interconnections, new transmission lines are expected to be placed in service with installation of future
 
units.
 
====8.1.3 Transmission====
System at Site
 
Section 8.2.1, along with Fig. 8.1-4 through 8.1-7, and 8.2-2, describes the transmission system at the site.
 
====8.1.4 Onsite====
AC Systems  6  4 River Bend Station is provided power from the 230-kV bays of the Fancy Point Substation via two physically and electrically independent lines. Each 230-kV line is terminated at a transformer yard. The two transformer yards, designated yard 1 and yard 2A, are physically separated from each other.
Transformer yard 1 is located adjacent to the east wall of the turbine building, while transformer yard 2A is located outside the security fence, southwest of the turbine building.
Transformer yard 1 contains three normal station service transformers, 1STX-XNS1A, 1STX-XNS1B and 1STX-XNS1C, and two preferred station service transformers, 1RTX-XSR1C and 1RTX-XSR1E, in addition to the two main stepup transformers 1MTX-XM1 and 1MTX-XM2. Transformer yard 2A contains two preferred station service transformers, 1RTX-XSR1F and 1RTX-XSR1D. The transformers in both transformer yards support the normal operation and safe shutdown of River Bend Station. See Fig. 8.2-
 
2 for the configuration of the two transformer yards.
4 6 The main generator leads of River Bend Station are connected by means of isolated phase bus duct to two 518.6/788.5 MVA, 65°C, FOA, 21.45-kV delta 150-kV BIL to 230-kV grounded wye 750-kV BIL, three-phase, 60 Hz main stepup transformers, 1MTX-XM1 and 1MTX-XM2. These two half-size transformers are paralleled on both the low (input) and high (output) sides. Disconnecting means are provided to allow the removal of one transformer from service, thus permitting the unit to continue generating power. The single 230-kV output circuit has bundled conductors, and is routed on a double circuit steel tower line to the 230-kV bays of the Fancy Point Substation approximately 4,000 ft southwest of
 
the plant.
 
The main generator leads of River Bend Station are also connected
 
by means of isolated phase bus duct to three normal station
 
service transformers with the following ratings:
RBS USAR Revision 22 8.1-3  1. Normal station service transformer s 1STX-XNS1A and 1STX-XNS1B are rated 47.5  MVA, 65°C,  FOA,  22-kV delta 150-kV BIL to 13.8-kV delta 110-kV BIL, three-phase, 60 Hz.
: 2. Normal station service transformer 1STX-XNS1C is rated 16 MVA, 65°C, FOA, 22-kV delta, 150-kV BIL primary with two secondary windings each rated 8 MVA with 4.16-kV
 
resistance grounded wye 75-kV BIL, three-phase, 60 Hz.
 
All three normal station service transformers are paralleled on their high (input) sides while their low (output) sides are routed to their separate 13.8-kV and 4.16-kV buses.
 
Preferred plant ac station service power is provided by two physically and electrically independent 230-kV lines originating
 
in the 230-kV bays of the Fancy Point Substation and terminating at transformer yards 1 and 2A. These 230-kV lines are installed on double circuit transmission towers, as shown in Fig. 8.2-1, with the station service power circuits located adjacent to the generator output circuits. Their function is to provide all power requirements when normal power is unavailable. Preferred
 
station service transformers are rated as follows:  13  6  4  1. Preferred station service transformer 1RTX-XSR1E is rated 51/68/85 MVA, 55°C OA/FOA/FOA 230-kV Delta 750-kV BIL to 13.8-kV ground wye 110-kV BIL, three-phase, 60 Hz and
 
1RTX-XSR1F is rated 51/68/85 MVA, 55°C OA/FOA/FOA 230-kV delta 750-kV BIL to 13.8 kV grounded wye 110-kV BIL, three-phase, 60Hz.
4 6 13  2. Preferred station service transformers 1RTX-XSR1C and 1RTX-XSR1D are rated 10/12.5 MVA, 65° C OA/FA, 230-kV grounded wye 750-kV BIL to 4.16-kV resistance grounded
 
wye 75-kV BIL, three-phase, 60 Hz.


The arrangement of the preferred and normal station service transformers is shown on Fig. 8.1-8 and 8.1-9. Each transformer is provided with its own fire barrier and a separate deluge valve and water spray fire protection line. Separate oil pits and
RBS USAR Revision 22 8.1-2 addition to the listed interconnections, new transmission lines are expected to be placed in service with installation of future units.
8.1.3 Transmission System at Site Section 8.2.1, along with Fig. 8.1-4 through 8.1-7, and 8.2-2, describes the transmission system at the site.
8.1.4 Onsite AC Systems
*6 *4 River Bend Station is provided power from the 230-kV bays of the Fancy Point Substation via two physically and electrically independent lines. Each 230-kV line is terminated at a transformer yard. The two transformer yards, designated yard 1 and yard 2A, are physically separated from each other.
Transformer yard 1 is located adjacent to the east wall of the turbine building, while transformer yard 2A is located outside the security
: fence, southwest of the turbine building.
Transformer yard 1 contains three normal station service transformers, 1STX-XNS1A, 1STX-XNS1B and 1STX-XNS1C, and two preferred station service transformers, 1RTX-XSR1C and 1RTX-XSR1E, in addition to the two main stepup transformers 1MTX-XM1 and 1MTX-XM2. Transformer yard 2A contains two preferred station service transformers, 1RTX-XSR1F and 1RTX-XSR1D.
The transformers in both transformer yards support the normal operation and safe shutdown of River Bend Station. See Fig. 8.2-2 for the configuration of the two transformer yards.
4* 6*
The main generator leads of River Bend Station are connected by means of isolated phase bus duct to two 518.6/788.5 MVA, 65°C, FOA, 21.45-kV delta 150-kV BIL to 230-kV grounded wye 750-kV BIL, three-phase, 60 Hz main stepup transformers, 1MTX-XM1 and 1MTX-XM2. These two half-size transformers are paralleled on both the low (input) and high (output) sides. Disconnecting means are provided to allow the removal of one transformer from service, thus permitting the unit to continue generating power. The single 230-kV output circuit has bundled conductors, and is routed on a double circuit steel tower line to the 230-kV bays of the Fancy Point Substation approximately 4,000 ft southwest of the plant.
The main generator leads of River Bend Station are also connected by means of isolated phase bus duct to three normal station service transformers with the following ratings:


retaining curbs are provided for the groups of transformers.  
RBS USAR Revision 22 8.1-3
: 1. Normal station service transformers 1STX-XNS1A and 1STX-XNS1B are rated 47.5 MVA, 65°C, FOA, 22-kV delta 150-kV BIL to 13.8-kV delta 110-kV BIL, three-phase, 60 Hz.
: 2. Normal station service transformer 1STX-XNS1C is rated 16 MVA, 65°C, FOA, 22-kV delta, 150-kV BIL primary with two secondary windings each rated 8 MVA with 4.16-kV resistance grounded wye 75-kV BIL, three-phase, 60 Hz.
All three normal station service transformers are paralleled on their high (input) sides while their low (output) sides are routed to their separate 13.8-kV and 4.16-kV buses.
Preferred plant ac station service power is provided by two physically and electrically independent 230-kV lines originating in the 230-kV bays of the Fancy Point Substation and terminating at transformer yards 1 and 2A. These 230-kV lines are installed on double circuit transmission towers, as shown in Fig. 8.2-1, with the station service power circuits located adjacent to the generator output circuits. Their function is to provide all power requirements when normal power is unavailable. Preferred station service transformers are rated as follows:
*13 *6 *4
: 1. Preferred station service transformer 1RTX-XSR1E is rated 51/68/85 MVA, 55°C OA/FOA/FOA 230-kV Delta 750-kV BIL to 13.8-kV ground wye 110-kV BIL, three-phase, 60 Hz and 1RTX-XSR1F is rated 51/68/85 MVA, 55°C OA/FOA/FOA 230-kV delta 750-kV BIL to 13.8 kV grounded wye 110-kV BIL, three-phase, 60Hz.
4* 6* 13*
: 2. Preferred station service transformers 1RTX-XSR1C and 1RTX-XSR1D are rated 10/12.5 MVA, 65° C OA/FA, 230-kV grounded wye 750-kV BIL to 4.16-kV resistance grounded wye 75-kV BIL, three-phase, 60 Hz.
The arrangement of the preferred and normal station service transformers is shown on Fig. 8.1-8 and 8.1-9. Each transformer is provided with its own fire barrier and a separate deluge valve and water spray fire protection line. Separate oil pits and retaining curbs are provided for the groups of transformers.
Oil pits and associated retention curbs have been sized to hold the oil from the largest transformer draining into the pit plus the water from the operation of fire protection systems of two transformers for 10 minutes.  


Oil pits and associated retention curbs have been sized to hold
RBS USAR Revision 22 8.1-4 This design prevents a fire or oil spill associated with one transformer from affecting the operability of other transformers.
Fire barriers are designed utilizing guidance from applicable NFPA requirements.
The secondaries of transformers located in both transformer yards are connected to 13.8-kV and 4.16-kV buses via cables installed in concrete-encased ductlines in the yard and cable tray inside the power plant. Fig. 8.1-4 and 8.1-6 illustrate the station service electrical system.
The two double-circuit tower lines from the Fancy Point Substation to the power plant are of the steel pole, H-frame structure design on the same right-of-way. These 230-kV tower structures are so designed and physically spaced that failure of one does not jeopardize the operation of the other (Fig. 8.2-1).
*7 *6 Each section of the 13.8-KV and 4.16-KV buses has access to the assigned normal and assigned preferred station transformers which are connected to the buses by circuit breakers controlled from the main control room. In addition, if the unit auxiliary loads are being supplied through the normal transformers, automated throw-over from normal to preferred source occurs (as described in Section 8.3.1.1.3) after unit trip or upon loss of normal power. Each of the two 13.8-kV buses, 1NPS-SWG1A and 1NPS-SWG1B, and each of the 4.16-kV buses, 1NNS-SWG1A and 1NNS-SWG1B, support redundant equipment. 13.8-kV buses 1NPS-SWG1C and 1NPS-SWG1D have access to the assigned preferred station service transformers 1RTX-XSR1E and 1RTX-XSR1F respectively, which are connected to the buses by circuit breakers controlled from the main control room.
6*
Each of the two primary 4.16-kV in-station normal buses, 1NNS-SWG1A and 1NNS-SWG1B, can be energized via the dual secondaries of normal station service transformer 1STX-XNS1C. NNS-SWG1A can also be energized from preferred station transformer 1RTX-XSR1C and NNS-SWG1B can also be energized from preferred station transformer 1RTX-XSR1D. A third 4.16-kV in-station normal swing bus, 1NNS-SWG1C, is subordinate to one or the other of the above 4.16-kV normal buses.
7*
Two of the standby 4.16-kV buses, 1ENS*SWG1A and 1ENS*SWG1B, are connected to preferred station service transformers, 1RTX-XSR1C and 1RTX-XSR1D, respectively.
The standby 4.16-kV
: bus, 1E22*S004, is normally connected to the 4.16-kV in-station normal swing bus 1NNS-SWG1C. Each of these standby buses has a standby diesel generator capable of supporting it upon loss of normal and preferred power. Switching allows each of the 4.16-kV standby buses to have access to one of the two 4.16-kV in-station normal buses while the 4.16-kV standby bus 1E22*S004 is subordinate to the 4.16-kV in-station swing bus 1NNS-SWG1C. The 4.16-kV standby buses serve redundant loads and are electrically isolated from each other.


the oil from the largest transformer draining into the pit plus
RBS USAR Revision 20 8.1-5 8.1.5 Onsite DC Systems
6 The onsite dc power systems provide power for
: control, instrumentation, indication, valve operators, solenoid valves, uninterruptible power supplies, and essential dc motors. There are three physically and electrically independent standby 125-V dc systems (including buses 1ENB*SWG01A, 1ENB*SWG01B, and 1E22*S001, which supply power to the standby diesel auxiliary loads) and seven normal 125-V dc systems, including buses 1BYS-SWG01A, 1BYS-SWG01B, and 1IHS-SWG01D, and 125 VDC panels 1BYS-PNL01, 1BYS-PNL04, 1BYS-PNL06, and 1BXY-PNL01 which supply power to nonsafety-related loads as shown on Fig. 8.3-6.
6
8.1.6 Identification of Safety-Related Systems 8.1.6.1 System Functions Sections 8.3.1.1.2.1 and 8.3.1.3, and Table 8.3-1 identify safety-related systems and their functions.
8.1.6.2 Power Supply Sources Power supply sources to safety-related systems, as shown in Fig. 8.1-4, consist of the main generator through one three-winding normal station service transformer, the two redundant offsite 230-kV transmission lines through two preferred station service transformers, two standby ac diesel generators, and a high pressure core spray (HPCS) ac diesel generator. Standby power is not connected to or influenced by the 13.8-kV system.
13 Each of the three diesel generators 1EGS*EG1A, 1EGS*EG1B, and 1E22*S001G1C is connected to 4.16-kV standby buses 1ENS*SWG1A, 1ENS*SWG1B, and 1E22*S004, respectively. Electric power to the safety-related systems from the normal and preferred station service transformers is supplied as follows.
The dual secondaries of normal station service transformer 1STX-XNS1C can be connected to two normal 4.16-kV buses 1NNS-SWG1A and 1NNS-SWG1B through normally open breakers. The two normal 4.16-kV buses are connected to the preferred station service transformers through normally closed breakers. The normal 4.16-kV swing bus 1NNS-SWG1C is subordinate to one or the other of the above normal 4.16-kV buses. The normal 4.16-kV bus 1NNS-SWG1A has a normally open tie to standby 4.16-kV bus 1ENS*SWG1B at the standby bus.
Normal 4.16-kV bus 1NNS-SWG1B has a normally open tie to standby 4.16-kV bus 1ENS*SWG1A at the standby bus. Normal 4.16-kV swing bus 1NNS-SWG1C has two 4.16-kV sources of power from either normal 4.16-kV bus 1NNS-SWG1B or normal 4.16-kV bus 1NNS-SWG1A which is controlled by station operating procedure. Normal 4.16-kV 13


the water from the operation of fire protection systems of two
RBS USAR 8.1-6 August 1987 swing bus 1NNS-SWG1C has a 4.16-kV tie to standby bus 1E22*S004.
 
Standby 4.16-kV buses 1ENS*SWG1A and 1ENS*SWG1B are energized from the preferred station service transformers at all times via normally closed switchgear circuit breakers connected to the secondaries of the preferred station service transformers.
transformers for 10 minutes.
8.1.7 Identification of Safety Criteria 8.1.7.1 General Functional Design Basis Chapter 3 outlines the general engineering criteria for nuclear plant design and delineates several areas of general classification and/or conformance which are applicable to the electrical power systems and equipment. Further clarification of some specific standards and criteria related to electrical systems is given in Chapter 7. Section 7.1.2 outlines various standards and criteria for systems which may include electrical functions similar to electrical power systems.
 
Specific requirements for electrical power systems and equipment are given in the following paragraphs.
RBS USAR Revision 22 8.1-4 This design prevents a fire or oil spill associated with one transformer from affecting the operability of other transformers. 
8.1.7.2 Design Basis General Design Criteria The conformance discussion provided in Section 3.1 for the General Design Criteria (GDC) applies to the electrical systems in Chapter 8, as identified in Table 8.1-2.
 
Fire barriers are designed utilizing guidance from applicable
 
NFPA requirements.
 
The secondaries of transformers located in both transformer yards
 
are connected to 13.8-kV and 4.16-kV buses via cables installed
 
in concrete-encased ductlines in the yard and cable tray inside the power plant. Fig. 8.1-4 and 8.1-6 illustrate the station
 
service electrical system.
 
The two double-circuit tower lines from the Fancy Point
 
Substation to the power plant are of the steel pole, H-frame structure design on the same right-of-way. These 230-kV tower structures are so designed and physically spaced that failure of
 
one does not jeopardize the operation of the other (Fig. 8.2-1). 7  6 Each section of the 13.8-KV and 4.16-KV buses has access to the assigned normal and assigned preferred station transformers which are connected to the buses by circuit breakers controlled from the main control room. In addition, if the unit auxiliary loads
 
are being supplied through the normal transformers, automated throw-over from normal to preferred source occurs (as described in Section 8.3.1.1.3) after unit trip or upon loss of normal power. Each of the two 13.8-kV buses, 1NPS-SWG1A and 1NPS-SWG1B, and each of the 4.16-kV buses, 1NNS-SWG1A and 1NNS-SWG1B, support redundant equipment. 13.8-kV buses 1NPS-SWG1C and 1NPS-SWG1D have access to the assigned preferred station service transformers 1RTX-XSR1E and 1RTX-XSR1F respectively, which are connected to the buses by circuit breakers controlled from the
 
main control room.
6 Each of the two primary 4.16-kV in-station normal buses, 1NNS-SWG1A and 1NNS-SWG1B, can be energized via the dual secondaries of normal station service transformer 1STX-XNS1C. NNS-SWG1A can also be energized from preferred station transformer 1RTX-XSR1C and NNS-SWG1B can also be energized from preferred station transformer 1RTX-XSR1D. A third 4.16-kV in-station normal swing bus, 1NNS-SWG1C, is subordinate to one or the other of the above
 
4.16-kV normal buses.
7 Two of the standby 4.16-kV buses, 1ENS*SWG1A and 1ENS*SWG1B, are connected to preferred station service transformers, 1RTX-XSR1C and 1RTX-XSR1D, respectively. The standby 4.16-kV bus, 1E22*S004, is normally connected to the 4.16-kV in-station normal swing bus 1NNS-SWG1C. Each of these standby buses has a standby
 
diesel generator capable of supporting it upon loss of normal and preferred power. Switching allows each of the 4.16-kV standby buses to have access to one of the two 4.16-kV in-station normal
 
buses while the 4.16-kV standby bus 1E22*S004 is subordinate to the 4.16-kV in-station swing bus 1NNS-SWG1C. The 4.16-kV standby buses serve redundant loads and are electrically isolated from
 
each other.
RBS USAR Revision 20 8.1-5 8.1.5 Onsite DC Systems 6The onsite dc power systems provide power for control, instrumentation, indication, valve operators, solenoid valves, uninterruptible power supplies, and essential dc motors. There are three physically and electrically independent standby 125-V
 
dc systems (including buses 1ENB*SWG01A, 1ENB*SWG01B, and 1E22*S001, which supply power to the standby diesel auxiliary
 
loads) and seven normal 125-V dc systems, including buses 1BYS-SWG01A, 1BYS-SWG01B, and 1IHS-SWG01D, and 125 VDC panels 1BYS-PNL01, 1BYS-PNL04, 1BYS-PNL06, and 1BXY-PNL01 which supply power
 
to nonsafety-related loads as shown on Fig. 8.3-6.
68.1.6 Identification of Safety-Related Systems 8.1.6.1 System Functions Sections 8.3.1.1.2.1 and 8.3.1.3, and Table 8.3-1 identify safety-related systems and their functions. 8.1.6.2 Power Supply Sources Power supply sources to safety-related systems, as shown in Fig. 8.1-4, consist of the main generator through one three-
 
winding normal station service transformer, the two redundant offsite 230-kV transmission lines through two preferred station service transformers, two standby ac diesel generators, and a high pressure core spray (HPCS) ac diesel generator. Standby
 
power is not connected to or influenced by the 13.8-kV system. 13Each of the three diesel generators 1EGS*EG1A, 1EGS*EG1B, and 1E22*S001G1C is connected to 4.16-kV standby buses 1ENS*SWG1A, 1ENS*SWG1B, and 1E22*S004, respectively. Electric power to the safety-related systems from the normal and preferred station service transformers is supplied as follows. The dual secondaries of normal station service transformer 1STX-XNS1C can be connected to two normal 4.16-kV buses 1NNS-SWG1A and 1NNS-SWG1B through normally open breakers. The two normal 4.16-kV buses are connected to the preferred station service transformers through normally closed breakers. The normal 4.16-kV swing bus 1NNS-SWG1C is subordinate to one or the other of the above normal 4.16-kV buses. The normal 4.16-kV bus 1NNS-SWG1A has a normally
 
open tie to standby 4.16-kV bus 1ENS*SWG1B at the standby bus
.Normal 4.16-kV bus 1NNS-SWG1B has a normally open tie to standby 4.16-kV bus 1ENS*SWG1A at the standby bus. Normal 4.16-kV swing bus 1NNS-SWG1C has two 4.16-kV sources of power from either normal 4.16-kV bus 1NNS-SWG1Bor normal 4.16-kV bus 1NNS-SWG1A which is controlled by station operating procedure. Normal 4.16-kV 13 RBS USAR  8.1-6 August 1987 swing bus 1NNS-SWG1C has a 4.16-kV tie to standby bus 1E22*S004.
Standby 4.16-kV buses 1ENS*SWG1A and 1ENS*SWG1B are energized from the preferred station service transformers at all times via normally closed switchgear circuit breakers connected to the  
 
secondaries of the preferred station service transformers. 8.1.7 Identification of Safety Criteria 8.1.7.1 General Functional Design Basis Chapter 3 outlines the general engineering criteria for nuclear plant design and delineates several areas of general  
 
classification and/or conformance which are applicable to the electrical power systems and equipment. Further clarification of some specific standards and criteria related to electrical systems is given in Chapter 7. Section 7.1.2 outlines various standards and criteria for systems which may include electrical  
 
functions similar to electrical power systems. Specific requirements for electrical power systems and equipment are given in the following paragraphs. 8.1.7.2 Design Basis  
 
General Design CriteriaThe conformance discussion provided in Section 3.1 for the General Design Criteria (GDC) applies to the electrical systems  
 
in Chapter 8, as identified in Table 8.1-2.
Branch Technical Positions The conformance discussion for the Branch Technical Positions (BTPs) is referenced in Table 8.1-3.
Branch Technical Positions The conformance discussion for the Branch Technical Positions (BTPs) is referenced in Table 8.1-3.
USNRC Regulatory GuidesThe following Regulatory Guides are specifically cited as applying to the safety-related electrical power systems and equipment. Safety-related systems and equipment are designed in  
USNRC Regulatory Guides The following Regulatory Guides are specifically cited as applying to the safety-related electrical power systems and equipment. Safety-related systems and equipment are designed in accordance with the referenced Regulatory Guides as described in Section 1.8.


accordance with the referenced Regulatory Guides as described in  
RBS USAR 8.1-7 August 1987 Regulatory Guide Title 1.6 Independence Between Redundant Standby (Onsite)
Power Sources and Between their Distribution Systems 1.9 Selection, Design and Qualification of Diesel-Generator Units Used as Standby (Onsite) Electric Power Systems at Nuclear Power Plants 1.22 Periodic Testing of Protection System Actuation Functions 1.29 Seismic Design Classification 1.30 Quality Assurance Requirements for the Installation, Inspection, and Testing of Instrumentation and Electric Equipment 1.32 Criteria for Electric Power Systems for Nuclear Safety-Related Power Plants 1.40 Qualification Tests of Continuous-Duty Motors Installed Inside the Containment of Water-Cooled Nuclear Power Plant 1.41 Preoperational Testing of Redundant Onsite Electric Power Systems to Verify Proper Load Group Assignments 1.47 Bypassed and Inoperable Status Indication for Nuclear Power Plant Safety Systems 1.53 Application of Single Failure Criterion to Nuclear Power Plant Protection Systems 1.62 Manual Initiation of Protective Action 1.63 Electric Penetration Assemblies in Containment Structures for Light-Water-Cooled Nuclear Power Plants 1.68 Initial Test Programs for Water-Cooled Nuclear Power Plants


Section 1.8.
RBS USAR 8.1-8 August 1987 Regulatory Guide Title 1.70 Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants 1.73 Qualification Tests of Electric Valve Operators Installed Inside the Containment of Nuclear Power Plants 1.75 Physical Independence of Electric Systems 1.81 Shared Emergency and Shutdown Electric Systems for Multi-Unit Nuclear Power Plants 1.89 Qualification of Class 1E Equipment for Nuclear Power Plants 1.93 Availability of Electric Power Sources 1.100 Seismic Qualification of Electric Equipment for Nuclear Power Plants 1.106 Thermal Overload Protection for Electric Motors on Motor-Operated Valves 1.108 Periodic Testing of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants 1.118 Periodic Testing of Electric Power and Protection Systems 1.120 Fire Protection Guidelines for Nuclear Power Plants 1.128 Installation Design and Installation of Large Lead Storage Batteries for Nuclear Power Plants 1.129 Maintenance, Testing, and Replacement of Large Lead Storage Batteries for Nuclear Power Plants
RBS USAR 8.1-7 August 1987 Regulatory Guide Title 1.6 Independence Between Redundant Standby (Onsite)
Power Sources and Between their Distribution


Systems 1.9 Selection, Design and Qualification of Diesel-Generator Units Used as Standby (Onsite) Electric
RBS USAR  
 

Power Systems at Nuclear Power Plants  1.22 Periodic Testing of Protection System Actuation Functions 1.29 Seismic Design Classification 1.30 Quality Assurance Requirements for the Installation, Inspection, and Testing of
 
Instrumentation and Electric Equipment  1.32 Criteria for Electric Power Systems for Nuclear Safety-Related Power Plants  1.40 Qualification Tests of Continuous-Duty Motors Installed Inside the Containment of Water-Cooled
 
Nuclear Power Plant  1.41 Preoperational Testing of Redundant Onsite Electric Power Systems to Verify Proper Load Group
 
Assignments 1.47 Bypassed and Inoperable Status Indication for Nuclear Power Plant Safety Systems  1.53 Application of Single Failure Criterion to Nuclear Power Plant Protection Systems  1.62 Manual Initiation of Protective Action 1.63 Electric Penetration Assemblies in Containment Structures for Light-Water-Cooled Nuclear Power
 
Plants 1.68 Initial Test Programs for Water-Cooled Nuclear Power Plants RBS USAR 8.1-8 August 1987 Regulatory Guide Title 1.70 Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants  1.73 Qualification Tests of Electric Valve Operators Installed Inside the Containment of Nuclear Power
 
Plants 1.75 Physical Independence of Electric Systems 1.81 Shared Emergency and Shutdown Electric Systems for Multi-Unit Nuclear Power Plants  1.89 Qualification of Class 1E Equipment for Nuclear Power Plants  1.93 Availability of Electric Power Sources 1.100 Seismic Qualification of Electric Equipment for Nuclear Power Plants  1.106 Thermal Overload Protection for Electric Motors on Motor-Operated Valves  1.108 Periodic Testing of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power
 
Plants 1.118 Periodic Testing of Electric Power and Protection Systems 1.120 Fire Protection Guidelines for Nuclear Power Plants 1.128 Installation Design and Installation of Large Lead Storage Batteries for Nuclear Power Plants  1.129 Maintenance, Testing, and Replacement of Large Lead Storage Batteries for Nuclear Power Plants RBS USAR
* Applies to Division III HPCS diesel generator only.  
* Applies to Division III HPCS diesel generator only.  
** Conformance with IEEE 323-1974 is described in Section 3.11. 8.1-9 August 1987 Regulatory Guide Title 1.131 Qualification Test of Electric Cables, Field Splices, and Connections for Light-Water-Cooled  
** Conformance with IEEE 323-1974 is described in Section 3.11.
8.1-9 August 1987 Regulatory Guide Title 1.131 Qualification Test of Electric Cables, Field Splices, and Connections for Light-Water-Cooled Nuclear Power Plants IEEE Standards Electrical power systems and equipment comply with the following standards of the Institute of Electrical and Electronics Engineers (IEEE):
IEEE Standard Title 279-1971 Criterion for Protection Systems for Nuclear Power Generating Stations 308-1974 Criteria for Class 1E Electric Systems Nuclear 1971*
Power Generating Stations 317-1976 Electrical Penetration Assemblies in Containment Structures for Nuclear Fueled Power Generating Stations 323-1974**
General Guide for Qualifying Class I Electrical Equipment for Nuclear Powered Generating Stations 334-1974 Type Test of Continuous Duty Class 1E Motors for Nuclear-Power Generating Stations 336-1971 Installation, Inspection, and Testing Requirements for Instrumentation and Requirements for Instrumentation and Electric Equipment During the Construction of Nuclear Power Generating Stations 338-1977 Criteria for the Periodic Testing of Nuclear 1971*
Power Generating Station Protection Systems


Nuclear Power Plants IEEE Standards Electrical power systems and equipment comply with the following standards of the Institute of Electrical and Electronics
RBS USAR  
 

Engineers (IEEE):
IEEE Standard Title279-1971 Criterion for Protection Systems for Nuclear Power Generating Stations 308-1974 Criteria for Class 1E Electric Systems Nuclear 1971* Power Generating Stations 317-1976 Electrical Penetration Assemblies in Containment Structures for Nuclear Fueled Power Generating
 
Stations323-1974** General Guide for Qualifying Class I Electrical Equipment for Nuclear Powered Generating Stations 334-1974 Type Test of Continuous Duty Class 1E Motors for Nuclear-Power Generating Stations 336-1971 Installation, Inspection, and Testing Requirements for Instrumentation and Requirements
 
for Instrumentation and Electric Equipment During
 
the Construction of Nuclear Power Generating
 
Stations338-1977 Criteria for the Periodic Testing of Nuclear 1971* Power Generating Station Protection Systems RBS USAR
* Applies to Division III HPCS diesel generator only.  
* Applies to Division III HPCS diesel generator only.  
** Conformance with IEEE 323-1975 is described in Section 3.10. 8.1-10 August 1987 IEEE Standard Title344-1975** Seismic Qualification of Class I Electric Equipment for Nuclear Power Generating Stations 379-1977 Trial Use Guide for the Application of the Single 1972* Failure Criterion to Nuclear Power Generating Station Protection Systems 382-1972 Trial-Use Guide for the Type Test of Class I Electric Valve Operators for Nuclear Power  
** Conformance with IEEE 323-1975 is described in Section 3.10.
8.1-10 August 1987 IEEE Standard Title 344-1975**
Seismic Qualification of Class I
Electric Equipment for Nuclear Power Generating Stations 379-1977 Trial Use Guide for the Application of the Single 1972*
Failure Criterion to Nuclear Power Generating Station Protection Systems 382-1972 Trial-Use Guide for the Type Test of Class I Electric Valve Operators for Nuclear Power Generating Stations 383-1974 Type Test of Class 1E Electric Cable Field
: Splices, and Connections for Nuclear Power Generating Station 384-1974 Criteria for Separation of Class 1E Equipment and Circuits 387-1977 Criteria for Diesel-Generator Units Applied as 1972*
Standby Power Supplies for Nuclear Power Generating Stations 415-1976 Planning of Preoperational Testing Programs for Class 1E Power Systems for Nuclear Power Generating Stations 420-1973 Trial Use Guide for Class 1E Control Switchboards for Nuclear Power Generating Stations 450-1975 Recommended Practice for Maintenance, Testing, and Replacement of Large Stationary Type Power Plant and Substation Lead Storage Batteries 484-1975 Installation Design and Installation of Large Lead Storage Batteries for Generating Stations and Substations


Generating Stations 383-1974 Type Test of Class 1E Electric Cable Field Splices, and Connections for Nuclear Power
RBS USAR 8.1-11 August 1987 Additional Standards Relevant standards, codes, etc, are referenced in text whenever special considerations warrant.
These are not generally applicable to electrical power systems and are not listed here.


Generating Station384-1974 Criteria for Separation of Class 1E Equipment and Circuits387-1977 Criteria for Diesel-Generator Units Applied as 1972* Standby Power Supplies for Nuclear Power Generating Stations 415-1976 Planning of Preoperational Testing Programs for Class 1E Power Systems for Nuclear Power
RBS USAR Revision 22 8.2-1 8.2 OFFSITE POWER SYSTEM 8.2.1 Description 8.2.1.1 Transmission System and Switchyard  
 
*16 *7 The offsite power system is designed to provide reliable and redundant sources of power for starting, operation, and safe shutdown of Unit 1 in accordance with General Design Criterion (GDC)
Generating Stations 420-1973 Trial Use Guide for Class 1E Control Switchboards for Nuclear Power Generating Stations 450-1975 Recommended Practice for Maintenance, Testing, and Replacement of Large Stationary Type Power
No. 17, Electric Power Systems (Table 8.1-2 and Section 3.1.2.17) and GDC No. 18, Inspection and Testing of Electric Power Systems. The offsite power system is shown in the following figures:
 
7* 16*
Plant and Substation Lead Storage Batteries 484-1975 Installation Design and Installation of Large Lead Storage Batteries for Generating Stations
: 1.
 
Fig. 8.1-1 December 31, 1985, Utility Grid
and Substations RBS USAR  8.1-11 August 1987 Additional StandardsRelevant standards, codes, etc, are referenced in text whenever special considerations warrant. These are not generally
: 2.
 
Fig. 8.1-3 January 1, 1987, Power Pool Map
applicable to electrical power systems and are not listed here.
: 3.
RBS USAR Revision 22 8.2-1 8.2 OFFSITE POWER SYSTEM  
Fig. 8.1-4 Fancy Point Substation - 230-kV Bays and Peripheral Loads
 
: 4.
====8.2.1 Description====
Fig. 8.1-5 Fancy Point Substation - 230-kV Bays
 
: 5.
8.2.1.1 Transmission System and Switchyard 16 7 The offsite power system is designed to provide reliable and redundant sources of power for starting, operation, and safe shutdown of Unit 1 in accordance with General Design Criterion (GDC) No. 17, Electric Power Systems (Table 8.1-2 and Section 3.1.2.17) and GDC No. 18, Inspection and Testing of Electric Power Systems. The offsite power system is shown in the  
Fig. 8.1-6 Station Service - One Line Diagram
 
: 6.
following figures:
Fig. 8.1-7 Fancy Point Substation - 500-kV Bays
7 16 1. Fig. 8.1-1 December 31, 1985, Utility Grid 2. Fig. 8.1-3 January 1, 1987, Power Pool Map  
: 7.
: 3. Fig. 8.1-4 Fancy Point Substation - 230-kV Bays and Peripheral Loads 4. Fig. 8.1-5 Fancy Point Substation - 230-kV Bays  
Fig. 8.2-1 Transmission Towers to 230-kV Switchyard from the Station
: 5. Fig. 8.1-6 Station Service - One Line Diagram  
: 8.
: 6. Fig. 8.1-7 Fancy Point Substation - 500-kV Bays  
Fig. 8.2-2 Connection of Onsite 13.8-kV and 4.16-kV Distribution System to the Preferred Power Supply
: 7. Fig. 8.2-1 Transmission Towers to 230-kV Switchyard from the Station 8. Fig. 8.2-2 Connection of Onsite 13.8-kV and 4.16-kV Distribution System to the Preferred  
: 9.
 
Fig. 8.2-3 Transmission System
Power Supply 9. Fig. 8.2-3 Transmission System  
: 10.
: 10. Figs. 8.2-4 Transmission Route Segments through 8.2-35  
Figs. 8.2-4 Transmission Route Segments through 8.2-35
: 11. Fig. 8.2-36 Fancy Point 500-kV and 230-kV Switchyard One-Line Diagram
: 11.
 
Fig. 8.2-36 Fancy Point 500-kV and 230-kV Switchyard One-Line Diagram 8.2.1.1.1 230/500-kV Switchyard The 230-kV bays of the substation, Fig. 8.1-4 and 8.1-5, consist of two buses and positions for thirty 230-kV circuit breakers (OCB) in a breaker-and-a-half scheme, with each of the two buses being capable of carrying the total connected load. Voltage on the bus is a nominal 230 kV, with a maximum rating of 242 kV and a minimum rating of 224.25 kV. There are three 230-kV lines serving Unit 1 along the right-of-way shown in Fig. 8.2-1, and one line connecting the 230-kV bays to the 500-kV bays via transformers.
8.2.1.1.1 230/500-kV Switchyard  
The 230-kV tie to the 500-kV switchyard consists of one 230-kV line of one span, strung between the transformer bay steel and the associated A-frame structure in the 230-kV switchyard. These 230-kV leads connect the 230-kV bays to a  
 
The 230-kV bays of the substation, Fig. 8.1-4 and 8.1-5, consist of two buses and positions for thirty 230-kV circuit breakers (OCB) in a breaker-and-a-half scheme, with each of the two buses being capable of carrying the total connected load. Voltage on the bus is a nominal 230 kV, with a maximum rating of 242 kV and  
 
a minimum rating of 224.25 kV. There are three 230-kV lines serving Unit 1 along the right-of-way shown in Fig. 8.2-1, and one line connecting the 230-kV bays to the 500-kV bays via  
 
transformers.  
 
The 230-kV tie to the 500-kV switchyard consists of one 230-kV  
 
line of one span, strung between the transformer bay steel and the associated A-frame structure in the 230-kV switchyard. These  
 
230-kV leads connect the 230-kV bays to a  
 
RBS USAR Revision 19 8.2-2 15bank of three single phase stepup transformers at the 500-kV bays. The 500-kV bays of the substation, Fig. 8.1-7, consists of
 
two buses and positions for six 500-kV gas circuit breakers (GCB) in a folded breaker-and-a-half configuration. The two-bus 500-kV bays located on the northwest side of and adjacent to the 230-kV bays are initially constructed as a three-breaker ring bus and are to be developed into a breaker-and-a-half scheme with the installation of future power plant units. Each bus is capable of
 
carrying the total connected load.
1516The two 230-kV lines previously described in Section 8.1 provide two physically and electrically independent sources of offsite power to the preferred station service transformers at the
 
station from the 230-kV bay of the Fancy Point Substation. The 230-kV bays are constructed with rigid aluminum tubing supported on insulators and galvanized steel towers and pedestals. The breakers are 230-kV dead tank,circuit breakers, using the breaker-and-a-half scheme. The layout of the 230-kV bays of the substation is shown in Fig. 8.1-5. The buses are constructed at 17-ft and 29-ft heights above ground. The buses
 
are designed to withstand a maximum fault on any section with Unit 1 operating. This is the maximum force-loading to which the buses are expected to be subjected. Similar designs have been used in the past and have proven to be adequate under all electrical fault and environmental conditions. The breaker-and-a-half design provides for the isolation of any faulted line without affecting the operation of any other line. This scheme also provides for the isolation of any one breaker in the 230-kV bus for inspection or maintenance without affecting the operation of any of the connecting lines or any other connection to the buses. The buses have adequate capacity to carry their loads under any postulated switching sequences. The design provides for the isolation of any breaker connecting Unit 1 to the
 
switchyard buses without limiting the operation of any line connecting to the 230-kV power grid. Either 230-kV offsite source circuit breaker can be isolated, inspected, and maintained as needed without affecting any line or unit input. Either of the 230-kV offsite source lines can be taken out of service for inspection or maintenance without jeopardizing the operation of


the other 230-kV source of offsite power.
RBS USAR Revision 19 8.2-2
16 RBS USAR Revision 25 8.2-3 A fault of any section of the 230-kV bus is cleared by the adjacent breakers and does not interrupt operation of any of the  
15 bank of three single phase stepup transformers at the 500-kV bays. The 500-kV bays of the substation, Fig. 8.1-7, consists of two buses and positions for six 500-kV gas circuit breakers (GCB) in a folded breaker-and-a-half configuration. The two-bus 500-kV bays located on the northwest side of and adjacent to the 230-kV bays are initially constructed as a three-breaker ring bus and are to be developed into a breaker-and-a-half scheme with the installation of future power plant units. Each bus is capable of carrying the total connected load.
15
16 The two 230-kV lines previously described in Section 8.1 provide two physically and electrically independent sources of offsite power to the preferred station service transformers at the station from the 230-kV bay of the Fancy Point Substation.
The 230-kV bays are constructed with rigid aluminum tubing supported on insulators and galvanized steel towers and pedestals. The breakers are 230-kV dead tank, circuit breakers, using the breaker-and-a-half scheme. The layout of the 230-kV bays of the substation is shown in Fig. 8.1-5. The buses are constructed at 17-ft and 29-ft heights above ground. The buses are designed to withstand a maximum fault on any section with Unit 1 operating. This is the maximum force-loading to which the buses are expected to be subjected. Similar designs have been used in the past and have proven to be adequate under all electrical fault and environmental conditions. The breaker-and-a-half design provides for the isolation of any faulted line without affecting the operation of any other line. This scheme also provides for the isolation of any one breaker in the 230-kV bus for inspection or maintenance without affecting the operation of any of the connecting lines or any other connection to the buses. The buses have adequate capacity to carry their loads under any postulated switching sequences. The design provides for the isolation of any breaker connecting Unit 1 to the switchyard buses without limiting the operation of any line connecting to the 230-kV power grid. Either 230-kV offsite source circuit breaker can be isolated, inspected, and maintained as needed without affecting any line or unit input. Either of the 230-kV offsite source lines can be taken out of service for inspection or maintenance without jeopardizing the operation of the other 230-kV source of offsite power.
16


remaining parts of the 230-kV switchyard bus. Only that element  
RBS USAR Revision 25 8.2-3 A fault of any section of the 230-kV bus is cleared by the adjacent breakers and does not interrupt operation of any of the remaining parts of the 230-kV switchyard bus. Only that element connected to the faulted section is interrupted.
The 500-kV bays of the substation are located northwest of and adjacent to the 230-kV bays and are constructed of SF6 components. The 500-kV bays are arranged in a folded breaker-and-a-half scheme, consisting of six 500-kV GCB positions. The initial installation for Unit 1 consists of three circuit breakers and three 500-kV lines in a ring bus configuration.
Fig.
8.1-7 illustrates the initial and final 500-kV configurations. There are two separate SF6 charging systems for the 500-kV bays: one to serve the 500-kV SF6 circuit breakers, and one to serve the 500-kV SF6 buses, disconnecting switches, and air bushings. The initial ring bus configuration provides for the isolation of any faulted line without affecting the operation of any other line. It also provides for the isolation of any one breaker in the 500-kV SF6 bus for inspection or maintenance without affecting the operation of any of the connecting lines or any other connections to the buses. The 500-kv buses terminate at the 500-kv SF6 air bushings. Connections are made to the 500-kV grid and to the 230-500-kV transformers via air-insulated, outdoor-constructed bus work and overhead lines from these air bushings.
7 The ac auxiliary power requirements of the 230-kV and 500-kV bays are provided by two 750-kVA, 13.8-kV to 480-V oil-filled transformers supplied from onsite 13.8-kV buses 1NPS-SWG1A and 1NPS-SWG1B.
7 The dc requirements for the Fancy Point Substation relay and control systems are provided by two 125-V batteries. Each battery system is supported by its own charger which is provided power from the auxiliary ac power system and by an existing source external to River Bend Station.


connected to the faulted section is interrupted.
RBS USAR Revision 25 8.2-4 16 Control functions between the plant and the substation are provided by two diverse methods. Control cables are routed in a concrete-encased duct bank to the substation control house. Routing within the substation between the various relay panels and control equipment is accomplished via a protected cable trench. An optic cable underbuilt on the reserve station service steel pole lines provides another diverse method of transmitting control functions and information between the plant and substation. The optical information is decoded at the substation and forwarded to the appropriate piece of equipment via control cables routed in a cable trench or raceway that is physically separated by 5 ft or more from the other trench or raceway described herein. The routing separation is maintained over the route length except at termination points where the cables route to the same piece of equipment.
 
The 500-kV bays of the substation are located northwest of and adjacent to the 230-kV bays and are constructed of SF 6 components. The 500-kV bays are arranged in a folded breaker-and-a-half scheme, consisting of six 500-kV GCB positions. The initial installation for Unit 1 consists of three circuit breakers and three 500-kV lines in a ring bus configuration.
Fig. 8.1-7 illustrates the initial and final 500-kV configurations. There are two separate SF 6 charging systems for the 500-kV bays:  one to serve the 500-kV SF 6 circuit breakers, and one to serve the 500-kV SF 6 buses, disconnecting switches, and air bushings. The initial ring bus configuration provides for the isolation of any faulted line without affecting the operation of any other line. It also provides for the isolation of any one breaker in the 500-kV SF 6 bus for inspection or maintenance without affecting the operation of any of the connecting lines or any other connections to the buses. The 500-kv buses terminate at the 500-kv SF 6 air bushings. Connections are made to the 500-kV grid and to the 230-500-kV transformers
 
via air-insulated, outdoor-constructed bus work and overhead
 
lines from these air bushings. 7 The ac auxiliary power requirements of the 230-kV and 500-kV bays are provided by two 750-kVA, 13.8-kV to 480-V oil-filled
 
transformers supplied from onsite 13.8-kV buses 1NPS-SWG1A and
 
1NPS-SWG1B.
7 The dc requirements for the Fancy Point Substation relay and control systems are provided by two 125-V batteries. Each battery system is supported by its own charger which is provided
 
power from the auxiliary ac power system and by an existing
 
source external to River Bend Station.
 
RBS USAR Revision 25 8.2-4 16 Control functions between the plant and the substation are provided by two diverse methods. Control cables are routed in a concrete-
 
encased duct bank to the substation control house. Routing within the substation between the various relay panels and control equipment is accomplished via a protected cable trench. An optic  
 
cable underbuilt on the reserve station service steel pole lines provides another diverse method of transmitting control functions and information between the plant and substation. The optical  
 
information is decoded at the substation and forwarded to the appropriate piece of equipment via control cables routed in a cable trench or raceway that is physically separated by 5 ft or more from  
 
the other trench or raceway described herein. The routing separation is maintained over the route length except at termination  
 
points where the cables route to the same piece of equipment.
16 The 125-V battery system furnishes the control power for circuit breakers in both the 500-kV and 230-kV switchyard bays. A complete loss of both 125-V battery systems, including the battery charger, prevents the operation of all circuit breakers in the switchyard.
16 The 125-V battery system furnishes the control power for circuit breakers in both the 500-kV and 230-kV switchyard bays. A complete loss of both 125-V battery systems, including the battery charger, prevents the operation of all circuit breakers in the switchyard.
The loss of the battery system in conjunction with a fault in the switchyard or any incoming line would require the operation of backup relaying elsewhere within the grid to clear the fault.
The loss of the battery system in conjunction with a fault in the switchyard or any incoming line would require the operation of backup relaying elsewhere within the grid to clear the fault.
Offsite power will be manually restored by isolating one of the reserve station service lines to an unfaulted line in the event of severe battery damage. The estimated time to perform the subject  
Offsite power will be manually restored by isolating one of the reserve station service lines to an unfaulted line in the event of severe battery damage. The estimated time to perform the subject operation is 15 min after personnel arrive at the switchyard.
 
16 The battery systems are monitored remotely using a
operation is 15 min after personnel arrive at the switchyard.
SCADA (Supervisory Control and Data Acquisition) system which provides a low-voltage alarm to the Southwest-Transmission Operation Center (SWTOC) dispatcher in the event of malfunction. Additionally, the batteries receive a visual inspection weekly and a complete inspection for operability to manufacturer's specifications each 6 months.
 
The weekly inspection consists of checking the electrolyte levels, the battery voltage, and the charge rate. The 6-month inspection includes checking the voltage and specific gravity of each
16 The battery systems are monitored remotely using a SCADA (Supervisory Control and Data Acquisition) system which provides a  
: cell, cleaning and retorquing the battery connectors, and if needed, the application of an equalize charge for about 24 hours. A form containing each of the above-mentioned items is filled out for each inspection. Completed inspection forms are kept on file at the Baton Rouge Substation Department.
 
16 All 230-kV circuit breakers are equipped with two independent trip coils and breaker failure protection for redundant power circuit protection. All of the protective relay systems for the 230-kV bays are redundant. These systems are overlapping so that each high-voltage component is covered by at least two sets of protective relays. The primary and the backup relay systems are supplied from separate current inputs, separate dc circuits from each 125-V battery, and are connected to separate trip coils of
low-voltage alarm to the Southwest-Transmission Operation Center (SWTOC) dispatcher in the event of malfunction. Additionally, the batteries receive a visual inspection weekly and a complete  
 
inspection for operability to manufacturer's specifications each 6 months. The weekly inspection consists of checking the  
 
electrolyte levels, the battery voltage, and the charge rate. The 6-month inspection includes checking the voltage and specific gravity of each cell, cleaning and retorquing the battery  
 
connectors, and if needed, the application of an equalize charge for about 24 hours. A form containing each of the above-mentioned items  
 
is filled out for each inspection. Completed inspection forms are  
 
kept on file at the Baton Rouge Substation Department.
16 All 230-kV circuit breakers are equipped with two independent trip coils and breaker failure protection for redundant power circuit protection. All of the protective relay systems for the 230-kV bays  


are redundant. These systems are overlapping so that each high-voltage component is covered by at least two sets of protective relays. The primary and the backup relay systems are supplied from separate current inputs, separate dc circuits from each 125-V
RBS USAR Revision 18 8.2-5 the power circuit breakers. Cross tripping between the trip coils is used. The potentials for the primary and backup relay systems associated with the three 230-kV lines serving Unit 1 are provided from one set of potential transformers on the north 230-kV bus (primary) or one set of potential transformers on the south 230-kV bus (alternate). A potential transfer scheme is provided between the primary potentials and the alternate potentials. The potentials for the primary and backup relay systems associated with the other 230-kV lines are provided from one set of coupling capacitor voltage transformers on each line terminal. The potentials for the 500 to 230-kV transformer backup relaying (230 kV) are provided from one set of coupling capacitors on the 230-kV side of the transformer.
The primary relay system for each of the three 230-kV lines serving Unit 1 is a pilot wire system over a primary pilot wire circuit. The backup relay system for each of the three 230-kV lines is a multiple-zone distance phase with directional overcurrent ground relay system over a backup pilot wire circuit.
Transfer tripping of switchyard breakers for in-plant relay operations uses either the primary or backup pilot wire circuits.
The redundant pilot wire circuits are monitored.
The primary relay system for each of the other 230-kV lines is a permissive, overreaching transfer trip system. The backup system for each of the other 230-kV lines is a three-zone distance phase and ground relay system that initiates local tripping.
16 The north and south 230-kV buses are protected with a primary restraint bus differential system and a backup restraint bus differential system.
16
The 500 to 230-kV transformer is protected on the 230-kV side by single-zone distance phase with directional overcurrent ground relaying that initiates local tripping.
All 500-kV circuit breakers are equipped with two independent trip coils and breaker-failure protection for redundant power circuit protection. All of the protective relay systems for the 500-kV bays are redundant. These systems are overlapping so that each switchyard high-voltage component is covered by at least two sets of protective  


battery, and are connected to separate trip coils of
RBS USAR Revision 25 8.2-6 relays. The electromechanical backup relay system has separate current inputs and receives its power from one of the redundant 125-V battery systems. Cross tripping between the trip coils is used. The potentials for the primary and backup relay systems associated with the 500-kV lines are provided from one set of coupling capacitor voltage transformers on each line terminal.
The secondary potentials are separated into two systems of junction boxes in the switchyard and are treated as redundant systems from this point. The potentials for the 500 to 230-kV transformer backup relaying (500 kV) are provided from one set of bushing potential devices on the 500-kV side of the transformer.
The primary relay systems for the two 500-kV lines are: 1) phase comparison relaying over a CS26 power line carrier channel; and
: 2) directional comparison tripping with phase and ground distance relays using a frequency shift audio tone, modulated on a microwave channel. The backup relay system for the two 500-kV lines is a three-zone distance phase and ground relay system that initiates local tripping.
16 16 The primary relay system for the 500-kV line to the 500 to 230-kV transformer is a separate restraint bus differential system. The primary relay system for the 500 to 230-kV transformer is a separate restraint transformer differential system. The backup relay system (500 kV) for the 500 to 230-kV transformer is a single zone distance phase with directional overcurrent ground relaying that initiates local tripping.


RBS USAR Revision 18 8.2-5 the power circuit breakers. Cross tripping between the trip coils is used. The potentials for the primary and backup relay systems associated with the three 230-kV lines serving Unit 1 are
RBS USAR Revision 19 8.2-7
16 The 230-kV and 500-kV circuit breakers can be operated either manually from the switchyard control house or remotely by either the Southwest-Transmission Operation Center dispatcher or the River Bend Station operator. Those remotely operable by the Southwest-Transmission Operation Center dispatcher are CBs 20650, 20660, 20735, 20740, 20745, 20765, 20770, and 20775. Those remotely operable by the River Bend Station operator are CBs 20610, 20620, 20635, 20640, 20670, and 20665.
The 500-kV circuit breakers have compressed air actuated mechanisms with stored capacity for three open and three close operations. The operations are contingent upon normal auxiliary power to the breaker during the 30 min preceding the initial operation. Switching operations from local stations upon loss of control or motive power require that the trip or close lever located directly on the GCB control cabinet be manually operated.
16
A mimic board of the Fancy Point Substation is located in the main control room to provide remote breaker status indication.
Physical separation of the offsite power sources to include the 230-kV bays through the preferred station transformers of the onsite Class 1E power system is maintained for all credible events.
The offsite power sources are non-Class 1E with all equipment manufactured to the accepted industrial standards. This design is considered to meet the requirements of GDC 1 as evoked for the offsite (preferred) power system.
In satisfaction of GDC 3, the two offsite power systems have either spatial separation or totally enclosed raceways over their entire length.
In satisfaction of GDC 4, the two offsite power sources are routed in such a manner as to permit continuous operation of one 230-kV offsite power line during a malfunction of the second 230-kV line.
8.2.1.1.2 Transmission System River Bend Station is connected to GSU's load demand area by a system of 230-kV and 500-kV overhead transmission lines. These lines were installed and erected from the River Bend Station's Fancy Point Substation to the Webre Substation,


provided from one set of potential transformers on the north 230-
RBS USAR 8.2-8 August 1987 Jaguar Bulk Substation, and McKnight Switching Station via three physically separate rights-of-way.
These three rights-of-way, designated Routes I, II, and III, provide the means to integrate River Bend Station into the existing GSU electrical system. Electric output from the station is transmitted to the electrical system via these three routes during normal plant operation.
Route I runs west from the Fancy Point Substation to the Big Cajun No. 2 Power Station switchyard and continues south to Webre Substation near Rosedale, Louisiana. Route I is 29.20 mi long.
Route II, 23.75 mi long, runs southeast and south from the Fancy Point Substation to the Jaguar Bulk Substation in Scotlandville, Louisiana.
Route III runs 27.20 mi east from the Fancy Point Substation to Point U, the McKnight Switching Station in McKnight, Louisiana.
The three transmission line routes are scheduled for completion as follows:
Route I - November 1980 (completed)
Route II - May 1981 (completed)
Route III - July 1983 (completed)
These transmission line routes are illustrated in Fig. 8.2-3.
There are no crossovers of the 230-kV or 500-kV transmission lines at any point along the three rights-of-way.
The 230-kV transmission lines run from the 230-kV bays along Routes I and II, as follows:
: 1.
230-kV; Fancy Point Substation to Port Hudson, 2 lines (Route II)
: 2.
230-kV; Fancy Point Substation to
: Enjay, 1 line (Route II)
: 3.
230-kV; Fancy Point Substation to Cajun Electric Power Cooperative, 1 line (Route II)
: 4.
Future line, 7 lines (Routes I and II)


kV bus (primary) or one set of potential transformers on the south 230-kV bus (alternate). A potential transfer scheme is provided between the primary potentials and the alternate potentials. The potentials for the primary and backup relay systems associated with the other 230-kV lines are provided from one set of coupling capacitor voltage transformers on each line terminal. The potentials for the 500 to 230-kV transformer backup relaying (230 kV) are provided from one set of coupling
RBS USAR 8.2-9 August 1987 As shown on Fig. 8.1-5, there are additional 230-kV transmission lines associated with future units.
All the new 230-kV lines are of the steel pole, H-frame structure design except that portion of Route II along Highway 19 which is a single-pole, steel, double-circuit structure. The 230-kV power conductors primarily consist of two conductor bundles of 649.5 kCMIL aluminum conductor, alloy reinforced (ACAR), cable spaced 45.7 cm (18 in) on center, with a nominal power capacity of 750 MVA. The 230-kV lines 351 and 352, from the Fancy Point Substation to the Jaguar Bulk Substation, utilize two 1,650 kCMIL ACAR cables per phase with a nominal power capacity of 1,200 MVA.
The minimum design phase-to-phase spacing on the 230-kV transmission line system is 4.9 m (16 ft). Two static lines are provided on each 230-kV transmission tower and consist of 5/16-in extra high strength (EHS) steel cable.
The 500-kV transmission lines run from the 500-kV bays along Routes I and III as follows:
: 1.
500-kV; Fancy Point Substation to McKnight Substation, 1 line (Route III)
: 2.
500-kV; Fancy Point Substation to Big Cajun No. 2, 1 line (Route I)
: 3.
500-kV; Fancy Point Substation to 500-kV/230-kV transformers, 2 lines
: 4.
Future lines, 4 lines All 500-kV transmission lines are of the steel, lattice-type design.
Two configurations of power conductors are used at the 500-kV level. Three conductor bundles of 1,024.5 kCMIL ACAR per phase spaced 45.7 cm (18 in) on center are used along Routes I and III with a nominal power capacity of 2,500 MVA. The Route I Mississippi River crossing utilizes one 3,075 kCMIL aluminum conductor steel reinforced (ACSR) cable per phase with a nominal power capacity of 2,500 MVA. The minimum phase-to-phase spacing on the 500-kV transmission line system is 11.0 m (30 ft). Two 7/16-in EHS steel cable static lines are used on each 500-kV transmission tower, with the exception of the 19 static lines used on the Mississippi River crossing which are No. 9 alumoweld cables.


capacitors on the 230-kV side of the transformer.
The primary relay system for each of the three 230-kV lines serving Unit 1 is apilot wire system over a primary pilot wire circuit. The backup relay system for each of the three 230-kV
lines is a multiple-zone distance phase with directional overcurrent ground relay system over a backup pilot wire circuit. Transfer tripping of switchyard breakers for in-plant relay operations useseither the primary or backup pilot wire circuits.
The redundant pilot wire circuits are monitored
.The primary relay system for each of the other 230-kV lines is a permissive, overreaching transfer trip system
. The backup system for each of the other 230-kV lines is a three-zone distance phase and ground relay system that initiates local tripping. 16 The north and south 230-kV buses are protected with a primary restraint bus differential system and a backup restraint bus
differential system.
16The 500 to 230-kV transformer is protected on the 230-kV side by single-zone distance phase with directional overcurrent ground
relaying that initiates local tripping. All 500-kV circuit breakers are equipped with two independent trip coils and breaker-failure protection for redundant power circuit protection. All of the protective relay systems for the 500-kV bays are redundant. These systems are overlapping so that each switchyard high-voltage component is covered by at least two
sets of protective RBS USAR Revision 25 8.2-6 relays. The electromechanical backup relay system has separate current inputs and receives its power from one of the redundant 125-V battery systems. Cross tripping between the trip coils is
used. The potentials for the primary and backup relay systems
associated with the 500-kV lines are provided from one set of coupling capacitor voltage transformers on each line terminal.
The secondary potentials are separated into two systems of junction boxes in the switchyard and are treated as redundant systems from this point. The potentials for the 500 to 230-kV transformer backup relaying (500 kV) are provided from one set of
bushing potential devices on the 500-kV side of the transformer.
The primary relay systems for the two 500-kV lines are: 1) phase comparison relaying over a CS26 power line carrier channel; and
: 2) directional comparison tripping with phase and ground distance
relays using a frequency shift audio tone, modulated on a
microwave channel. The backup relay system for the two 500-kV
lines is a three-zone distance phase and ground relay system that
initiates local tripping. 16  16 The primary relay system for the 500-kV line to the 500 to 230-kV transformer is a separate restraint bus differential system. The
primary relay system for the 500 to 230-kV transformer is a separate restraint transformer differential system. The backup relay system (500 kV) for the 500 to 230-kV transformer is a
single zone distance phase with directional overcurrent ground
relaying that initiates local tripping.
RBS USAR Revision 198.2-716 The 230-kV and 500-kV circuit breakers can be operated either manually from the switchyard control house or remotely by either
the Southwest-Transmission Operation Center dispatcher or the River Bend Station operator. Those remotely operable by the Southwest-Transmission Operation Center dispatcher areCBs 20650, 20660, 20735, 20740, 20745
, 20765, 20770, and 20775. Those remotely operable by the River Bend Station operator areCBs 20610, 20620, 20635, 20640, 20670, and 20665.
The 500-kV circuit breakers have compressed air actuated mechanisms with stored capacity for three open and three close operations. The operations are contingent upon normal auxiliary power to the breaker during the 30 min preceding the initial operation. Switching operations from local stations upon loss of
control or motive power require that the trip or close lever
located directly on the GCB control cabinet be manually operated.
16A mimic board of the Fancy Point Substation is located in the main control room to provide remote breaker status indication.
Physical separation of the offsite power sources to include the 230-kV bays through the preferred station transformers of the onsite Class 1E power system is maintained for all credible
events.The offsite power sources are non-Class 1E with all equipment manufactured to the accepted industrial standards. This design is considered to meet the requirements of GDC 1 as evoked for the
offsite (preferred) power system. In satisfaction of GDC 3, the two offsite power systems have either spatial separation or totally enclosed raceways over their
entire length. In satisfaction of GDC 4, the two offsite power sources are routed in such a manner as to permit continuous operation of one
230-kV offsite power line during a malfunction of the second 230-
kV line. 8.2.1.1.2 Transmission System River Bend Station is connected to GSU's load demand area by a system of 230-kV and 500-kV overhead transmission lines. These lines were installed and erected from the River Bend Station's
Fancy Point Substation to the Webre Substation, RBS USAR  8.2-8 August 1987 Jaguar Bulk Substation, and McKnight Switching Station via three physically separate rights-of-way. These three rights-of-way, designated Routes I, II, and III, provide the means to integrate River Bend Station into the existing GSU electrical system. Electric output from the station is transmitted to the electrical system via these three routes
during normal plant operation. Route I runs west from the Fancy Point Substation to the Big Cajun No. 2 Power Station switchyard and continues south to Webre
Substation near Rosedale, Louisiana. Route I is 29.20 mi long. Route II, 23.75 mi long, runs southeast and south from the Fancy Point Substation to the Jaguar Bulk Substation in Scotlandville, Louisiana.Route III runs 27.20 mi east from the Fancy Point Substation to Point U, the McKnight Switching Station in McKnight, Louisiana.
The three transmission line routes are scheduled for completion
as follows:
Route I - November 1980 (completed)
Route II - May 1981 (completed)
Route III - July 1983 (completed) These transmission line routes are illustrated in Fig. 8.2-3. There are no crossovers of the 230-kV or 500-kV transmission
lines at any point along the three rights-of-way. The 230-kV transmission lines run from the 230-kV bays along Routes I and II, as follows: 1. 230-kV; Fancy Point Substation to Port Hudson, 2 lines (Route II) 2. 230-kV; Fancy Point Substation to Enjay, 1 line (Route II) 3. 230-kV; Fancy Point Substation to Cajun Electric Power Cooperative, 1 line (Route II)4. Future line, 7 lines (Routes I and II)
RBS USAR  8.2-9 August 1987 As shown on Fig. 8.1-5, there are additional 230-kV transmission lines associated with future units. All the new 230-kV lines are of the steel pole, H-frame structure design except that portion of Route II along Highway 19 which is a single-pole, steel, double-circuit structure. The 230-kV power conductors primarily consist of two conductor bundles of 649.5 kCMIL aluminum conductor, alloy reinforced (ACAR), cable spaced 45.7 cm (18 in) on center, with a nominal power capacity of 750 MVA. The 230-kV lines 351 and 352, from the Fancy Point Substation to the Jaguar Bulk Substation, utilize two 1,650 kCMIL ACAR cables per phase with a nominal power capacity of 1,200 MVA. 
The minimum design phase-to-phase spacing on the 230-kV transmission line system is 4.9 m (16 ft). Two static lines are provided on each 230-kV transmission tower and consist of 5/16-in
extra high strength (EHS) steel cable. The 500-kV transmission lines run from the 500-kV bays along Routes I and III as follows:1. 500-kV; Fancy Point Substation to McKnight Substation, 1 line (Route III)2. 500-kV; Fancy Point Substation to Big Cajun No. 2, 1 line (Route I)3. 500-kV; Fancy Point Substation to 500-kV/230-kV transformers, 2 lines4. Future lines, 4 lines  All 500-kV transmission lines are of the steel, lattice-type design.Two configurations of power conductors are used at the 500-kV level. Three conductor bundles of 1,024.5 kCMIL ACAR per phase spaced 45.7 cm (18 in) on center are used along Routes I and III with a nominal power capacity of 2,500 MVA. The Route I Mississippi River crossing utilizes one 3,075 kCMIL aluminum conductor steel reinforced (ACSR) cable per phase with a nominal power capacity of 2,500 MVA. The minimum phase-to-phase spacing on the 500-kV transmission line system is 11.0 m (30 ft). Two
7/16-in EHS steel cable static lines are used on each 500-kV transmission tower, with the exception of the 19 static lines used on the Mississippi River crossing which are No. 9 alumoweld
cables.
RBS USAR Revision 16 8.2-10 March 2003 All transmission lines of 230-kV and 500-kV associated with the Fancy Point Substation and River Bend Station are designed for medium loading conditions and high thunderstorm occurrence rate.
RBS USAR Revision 16 8.2-10 March 2003 All transmission lines of 230-kV and 500-kV associated with the Fancy Point Substation and River Bend Station are designed for medium loading conditions and high thunderstorm occurrence rate.
There are no unusual features of these lines. The terrain in the  
There are no unusual features of these lines. The terrain in the Gulf States system area is flat to gently sloping.
8.2.1.1.2.1 Route Descriptions Fig. 8.2-3 illustrates the three transmission line routes and identifies the route segments referenced below.
Route I Route I extends 29.2 mi from the Fancy Point Substation to the Webre Substation, and consists of lattice steel towers for 500-kV service with provisions for 230-kV underbuild lines, and steel pole H-frame 230-kV towers.
The 500-kV line 746 runs west from the switchyard to the Big Cajun No. 2 Power Station switchyard on twelve 500-kV lattice towers. From there, 500-kV line 745 proceeds south to the Webre Substation on 131 500-kV lattice towers with provisions for either one or two 230-kV underbuild circuits.
16 An existing 230-kV line 715 runs southwest to the Cajun Electric Power Company Substation near the False River cutoff, and from there to the Addis Substation with existing 230-kV line 731.
16
Segment A to B originates at the substation and continues south-southwest 1.07 mi. The segment shares the same right-of-way with the first part of Route II, and provides for seven 230-kV lines on four H-frame structures and one 500-kV line 746 on lattice steel towers with provisions for two 230-kV underbuild lines. The 500-kV line and four 230-kV lines on three H-frame structures are shown on Fig. 8.2-4. Facilities for the seven 230-kV lines and one 500-kV line were constructed in 1980.
Additional 230-kV lines will be installed at a later date when they are needed for additional capacity to support load growth in the Gulf States service area.
Segment B to C is 1.80 mi long and runs west to Point C, the Big Cajun No. 2 Power Plant switchyard. Since this segment crosses pasture land and water, different types of towers for 500-kV line 746 have been constructed. A typical tower is shown on Fig. 8.2-5.


Gulf States system area is flat to gently sloping. 8.2.1.1.2.1 Route Descriptions Fig. 8.2-3 illustrates the three transmission line routes and identifies the route segments referenced below.
RBS USAR 8.2-11 August 1987 From the switchyard at Big Cajun No. 2 (Point C) segment C to D of Route I extends 1.83 mi west and south to Point D carrying single circuit 500-kV line 745 (Fig. 8.2-6).
Route IRoute I extends 29.2 mi from the Fancy Point Substation to the Webre Substation, and consists of lattice steel towers for 500-kV service with provisions for 230-kV underbuild lines, and steel
Segment D to E runs from Point D south and southeast to Point E.
The corridor is 7.22 mi long and runs parallel to an existing right-of-way. The right-of-way on this segment carries the one existing 230-kV line 731 constructed on 230-kV single circuit wood H-frame towers and the 500-kV line 745 with provisions for a future 230-kV underbuild line as shown on Fig. 8.2-7.
Segment E to F is 9.65 mi long and extends southwest and south parallel to existing rights-of-way. This right-of-way carries 500-kV line 745 with provisions for a future 230-kV underbuild line as shown on Fig. 8.2-8.
Segment F to G is 7.22 mi long and also runs parallel to an existing right-of-way. The 500-kV line 745 tower has provisions for two future 230-kV underbuild lines (Fig. 8.2-9 and 8.2-10).
Segment G to H of Route I is 0.41 mi long and extends south parallel to the Texas and Pacific Railroad terminating at Webre Substation, Point H. This segment carries the new 500-kV line 745 with provisions for two future 230-kV underbuild lines (Fig. 8.2-11).
Route II Route II extends 23.75 mi from the Fancy Point Substation to the Jaguar Bulk Substation and consists of 129 230-kV steel pole H-frame towers and 47 230-kV single steel pole towers for 230-kV lines 351, 352, and 354. Each tower has provisions for carrying two 230-kV circuits.
Line Route II begins at the substation, Point A, and runs southeast to Point Q, Jaguar Bulk Substation in Scotlandville, Louisiana. The total route length is 23.75 mi and is divided into 10 segments.
Segment A to B of Route II is shared with Segment A to B of Route I and has been previously discussed in this section.
Segment B to I is adjacent to an existing transmission corridor running south-southeast. The 0.71 mi segment has provisions for seven 230-kV lines on four H-frame structures, an existing 69-kV and future 230-kV lines on a fifth H-frame structure (Fig. 8.2-12).


pole H-frame 230-kV towers. The 500-kV line 746 runs west from the switchyard to the Big Cajun No. 2 Power Station switchyard on twelve 500-kV lattice towers. From there, 500-kV line 745 proceeds south to the Webre Substation on 131 500-kV lattice towers with provisions for
RBS USAR 8.2-12 August 1987 Segment I to J is 1.0 mi long. It runs northeast adjacent to an existing pipeline right-of-way and consists of five 230-kV lines and existing 69-kV line 723 on four H-frame structures (Fig. 8.2-13).
Segment J to K is 1.76 mi long. It begins at Point J and runs southeast to a point 0.19 mi south of Thompson Creek. This segment is divided into three sections (0.86 mi, 0.68 mi, and 0.19 mi) with tower configurations shown on Fig. 8.2-14 through 8.2-16. This segment accommodates four H-frame structures which carry existing 230-, 138-, 69-kV lines, and three future 230-kV lines.
Segment K to L of Route II is 2.75 mi long and is divided in two sections (Fig. 8.2-17 and 8.2-18).
Segment L to M runs for 4.2 mi south and west from Point L to Port Hudson Bulk Substation, Point M. This segment consists of two double circuit and one single circuit H-frame structures accommodating five 230-kV circuits (Fig. 8.2-19 through 8.2-24).
Segment M to N (Fig. 8.2-25) is 4.83 mi in length. The segment consists of two H-frame double circuit and one H-frame single circuit structures accommodating 69-kV line 700, 230-kV lines 352 and 712, future 230-kV line 353, and a future 138-kV or 230-kV line.
Segment N to O (Fig. 8.2-26) is 0.22 mi long and consists of one H-frame tower accommodating 230-kV line 352 and one future 230-kV line.
Segment O to P runs for 1.67 mi parallel to the right-of-way of the Illinois Central Gulf Railroad and State Highway 19. It accommodates one single-pole structure for 230-kV line 352 and one future 230-kV line (Fig. 8.2-27 and 8.2-28).
Segment P to Q is 5.68 mi long, runs parallel to the Illinois Central Gulf Railroad and State Highway 19, and terminates at Point Q, the Jaguar Bulk Substation.
The right-of-way accommodates 230-kV line 352, which becomes 230-kV line 351, and a future 230-kV line on a one-pole tower structure (Fig. 8.2-29 through 8.2-31).
Route III Route III extends 27.2 mi from the Fancy Point Substation to the McKnight Switching Station, and consists of an estimated 132 500-kV lattice steel towers accommodating 500-kV line


either one or two 230-kV underbuild circuits. 16 An existing 230-kV line 715 runs southwest to the Cajun Electric Power Company Substation near the False River cutoff, and from
RBS USAR 8.2-13 August 1987 752. These towers can also accommodate either one or two 230-kV underbuild circuits.
Segment A to R starts at the substation and runs east-southeast 2.21 mi to Point R. The segment carries the 500-kV line 752 on a steel lattice tower with provisions for two future 230-kV underbuild lines (Fig. 8.2-32).
Segment R to S is 2.5 mi long, zigzagging northeast and east alongside of a
pipeline right-of-way.
The right-of-way accommodates the 500-kV line 752 with provisions for two future 230-kV underbuild lines (Fig. 8.2-33).
Segment S to T is 8.0 mi in length and consists of lattice steel towers accommodating 500-kV line 752 with provisions for the future addition of two 230-kV underbuild lines, as shown on Fig. 8.2-34.
Segment T to U is 14.51 mi long and follows a railroad right-of-way.
This segment consists of a
lattice steel tower accommodating 500-kV line 752 with provisions for the future addition of two 230-kV underbuild lines (Fig. 8.2-35).
8.2.1.1.3 Summary All features of the offsite power supply are designed to provide maximum practical reliability and redundancy in servicing the station safety load groups.
Compliance with GDC 17 is demonstrated by supplying the substation with offsite ac power by means of two 500-kV and four 230-kV physically independent circuits along two separate rights-of-way. Furthermore, the offsite power sources to the preferred station service transformers are then brought in by two physically independent circuits from this substation. Physical separation, the breaker-and-a-half switching configuration, redundant substation protection systems, and transmission system are designed on load flow and stability studies so as to minimize simultaneous failure of all offsite power sources.
8.2.1.2 Compliance with Design Criteria and Standards 8.2.1.2.1 General Design Criteria Criterion 17 The offsite power system conforms to the requirements of this criterion as follows.


there to the Addis Substation with existing 230-kV line 731.
RBS USAR Revision 16 8.2-14 March 2003 Two physically and electrically independent 230-kV circuits, providing two sources of power, are brought into the plant as shown in Fig. 8.1-4 and 8.2-2.
16Segment A to B originates at the substation and continues south-southwest 1.07 mi. The segment shares the same right-of-way with the first part of Route II, and provides for seven
16 Either of the two 230-kV circuits provides sufficient offsite capacity and capability to ensure operation of all safety-related loads for the unit following a design basis accident with loss of normal (generator) power supply. With offsite power available, the standby 4.16-kV buses 1ENS*SWG1A and 1ENS*SWG1B are energized at all times, and are unaffected by loss of the normal (generator) power supply.
16
The normal 4.16-kV swing bus 1NNS-SWG1C, which has a normally closed tie to the standby 4.16-kV bus 1E22*S004, has access to the preferred sources via either normal 4.16-kV bus 1NNS-SWG1A or 1NNS-SWG1B upon loss of normal (generator) power supply.
8.2.1.2.2 Regulatory Guides Regulatory Guide 1.32 Conformance of the offsite power system with specific requirements delineated in Regulatory Guide 1.32 is as follows.
Two circuits from the transmission network are available to the safety systems. Offsite preferred power circuits are connected via normally closed breakers to standby 4.16-kV buses 1ENS*SWG1A and 1ENS*SWG1B at all times. Loss of normal plant auxiliary supply does not influence or affect the tie circuits of standby 4.16-kV buses 1ENS*SWG1A and 1ENS*SWG1B from the offsite sources.
16 Standby 4.16-kV bus 1E22*S004 is fed from NNS-SWGIC that can be fed from one of the two normal 4.16-kV buses INNS-SWG1A or INNS-SWG1B, which provides access (Section 8.3.1.1.3) to one of the offsite circuits (Fig. 8.1-4), via the preferred station service transformers, IRTX-XSRIC or IRTX-XSRID, respectively.
16
8.2.1.2.3 IEEE Standards IEEE Standard 308 The offsite power system conforms to the requirements of this standard (Fig. 8.1-3 and 8.1-4).
Requirements of Section 5.2.3 of IEEE Standard 308 are met by having two physically and electrically independent, and continuously available circuits from the transmission


230-kV lines on four H-frame structures and one 500-kV line 746 on lattice steel towers with provisions for two 230-kV underbuild lines. The 500-kV line and four 230-kV lines on three H-frame structures are shown on Fig. 8.2-4. Facilities for the seven 230-kV lines and one 500-kV line were constructed in 1980.
RBS USAR Revision 8 8.2-15 August 1996 network to the Class 1E power system. Each of these circuits is capable of starting and operating all safety-related loads and is monitored in the main control room to verify its availability.
8.2.1.2.4 Additional Standards National Electrical Safety Code (NESC) - 1977 The offsite power system meets or exceeds the NESC requirements for a high density transmission system, Grade B.
8.2.1.3 Testing, Quality Assurance, and System Operability Surveillance Tests and Inspections The preoperational and initial startup test programs for the preferred power system is in accordance with Regulatory Guides 1.41 and 1.68 and GDC 1. The test program capabilities consider GDC 18 and 21 as discussed in Section 3.1.2.
During the preoperational stage, all components of the preferred power system are installed, tested, and inspected to demonstrate that all components are correct and properly mounted. All connections are verified as being correct and continuous, and all components as operational. All metering and protective devices are properly calibrated and adjusted. These tests are described in Section 14.
Following satisfactory checkout of all components of a system as previously described, the initial system tests are performed according to the technical specifications with all components installed. The initial system tests include operational tests conducted to demonstrate that the equipment operates within design limits and that the system is operational and meets its performance specifications.  
8 The technical specifications/requirements include in-service test and surveillance requirements for the preferred power system following the preoperational and initial system tests and inspections. The particular tests and the frequency of these tests depend upon the specific components installed, their function and environment. These tests are directed at detecting deterioration of the system toward an unacceptable condition and demonstrating that standby components are operable.
8


Additional 230-kV lines will be installed at a later date when
RBS USAR Revision 16 8.2-16 March 2003 Circuit breakers and associated devices can be tested when their associated loads or systems are shut down or not in service.
Protective relays are tested under a simulated overload or fault condition, and their calibration is verified. The breaker opening and closing can also be demonstrated. Availability of power is indicated by breaker position lights.
The capability of the preferred power system to transmit sufficient energy to start and operate all required safety-related loads is confirmed during periodic tests.
These tests also confirm the capability of the supply breakers to operate and transmit the required energy upon receipt of a control input.
These tests are performed at scheduled intervals and verify the ability of the preferred power system to furnish electrical energy for the shutdown of the plant and for the operation of safety-related systems and engineered safety features.
Quality Assurance Quality Assurance for the offsite power system is based on industry standards applicable to normal systems.
It considers IEEE 336 and Regulatory Guide 1.30, where applicable, to non-Class 1E systems, to meet GDC 1 for equipment requirements.
System Operability Surveillance
16 Surveillance and status of the offsite power system operability are provided by automatic system indication in the main control room. A panel located in front of the principal plant control console provides a positive indication of breaker positions for the offsite switchyard. Inoperability of offsite power supplies either by event or deliberate action is annunciated to alert main control room operators to anomalies on the system grid.
Additionally, main control room operators have voice communication systems to contact the Southwest-Transmission Operation Center to ascertain system grid status.
16
Offsite Power System Monitoring and Surveillance
5 The transmission lines of GSU are inspected periodically by aerial patrol.
5


they are needed for additional capacity to support load growth in  
RBS USAR 8.2-17 August 1987 Routine maintenance of substation batteries includes a weekly visual inspection of charge rate and voltage level and a quarterly test of the batteries' ability to maintain voltage under normal station load.
Routine maintenance on power circuit breakers is performed as required to verify that all design criteria for operation are not exceeded.
Control and protective breakers are separated to the maximum extent possible to ensure that failure of any item does not impair system protection.
8.2.2 Analysis 8.2.2.1 Availability Considerations The 500-kV and 230-kV transmission lines and their associated structures, interconnecting the substation with the system, are designed to withstand the environmental loading conditions for the area with regard to wind, temperature, lightning, and flooding.
The transmission lines approach the substation on separate rights-of-way on the southeast and southwest sides of the substation. Due to this separation, failure of one line on one right-of-way does not cause failure of another line on the second right-of-way.
Two independent and redundant transmission lines are provided as offsite power sources for the power plant safety load groups which, as shown in Section 8.3, remain independent down to the lowest voltage level of distribution. These 230-kV sources supply the two 4.16-kV preferred transformers as shown in Fig. 8.1-6.
The 230-kV bays have a breaker-and-a-half configuration with breaker failure backup protection. Substation reliability and operating flexibility are achieved as follows:
: 1.
Any transmission line can be cleared under normal or fault conditions without affecting any other transmission line.
: 2.
Any system circuit breaker can be isolated for maintenance without interrupting the power or protection to any circuit.


the Gulf States service area. Segment B to C is 1.80 mi long and runs west to Point C, the Big Cajun No. 2 Power Plant switchyard. Since this segment crosses
RBS USAR Revision 16 8.2-18 March 2003
: 3.
Short circuits on a section of a bus are isolated without interrupting service to any circuit other than that connected to the faulted bus section.
The two independent circuits from the substation to the preferred transformers are routed separately as shown in Fig. 8.2-1. Due to this separation, a failure of one circuit does not cause the failure of the other circuit. Therefore, these two circuits provide separate and redundant sources to safety load groups.
While it is improbable that all transmission lines could be out of service simultaneously, such an event would not jeopardize a safe shutdown of the station because the onsite standby diesel generators would be able to supply the necessary power to systems required for safe shutdown or LOCA. The onsite power system, including automatic startup and load sequencing, is described in Section 8.3.
16 With any single line in service under its design condition of operation, sufficient offsite power would be available to handle a LOCA and safe shutdown of the unit.
16
Outage data on the 230-kV and 500-kV lines in GSU transmission of current experience is given in Tables 8.2-1, 8.2-2, 8.2-4, and 8.2-5.
8.2.2.2 Stability Considerations The design and operation of interconnected power systems must be such that they remain stable following severe faults. This is essential to avoid widespread or cascading interruptions to service, and requires that various stability studies be carried out using mathematical models for the components of electrical power systems.  
11 A transient stability study (analysis of conditions within 1 sec after the fault) in compliance with the criteria of the Southwest Power Pool Coordination Council, which is comparable with Southeastern Electric Reliability Council criteria, was performed on River Bend Station Unit 1 using the 1984 summer peak as the base case. The generators were represented as constant voltages behind transient reactance, with no exciter-regulator and no turbine governor, so that conservative results were obtained.
Studies have also been performed (including consideration of regulation, excitation, and governor action) which verify that the system is dynamically stable.
Stability of the interconnected utilities, when Unit 1 goes
: online, was investigated under the following conditions:
11


pasture land and water, different types of towers for 500-kV line 746 have been constructed. A typical tower is shown on Fig. 8.2-
RBS USAR 8.2-19 August 1987
: 1.
Three-phase fault on GSU's Fancy Point Substation 230-kV bus, with a subsequent clearing of the fault in 6 cycles and tripping of River Bend Station Unit 1.
: 2.
Three-phase fault on CEPCO's Big Cajun 500-kV bus, with a subsequent clearing of the fault in 4.5 cycles and tripping of Big Cajun Unit No. 3.
: 3.
Three-phase fault on Grand Gulf Nuclear Station 500-kV bus, with a subsequent clearing of the fault in 4.5 cycles and tripping of Grand Gulf Unit No. 2 (1,250 MW).
: 4.
Three-phase fault on Arkansas Nuclear One 500-kV bus, with a subsequent clearing of the fault in 4.5 cycles and tripping of Arkansas Nuclear One Unit No. 2 (950 MW).
: 5.
: 5.
RBS USAR  8.2-11 August 1987 From the switchyard at Big Cajun No. 2 (Point C) segment C to D of Route I extends 1.83 mi west and south to Point D carrying
Three-phase fault on Tennessee Valley Authority's Brown's Ferry Station 500-kV bus, with a subsequent clearing of the fault in 4.5 cycles and tripping of Brown's Ferry Station Unit No. 3 (1,050 MW).
 
: 6.
single circuit 500-kV line 745 (Fig. 8.2-6). Segment D to E runs from Point D south and southeast to Point E. The corridor is 7.22 mi long and runs parallel to an existing right-of-way. The right-of-way on this segment carries the one existing 230-kV line 731 constructed on 230-kV single circuit wood H-frame towers and the 500-kV line 745 with provisions for a  
Three-phase fault on GSU's Willow Glen 230-kV bus, with a subsequent clearing of the fault in 6 cycles and tripping of Willow Glen Unit No. 4 (540 MW).
 
: 7.
future 230-kV underbuild line as shown on Fig. 8.2-7. Segment E to F is 9.65 mi long and extends southwest and south parallel to existing rights-of-way. This right-of-way carries 500-kV line 745 with provisions for a future 230-kV underbuild
Three-phase fault on the 230-kV line from the Fancy Point Substation to Enjay at the River Bend Station end, with a subsequent opening of the line at both ends in 6 cycles.
 
: 8.
line as shown on Fig. 8.2-8. Segment F to G is 7.22 mi long and also runs parallel to an existing right-of-way. The 500-kV line 745 tower has provisions
Three-phase fault on the 230-kV line from the Fancy Point Substation to Port Hudson at the River Bend Station end, with a subsequent opening of the line at both ends in 6 cycles.
 
: 9.
for two future 230-kV underbuild lines (Fig. 8.2-9 and 8.2-10). Segment G to H of Route I is 0.41 mi long and extends south parallel to the Texas and Pacific Railroad terminating at Webre Substation, Point H. This segment carries the new 500-kV line 745 with provisions for two future 230-kV underbuild lines (Fig. 8.2-11).
Three-phase fault on the 230-kV line from the Fancy Point Substation to Cajun No. 1 at the River Bend Station end, with a subsequent clearing of the line at both ends in 6 cycles.
Route IIRoute II extends 23.75 mi from the Fancy Point Substation to the Jaguar Bulk Substation and consists of 129 230-kV steel pole H-frame towers and 47 230-kV single steel pole towers for 230-kV lines 351, 352, and 354. Each tower has provisions for carrying
: 10. Three-phase fault on the 500-kV line from the Fancy Point Substation to Big Cajun at the River Bend Station end, with a subsequent clearing of the line at both ends in 4 cycles.
 
: 11. Three-phase fault on the 500-kV line from the Fancy Point Substation to McKnight at the River Bend
two 230-kV circuits.Line Route II begins at the substation, Point A, and runs southeast to Point Q, Jaguar Bulk Substation in Scotlandville, Louisiana. The total route length is 23.75 mi and is divided
 
into 10 segments.Segment A to B of Route II is shared with Segment A to B of Route I and has been previously discussed in this section.Segment B to I is adjacent to an existing transmission corridor running south-southeast. The 0.71 mi segment has provisions for seven 230-kV lines on four H-frame structures, an existing 69-kV and future 230-kV lines on a fifth H-frame structure (Fig. 8.2-
 
12).
RBS USAR  8.2-12 August 1987 Segment I to J is 1.0 mi long. It runs northeast adjacent to an existing pipeline right-of-way and consists of five 230-kV lines and existing 69-kV line 723 on four H-frame structures (Fig. 8.2-
 
13).Segment J to K is 1.76 mi long. It begins at Point J and runs southeast to a point 0.19 mi south of Thompson Creek. This segment is divided into three sections (0.86 mi, 0.68 mi, and 0.19 mi) with tower configurations shown on Fig. 8.2-14 through 8.2-16. This segment accommodates four H-frame structures which carry existing 230-, 138-, 69-kV lines, and three future 230-kV
 
lines.Segment K to L of Route II is 2.75 mi long and is divided in two sections (Fig. 8.2-17 and 8.2-18). Segment L to M runs for 4.2 mi south and west from Point L to Port Hudson Bulk Substation, Point M. This segment consists of two double circuit and one single circuit H-frame structures
 
accommodating five 230-kV circuits (Fig. 8.2-19 through 8.2-24). Segment M to N (Fig. 8.2-25) is 4.83 mi in length. The segment consists of two H-frame double circuit and one H-frame single circuit structures accommodating 69-kV line 700, 230-kV lines 352 and 712, future 230-kV line 353, and a future 138-kV or 230-kV
 
line.Segment N to O (Fig. 8.2-26) is 0.22 mi long and consists of one H-frame tower accommodating 230-kV line 352 and one future 230-kV
 
line.Segment O to P runs for 1.67 mi parallel to the right-of-way of the Illinois Central Gulf Railroad and State Highway 19. It accommodates one single-pole structure for 230-kV line 352 and
 
one future 230-kV line (Fig. 8.2-27 and 8.2-28). Segment P to Q is 5.68 mi long, runs parallel to the Illinois Central Gulf Railroad and State Highway 19, and terminates at Point Q, the Jaguar Bulk Substation. The right-of-way accommodates 230-kV line 352, which becomes 230-kV line 351, and a future 230-kV line on a one-pole tower structure (Fig. 8.2-29
 
through 8.2-31).
Route IIIRoute III extends 27.2 mi from the Fancy Point Substation to the McKnight Switching Station, and consists of an estimated 132 500-
 
kV lattice steel towers accommodating 500-kV line RBS USAR  8.2-13 August 1987 752. These towers can also accommodate either one or two 230-kV underbuild circuits. Segment A to R starts at the substation and runs east-southeast 2.21 mi to Point R. The segment carries the 500-kV line 752 on a steel lattice tower with provisions for two future 230-kV
 
underbuild lines (Fig. 8.2-32). Segment R to S is 2.5 mi long, zigzagging northeast and east alongside of a pipeline right-of-way. The right-of-way accommodates the 500-kV line 752 with provisions for two future
 
230-kV underbuild lines (Fig. 8.2-33). Segment S to T is 8.0 mi in length and consists of lattice steel towers accommodating 500-kV line 752 with provisions for the future addition of two 230-kV underbuild lines, as shown on
 
Fig. 8.2-34. Segment T to U is 14.51 mi long and follows a railroad right-of-way. This segment consists of a lattice steel tower accommodating 500-kV line 752 with provisions for the future
 
addition of two 230-kV underbuild lines (Fig. 8.2-35).
8.2.1.1.3 Summary
 
All features of the offsite power supply are designed to provide maximum practical reliability and redundancy in servicing the station safety load groups. Compliance with GDC 17 is demonstrated by supplying the substation with offsite ac power by means of two 500-kV and four 230-kV physically independent circuits along two separate rights-of-way. Furthermore, the offsite power sources to the preferred station service transformers are then brought in by two physically independent circuits from this substation. Physical separation, the breaker-and-a-half switching configuration, redundant substation protection systems, and transmission system are designed on load flow and stability studies so as to minimize simultaneous failure
 
of all offsite power sources.8.2.1.2 Compliance with Design Criteria and Standards 8.2.1.2.1 General Design Criteria
 
Criterion 17The offsite power system conforms to the requirements of this criterion as follows.
RBS USAR Revision 16 8.2-14 March 2003 Two physically and electrically independent 230-kV circuits, providing two sources of power, are brought into the plant as
 
shown in Fig. 8.1-4 and 8.2-2. 16Either of the two 230-kV circuits provides sufficient offsite capacity and capability to ensure operation of all safety-related loads for the unit following a design basis accident with loss of normal (generator) power supply. With offsite power available, the standby 4.16-kV buses 1ENS*SWG1A and 1ENS*SWG1B are energized
 
at all times, and are unaffected by loss of the normal (generator) power supply.
16The normal 4.16-kV swing bus 1NNS-SWG1C, which has a normally closed tie to the standby 4.16-kV bus 1E22*S004, has access to the preferred sources via either normal 4.16-kV bus 1NNS-SWG1A or
 
1NNS-SWG1B upon loss of normal (generator) power supply. 8.2.1.2.2 Regulatory Guides
 
Regulatory Guide 1.32Conformance of the offsite power system with specific requirements delineated in Regulatory Guide 1.32 is as follows.
Two circuits from the transmission network are available to the safety systems. Offsite preferred power circuits are connected via normally closed breakers to standby 4.16-kV buses 1ENS*SWG1A and 1ENS*SWG1B at all times. Loss of normal plant auxiliary
 
supply does not influence or affect the tie circuits of standby
 
4.16-kV buses 1ENS*SWG1A and 1ENS*SWG1B from the offsite sources. 16 Standby 4.16-kV bus 1E22*S004 is fed from NNS-SWGIC that can be fed from one of the two normal 4.16-kV buses INNS-SWG1A or INNS-SWG1B, which provides access (Section 8.3.1.1.3) to one of the offsite circuits (Fig. 8.1-4), via the preferred station service
 
transformers, IRTX-XSRIC or IRTX-XSRID, respectively.
168.2.1.2.3 IEEE Standards IEEE Standard 308The offsite power system conforms to the requirements of this standard (Fig. 8.1-3 and 8.1-4). Requirements of Section 5.2.3 of IEEE Standard 308 are met by having two physically and electrically independent, and
 
continuously available circuits from the transmission RBS USAR Revision 8 8.2-15 August 1996 network to the Class 1E power system. Each of these circuits is capable of starting and operating all safety-related loads and is
 
monitored in the main control room to verify its availability. 8.2.1.2.4 Additional Standards
 
National Electrical Safety Code (NESC) - 1977The offsite power system meets or exceeds the NESC requirements for a high density transmission system, Grade B. 8.2.1.3 Testing, Quality Assurance, and System Operability Surveillance Tests and InspectionsThe preoperational and initial startup test programs for the preferred power system is in accordance with Regulatory Guides 1.41 and 1.68 and GDC 1. The test program capabilities
 
consider GDC 18 and 21 as discussed in Section 3.1.2. During the preoperational stage, all components of the preferred power system are installed, tested, and inspected to demonstrate that all components are correct and properly mounted. All connections are verified as being correct and continuous, and all components as operational. All metering and protective devices
 
are properly calibrated and adjusted. These tests are described
 
in Section 14. Following satisfactory checkout of all components of a system as previously described, the initial system tests are performed according to the technical specifications with all components installed. The initial system tests include operational tests conducted to demonstrate that the equipment operates within
 
design limits and that the system is operational and meets its
 
performance specifications. 8 The technical specifications/requirements include in-service test and surveillance requirements for the preferred power system following the preoperational and initial system tests and inspections. The particular tests and the frequency of these tests depend upon the specific components installed, their function and environment. These tests are directed at detecting deterioration of the system toward an unacceptable condition and
 
demonstrating that standby components are operable.
8 RBS USAR Revision 16 8.2-16 March 2003 Circuit breakers and associated devices can be tested when their associated loads or systems are shut down or not in service.
Protective relays are tested under a simulated overload or fault condition, and their calibration is verified. The breaker opening and closing can also be demonstrated. Availability of
 
power is indicated by breaker position lights. The capability of the preferred power system to transmit sufficient energy to start and operate all required safety-
 
related loads is confirmed during periodic tests.
These tests also confirm the capability of the supply breakers to operate and transmit the required energy upon receipt of a
 
control input. These tests are performed at scheduled intervals and verify the ability of the preferred power system to furnish electrical energy for the shutdown of the plant and for the operation of
 
safety-related systems and engineered safety features.
Quality AssuranceQuality Assurance for the offsite power system is based on industry standards applicable to normal systems. It considers IEEE 336 and Regulatory Guide 1.30, where applicable, to non-Class 1E systems, to meet GDC 1 for equipment
 
requirements.
System Operability Surveillance16 Surveillance and status of the offsite power system operability are provided by automatic system indication in the main control room. A panel located in front of the principal plant control
 
console provides a positive indication of breaker positions for the offsite switchyard. Inoperability of offsite power supplies
 
either by event or deliberate action is annunciated to alert main control room operators to anomalies on the system grid.
Additionally, main control room operators have voice
 
communication systems to contact the S outhwest-Transmission Operation Center to ascertain system grid status.
16Offsite Power System Monitoring and Surveillance5 The transmission lines of GSU are inspected periodically by aerial patrol.
5 RBS USAR  8.2-17 August 1987 Routine maintenance of substation batteries includes a weekly visual inspection of charge rate and voltage level and a quarterly test of the batteries' ability to maintain voltage
 
under normal station load. Routine maintenance on power circuit breakers is performed as required to verify that all design criteria for operation are not


exceeded.Control and protective breakers are separated to the maximum extent possible to ensure that failure of any item does not
RBS USAR 8.2-20 August 1987 Station end, with a subsequent clearing of the line at both ends in 4 cycles.
 
: 12. Three-phase fault on the 230-kV line from the Fancy Point Substation to Enjay at the River Bend Station end, with a subsequent clearing of the Enjay end in 6 cycles and the Fancy Point Substation end in 12 cycles (stuck breaker).
impair system protection.
: 13. Three-phase fault on the 230-kV line from the Fancy Point Substation to Port Hudson at the River Bend Station end, with a subsequent clearing of the Port Hudson end in 6 cycles and the River Bend Station end in 12 cycles (stuck breaker).
 
: 14. Three-phase fault on GSU's Enjay 230-kV bus, with a subsequent clearing of the fault in 6 cycles and tripping of 160 MW of load.
====8.2.2 Analysis====
: 15. Three-phase fault on GSU's Esso 230-kV bus, with a subsequent clearing of the fault in 6 cycles and tripping of 350 MW of load.
 
The listed cases are conservative with respect to other unlisted less severe faults. Therefore a fault of any kind (loss of the River Bend Station Unit 1, loss of critical loads, loss of EHV transmission lines, or loss of a large unit inside GSU's system as well as neighboring systems) with successful clearing does not cause system instability or result in loss of offsite power to safety-related systems. In addition, load flow contingency analyses (Table 8.2-3) show that any line or 500 to 230-kV transformer outage in the Fancy Point Substation does not result in loss of offsite power supply.
8.2.2.1 Availability Considerations The 500-kV and 230-kV transmission lines and their associated structures, interconnecting the substation with the system, are
Physical separation of the 230-kV offsite power sources, substation protection, redundancy, and transmission system design based on load flow and stability analysis minimizes the possibility of simultaneous failure of power sources (normal station service supply, preferred station service supply, and standby ac diesel generators).
 
designed to withstand the environmental loading conditions for the area with regard to wind, temperature, lightning, and
 
flooding.The transmission lines approach the substation on separate rights-of-way on the southeast and southwest sides of the substation. Due to this separation, failure of one line on one
 
right-of-way does not cause failure of another line on the second
 
right-of-way.Two independent and redundant transmission lines are provided as offsite power sources for the power plant safety load groups which, as shown in Section 8.3, remain independent down to the lowest voltage level of distribution. These 230-kV sources supply the two 4.16-kV preferred transformers as shown in
 
Fig. 8.1-6. The 230-kV bays have a breaker-and-a-half configuration with breaker failure backup protection. Substation reliability and
 
operating flexibility are achieved as follows: 1. Any transmission line can be cleared under normal or fault conditions without affecting any other
 
transmission line. 2. Any system circuit breaker can be isolated for maintenance without interrupting the power or
 
protection to any circuit.
RBS USAR Revision 16 8.2-18 March 2003 3. Short circuits on a section of a bus are isolated without interrupting service to any circuit other than
 
that connected to the faulted bus section. The two independent circuits from the substation to the preferred transformers are routed separately as shown in Fig. 8.2-1. Due to this separation, a failure of one circuit does not cause the
 
failure of the other circuit. Therefore, these two circuits provide separate and redundant sources to safety load groups. 
 
While it is improbable that all transmission lines could be out of service simultaneously, such an event would not jeopardize a safe shutdown of the station because the onsite standby diesel
 
generators would be able to supply the necessary power to systems required for safe shutdown or LOCA. The onsite power system, including automatic startup and load sequencing, is described in
 
Section 8.3. 16 With any single line in service under its design condition of operation, sufficient offsite power would be available to handle
 
a LOCA and safe shutdown of the unit.
16Outage data on the 230-kV and 500-kV lines in GSU transmission of current experience is given in Tables 8.2-1, 8.2-2, 8.2-4, and
 
8.2-5.8.2.2.2 Stability Considerations The design and operation of interconnected power systems must be such that they remain stable following severe faults. This is essential to avoid widespread or cascading interruptions to
 
service, and requires that various stability studies be carried out using mathematical models for the components of electrical
 
power systems. 11A transient stability study (analysis of conditions within 1 sec after the fault) in compliance with the criteria of the Southwest Power Pool Coordination Council, which is comparable with Southeastern Electric Reliability Council criteria, was performed on River Bend Station Unit 1 using the 1984 summer peak as the base case. The generators were represented as constant voltages behind transient reactance, with no exciter-regulator and no turbine governor, so that conservative results were obtained.
Studies have also been performed (including consideration of
 
regulation, excitation, and governor action) which verify that the system is dynamically stable. Stability of the interconnected utilities, when Unit 1 goes online, was
 
investigated under the following conditions:
11 RBS USAR  8.2-19 August 1987 1. Three-phase fault on GSU's Fancy Point Substation 230-kV bus, with a subsequent clearing of the fault in 6
 
cycles and tripping of River Bend Station Unit 1. 2. Three-phase fault on CEPCO's Big Cajun 500-kV bus, with a subsequent clearing of the fault in 4.5 cycles and
 
tripping of Big Cajun Unit No. 3. 3. Three-phase fault on Grand Gulf Nuclear Station 500-kV bus, with a subsequent clearing of the fault in 4.5 cycles and tripping of Grand Gulf Unit No. 2
 
(1,250 MW). 4. Three-phase fault on Arkansas Nuclear One 500-kV bus, with a subsequent clearing of the fault in 4.5 cycles and tripping of Arkansas Nuclear One Unit No. 2
 
(950 MW). 5. Three-phase fault on Tennessee Valley Authority's Brown's Ferry Station 500-kV bus, with a subsequent clearing of the fault in 4.5 cycles and tripping of
 
Brown's Ferry Station Unit No. 3 (1,050 MW). 6. Three-phase fault on GSU's Willow Glen 230-kV bus, with a subsequent clearing of the fault in 6 cycles and
 
tripping of Willow Glen Unit No. 4 (540 MW). 7. Three-phase fault on the 230-kV line from the Fancy Point Substation to Enjay at the River Bend Station
 
end, with a subsequent opening of the line at both ends
 
in 6 cycles. 8. Three-phase fault on the 230-kV line from the Fancy Point Substation to Port Hudson at the River Bend Station end, with a subsequent opening of the line at
 
both ends in 6 cycles. 9. Three-phase fault on the 230-kV line from the Fancy Point Substation to Cajun No. 1 at the River Bend
 
Station end, with a subsequent clearing of the line at
 
both ends in 6 cycles. 10. Three-phase fault on the 500-kV line from the Fancy Point Substation to Big Cajun at the River Bend Station end, with a subsequent clearing of the line at both
 
ends in 4 cycles. 11. Three-phase fault on the 500-kV line from the Fancy Point Substation to McKnight at the River Bend RBS USAR  8.2-20 August 1987 Station end, with a subsequent clearing of the line at both ends in 4 cycles. 12. Three-phase fault on the 230-kV line from the Fancy Point Substation to Enjay at the River Bend Station  
 
end, with a subsequent clearing of the Enjay end in 6  
 
cycles and the Fancy Point Substation end in 12 cycles (stuck breaker). 13. Three-phase fault on the 230-kV line from the Fancy Point Substation to Port Hudson at the River Bend Station end, with a subsequent clearing of the Port  
 
Hudson end in 6 cycles and the River Bend Station end  
 
in 12 cycles (stuck breaker). 14. Three-phase fault on GSU's Enjay 230-kV bus, with a subsequent clearing of the fault in 6 cycles and  
 
tripping of 160 MW of load. 15. Three-phase fault on GSU's Esso 230-kV bus, with a subsequent clearing of the fault in 6 cycles and  
 
tripping of 350 MW of load. The listed cases are conservative with respect to other unlisted less severe faults. Therefore a fault of any kind (loss of the River Bend Station Unit 1, loss of critical loads, loss of EHV  
 
transmission lines, or loss of a large unit inside GSU's system as well as neighboring systems) with successful clearing does not  
 
cause system instability or result in loss of offsite power to safety-related systems. In addition, load flow contingency analyses (Table 8.2-3) show that any line or 500 to 230-kV transformer outage in the Fancy Point Substation does not result  
 
in loss of offsite power supply.Physical separation of the 230-kV offsite power sources, substation protection, redundancy, and transmission system design  
 
based on load flow and stability analysis minimizes the possibility of simultaneous failure of power sources (normal station service supply, preferred station service supply, and  
 
standby ac diesel generators).
This complies with the last paragraph of GDC 17.
This complies with the last paragraph of GDC 17.
RBSUSAR8.3-1August19878.3ONSITEPOWERSYSTEMS8.3.1ACPowerSystems 8.3.1.1Description 8.3.1.1.1General TheonsiteacpowersystemsforRiverBendStationarethosesystemswhichincludeelectricalequipmentandconnections requiredtodistributepowertostationauxiliariesandservice loadsduringallmodesofplantoperation.Theirobjectiveisto providereliableacpowerrequiredduringanormalstartup, operation,andshutdown,orduringanemergencyshutdown.Theac powersystemmusthaveadequateindependence,redundancy, capacity,andtestabilitytoensureitscapabilityforperforming thefunctionsrequiredoftheengineeredsafetyfeatures(ESF) andotherreactorprotectionsystems.Theonsiteelectricalpowersystems(Fig.8.1-4,8.1-6,8.3-1,and8.3-2)extendfromtheonsiteterminationofincominglines uptoandincludingtheelectricalpowerutilizationdevices.
Theseconsistofpowersources(networkinterconnections,onsite standbypowersourcesandtheirauxiliaries,uninterruptible powersources,andbatterysystems),distributionequipment (transformers,circuitbreakers,buses,andinterconnecting cables),instrumentationandcontrols(surveillance instrumentation,protectivecircuitry,andcontrolcircuitry),
andutilizationdevices(motors,solenoids,andheaters).ThephysicalarrangementoftheonsiteelectricalsafetysystemsisdesignedtopreservetheindependenceofredundantESFs.
Physicalseparation,achievedbydistanceorbarriers,is providedbetweensimilarcomponentsofredundantelectrical systems.Inaddition,separationisprovidedbetweenredundant power,instrumentation,andcontrolcircuitryservingorbeing servedfromthesecomponents.Thesafety-relatedelectrical systemsarephysicallyindependentandarelocatedwithinSeismic CategoryIstructuresorportionsofstructuresdesignedtomeet SeismicCategoryIcriteria.Thecontinuityandintegrityofloadfunctionsaremaintainedbyredundantequipmentsuppliedfromseparatesourcesviaseparate cable,cabletray,andconduitsystems.Transformersaresizedforanticipatedmaximumnormalloadplusthosenormalloadswhichmaybetransferredtothemby RBSUSAR8.3-2August1987theswing-busorsectionsofsplit-busunitsubstationloadcenters,byclosureofthetiebreakers.Thesetransformersare notintendedtosupporttotalconnectedload.Motorsaresized tocarryfullloadwithoutencroachmentontheservicefactor margin,and"runout"overloads,suchasthosecausedbybreaks inpipesdownstreamfrompumps,withoutexceedingtheservice factorload.Thedieselgeneratorsaresizedtoacceptfull standbyrequirementsandtoensurefrequencyandvoltage stabilityduringstartingperiodsinaccordancewithRegulatory Guide1.9,exceptfortheHPCSdieselwhichisdescribedin Section8.3.1.2.2.2.Motorsaresizedforanticipatedmaximumloadatagivenspeedwithconsiderationgiventotorquerequirements.Motorinsulation ischosenbytakingintoconsiderationtheenvironmentinwhich themotoristooperate.Theseconsiderationsincludebutare notlimitedtoambienttemperature,humidity,radiationlevel, seismicrequirements,andvoltagelevelofoperation.Theinterruptingcapacityofswitchgear,loadcenters,motorcontrolcenters,anddistributionpanelsisbaseduponstudiesof theelectricalsystem.Thesestudiesconsider,asaminimum,the sizeoftheconnectedload,motorstartingload,motorstarting current,andsystemandconnectedloadcontributionsunder faultedconditions.8.3.1.1.2SystemsIdentification 8.3.1.1.2.1Safety-RelatedSystemsandIdentification TheseClass1Eacpowersystemsofthenuclearplantprovidefunctionsassociatedwithmitigatingtheeffectsofaccidentsor providingforsafeplantshutdown.Thesesystemsaredivided intothreephysicallyandelectricallyindependentdivisions whichareidentifiedbydistinctmeans.Thethreedivisionsare identifiedasfollows:DivisionI-RedDivisionII-Blue DivisionIII-OrangeSeeSection8.3.1.3foradditionalidentificationofthesesafety-relateddivisions.TheClass1Eacpowersystemdivisions andtheirassociatedstandbyswitchgearsandloadcentersare delineatedinFig.8.1-4and8.1-6.
RBSUSAR8.3-3August1987Thesesystemsinclude,butarenotnecessarilylimitedto,the following:1.Emergencycorecoolingsystems(ECCS) 2.Standbyservicewater(SSW)system 3.Standbygastreatmentsystem(SGTS) 4.Coolingsystemsa.Maincontrolroomair-conditioning b.Standbyswitchgearandstandbybatteryroomsventilationandcoolingc.Safeguardequipmentintheauxiliarybuildingventilationd.Standbydieselgeneratorrooms ventilation5.Containmentandreactorvesselisolationcontrolsystem(CRVICS)6.Standbylightingsystem 7.InstrumentationandcontrolfortheRPSandESF functions.LoadsconnectedtotheseClass1Esafety-relatedsystemsarelistedinTable8.3-1.8.3.1.1.2.2Nonsafety-RelatedPowerGenerationSystems Thesesystemsofthenuclearplantarethosewhicharenotessentialforsafeshutdown.Electricalfailureofthese systemscannotresultinthereleaseorfailuretominimize releaseofradioactivematerial.Thesenormalnon-Class1Eac systemsarenonsafety-relatedandthereforenondivisional.They areidentifiedasbeingpartoftheblacksystemorarenotgiven coloridentificationasdescribedinSection8.3.1.3.These systemsinclude,butarenotnecessarilylimitedto,the


following:1.Maincondensatesystem 2.Reactorfeedwatersystem 3.Condensatemakeupsystem RBS USAR Revision 22 8.3-4 6  4. Turbine plant component cooling water system
RBS USAR 8.3-1 August 1987 8.3 ONSITE POWER SYSTEMS 8.3.1 AC Power Systems 8.3.1.1 Description 8.3.1.1.1 General The onsite ac power systems for River Bend Station are those systems which include electrical equipment and connections required to distribute power to station auxiliaries and service loads during all modes of plant operation.
: 5. Reactor plant component cooling water system  
Their objective is to provide reliable ac power required during a
: 6. Plant ventilation system
normal
: 7. Normal service water system
: startup, operation, and shutdown, or during an emergency shutdown.
: 8. Circulating water system
The ac power system must have adequate independence, redundancy, capacity, and testability to ensure its capability for performing the functions required of the engineered safety features (ESF) and other reactor protection systems.
: 9. Reactor water cleanup system
The onsite electrical power systems (Fig. 8.1-4, 8.1-6, 8.3-1, and 8.3-2) extend from the onsite termination of incoming lines up to and including the electrical power utilization devices.
: 10. Service water cooling system.
These consist of power sources (network interconnections, onsite standby power sources and their auxiliaries, uninterruptible power
6 8.3.1.1.3  Power Supplies and Buses
: sources, and battery systems),
distribution equipment (transformers, circuit
: breakers, buses, and interconnecting cables),
instrumentation and controls (surveillance instrumentation, protective circuitry, and control circuitry),
and utilization devices (motors, solenoids, and heaters).
The physical arrangement of the onsite electrical safety systems is designed to preserve the independence of redundant ESFs.
Physical separation, achieved by distance or
: barriers, is provided between similar components of redundant electrical systems.
In addition, separation is provided between redundant
: power, instrumentation, and control circuitry serving or being served from these components.
The safety-related electrical systems are physically independent and are located within Seismic Category I structures or portions of structures designed to meet Seismic Category I criteria.
The continuity and integrity of load functions are maintained by redundant equipment supplied from separate sources via separate cable, cable tray, and conduit systems.
Transformers are sized for anticipated maximum normal load plus those normal loads which may be transferred to them by


8.3.1.1.3.1 Station Service Transformers 13 7 The normal ac power supply can provide electrical power for all station auxiliary loads when the main generator is operating.
RBS USAR 8.3-2 August 1987 the swing-bus or sections of split-bus unit substation load centers, by closure of the tie breakers.
It consists of three normal station service transformers 1STX-X NS1A, 1STX-XNS1B and 1STX-XNS1C, electric power through STX-XNS1C is not used, energized by isolated phase bus duct from the generator
These transformers are not intended to support total connected load.
Motors are sized to carry full load without encroachment on the service factor margin, and "run out" overloads, such as those caused by breaks in pipes downstream from
: pumps, without exceeding the service factor load.
The diesel generators are sized to accept full standby requirements and to ensure frequency and voltage stability during starting periods in accordance with Regulatory Guide 1.9, except for the HPCS diesel which is described in Section 8.3.1.2.2.2.
Motors are sized for anticipated maximum load at a
given speed with consideration given to torque requirements. Motor insulation is chosen by taking into consideration the environment in which the motor is to operate.
These considerations include but are not limited to ambient temperature,
: humidity, radiation
: level, seismic requirements, and voltage level of operation.
The interrupting capacity of switchgear, load
: centers, motor control centers, and distribution panels is based upon studies of the electrical system.
These studies consider, as a minimum, the size of the connected load, motor starting load, motor starting
: current, and system and connected load contributions under faulted conditions.
8.3.1.1.2 Systems Identification 8.3.1.1.2.1 Safety-Related Systems and Identification These Class 1E ac power systems of the nuclear plant provide functions associated with mitigating the effects of accidents or providing for safe plant shutdown.
These systems are divided into three physically and electrically independent divisions which are identified by distinct means.
The three divisions are identified as follows:
Division I
- Red Division II
- Blue Division III - Orange See Section 8.3.1.3 for additional identification of these safety-related divisions.
The Class 1E ac power system divisions and their associated standby switchgears and load centers are delineated in Fig. 8.1-4 and 8.1-6.


terminals, as shown in Fig. 8.1-4.
RBS USAR 8.3-3 August 1987 These systems
13  6 4 The preferred ac power supply can provide for all station auxiliary loads. This includes the maximum operational combination of full load power, startup power, hot standby maintenance power, shutdown power, and the safety-related loads.
: include, but are not necessarily limited to, the following:
1.
Emergency core cooling systems (ECCS) 2.
Standby service water (SSW) system 3.
Standby gas treatment system (SGTS) 4.
Cooling systems a.
Main control room air-conditioning b.
Standby switchgear and standby battery rooms ventilation and cooling c.
Safeguard equipment in the auxiliary building ventilation d.
Standby diesel generator rooms ventilation 5.
Containment and reactor vessel isolation control system (CRVICS) 6.
Standby lighting system 7.
Instrumentation and control for the RPS and ESF functions.
Loads connected to these Class 1E safety-related systems are listed in Table 8.3-1.
8.3.1.1.2.2 Nonsafety-Related Power Generation Systems These systems of the nuclear plant are those which are not essential for safe shutdown.
Electrical failure of these systems cannot result in the release or failure to minimize release of radioactive material.
These normal non-Class 1E ac systems are nonsafety-related and therefore nondivisional.
They are identified as being part of the black system or are not given color identification as described in Section 8.3.1.3.
These systems
: include, but are not necessarily limited to, the following:
1.
Main condensate system 2.
Reactor feedwater system 3.
Condensate makeup system


Preferred power is taken from two physically and electrically independent 230-kV lines originating in the onsite 230-kV substation. The 230-kV line terminating at transformer yard 1 energizes transformers 1RTX-XSR1E and 1RTX-XSR1C. The 230-kV line  
RBS USAR Revision 22 8.3-4
6
: 4.
Turbine plant component cooling water system
: 5.
Reactor plant component cooling water system
: 6.
Plant ventilation system
: 7.
Normal service water system
: 8.
Circulating water system
: 9.
Reactor water cleanup system
: 10.
Service water cooling system.
6
8.3.1.1.3 Power Supplies and Buses 8.3.1.1.3.1 Station Service Transformers
13 7 The normal ac power supply can provide electrical power for all station auxiliary loads when the main generator is operating. It consists of three normal station service transformers 1STX-XNS1A, 1STX-XNS1B and 1STX-XNS1C, electric power through STX-XNS1C is not used, energized by isolated phase bus duct from the generator terminals, as shown in Fig. 8.1-4.
13 6 4 The preferred ac power supply can provide for all station auxiliary loads.
This includes the maximum operational combination of full load power, startup power, hot standby maintenance power, shutdown power, and the safety-related loads.
Preferred power is taken from two physically and electrically independent 230-kV lines originating in the onsite 230-kV substation. The 230-kV line terminating at transformer yard 1 energizes transformers 1RTX-XSR1E and 1RTX-XSR1C. The 230-kV line terminating at the transformer yard 2A energizes transformers 1RTX-XSR1F and 1RTX-XSR1D. These preferred station service transformers have the following ratings:
7
: 1.
1RTX-XSR1E 230-13.8 KV, 51/68/85 MVA OA/FOA/FOA
: 2.
1RTX-XSR1F 230-13.8 kV, 51/68/85 MVA OA/FOA/FOA
: 3.
1RTX-XSR1C and 1RTX-XSR1D, 230-4.16 kV, 10/12.5 MVA, OA/FA 4 6


terminating at the transformer yard 2A energizes transformers 1RTX-XSR1F and 1RTX-XSR1D. These preferred station service  
RBS USAR Revision 7 8.3-4a January 1995 The secondaries of normal and preferred station service transformers are routed into the plant via cables run in reinforced concrete ductlines and cable trays within the plant to their associated medium voltage switchgear buses as subsequently described.
7*


transformers have the following ratings:
RBS USAR Revision 6 8.3-4b August 1993 THIS PAGE LEFT INTENTIONALLY BLANK
7  1. 1RTX-XSR1E  230-13.8 KV,    51/68/85 MVA OA/FOA/FOA
: 2. 1RTX-XSR1F 230-13.8 kV, 51/68/85 MVA OA/FOA/FOA
: 3. 1RTX-XSR1C and 1RTX-XSR1D, 230-4.16 kV, 10/12.5 MVA, OA/FA 4 6 RBSUSARRevision78.3-4aJanuary1995Thesecondariesofnormalandpreferredstationservicetransformersareroutedintotheplantviacablesrunin reinforcedconcreteductlinesandcabletrayswithintheplantto theirassociatedmediumvoltageswitchgearbusesassubsequently


described.
RBS USAR Revision 22 8.3-5 8.3.1.1.3.2 13.8-kV Systems (750-MVA Interrupting Capability)  
7 RBS USARRevision68.3-4bAugust1993THISPAGELEFTINTENTIONALLYBLANK RBS USAR Revision 22 8.3-5 8.3.1.1.3.2 13.8-kV Systems (750-MVA Interrupting Capability) 7 6 4 RBS has two independent 13.8-kV buses, 1NPS-SWG1A and 1NPS-SWG1B, supporting most of the station auxiliary motor and transformer loads. Each bus supports half the load and has a manually  
7 6 4 RBS has two independent 13.8-kV buses, 1NPS-SWG1A and 1NPS-SWG1B, supporting most of the station auxiliary motor and transformer loads. Each bus supports half the load and has a manually controlled air circuit breaker (ACB) for access to its normal source transformers, 1STX-SNX1A and 1STX-XNS1B respectively, and an automatically or manually controlled ACB for access to its preferred source transformers 1RTX-XSR1E and 1RTX-XSR1F, respectively. The 13.8-kV bus 1NPS-SWG1A takes preferred power from transformer 1RTX-XSR1E located at transformer yard 1, while 13.8-kV bus 1NPS-SWG1B takes preferred power from transformer 1RTX-XSR1F located at transformer yard 2A.
4 6 7
Opening the normal supply breaker initiates closing the preferred supply breaker, subject to the following restrictions which prevent the breaker from closing:
: 1.
Overcurrent or ground fault trip of the normal breaker
: 2.
Manual trip of the normal breaker
: 3.
Loss of voltage of the preferred supply
: 4.
Preferred supply breaker locked-out.
7 A fast automatic transfer scheme and a slow automatic transfer scheme are provided. Unit protective relays initiate opening the normal supply breaker. Time delay contacts from the unit protective relays will block fast transfer if the transfer does not take place within 10 cycles. Manually opening the main generator output breakers at Fancy Point and/or from the Main Control Room will also block a fast transfer. If the fast transfer is unsuccessful, all motor breakers and normal supply breakers are automatically tripped. The slow transfer scheme is then initiated and permitted only when residual voltage on the bus reaches 25 percent or less of the rated voltage.
Return to the normal supply after an automatic throwover can only be done manually. Normal and preferred supply breakers are paralleled for a short period of time during manual throwover.
During manual throwover, the plant operator closes the normal supply breaker and immediately opens the preferred supply breaker. Closing both breakers alarms after a short time delay in the main control room.
7


controlled air circuit breaker (ACB) for access to its normal  
RBS USAR Revision 20 8.3-6 Offsite power energizing standby 4.16-kV buses via the preferred station service transformers are not jeopardized during manual throwover.
Both the normal and preferred supply breakers to the normal 4.16-kV buses effectively isolate faults on the normal bus to protect the offsite sources of power to the standby 4.16-kV buses.
The 13.8-kV feeders from separate sources are routed to the following peripheral areas, as shown in Fig. 8.1-6:
1.
Cooling tower and water treatment areas - Four feeders, two on each 13.8-kV
: bus, are used to service the six double-ended normal 480-V load centers.
Feeder 1NPS-ACB06 from 13.8-kV bus 1NPS-SWG1A provides power to two 1,000/1,150-kVA transformers, 1NJS-X2E and 1NJS-X2G, at cooling towers 1B and 1D and one 500-kVA transformer, 1NJS-X3A, at the clarifier area.
The second feeder 1NPS-ACB05, from 13.8-kV bus 1NPS-SWG1A provides power to two 1,000/1,150-kVA transformers, 1NJS-X2A and 1NJS-
: X2C, at cooling towers 1A and 1C and one 750-kVA transformer 1NJS-X3C at the hypochlorite area.
Feeder 1NPS-ACB21 from 13.8-kV bus 1NPS-SWG1B provides power to two 1000/1150-kVA transformers, 1NJS-X2F and 1NJS-
: X2H, at cooling towers 1B and 1D and one 500-kVA transformer, 1NJS-X3B, at the clarifier area.
The second feeder 1NPS-ACB22 from 13.8-kV bus 1NPS-SWG1B provides power to two 1000/1150-kVA transformers, 1NJS-X2B and 1NJS-X2D, at cooling towers 1A and 1C and one 750-kVA transformer, 1NJS-X3D, at the hypochlorite area.
2.
Circulating water pump area - Two 13.8-kV feeders, one from each 13.8-kV bus, provide power to a 4.16-kV split bus.
Feeder 1NPS-ACB07, from 13.8-kV bus 1NPS-SWG1A, provides power to 10/12.5-MVA transformer 1STX-XS2A which is connected to 4.16-kV bus 1NNS-SWG2A.
Bus 1NNS-SWG2A supports two circulating water pumps and two service water pumps.
The second feeder 1NPS-ACB23, from 13.8-kV bus 1NPS-SWG1B, provides power to 10/12.5-MVA transformer 1STX-XS2B which is connected to 4.16-kV bus 1NNS-SWG2B.
Bus 1NNS-SWG2B supports two circulating water pumps and one service water pump.
3.
The 230-kV and 500-kV switchyards and the makeup water intake structure -
Two 13.8-kV
: feeders, one from each 13.8-kV
: bus, provide power to the 230-kV and 500-kV switchyards and the river edge makeup


source transformers, 1STX-SNX1A and 1STX-XNS1B respectively, and an automatically or manually controlled ACB for access to its preferred source transformers 1RTX-XSR1E and 1RTX-XSR1F, respectively. The 13.8-kV bus 1NPS-SWG1A takes preferred power from transformer 1RTX-XSR1E located at transformer yard 1, while 13.8-kV bus 1NPS-SWG1B takes preferred power from transformer  
RBS USAR Revision 25 8.3-7 pumps. Feeder 1NPS-ACB10, from 13.8-kV bus 1NPS-SWG1A, is run to disconnecting switch 1YWC-SW2 at the switchyard where it is connected to a
750-kVA transformer, and then run to 2.5/3.125-MVA transformer 1STX-XS3A feeding 4.16-kV bus 1NNS-SWG3A, and 500-kVA transformer 1STX-XS4A feeding 480-V motor control center 1NHS-MCC12A. The second feeder 1NPS-ACB26, from 13.8-kV bus 1NPS-SWG1B, is run to disconnecting switch 1YWC-SW1 at the switchyard where it is connected to a 750-kVA transformer, and then run to 2.5/3.125-MVA transformer 1STX-XS3B feeding 4.16-kV bus 1NNS-SWG3B, and 288.5-kVA transformer 1STX-XS4B feeding 480-V motor control center 1NHS-MCC12B.
1 6
: 4.
Service Water Cooling Area - Two 13.8-kV feeders one each from 1NPS-SWG1C and 1NPS-SWG1D provide power to a 4.16-kV split bus. Feeder 1NPS-ACB43 from 1NPS-SWG1C provides power to 7.5 MVA OA transformer 1STX-XS5A which is connected to 1NNS-SWG6A. Bus 1NNS-SWG6A supports two service water cooling pumps and feeder to 1NJS-X4A. The second feeder 1NPS-ACB44 provides power to 7.5 MVA transformer 1STX-XS5B which is connected to 4.16-kV bus 1NNS-SWG6B. Bus 1NNS-SWG6B supports one service water cooling pump and feeder to 1NJS-X4B.
6 8.3.1.1.3.3 4.16-kV Systems (250-MVA Interrupting Capability) 13 7 Each of the two normal in-station 4.16-kV buses NNS-SWG1A and NNS-SWG1B are fed from either the normal station service transformer STX-XNS1C, which has dual secondary windings, one connected to each bus or from their associated preferred station service transformers, RTX-XSR1C and RTX-XSR1D, respectively. The above transformers have been sized for all load conditions on buses NNS-SWG1A and NNS-SWG1B.
13 For buses NNS-SWG1A, NNS-SWG1B, and NNS-SWG1C the control logic is identical to that described for buses NPS-SWG1A and NPS-SWG1B, except as noted below for bus NNS-SWG1C and the fast transfer is blocked on the NNS-SWG1A/B bus feeding bus NNS-SWG1C and E22-S004 when HPCS pump, E22-PC001, or the Division III standby service water pump, SWP-P2C, is running. For bus NNS-SWG1C only, a manual transfer capability is provided. When a sustained undervoltage on the bus is sensed, all motor circuit breakers are tripped. No automatic transfer of NNS-SWG1C alone is provided, it will fast transfer with NNS-SWG1A or NNS-SWG1B from the normal service transformer to the preferred station service transformer unless blocked as described above.
7


1RTX-XSR1F located at transformer yard 2A.
RBS USAR Revision 13 8.3-7a September 2000
4 6 7 Opening the normal supply breaker initiates closing the preferred supply breaker, subject to the following restrictions which
*13 A 4.16-kV split bus and a 4.16-kV swing bus are energized from the normal 4.16-kV buses.
4.16-kV split buses 1NNS-SWG4A and 1NNS-SWG4B are connected to primary normal buses 1NNS-SWG1A and 1NNS-SWG1B, respectively.
4.16-kV swing bus 1NNS-SWG1C is connected to 1NNS-SWG1B via normally closed circuit breakers and to 1NNS-SWG1A via normally open circuit breakers.
13*
There are three standby 4.16-kV buses: 1ENS*SWG1A, 1ENS*SWG1B and 1E22*S004.
Buses 1ENS*SWG1A and 1ENS*SWG1B are energized from the preferred station service transformers 1RTX-XSR1C and 1RTX-XSR1D, respectively. Standby buses 1ENS*SWG1A and 1ENS*SWG1B also have manual


prevent the breaker from closing:
RBS USAR Revision 6 8.3-7b August 1993 THIS PAGE LEFT INTENTIONALLY BLANK
: 1. Overcurrent or ground fault trip of the normal breaker
: 2. Manual trip of the normal breaker
: 3. Loss of voltage of the preferred supply
: 4. Preferred supply breaker locked-out. 7 A fast automatic transfer scheme and a slow automatic transfer scheme are provided. Unit protective relays initiate opening the normal supply breaker. Time delay contacts from the unit protective relays will block fast transfer if the transfer does not take place within 10 cycles. Manually opening the main


generator output breakers at Fancy Point and/or from the Main Control Room will also block a fast transfer. If the fast
RBS USAR Revision 13 8.3-8 September 2000 access to normal primary buses 1NNS-SWG1B and 1NNS-SWG1A, respectively, if required during loss of preferred power. There is no automatic fast or slow transfer from the preferred transformers to the normal buses for either 1ENS*SWG1A or 1ENS*SWG1B.
The third standby 4.16-kV bus 1E22*S004 is energized from the normal 4.16-kV swing bus 1NNS-SWG1C.
7* *13 Each of these standby 4.16-kV buses has a standby 4.16-kV diesel generator capable of supporting its respective design load upon loss of preferred power.
The diesel generator 1EGS*EG1A supports standby 4.16-kV bus 1ENS*SWG1A and diesel generator 1EGS*EG1B supports standby 4.16-kV bus 1ENS*SWG1B.
The HPCS system diesel generator 1E22*S001G1C supports standby 4.16-kV bus 1E22*S004.
Each standby diesel generator is physically separated from the others and is located in the Seismic Category I diesel generator building. Failure of one diesel will not impede the operation of the other two diesel generators.
13*
Standby 4.16-kV bus 1ENS*SWG1A and normal 4.16-kV bus 1NNS-SWG1A may be fed from the preferred station service transformer 1RTX-XSRIC simultaneously.
If an undervoltage condition were to occur concurrently on both buses, a trip signal would be given to the normal supply breaker on 1NNS-SWG1A and to the motor feeder breakers on that bus.
If proper voltage is not available, a trip signal would be given to the preferred supply breaker on 1ENS*SWG1A and the standby diesel generator would start and would energize the standby 4.16-kV bus.
Division 2 equipment follows the same operation.
Reference 2 provides a
description of the standby bus transfers and tripping under loss of power conditions.
The standby 4.16-kV standby buses are electrically independent and physically isolated from one another.
Their loads are redundant as required and consist of standby motors and standby 480-V load centers.
An exception is the standby service water system.
The train A
pumps are powered by 1ENS*SWG1A and 1E22*S004 (one pump on each bus).
The train B pumps are both powered by 1ENS*SWG1B.
Dc control power for the standby 4.16-kV switchgear and for 1NNS-SWG1A, 1NNS-SWG1B, and 1NNS-SWG1C is supplied as shown in Table 8.3-8.
4.16-kV switchgear assemblies 1NNS-SWG2A and 1NNS-SWG2B at the circulating water pump area and 1NNS-SWG3A and 1NNS-SWG3B at the cooling tower makeup pump area and


transfer is unsuccessful, all motor breakers and normal supply breakers are automatically tripped. The slow transfer scheme is then initiated and permitted only when residual voltage on the  
RBS USAR Revision 6 8.3-9 August 1993
*6 1NNS-SWG4A and 1NNS-SWG4B at the radwaste building and 1NNS-SWG6A and 1NNS-SWG6B at the service water cooling switchgear building are of the split-bus design.
Under normal conditions the supply breaker on each bus is closed and the bus tie breaker is open.
No automatic closing of the tie breaker takes place after tripping either supply breaker.
Closing all breakers is by manual control.
When the supply breakers and bus tie breaker are to be closed to parallel two sources for a short period of time during throwover, closing of the last breaker is supervised by a synchronizing check relay.
Closure of the four tie breakers initiates an alarm.
6*
8.3.1.1.3.4 480-V Systems All normal load centers for nonsafety-related service are the split-bus design.
Two load center transformers of each load center are energized from normal 13.8-kV buses 1NPS-SWG1A and 1NPS-SWG1B.
In
: turn, load center transformers supply opposite sides of the split bus.
These buses can be connected by closing the tie breaker.
There is no automatic transfer between the two load center 480-V power sources.
No interlocks are provided to prevent paralleling of the two load center 480-V power sources.
Closing the two load center supply main breakers and the split-bus tie breaker is indicated in the main control room.
*6 1NJS-LDC4A and 1NJS-LDC4B 480 VAC load-centers are of the same split design as the other non-safety related load centers.
Service water cooling load-center transformers are energized from normal 4.16-kV buses 1NNS-SWG6A and 1NNS-SWG6B.
In
: turn, load center transformers supply opposite sides of the split bus.
These buses can be connected by closing the tie breaker.
There is no automatic transfer between the two load center 480-V power sources. No interlocks are provided to prevent paralleling of the two load center 480-V power sources.
Closing the two load center supply main breakers and the split-bus tie breaker is indicated in the main control room.
6*
The standby 480-V load centers are single-ended and have circuit breakers with an interrupting capability of not less than 30,000 amp symmetrical.
These standby load centers are fed from the standby 4.16-kV buses.
Standby 4.16-kV bus 1ENS*SWG1A provides power for standby 480-V load centers 1EJS*LDC1A and 1EJS*LDC2A.
Standby 4.16-kV bus 1ENS*SWG1B provides power for standby 480-V load centers 1EJS*LDC1B and 1EJS*LDC2B.
DC control power is supplied as shown in Table 8.3-8.
Standby 480-V load center loads are redundant


bus reaches 25 percent or less of the rated voltage.  
RBS USAR Revision 6 8.3-9a August 1993 and include standby motors and standby motor control centers.
There are several normal loads connected to the standby load centers identified in Table 8.3-7 and which are tripped off the bus during a
LOCA.
The standby 480-V load centers of Division I are electrically independent from those of Division II and are physically isolated from one another.
Molded case circuit breakers of both normal and standby motor control centers have an interrupting capability of 25,000 amp symmetrical.
Standby motor control centers of Division I are electrically independent and physically isolated from those of Division II.
Normal loads connected to the standby motor control centers and which are tripped off the bus during LOCA are identified in Table 8.3-7.


Return to the normal supply after an automatic throwover can only be done manually. Normal and preferred supply breakers are paralleled for a short period of time during manual throwover. 
RBS USAR Revision 6 8.3-9b August 1993 THIS PAGE LEFT INTENTIONALLY BLANK


During manual throwover, the plant operator closes the normal supply breaker and immediately opens the preferred supply breaker. Closing both breakers alarms after a short time delay
RBS USAR Revision 16 8.3-10 March 2003 8.3.1.1.3.5 Low Voltage Systems The instrumentation and control supply system consists of a 125-V dc system (Fig. 8.3-6), 120-V ac safety-related uninterruptible power supply systems (Fig. 8.3-2),
120-V ac normal uninterruptible power supply systems (Fig. 8.3-1), and 120-V ac regulated power supplies. The 125-V dc systems provide dc power for dc
: loads, uninterruptible power
: supplies, backup instrumentation and control, and are described in Section 8.3.2.
The 120-V ac uninterruptible power supplies provide ac power for security, control, and instrumentation systems for the nonsafety-related and engineered safeguard systems (Section 8.3.1.1.3.7).
The 120-V ac regulated power supplies provide ac power for instrumentation, security, and communication systems for the nonsafety-related and engineered safeguard systems.
The instrumentation and status indications of Class 1E switchgear aforementioned are described in Section 7.
8.3.1.1.3.6 Standby Electrical Power Systems The standby electrical power systems are designed to provide redundant sources of onsite ac electric power which are self-contained within the unit and which are not dependent on the normal and preferred sources of supply. The standby electrical power systems are capable of supplying ac power for electrical loads which are required for a safe shutdown of the reactor.
16 The standby system ac distribution buses are rated at 4.16-kV and 480-V. There are three standby 4.16-kV ac buses and four standby 480-V ac load centers. The bus configuration (Fig. 8.1-6) is described in Sections 8.3.1.1.3.3 and 8.3.1.1.3.4. Upon loss of voltage on associated standby 4.16-kV buses, or a LOCA signal initiated by an abnormally low water level in the reactor vessel or a high drywell pressure, or a manual start signal, the generators are started and brought up to rated frequency and voltage. If, at this time, the two redundant supply power lines to the buses are
: open, the standby generator breakers automatically close on their associated dead buses. The diesel generators are not automatically connected to their respective standby 4.16-kV buses if the buses are still connected to either the preferred or normal station service transformers.
16
Unit 1 reactor has three diesel generators: 1EGS*EG1A, 1EGS*EG1B, and 1E22*S001G1C. Diesels 1EGS*EG1A and 1EGS*EG1B are devoted to safety-related equipment as shown


in the main control room.
RBS USAR Revision 12 8.3-11 December 1999 in Fig. 8.1-6. Diesel 1E22*S001G1C energizes the HPCS system as described in Section 8.3.1.1.3.6.2.
7 RBS USAR Revision 20                  8.3-6Offsitepowerenergizingstandby4.16-kVbusesviathepreferredstationservicetransformersarenotjeopardizedduringmanual throwover.Boththenormalandpreferredsupplybreakerstothe normal4.16-kVbuseseffectivelyisolatefaultsonthenormalbus toprotecttheoffsitesourcesofpowertothestandby4.16-kV
8.3.1.1.3.6.1 Standby Diesel Generators 8.3.1.1.3.6.1.1 Description Each standby diesel generator is physically independent, located in a building structure designed to withstand earthquakes and to protect the standby diesel generators against tornadoes, floods, hurricanes, and tornado-generated missiles (Section 3.8). Within the protected structure, each standby diesel generator, including its associated starting equipment and other auxiliaries, is installed in a separate room of a Seismic Category I building so that an incident at one generator will not physically or electrically involve the others. Each standby diesel generator is provided with a separate missile-protected combustion air intake, room air intake and discharge, and diesel engine exhaust opening.
Seismic qualification of the standby diesel generators and associated equipment is discussed in Sections 3.9.2.2A and 3.10A.
In addition, the standby diesel generators can provide full rated load when subjected to extreme atmospheric conditions, e.g., due to a hurricane or tornado. The probability of a tornado striking a
point on the site is
: low, about once in 3,415 yrs (Section 2.3.1.2.4).
Each standby diesel generator is provided with an independent fuel oil system consisting of a day tank with fuel capacity for 1-hr minimum operation at required load, and one 100 percent capacity Class 1E fuel oil transfer pump for automatically filling the day tank from its respective storage tank. One fuel oil storage tank for each standby diesel generator supplies fuel for continuous operation at its rated capacity for 7 days (Section 9.5.4).
12 Each standby diesel generator unit is provided with two independent and redundant air starting systems with separately powered air compressors to furnish air for automatic and manual starting and for control air. The starting systems for each standby diesel generator includes electrically driven compressors, primary air tanks, reserve air tanks, and necessary gears and valves for cranking the engine. The two starting systems (the HPCS diesel's air compressors are described in Section 8.3.1.1.3.6.2) are arranged so that failure of one will not jeopardize proper operation of the other. Each train of the starting system is capable of at least eight cranking cycles without the assistance of 12


buses.
RBS USAR Revision 16 8.3-12 March 2003
The13.8-kVfeedersfromseparatesourcesareroutedtothe followingperipheralareas,asshowninFig.8.1-6:1.Coolingtowerandwatertreatmentareas-Fourfeeders,twooneach13.8-kVbus,areusedtoservicethesix double-endednormal480-Vloadcenters.Feeder1NPS-ACB06from13.8-kVbus1NPS-SWG1Aprovidespowertotwo 1,000/1,150-kVAtransformers,1NJS-X2Eand1NJS-X2G,at coolingtowers1Band1Dandone500-kVAtransformer, 1NJS-X3A,attheclarifierarea.Thesecondfeeder 1NPS-ACB05,from13.8-kVbus1NPS-SWG1Aprovidespower totwo1,000/1,150-kVAtransformers,1NJS-X2Aand1NJS-X2C,atcoolingtowers1Aand1Candone750-kVA transformer1NJS-X3Catthehypochloritearea.Feeder 1NPS-ACB21from13.8-kVbus1NPS-SWG1Bprovidespower totwo1000/1150-kVAtransformers,1NJS-X2Fand1NJS-X2H,atcoolingtowers1Band1Dandone500-kVA transformer,1NJS-X3B,attheclarifierarea.The secondfeeder1NPS-ACB22from13.8-kVbus1NPS-SWG1B providespowertotwo1000/1150-kVAtransformers,1NJS-X2Band1NJS-X2D,atcoolingtowers1Aand1Candone 750-kVAtransformer,1NJS-X3D,atthehypochlorite
16 outside power. The time required by each air compressor to recharge its tank from minimum starting air pressure to operating air pressure is approximately 30 minutes. Each standby diesel engine is provided with cooling by means of a shell and tube heat exchanger cooled by water from the SSW system. Each generator is a self-cooled air-ventilated unit. All necessary auxiliaries directly associated with each standby diesel-generator unit, such as ventilating fans, battery chargers, fuel oil transfer pump, etc, are powered from their associated standby buses. Electrical power for starting and control is supplied from the 125-V dc system associated with that generator.
16
11 The standby diesels for 1EGS*EG1A and 1EGS*EG1B are Transamerica Delaval, Inc. type DSR 48 and provide 4869 bhp in continuous duty. However, special requirements are imposed by the Facility Operating License for continuous operation of these two standby diesels above 4197 bhp (3130 KW). The synchronous generators were manufactured by Parsons Peebles Electric Products, Inc.
11
The rating of each standby diesel generator is determined from plant design and power requirements and has the capability to ensure proper starting and operation of all required motor loads without excessive frequency or voltage drop. The rating of each of the standby diesel generators is adequate for the maximum required coincident loads during the unit design basis accident (DBA) in accordance with Regulatory Guide 1.9, except for the HPCS diesel. The philosophy applicable to the sizing of the HPCS diesel is defined in Section 8.3.1.1.3.6.2.
The nameplate ratings of the standby diesel generator sets are as follows:
Standby Standby Diesel Generator Diesel Generator Time 1EGS*EG1A 1EGS*EG1B (hr) 3,500 kW 3,500 kW 8,760 3,850 kW 3,850 kW 2
The 8,760-hr rating is on continuous duty under normal maintenance.
The standby diesel generators are specified to provide their rated output for combustion air temperatures ranging from 2°F to 110°F.
No derating is required for ambient atmospheric pressures down to 20.58 inches Hg - absolute (10.1 psia).
Humidity


area.2.Circulatingwaterpumparea-Two13.8-kVfeeders,onefromeach13.8-kVbus,providepowertoa4.16-kVsplit bus.Feeder1NPS-ACB07,from13.8-kVbus1NPS-SWG1A, providespowerto10/12.5-MVAtransformer1STX-XS2A whichisconnectedto4.16-kVbus1NNS-SWG2A.Bus 1NNS-SWG2Asupportstwocirculatingwaterpumpsandtwo servicewaterpumps.Thesecondfeeder1NPS-ACB23, from13.8-kVbus1NPS-SWG1B,providespowerto1 0/1 2.5-MVAtransformer1STX-XS2Bwhichisconnectedto4.16-kV bus1NNS-SWG2B.Bus1NNS-SWG2Bsupportstwo circulatingwaterpumpsandoneservicewaterpump.3.The230-kVand500-kVswitchyardsandthemakeupwaterintakestructure-Two13.8-kVfeeders,onefromeach 13.8-kVbus,providepowertothe230-kVand500-kV switchyardsandtheriveredgemakeup RBS USAR Revision 25 8.3-7 pumps. Feeder 1NPS-ACB10, from 13.8-kV bus 1NPS-SWG1A, is run to disconnecting switch 1YWC-SW2 at the switchyard where it is connected to a 750-kVA
RBS USAR Revision 16 8.3-13 March 2003 extremes are not expected to affect the operation of the standby diesel generators since the intake air is compressed and heated in the turbochargers prior to entering the engines.  
16 8 The standby generator and the 4.16-kV preferred station service system are manually synchronized during periodic testing or upon restoration of preferred power. A synchronous check relay is provided to prevent breaker closure during synchronizing operations unless the busses are synchronized within the tolerances of the relay. A synchronous check relay is provided to prevent breaker closure during synchronizing operations unless the busses are synchronized within the tolerances of the relay.
If any safety-related switching equipment fails to operate automatically, manual operation is possible, remotely in the main control room or at the standby diesel generator control room.
Except for sensors and other equipment that must be directly mounted on the engine or associated piping, the controls and monitoring instrumentation are installed on free-standing floor-mounted panels located in a vibration-free floor area.
8 16
8.3.1.1.3.6.1.2 Starting and Loading
13 The standby diesel generator sets are designed for independent operation, but they may be operated in parallel with the plant auxiliary system for exercising and test purposes. Standby buses 1ENS*SWG1A and 1ENS*SWG1B are normally continuously energized from the preferred station service transformers. Standby bus 1E22*S004 is also normally continuously energized from the preferred station service system. The standby diesel generators are started upon receipt of an undervoltage signal from the standby bus source, upon receipt of a LOCA signal or on manual signal. The automatic transfer of each standby bus to its standby generator is done only on loss of voltage measured on the standby 4.16-kV bus. Transfer is accomplished by opening both the normal and preferred station service transformer supply circuit breakers and closing the standby generator's circuit breaker when the generator is at proper voltage and frequency.
13
Low voltage on a standby bus automatically disconnects all 4.16-kV motor loads on the bus. Sequencing of loads supplied from the standby diesel generators is required to prevent exceeding the motor starting and load pickup capability of the standby diesel generator. Provisions are made for automatic sequencing of all loads in accordance with Table 8.3-2. Other loads may be connected by the station operators (by manually controlled breakers) when load conditions permit. There is no automatic load shedding of the standby 4.16-kV buses when power is furnished by the standby diesel generator.


transformer, and then run to 2.5/3.125-MVA transformer 1STX-XS3A feeding 4.16-kV bus 1NNS-SWG3A, and 500-kVA
RBS USAR Revision 22 8.3-14 The load sequencing control for the onsite and offsite power sources for River Bend Station utilizes individual timers and permissive circuitry for individual feeder breakers being sequenced on standby buses. Although there is a logic which ties the operation of the entire load sequencing scheme together, failure of one or more breaker timers or permissive circuits to operate does not prevent other breaker timers and permissives from performing their intended functions. Timers and permissives are located in qualified switchgear and relay panel enclosures for the breakers they control. There are no credible sneak circuits or common failure modes in the sequencing design that could render either the onsite or offsite power sources unavailable.
An emergency demand start signal overrides all other operating modes including test and returns control of the diesel-generator unit to the automatic load sequencing system.
The standby diesel generator incorporates two modes of control, OPERATIONAL and MAINTENANCE.
: a.
In the OPERATIONAL mode the diesel starts and comes up to speed when either of the following conditions is present:
: 1)
A MANUAL START SIGNAL generated from the local control panel and the units entire protective system is reset.
A Manual Start Signal, starts the diesel generator in the slow start mode of operation. This slow start, which is recommended by the manufacturer, extends the starting time of the diesel to minimize the aging effects associated with fast starts.
16
: 2)
An EMERGENCY START SIGNAL generated by either a LOCA signal or a sustained bus undervoltage or by depressing emergency START push button in the main control room or by pressing the emergency start button on the control panel.
The emergency start overrides all conditions and returns the unit to rated speed. (Refer to Section 3.1.1.4.1) Emergency start overrides all conditions such as:

Slow Start

Manual Running

Test

Tripping on fault conditions except for the following:
: 1. Overspeed
: 2. Generator Differential
: 3. Lube and Jacket Water high temperature trips unless the emergency start comes from a LOCA signal or the trips are bypassed by a local control switch (Applicable to EGS-EG1A and EGS-EG1B ONLY).
16
: b.
In the MAINTENANCE mode only the engine ROLL pushbutton on the local panel is operative. This feature permits cranking the diesel without effecting a start.
: c.
The standby diesel generators may be tested while in the operational mode by manually starting the engines and manually closing the circuit breakers connecting


transformer 1STX-XS4A feeding 480-V motor control center 1NHS-MCC12A. The second feeder 1NPS-ACB26, from 13.8-kV bus 1NPS-SWG1B, is run to disconnecting switch 1YWC-SW1 at the switchyard where it is connected to a 750-kVA transformer, and then run to  
RBS USAR Revision 16 8.3-15 March 2003 the standby diesel generators to the bus. In this manner, the standby diesel generators can be tested under load while in parallel with the grid.
Should the grid go to an undervoltage or underfrequency condition, the circuit breakers in the Fancy Point Substation trip and deenergize the circuit feeding the preferred station service transformers. The pilot wire system also initiates a trip of the 4.16-kV circuit breaker between the preferred station service transformer and the bus. With the preferred or alternate supply breakers in the open position, the generator setting would switch from the parallel operation mode to the isochronous mode, and the standby diesel generator picks up the entire load of the standby 4.16-kV bus sequentially.
The standby diesel generators are capable of running unloaded for 7 days without degrading the performance or reliability of the engine. The manufacturer has demonstrated this capability with a special no load endurance test.
8.3.1.1.3.6.2 High Pressure Core Spray Power Supply System 8.3.1.1.3.6.2.1 Description Fig. 8.3-3 shows the HPCS power system (Division III) simplified one-line diagram electrical arrangement, power distribution, protective relaying, and instrumentation for the HPCS power system.
The HPCS power supply system is self-contained except for the initiation signal source and access to the preferred source of offsite power through the plant ac power distribution system. It has a dedicated diesel generator, 1E22*S001G1C and is operable as an isolated system independent of electrical connection to any other system.
16 The HPCS diesel 1E22*S001G1C is a Stewart and Stevenson EMD 20645-E4, 20-cylinder vee type. It provides 3600 bhp in continuous duty. The synchronous generator was manufactured by Ideal. This SM-100 model has a 2,000-hr rating of 2850 kW.
16
Seismic qualification of the HPCS diesel generator and associated equipment is discussed in Section 3.9.2.2B and 3.10B. In addition, the HPCS diesel generator can provide full-rated load when subjected to extreme atmospheric conditions. No derating is required for operation in


2.5/3.125-MVA transformer 1STX-XS3B feeding 4.16-kV bus  
RBS USAR Revision 8 8.3-16 August 1996 ambient temperatures up to 120°F, a
relative humidity of 90 percent, and an atmospheric pressure down to 28.25 inches Hg.
Low combustion air temperatures do not affect the operability of the HPCS diesel generator since the intake air is compressed and heated in the turbocharger prior to entering the engine.
*8 *4 The standby auxiliary equipment such as heaters and battery charger are supplied from the same power source as the HPCS motor.
The non-safety related HPCS DG air compressors are supplied from non-safety related power sources.
8* 4*
Voltage and frequency of the HPCS diesel generator is compatible with that available from the plant ac power system.
*8 The HPCS diesel generator has the capability to restore power quickly to the HPCS bus in the event offsite power is unavailable and to provide all required power for the startup and operation of the HPCS
: system, one standby service water pump
: motor, and miscellaneous auxiliaries associated with it.
The HPCS diesel generator starts automatically on a
LOCA signal from the plant protection system or undervoltage on the HPCS 4.16-kV bus (1E22*S004), and will be automatically connected to the HPCS bus when the plant preferred ac power supply is not available.
The failure of this unit will not negate the capability of other power sources.
There is no provision for automatic paralleling of the HPCS diesel generator with the auxiliary power or with standby power sources.
Provisions for manual paralleling with normal power sources are made for loading the diesel generator during the exercise mode.
A synchronous check relay is provided to prevent breaker closure during paralleling unless the busses are synchornized within the tolerances of the relay.
If a LOCA signal occurs while the HPCS diesel generator is running in parallel with the normal bus, the diesel generator breaker will automatically trip.
At least one interlock is provided to avoid accidental paralleling.
There is no sharing of the HPCS power system with other standby diesel generators.
*8 The HPCS power system loads consist of the HPCS pump/motor and associated auxiliaries, motor-operated
: valves, one standby service water
: pump, and miscellaneous auxiliary loads.
Table 8.3-3 shows the Division III loads.
The HPCS pump motor is a General Electric 4-kV vertical induction motor rated at 2500 hp.
The vertical pump was manufactured by the Borg-Warner Byron-Jackson Pump Division.
It is rated at 5,125 gpm with 945 ft of head and its motor has a
maximum shaft bhp of 2,500 at 1,780 rpm.
The HPCS electric system is capable of performing its function when subjected to the effects of design bases


1NNS-SWG3B, and 288.5-kVA transformer 1STX-XS4B feeding 480-V motor control center 1NHS-MCC12B.
RBS USAR Revision 8 8.3-17 August 1996 natural phenomena.
1  6 4. Service Water Cooling Area - Two 13.8-kV feeders one each from 1NPS-SWG1C and 1NPS-SWG1D provide power to a 4.16-kV split bus. Feeder 1NPS-ACB43 from 1NPS-SWG1C provides power to 7.5 MVA OA transformer 1STX-XS5A which is connected to 1NNS-SWG6A. Bus 1NNS-SWG6A supports two service water cooling pumps and feeder to 1NJS-X4A. The second feeder 1NPS-ACB44 provides power to 7.5 MVA transformer 1STX-XS5B which is connected to 4.16-kV bus 1NNS-SWG6B. Bus 1NNS-SWG6B supports one
It is designed in accordance with Seismic Category I and housed in a Seismic Category I structure.
The detailed description of the fuel oil storage and transfer system associated with the HPCS diesel generator unit is described in Section 9.5.4.
Fuel for the HPCS diesel engine is provided in a separate day tank and in a storage tank.
The day tank permits a minimum of 1 hr of operation at rated load.
The combined capacity of the day tank and the storage tank permits the HPCS diesel engine to operate at continuous rated load conditions for at least 7 days.
*8 The engine air starting system contains two complete sets of starting components, either of which is capable of starting the engine.
: However, to further ensure starting within the time requirements, both sets are utilized simultaneously to crank the engine.
Each set of components consists of dual air start motors, air relay valve, solenoid valve, air receivers, and air compressor assembly.
Both compressors are capable of automatic start and stop and are controlled by pressure switches to maintain required pressure in the air receivers.
The two air starting systems are redundant, independent, and arranged so that failure to start in one system will not jeopardize starting of the diesel generator by the other system.
8*
Manual controls are provided to permit the operator to select the most suitable distribution path from the power supply to the load.
An automatic start signal overrides the exercise mode.
Provisions are made for control from the main control room and external to the main control room from an HPCS diesel generator control panel located external to the main control room in the diesel generator building as shown in Figure 8.3-11.
The control panel includes facilities for breaker control of incoming feeder and HPCS generator breaker together with frequency
: meter, synchroscope,
: bus, and incoming voltmeters and engine speed control device.
Except for sensors and other equipment that must be directly mounted on the engine or associated
: piping, the controls and monitoring instrumentation are installed on free-standing floor-mounted panels located in a vibration-free floor area.
Control power for the HPCS diesel generator unit is supplied from its own 125-V battery
: system, which consists of a


service water cooling pump and feeder to 1NJS-X4B.
RBS USAR Revision 21 8.3-18 battery with its own battery charger. The charger is designed to carry the continuous load in addition to normal battery charging current. Section 8.3.2.2 provides a discussion of the HPCS 125-V dc system. Tables 8.3-3 and 8.3-6 show the HPCS diesel generator size and the 125-V dc load requirements.
6 8.3.1.1.3.3 4.16-kV Systems (250-MVA Interrupting Capability)  13  7 Each of the two normal in-station 4.16-kV buses NNS-SWG1A and NNS-SWG1B are fed from either the normal station service transformer STX-XNS1C, which has dual secondary windings, one connected to each bus or from their associated preferred station service transformers, RTX-XSR1C and RTX-XSR1D, respectively. The above transformers have been sized for all load conditions on
8.3.1.1.3.6.2.2 Starting and Loading A loss of normal potential at the HPCS bus is one of the three initiating signals which automatically starts the HPCS diesel generator. The other two signals are accident signals of reactor low water level and high drywell pressure which are described in detail in Section 7.3.1. On receipt of a start signal or HPCS supply bus undervoltage, the HPCS diesel generator will start and accelerate to operating voltage and frequency as standby power supply for the HPCS system. On reaching rated speed and voltage, the generator is automatically connected to the HPCS bus if ac power is not available at the bus. Once the diesel generator has been energized, the unit will continue to operate until manually deenergized or until the protective devices of the HPCS diesel generator cause a trip.
The HPCS diesel generator is capable of running unloaded for 4.5 hours without degrading the performance or reliability of the engine, after which, it must be run at a minimum of 40 percent of nameplate rating for 30 minutes.
The HPCS diesel generator has the capacity to start all motors as required by the design basis so that the main pump is at rated speed and all required valve operations are completed within the time requirements described in Sections 6.3 and 9.2.7. All HPCS loads associated with the DBA are started concurrently, except the DG room vent fan, the standby service water pump, and its associated motor-operated valve 1SWP*MOV40C, which are sequenced to start as noted in Table 8.3-3.
An emergency demand start signal overrides all other operating modes including tests and then returns control to the sequencing system. Refer to Section 5 of NEDO 10905 for a description of control and protection of the HPCS diesel generator.
8.3.1.1.3.7 120-Volt AC Uninterruptible Power Supply System The 120-V ac uninterruptible power supply system supplies control power to vital computer and instrumentation loads for which power interruption must be avoided.
These


buses NNS-SWG1A and NNS-SWG1B.
RBS USAR Revision 20 8.3-19 services are necessary for the normal operation of the plant.
13 For buses NNS-SWG1A, NNS-SWG1B, and NNS-SWG1C the control logic is identical to that described for buses NPS-SWG1A and NPS-SWG1B, except as noted below for bus NNS-SWG1C and the fast transfer is blocked on the NNS-SWG1A/B bus feeding bus NNS-SWG1C and E22-S004 when HPCS pump, E22-PC001, or the Division III standby service
Power from the uninterruptible power supplies is free from extraneous voltage spikes, switching surges, and momentary interruptions, and satisfies the voltage and frequency variation limits of the station computers and instrumentation systems. A high degree of power continuity is provided, with the uninterruptible power supply being able to switch automatically between two independent sources of input power, or to transfer to an independent alternate source of regulated ac power with sufficient speed so the operation of the computer and instrumentation is not affected.
x o13 Normally the uninterruptible power supply inverter (Figure 8.3-1 and 8.3-2) receives dc power from a 480-V ac motor control center (MCC) feeding an ac-to-dc rectifier, with a second source of dc power coming from the 125-V dc station battery. Any failure of the MCC feeding the rectifier results in the station battery carrying the uninterruptible power supply load without interruption. Malfunctions of both of the two dc sources of power to the inverter or the inverter itself causes the static switch to automatically transfer the power source to an independent alternate source fed from a 480-V ac MCC feeder through a voltage regulating transformer in all uninterruptible power supplies.
1BYS-INV06 furnishes power to DRMS, ERIS, and other support service loads. A make-before-break manual bypass switch enables maintenance, inspection, and testing of the uninterruptible power supply components to be safely performed while feeding the loads from the alternate source voltage regulating transformer.
13mx x o15 x o1 There are a total of eleven uninterruptible power supply systems in the plant. ENB-INV01A and ENB-INV01A1 are associated with Division I, ENB-INV01B and ENB-INV01B1 are associated with Division II and the remainder (BYS-INV01A, BYS-INV01B, BYS-INV02, BYS-INV04, BYS-INV06, and IHS-INV01) are connected to normal buses. BYS-INV03 is a nonsafety-related swing inverter which supplies 120 VAC power to distribution panel. Through switches near the local inverter, BYS-INV03 may be utilized to supply backup power to the loads of BYS-INV01A or BYS-INV01B.
Either ENB-INV01A (01B) or ENB-INV01A1 (01B1)
(but not both simultaneously) may be selected to supply power to VBS-PNL01A (01B) through the use of manual transfer switch VBS-TRS02A (02B). Either unit may be in-service at any given time, with the other unit de-energized and available as a backup. Upon failure of the in-service UPS, the backup unit is energized and placed in service via operation of VBS-TRS02A (02B). This allows a rapid method of in service via operation of VBS-TRS02B. This allows a rapid method of restoring power to the Division I (II) 120 Volt AC Vital Bus in the event of a failure of the in-service UPS. The ac sources for the uninterruptible power supplies associated with the standby systems are derived from the standby diesel generators feeding buses 1ENS*SWG1A and 1ENS*SWG1B.
All uninterruptible power supplies and their associated distribution panels are completely independent (by division). Those panels associated with standby systems serve redundant safety-related equipment. The distribution 1mx 15mx


water pump, SWP-P2C, is running. For bus NNS-SWG1C only, a manual transfer capability is provided. When a sustained
RBS USAR Revision 8 8.3-20 August 1996 panels contain fused disconnect switches for branch circuit protection.
Manual or automatic devices for switching to interconnect the redundant safety-related uninterruptible power supplies are not provided.
8.3.1.1.3.8 Reactor Protection System (RPS) Power System 8.3.1.1.3.8.1 General The RPS power system is designed to provide power to the logic system that is part of the reactor protection system. It prevents auxiliary power system switching transients from causing an inadvertent reactor scram due to a transient disturbance of power to the reactor scram logic.
The principal elements of the RPS power system include two high
: inertia, alternating
: current, motor generator sets and distribution equipment.
Each motor generator set supplies power for the nuclear steam supply shutoff
: system, neutron monitoring
: system, parts of process radiation monitoring system, and reactor protection trip system.
The RPS power is classified as nonessential because failure of the power supply causes a reactor scram and isolation.
: However, the power feeds to redundant logics are physically separated by running in separate conduits.
RPS safety-related signal cables, power cables, and raceways are identified by nameplates and/or color codes to distinguish from nonsafety-related equipment and to distinguish between redundant, safety-related equipment.
RPS safety-related instrument panels are identified by color coded nameplates to distinguish from nonsafety-related equipment and to distinguish among redundant, safety-related equipment.
RBS provides protection of RPS buses A
and B
from voltage and frequency anomalies which could damage RPS components and thus preclude improper operation of the RPS.
The protection is afforded by the use of electrical protection assemblies (EPAs) which are Class 1E.
The EPAs provide redundant protection to the buses by acting to disconnect the buses from the power sources not within design specifications.
*8 The EPA (Figure 7.2-1) consists of a circuit breaker with a trip coil controlled by three individual solid state relays which sense line voltage and frequency and trip the breaker open on
*8


undervoltage on the bus is sensed, all motor circuit breakers are tripped. No automatic transfer of NNS-SWG1C alone is provided, it will fast transfer with NNS-SWG1A or NNS-SWG1B from the normal service transformer to the preferred station service transformer
RBS USAR Revision 25 8.3-21 the conditions of overvoltage, undervoltage, and under-frequency.
Provision is made for setpoint verification, calibration, and adjustment under administrative control. After tripping, the circuit breaker must be reset manually. Trip setpoints are based on providing 115-V ac, 60-Hz power at the RPS logic cabinets.
The protective circuit functional range is `10 percent of nominal ac voltage and -5 percent of nominal frequency.
The four EPA enclosures for each RPS bus are mounted on a Seismic Category I structure separately from the motor generator sets and separate from the four EPAs of the other RPS bus. Two EPAs are installed in series between each of the two RPS motor-generator sets and the RPS buses and between the auxiliary power sources and RPS buses. Figure 7.2-1 provides an overview of the eight EPA units and their connections between the power sources and the RPS buses. The EPA is designed as a Class 1E electrical component.
It is designed and fabricated to meet the quality assurance requirements of 10CFR50 Appendix B.
8.3.1.1.3.8.2 Components Each of these high inertia motor generator sets has a voltage regulator which is designed to respond to a step load change of 50 percent of rated load with an output voltage change of not more than 15 percent. High inertia is provided by a flywheel.
The inertia is sufficient to maintain the voltage and frequency of generated voltage within 5 percent of the rated values for a minimum of 1 sec following a total loss of power to the drive motor.
8.3.1.1.3.8.3 Sources The power to each of the RPS buses is supplied from two 120-V ac sources. The primary source of power is the motor generator sets. The alternate source of 120-V ac power is Class 1E and redundant, and consists of a
480-120-V voltage-regulating transformer. The two motor generator sets are supplied from separate 480-V motor control centers normally energized from the normal station service transformers, and which also are connectable to the preferred station service transformers via the non-Class 1E distribution system. Indicating lights are provided in the main control room to monitor the status of both the motor generator sets and the instrument buses.


unless blocked as described above.
RBS USAR Revision 25 8.3-22 8.3.1.1.3.8.4 Operating Configuration During operation, the reactor protection system buses are energized by their respective motor generator sets. Either motor generator set can be taken out of service by manually operating the power source selector switch which disconnects the motor generator set and connects the respective RPS bus to its alternate power source. Only one RPS bus may be placed on alternate power when in Modes 1 OR 2 except for limited emergent plant situations which require both RPS buses to be connected to their alternate supplies for short periods. Alignment of both RPS buses to their alternate supplies is not the normal line up because of increased vulnerability to grid perturbations that could result in inadvertent trip of both divisions of RPS connected loads. Short periods are not to exceed the time required to correct the limited emergent plant situation(s) to restore at least one RPS bus to normal power supply. A loss of power to either motor generator set is monitored in the main control room (white indicating lamp goes off) where the operator, on detecting such a condition, can switch over to the alternate power source. A loss of power to one motor generator set results in a single RPS trip system trip. A persistent loss of electrical power to both motor generator sets (1 sec minimum) results in a scram.
7 RBS USARRevision138.3-7aSeptember200013A4.16-kVsplitbusanda4.16-kVswingbusareenergizedfrom thenormal4.16-kVbuses.4.16-kVsplitbuses1NNS-SWG4Aand 1NNS-SWG4Bareconnectedtoprimarynormalbuses1NNS-SWG1Aand 1NNS-SWG1B,respectively.4.16-kVswingbus1NNS-SWG1Cis connectedto1NNS-SWG1Bvianormallyclosedcircuitbreakersand to1NNS-SWG1Avianormallyopencircuitbreakers.
8.3.1.1.3.9 Adequacy of Electrical Distribution System Voltages 16 Two completely separate schemes of undervoltage protection are provided on the Division I and II Class 1E buses at the 4.16-kV level. The selection of undervoltage and time delay setpoints has been determined from an analysis of the voltage requirements of the Class 1E loads. These setpoints are verified during surveillance testing.
13Therearethreestandby4.16-kVbuses:1ENS*SWG1A,1ENS*SWG1Band 1E22*S004.Buses1ENS*SWG1Aand1ENS*SWG1Bareenergizedfrom thepreferredstationservicetransformers1RTX-XSR1Cand1RTX-XSR1D,respectively.Standbybuses1ENS*SWG1Aand1ENS*SWG1Balso
16 The first undervoltage scheme detects loss of power at the Class 1E buses. This undervoltage setpoint is set below any anticipated transient voltage condition, with a time delay of approximately 3 seconds.
The second level of undervoltage protection is set at approximately 90 percent and utilizes two separate time delays based on the following conditions:
1.
The first time delay is approximately 5 sec, which establishes a sustained degraded voltage condition (i.e.,
something longer than a
motor starting transient). Following this delay, an alarm in the main control room alerts the operator to the degraded condition. The subsequent occurrence of a LOCA signal immediately separates the Class 1E distribution system


have manual RBS USARRevision68.3-7bAugust1993THISPAGELEFTINTENTIONALLYBLANK RBSUSARRevision138.3-8September2000accesstonormalprimarybuses1NNS-SWG1Band1NNS-SWG1A,respectively,ifrequiredduringlossofpreferredpower.There isnoautomaticfastorslowtransferfromthepreferred transformerstothenormalbusesforeither1ENS*SWG1Aor 1ENS*SWG1B.Thethirdstandby4.16-kVbus1E22*S004isenergized fromthenormal4.16-kVswingbus1NNS-SWG1C.
RBS USAR Revision 25 8.3-22a from the offsite power system, starts load shed logic and load sequence timers, starts the diesel generator, and permits auto-close of the diesel generator breaker.
7*13Eachofthesestandby4.16-kVbuseshasastandby4.16-kVdiesel generatorcapableofsupportingitsrespectivedesignloadupon lossofpreferredpower.Thedieselgenerator1EGS*EG1Asupports standby4.16-kVbus1ENS*SWG1Aanddieselgenerator1EGS*EG1B supportsstandby4.16-kVbus1ENS*SWG1B.TheHPCSsystemdiesel generator1E22*S001G1Csupportsstandby4.16-kVbus1E22*S004.
xo13 2.
Eachstandbydieselgeneratorisphysicallyseparatedfromthe othersandislocatedintheSeismicCategoryIdieselgenerator building.Failureofonedieselwillnotimpedetheoperationof theothertwodieselgenerators.
The second time delay is approximately 60 sec, which ensures that permanently connected Class 1E loads will not be damaged. Following this time 13mx
13Standby4.16-kVbus1ENS*SWG1Aandnormal4.16-kVbus1NNS-SWG1A maybefedfromthepreferredstationservicetransformer1RTX-XSRICsimultaneously.Ifanundervoltageconditionweretooccur concurrentlyonbothbuses,atripsignalwouldbegiventothe normalsupplybreakeron1NNS-SWG1Aandtothemotorfeeder breakersonthatbus.Ifpropervoltageisnotavailable,atrip signalwouldbegiventothepreferredsupplybreakeron 1ENS*SWG1Aandthestandbydieselgeneratorwouldstartandwould energizethestandby4.16-kVbus.Division2equipmentfollows thesameoperation.Reference2providesadescriptionofthe standbybustransfersandtrippingunderlossofpower


conditions.Thestandby4.16-kVstandbybusesareelectricallyindependentandphysicallyisolatedfromoneanother.Theirloadsare redundantasrequiredandconsistofstandbymotorsandstandby 480-Vloadcenters.Anexceptionisthestandbyservicewater system.ThetrainApumpsarepoweredby1ENS*SWG1Aand 1E22*S004(onepumponeachbus).ThetrainBpumpsareboth poweredby1ENS*SWG1B.Dccontrolpowerforthestandby4.16-kV switchgearandfor1NNS-SWG1A,1NNS-SWG1B,and1NNS-SWG1Cis suppliedasshowninTable8.3-8.4.16-kVswitchgearassemblies1NNS-SWG2Aand1NNS-SWG2Batthecirculatingwaterpumpareaand1NNS-SWG3Aand1NNS-SWG3Batthe coolingtowermakeuppumpareaand RBSUSARRevision68.3-9August199361NNS-SWG4Aand1NNS-SWG4Battheradwastebuildingand1NNS-SWG6A and1NNS-SWG6Battheservicewatercoolingswitchgearbuilding areofthesplit-busdesign.Undernormalconditionsthesupply breakeroneachbusisclosedandthebustiebreakerisopen.
RBS USAR 8.3-23 August 1987 delay, if the operator has failed to restore adequate
Noautomaticclosingofthetiebreakertakesplaceafter trippingeithersupplybreaker.Closingallbreakersisby manualcontrol.Whenthesupplybreakersandbustiebreakeraretobeclosedtoparalleltwosourcesforashortperiodoftime duringthrowover,closingofthelastbreakerissupervisedbya synchronizingcheckrelay.Closureofthefourtiebreakers initiatesanalarm.
: voltages, the Class 1E system is automatically separated from the offsite power system, the load shed logic and load sequence timers
68.3.1.1.3.4480-VSystemsAllnormalloadcentersfornonsafety-relatedservicearethesplit-busdesign.Twoloadcentertransformersofeachload centerareenergizedfromnormal13.8-kVbuses1NPS-SWG1Aand 1NPS-SWG1B.Inturn,loadcentertransformerssupplyopposite sidesofthesplitbus.Thesebusescanbeconnectedbyclosing thetiebreaker.Thereisnoautomatictransferbetweenthetwo loadcenter480-Vpowersources.Nointerlocksareprovidedto preventparallelingofthetwoloadcenter480-Vpowersources.
: start, and the diesel generator starts and permits auto-close of the diesel generator breaker.
Closingthetwoloadcentersupplymainbreakersandthesplit-bustiebreakerisindicatedinthemaincontrolroom.61NJS-LDC4Aand1NJS-LDC4B480VACload-centersareofthesame splitdesignastheothernon-safetyrelatedloadcenters.
Undervoltage protection is afforded to the ac distribution system down to and including the 480-V motor control centers (MCCs) level.
Servicewatercoolingload-centertransformersareenergizedfrom normal4.16-kVbuses1NNS-SWG6Aand1NNS-SWG6B.Inturn,load centertransformerssupplyoppositesidesofthesplitbus.
The tripping of the 4.16-kV air circuit breakers (ACBs) discussed above also results in no voltage at the 480-V load centers and MCCs which, in turn, will cause motor feeder ACBs and contacts to open circuit. Subsequent energization of the 4.16-kV buses by the diesel generator results in the re-energization of MCC motor loads with the closing of their contacts at approximately 70 percent voltage.
Thesebusescanbeconnectedbyclosingthetiebreaker.There isnoautomatictransferbetweenthetwoloadcenter480-Vpower sources.Nointerlocksareprovidedtopreventparallelingofthe twoloadcenter480-Vpowersources.Closingthetwoloadcenter supplymainbreakersandthesplit-bustiebreakerisindicated inthemaincontrolroom.
The voltage sensors are designed to satisfy the following applicable requirements:
6Thestandby480-Vloadcentersaresingle-endedandhavecircuit breakerswithaninterruptingcapabilityofnotlessthan30,000 ampsymmetrical.Thesestandbyloadcentersarefedfromthe standby4.16-kVbuses.Standby4.16-kVbus1ENS*SWG1Aprovides powerforstandby480-Vloadcenters1EJS*LDC1Aand1EJS*LDC2A.
1.
Standby4.16-kVbus1ENS*SWG1Bprovidespowerforstandby480-V loadcenters1EJS*LDC1Band1EJS*LDC2B.DCcontrolpoweris suppliedasshowninTable8.3-8.Standby480-Vloadcenter loadsareredundant RBSUSARRevision68.3-9aAugust1993andincludestandbymotorsandstandbymotorcontrolcenters.Thereareseveralnormalloadsconnectedtothestandby loadcentersidentifiedinTable8.3-7andwhicharetrippedoff thebusduringaLOCA.Thestandby480-Vloadcentersof DivisionIareelectricallyindependentfromthoseofDivisionII andarephysicallyisolatedfromoneanother.Moldedcasecircuitbreakersofbothnormalandstandbymotorcontrolcentershaveaninterruptingcapabilityof25,000amp symmetrical.StandbymotorcontrolcentersofDivisionIare electricallyindependentandphysicallyisolatedfromthoseof DivisionII.Normalloadsconnectedtothestandbymotorcontrol centersandwhicharetrippedoffthebusduringLOCAare identifiedinTable8.3-7.
Class 1E equipment is utilized and is physically located at and electrically connected to the Class 1E switchgear.
RBSUSARRevision68.3-9bAugust1993THISPAGELEFTINTENTIONALLYBLANK RBS USAR Revision 16 8.3-10 March 2003 8.3.1.1.3.5 Low Voltage Systems The instrumentation and control supply system consists of a 125-V dc system (Fig. 8.3-6), 120-V ac safety-related uninterruptible power supply systems (Fig. 8.3-2), 120-V ac normal uninterruptible power supply systems (Fig. 8.3-1), and 120-V ac regulated power supplies. The 125-V dc systems provide dc power
2.
An independent scheme is provided for Division I and II of the Class 1E power system.
3.
The undervoltage protection includes coincidence logic (2
out of 3) on a
per-bus basis to preclude spurious trips of the offsite power source.
4.
The voltage sensors automatically initiate the disconnection of offsite power sources whenever the voltage setpoint and time delay limits have been exceeded.
5.
Capability for test and calibration during power operation is provided.
Undervoltage relay settings on the Class 1E 4.16-kV buses can be checked during plant operation by testing one single-phase undervoltage relay at a time.
Disconnecting one phase of the three-phase system does not impair the operation of the switchgear.
Normally a
two-out-of-three
: logic, the removal of one relay results in an effective one-out-of-two logic, i.e., an undervoltage detected by any one of the two remaining relays still in the circuit would initiate an undervoltage tripping sequence.
The removed relay can then be checked against a


for dc loads, uninterruptible power supplies, backup instrumentation and control, and are described in Section 8.3.2.
RBS USAR Revision 6 8.3-24 August 1993 variable voltage test input to verify its intended setpoint.
The 120-V ac uninterruptible power supplies provide ac power for
6.
Annunciation is provided in the control room by any bypasses incorporated in the design.
The Class 1E bus load shedding scheme automatically prevents shedding during sequencing of the emergency loads to the bus.
The load shedding feature is reinstated upon completion of the load sequencing action.
The voltage levels at the safety-related buses are optimized for the maximum and minimum load conditions that are expected throughout the anticipated range of voltage variations of the offsite power sources.
The trip settings selected are based on an analysis of the voltage at the terminals of the Class 1E loads.
The analyses performed to determine minimum operating voltages consider maximum unit steady state and transient loads for events such as a
unit
: trip, loss of coolant
: accident, startup, or
: shutdown, with the offsite power supply (grid) at minimum anticipated voltage and only the offsite source being considered available.
Maximum voltages are analyzed with the offsite power supply at maximum expected voltage concurrent with minimum unit loads.
*1 The analytical techniques and assumptions used in the voltage analysis were verified by actual measurement.
The verification and test were performed prior to initial full-power reactor operation on all sources of offsite power by:
1*
1.
Loading the station distribution
: buses, including all Class 1E buses down to the 120/240 V level, to at least 30 percent.
2.
Recording the existing grid and Class 1E bus voltages and bus loading down to the 120/240 V level at steady state conditions and during the starting of both a
large Class 1E and non-Class 1E motor (not concurrently).
*6 3.
Using the analytical techniques and assumptions of the voltage analysis above, and the measured existing grid voltage and bus losing conditions recorded during conduct of the test, a new set of voltages for all the Class 1E buses down to the 120/240 V level was calculated.
6*


security, control, and instrumentation systems for the nonsafety-related and engineered safeguard systems (Section 8.3.1.1.3.7).
RBS USAR Revision 17 8.3-25
6
: 4.
The analytically derived voltage values were compared against the test results.
6
Two completely separate schemes of undervoltage protection are provided on the Division III Class 1E HPCS bus at the 4.16-kV level. The selection of undervoltage and time delay setpoints has been determined from an analysis of the voltage requirements of the Class 1E loads. These setpoints will be verified during the actual system testing. The first and second level undervoltage protection scheme senses voltage at the incoming side of the normal supply breaker.  
13 The first level undervoltage setpoint is set below any anticipated transient voltage condition, with a time delay of approximately 3 sec.
The second level of undervoltage protection is set at approximately 90 percent of normal voltage and utilizes two separate time delays based on the following conditions:
: 1.
The first time delay is approximately 5 sec and establishes a sustained degraded voltage condition (i.e.,
something longer than a
motor starting transient). Following this delay, an alarm in the main control room alerts the operator to the degraded condition. The subsequent occurrence of a LOCA signal immediately separates the Division III HPCS bus from the offsite power system. The Division III HPCS bus will experience a loss of voltage and the primary undervoltage relays and control circuit will start load shed logic, start the diesel generator, and permit auto-close of the diesel generator breaker when the diesel generator attains its rated speed, voltage, and frequency.
13
: 2.
The second time delay is approximately 60 sec and is set to ensure that permanently connected Class 1E loads will not be damaged. Following this time delay, if the operator has failed to restore adequate voltages, the Division III HPCS bus is automatically separated from the offsite power system. The Division III HPCS bus will experience a loss of voltage and the primary undervoltage relays and control circuit will start the load shed logic, start the diesel generator, and permit auto-close of the diesel generator breaker when the diesel generator attains its rated speed, voltage, and frequency.


The 120-V ac regulated power supplies provide ac power for  
RBS USAR 8.3-26 August 1987 Undervoltage protection is afforded to the ac distribution system down to and including the 480-V motor control center (MCC) level.
The tripping of the 4.16-kV offsite power supply circuit breaker discussed above also results in no voltage at the 480-V MCC bus
: which, in
: turn, will cause motor feeder contactors to dropout.
Subsequent energization of the 4.16-kV HPCS bus by the diesel generator results in the reenergization of 480-V MCC bus.
Auto-closer interlocks will operate the contactors at approximately 70 percent voltage to energize the motor loads.
The voltage sensors are designed to satisfy the following applicable requirements:
1.
Class 1E equipment is utilized and is physically located at and electrically connected to the Class 1E switchgear.
2.
An independent scheme is provided for the Division III Class 1E HPCS power system.
3.
The second level of undervoltage protection includes coincidence logic (2
out of 2) to preclude spurious trips of the offsite power source.
4.
The voltage sensors automatically initiate the disconnection of offsite power sources whenever the voltage setpoint and time delay limits have been exceeded.
5.
Capability for test and calibration during power operation is provided.
6.
Annunciation is provided in the control room by any bypasses incorporated in the design.
The Class 1E HPCS bus load shedding scheme automatically prevents shedding during sequencing of the emergency loads to the bus.
The load shedding feature is reinstated upon completion of the load sequencing action.
The voltage levels at the HPCS bus are optimized for the maximum and minimum load conditions that are expected throughout the anticipated range or voltage variations of the offsite power sources.
The trip settings selected are based on an analysis of the voltage at the terminals of the Class 1E loads.
The analyses performed to determine minimum operating voltages consider maximum unit steady state and transient loads for events such as unit trip, loss of coolant accident, startup, or shutdown, with the offsite


instrumentation, security, and communication systems for the  
RBS USAR Revision 9 8.3-27 November 1997 power supply (grid) at minimum anticipated voltage and only the offsite source being considered available.
Maximum voltages are analyzed with the offsite power supply at maximum expected voltage concurrent with minimum unit loads.
*6 The analytical techniques and assumptions used in the voltage analysis were verified by actual measurement.
The verification and test will be performed prior to initial full-power reactor operation on all sources of offsite power by:
6*
1.
Loading the station distribution
: buses, including all Class 1E buses down to the 120-V level, to at least 30 percent.
2.
Recording the existing grid and Class 1E bus voltages and bus loading down to the 120-V level at steady-state conditions and during the starting of a large Class 1E HPCS pump motor.
*6 3.
Using the analytical techniques and assumptions of the voltage analysis above, and the measured existing grid voltage and bus loading conditions recorded during conduct of the
: test, a
new set of voltages for the Class 1E HPCS bus down to the 120-V level was calculated.
4.
The analytically derived voltage values were compared against the test results.
6*
8.3.1.1.3.10 Control Interlocks for AC Electrical Circuits Control circuits of all 4.16-kV circuit breakers and 480-V load center breakers in safety-related systems were reviewed to determine if inadvertent operation of other components in the same or other systems resulted when the circuit breaker for a
particular component was racked out to the test position or operated in the test position.
The results of this review have been summarized and verify that the present design of electrical control circuitry for RBS does not result in any inadvertent operations.
*9 1.
In the case of 4.16-kV circuit breakers, interlock to other components is achieved using breaker auxiliary switch contacts.
The operation of the interlocked circuitry is controlled administratively when the circuit breaker is operated in the test position.
9*


nonsafety-related and engineered safeguard systems. The instrumentation and status indications of Class 1E switchgear aforementioned are described in Section 7. 8.3.1.1.3.6 Standby Electrical Power Systems
RBS USAR 8.3-28 August 1987 2.
In the case of 480-V load center breakers, interlock to other components is achieved using the contacts of an auxiliary relay in the breaker control circuit.
A breaker housing limit switch contact is used to lock out this relay in the racked out position of the breaker.
3.
13.8 kV circuit breakers are not used to control power to any safety-related systems or components.
4.
In the case of motor control
: centers, interlock to other system components is achieved using auxiliary relays in their control circuits.
Testing of motor control centers does not result in any inadvertent operation of other system components.
5.
120-V ac/dc circuit breakers do not provide any interlocks to other system components.
8.3.1.1.4 System Protection and Surveillance Transformers with their low voltage winding at or above 4.16 kV, except 1STX-XS3A and 1STX-XS3B at the makeup water
: area, have differential protection.
All 4.16-kV and 13.8-kV ac motor circuits have phase time overcurrent relays with instantaneous trips set above locked rotor levels.
Also, 4.16-kV and 13.8-kV motors have time over-current ground relaying.
The reactor feed pump motors and the reactor recirculating pump motors with their dedicated transformers have differential protection.
Circuit relays are coordinated with those at the source.
Breakers at the 480-V level have time-overcurrent tripping. All molded case breakers in motor control centers and the dedicated motor supply breakers in 480-V load centers have instantaneous short circuit tripping devices set above motor inrush current level.
Breakers in 480-V load centers serving motor control centers have minimum time delay on short circuits; those used in bus-tie service have intermediate time delay; and those in main supply service have maximum time delay on short circuits.
Load centers in standby service have 480-V breakers in the main supply.
The tripping selectivity outlined and appropriate choice of relays and thermal tripping devices facilitate application of the required coordination of protection.


The standby electrical power systems are designed to provide redundant sources of onsite ac electric power which are self-
RBS USAR 8.3-29 August 1987 8.3.1.1.4.1 Standby Diesel Generators The protection system of standby diesel generators is described as follows (see logic diagrams, Figure 7.3-23, sheets 17 through 28):
1.
The standby diesel generator is rendered incapable of responding to an emergency auto start signal during any diesel generator operational condition (including testing and operation from the local control panel) by the following conditions:
a.
Diesel control panel loss of control power b.
Starting air pressure low c.
Stop solenoid 1EGS*SOV24A or 1EGS*SOV24B, for 1EGS*EG1A or 1EGS*EG1B, respectively, energized.
The diesel generator stop solenoid is energized and sealed in whenever the manual stop pushbuttons are operated or the diesel generator primary or backup protection relays are tripped.
The stop solenoid is sealed in to prevent an automatic diesel generator emergency start occurring before all the diesel generator controls and protection devices are reset to normal operating conditions.
The local control room or main control room operator can deenergize the diesel generator stop solenoid by operating the STOP RESET pushbutton provided, one in each control room.
d.
Diesel in the maintenance mode (includes barring device engaged) e.
Overspeed trip device actuated f.
Generator backup protection lockout relay tripped g.
Generator primary protection lockout relay tripped 2.
The standby diesel generator unit is tripped under the following conditions during both normal and emergency operation:
a.
Engine overspeed


contained within the unit and which are not dependent on the normal and preferred sources of supply. The standby electrical
RBS USAR Revision 22 8.3-30
16
: b.
Both STOP pushbuttons manually operated. For each standby diesel generator unit, two pushbuttons are located at both the main control room and at the local control panel. The two pushbuttons are arranged such that the operator must use both hands to simultaneously operate both pushbuttons in the main control room. The operator can operate both pushbuttons with one hand at the local panel.
16
: c.
Generator differential relay trip
: d.
Extreme high jacket water temperature and high lube oil temperature trips are active unless a LOCA signal is present or manually bypassed by a local control switch (Applicable to EGS-EG1A and EGS-EG1B ONLY).
: 3.
The standby diesel generator unit is tripped under the following conditions during normal operation only.
: a.
Generator voltage controlled - inverse time phase overcurrent
: b.
Generator reverse power
: c.
Generator loss of field
: d.
Extreme high jacket water temperature trip
: e.
High bearing temperature trip
: f.
Extreme low jacket water pressure trip
: g.
High crankcase pressure trip
: h.
Trip low turbo oil pressure
: i.
Trip high vibration
: j.
Trip high temperature lube oil
: k.
Low lube oil pressure trip
: l.
Generator ground overcurrent
: 4.
Protective functions of each standby diesel generator are annunciated locally in each of the standby diesel generator control rooms.
The following alarms are separated into subsystem groups. Each subsystem group is provided with a "first out" indication as per Regulatory Guide 1.9.


power systems are capable of supplying ac power for electrical
RBS USAR Revision 16 8.3-31 March 2003
: a.
Diesel engine lube oil subsystem (see Figure 7.3-17)
(1)
Lube oil filter differential pressure high (2)
Lube oil strainer differential pressure high (3)
Turbo oil pressure low (4)
Lube oil pressure low (5)
Turbo oil low pressure - TRIP (6)
Lube oil low pressure - TRIP (7)
Crankcase high pressure - TRIP (8)
Lube oil outlet temperature high (9)
Lube oil inlet temperature high (10) Lube oil outlet temperature low (11) Lube oil inlet temperature low (12) Lube oil tank level high (13) Lube oil tank level low (14) Lube oil outlet high temperature - TRIP
16 (15) Bearing oil high temperature - TRIP 16
: b.
Diesel engine fuel oil subsystem (see Figure 7.3-15)
(1)
Fuel oil storage tank level low (2)
Diesel engine strainer differential pressure high (3)
Fuel oil day tank level extreme low (4)
Fuel oil day tank level extreme high (5)
Fuel oil filter differential pressure high (6)
Fuel oil pump overspeed drive failure


loads which are required for a safe shutdown of the reactor. 16 The standby system ac distribution buses are rated at 4.16-kV and 480-V. There are three standby 4.16-kV ac buses and four standby 480-V ac load centers. The bus configuration (Fig. 8.1-6) is described in Sections 8.3.1.1.3.3 and 8.3.1.1.3.4. Upon loss of  
RBS USAR Revision 16 8.3-32 March 2003 (7)
Fuel oil pressure low
16 14
: c.
Diesel engine jacket water subsystem (see Figure 7.3-23) 14 16
(1) Jacket water pressure low (2) Jacket water extreme low pressure - TRIP (3) Jacket water outlet temperature extreme high
- TRIP (4) Jacket water outlet temperature high (5) Jacket water inlet temperature high (6) Jacket water outlet temperature low (7) Jacket water inlet temperature low (8) Jacket water level low
: d.
Diesel engine air start subsystem (see Figure 7.3-16)
(1) Start air receiver pressure low (2) Control air pressure low (3) Diesel start air pressure low
: e.
Diesel generator subsystem (see Figure 7.3-23, Sheets 22 and 28)
(1) Standby generator differential - TRIP (2) Standby generator fault - TRIP (3) Standby generator ground fault (4) Standby generator loss of field The following standby diesel generator protective functions are annunciated individually:
15
: a.
DELETED
: b.
DELETED 15
: c.
Emergency exhaust fan trouble


voltage on associated standby 4.16-kV buses, or a LOCA signal
RBS USAR Revision 22 8.3-33
 
: d.
initiated by an abnormally low water level in the reactor vessel or a  high drywell pressure, or a manual start signal, the generators are started and brought up to rated frequency and voltage. If, at this time, the two redundant supply power lines
Auxiliary systems not in auto  
 
16
to the buses are open, the standby generator breakers automatically close on their associated dead buses. The diesel
: e.
 
Bearing high temperature - TRIP 16
generators are not automatically connected to their respective
: f.
 
Fuel oil strainer differential pressure high
standby 4.16-kV buses if the buses are still connected to either
: g.
 
Fuel oil dc pump running
the preferred or normal station service transformers.
: h.
16Unit 1 reactor has three diesel generators: 1EGS*EG1A, 1EGS*EG1B, and 1E22*S001G1C. Diesels 1EGS*EG1A and 1EGS*EG1B are devoted to
After cooler water inlet temperature high
 
: i.
safety-related equipment as shown RBS USAR Revision 12 8.3-11 December 1999 in Fig. 8.1-6. Diesel 1E22*S001G1C energizes the HPCS system as described in Section 8.3.1.1.3.6.2. 8.3.1.1.3.6.1 Standby Diesel Generators
Barring device engaged
 
: j.
8.3.1.1.3.6.1.1 Description Each standby diesel generator is physically independent, located in a building structure designed to withstand earthquakes and to protect the standby diesel generators against tornadoes, floods, hurricanes, and tornado-generated missiles (Section 3.8). Within
Diesel start air pressure high
 
: k.
the protected structure, each standby diesel generator, including
Unit start failure
 
: l.
its associated starting equipment and other auxiliaries, is installed in a separate room of a Seismic Category I building so that an incident at one generator will not physically or electrically involve the others. Each standby diesel generator
Vibration - TRIP
 
: m.
is provided with a separate missile-protected combustion air intake, room air intake and discharge, and diesel engine exhaust
Overspeed - TRIP
 
: n.
opening.Seismic qualification of the standby diesel generators and associated equipment is discussed in Sections 3.9.2.2A and 3.10A.
4160 Standby bus distribution breakers auto -TRIP
In addition, the standby diesel generators can provide full rated
: o.
 
Diesel generator potential circuit blown fuse
load when subjected to extreme atmospheric conditions, e.g., due
: p.
 
4160 Standby bus undervoltage In addition to the above-listed annunciators, the following standby diesel generator conditions are also indicated in each diesel generator control room:  
to a hurricane or tornado. The probability of a tornado striking a point on the site is low, about once in 3,415 yrs (Section 2.3.1.2.4).
14
Each standby diesel generator is provided with an independent fuel oil system consisting of a day tank with fuel capacity for 1-hr minimum operation at required load, and one 100 percent capacity Class 1E fuel oil transfer pump for automatically filling the day tank from its respective storage tank. One fuel oil storage tank for each standby diesel generator supplies fuel for continuous operation at its rated capacity for 7 days (Section 9.5.4). 12Each standby diesel generator unit is provided with two independent and redundant air starting systems with separately
: a.
 
Unit available emergency status - white light on
powered air compressors to furnish air for automatic and manual starting and for control air. The starting systems for each
: b.
 
AC control power - white light on
standby diesel generator includes electrically driven
: c.
 
DC control power - white light on
compressors, primary air tanks, reserve air tanks, and necessary gears and valves for cranking the engine. The two starting
: d.
 
Ready to load - white light on
systems (the HPCS diesel's air compressors are described in Section 8.3.1.1.3.6.2) are arranged so that failure of one will not jeopardize proper operation of the other. Each train of the starting system is capable of at least eight cranking cycles
: e.
 
Unit tripped - amber light on 14
without the assistance of 12 RBS USAR Revision 16 8.3-12 March 2003 16outside power. The time required by each air compressor to recharge its tank from minimum starting air pressure to operating air pressure is approximately 30 minutes. Each standby diesel
: f.
 
At synchronous speed - red light on
engine is provided with cooling by means of a shell and tube heat exchanger cooled by water from the SSW system. Each generator is a self-cooled air-ventilated unit. All necessary auxiliaries
: g.
 
Starting - red light on
directly associated with each standby diesel-generator unit, such as ventilating fans, battery chargers, fuel oil transfer pump, etc, are powered from their associated standby buses. Electrical
: h.
 
Shutdown system active - red light on
power for starting and control is supplied from the 125-V dc
: i.
 
High temperature bypass switch, operate - white light on, Bypass - amber light on (Applicable to EGS-EG1A and EGS-EG1B ONLY).
system associated with that generator.
: 5.
1611 The standby diesels for 1EGS*EG1A and 1EGS*EG1B are Transamerica Delaval, Inc. type DSR 48 and provide 4869 bhp in continuous duty. However, special requirements are imposed by the Facility Operating License for continuous operation of these two standby diesels above 4197 bhp (3130 KW). The synchronous generators
The following remote annunciation is provided in the main control room for each standby diesel  
 
were manufactured by Parsons Peebles Electric Products, Inc.
11The rating of each standby diesel generator is determined from plant design and power requirements and has the capability to ensure proper starting and operation of all required motor loads without excessive frequency or voltage drop. The rating of each of the standby diesel generators is adequate for the maximum required coincident loads during the unit design basis accident (DBA) in accordance with Regulatory Guide 1.9, except for the HPCS diesel. The philosophy applicable to the sizing of the HPCS
 
diesel is defined in Section 8.3.1.1.3.6.2.
The nameplate ratings of the standby diesel generator sets are as follows:  Standby  Standby  Diesel Generator  Diesel Generator  Time    1EGS*EG1A        1EGS*EG1B      (hr)    3,500 kW    3,500 kW  8,760 3,850 kW    3,850 kW      2 The 8,760-hr rating is on continuous duty under normal maintenance.
The standby diesel generators are specified to provide their rated output for combustion air temperatures ranging from 2°F to
 
110°F.No derating is required for ambient atmospheric pressures down to 20.58 inches Hg - absolute (10.1 psia). Humidity RBS USAR Revision 16 8.3-13 March 2003 extremes are not expected to affect the operation of the standby diesel generators since the intake air is compressed and heated
 
in the turbochargers prior to entering the engines. 168The standby generator and the 4.16-kV preferred station service system are manually synchronized during periodic testing or upon restoration of preferred power. A synchronous check relay is
 
provided to prevent breaker closure during synchronizing operations unless the busses are synchronized within the tolerances of the relay. A synchronous check relay is provided
 
to prevent breaker closure during synchronizing operations unless the busses are synchronized within the tolerances of the relay. 
 
If any safety-related switching equipment fails to operate
 
automatically, manual operation is possible, remotely in the main control room or at the standby diesel generator control room.
Except for sensors and other equipment that must be directly mounted on the engine or associated piping, the controls and
 
monitoring instrumentation are installed on free-standing floor-
 
mounted panels located in a vibration-free floor area.
8 168.3.1.1.3.6.1.2 Starting and Loading 13The standby diesel generator sets are designed for independent operation, but they may be operated in parallel with the plant auxiliary system for exercising and test purposes. Standby buses 1ENS*SWG1A and 1ENS*SWG1B are normally continuously energized from the preferred station service transformers. Standby bus
 
1E22*S004 is also normally continuously energized from the preferred station service system. The standby diesel generators are started upon receipt of an undervoltage signal from the
 
standby bus source, upon receipt of a LOCA signal or on manual
 
signal. The automatic transfer of each standby bus to its standby generator is done only on loss of voltage measured on the standby 4.16-kV bus. Transfer is accomplished by opening both the normal
 
and preferred station service transformer supply circuit breakers
 
and closing the standby generator's circuit breaker when the
 
generator is at proper voltage and frequency.
13Low voltage on a standby bus automatically disconnects all 4.16-kV motor loads on the bus. Sequencing of loads supplied from the standby diesel generators is required to prevent exceeding the
 
motor starting and load pickup capability of the standby diesel generator. Provisions are made for automatic sequencing of all loads in accordance with Table 8.3-2. Other loads may be
 
connected by the station operators (by manually controlled breakers) when load conditions permit. There is no automatic load shedding of the standby 4.16-kV buses when power is
 
furnished by the standby diesel generator.
RBS USAR Revision 22 8.3-14 The load sequencing control for the onsite and offsite power sources for River Bend Station utilizes individual timers and
 
permissive circuitry for individual feeder breakers being sequenced on standby buses. Although there is a logic which ties
 
the operation of the entire load sequencing scheme together, failure of one or more breaker timers or permissive circuits to
 
operate does not prevent other breaker timers and permissives from performing their intended functions. Timers and permissives are located in qualified switchgear and relay panel enclosures for the breakers they control. There are no credible sneak
 
circuits or common failure modes in the sequencing design that could render either the onsite or offsite power sources
 
unavailable.
An emergency demand start signal overrides all other operating
 
modes including test and returns control of the diesel-generator
 
unit to the automatic load sequencing system.
The standby diesel generator incorporates two modes of control, OPERATIONAL and MAINTENANCE.
: a. In the OPERATIONAL mode the diesel starts and comes up to speed when either of the following conditions is present:
: 1) A MANUAL START SIGNAL generated from the local control panel and the units entire protective system is reset.
 
A Manual Start Signal, starts the diesel generator in the "slow start" mode of operation. This "slow start,"
which is recommended by the manufacturer, extends the
 
starting time of the diesel to minimize the aging
 
effects associated with fast starts. 16  2) An EMERGENCY START SIGNAL generated by either a LOCA signal or a sustained bus undervoltage or by depressing
 
emergency START push button in the main control room or
 
by pressing the emergency start button on the control
 
panel.      The emergency start overrides all conditions and returns the unit to rated speed.  (Refer to Section 3.1.1.4.1)  Emergency start overrides all conditions such as: Slow Start Manual Running Test Tripping on fault conditions except for the following: 1.Overspeed 2.Generator Differential 3.Lube and Jacket Water h igh temperature trips unless the emergency start comes from a LOCA signal or the trips are bypassed by a local control switch (Applicable to EGS-EG1A and EGS-EG1B ONLY)
. 16 b. In the MAINTENANCE mode only the engine ROLL pushbutton on the local panel is operative. This feature permits cranking
 
the diesel without effecting a start.
: c. The standby diesel generators may be tested while in the operational mode by manually starting the engines and
 
manually closing the circuit breakers connecting RBS USAR Revision 16 8.3-15 March 2003  the standby diesel generators to the bus. In this manner, the standby diesel generators can be tested under load while
 
in parallel with the grid. Should the grid go to an undervoltage or underfrequency condition, the circuit breakers in the Fancy Point
 
Substation trip and deenergize the circuit feeding the preferred station service transformers. The pilot wire
 
system also initiates a trip of the 4.16-kV circuit breaker
 
between the preferred station service transformer and the bus. With the preferred or alternate supply breakers in the open position, the generator setting would switch from the
 
parallel operation mode to the isochronous mode, and the
 
standby diesel generator picks up the entire load of the
 
standby 4.16-kV bus sequentially. The standby diesel generators are capable of running unloaded for 7 days without degrading the performance or reliability of the engine. The manufacturer has demonstrated this
 
capability with a special no load endurance test. 8.3.1.1.3.6.2 High Pressure Core Spray Power Supply System
 
8.3.1.1.3.6.2.1 Description Fig. 8.3-3 shows the HPCS power system (Division III) simplified one-line diagram electrical arrangement, power distribution, protective relaying, and instrumentation for the HPCS power
 
system.The HPCS power supply system is self-contained except for the initiation signal source and access to the preferred source of offsite power through the plant ac power distribution system. It has a dedicated diesel generator, 1E22*S001G1C and is operable as an isolated system independent of electrical connection to any
 
other system. 16The HPCS diesel 1E22*S001G1C is a Stewart and Stevenson EMD 20645-E4, 20-cylinder vee type. It provides 3600 bhp in continuous duty. The synchronous generator was manufactured by
 
Ideal. This SM-100 model has a 2,000-hr rating of 2850 kW.
16Seismic qualification of the HPCS diesel generator and associated equipment is discussed in Section 3.9.2.2B and 3.10B. In addition, the HPCS diesel generator can provide full-rated load when subjected to extreme atmospheric conditions. No derating is
 
required for operation in RBSUSARRevision88.3-16August1996ambienttemperaturesupto120°F,arelativehumidityof90percent,andanatmosphericpressuredownto28.25inchesHg.
Lowcombustionairtemperaturesdonotaffecttheoperabilityof theHPCSdieselgeneratorsincetheintakeairiscompressedand heatedintheturbochargerpriortoenteringtheengine.84Thestandbyauxiliaryequipmentsuchasheatersandbattery chargeraresuppliedfromthesamepowersourceastheHPCS motor.Thenon-safetyrelatedHPCSDGaircompressorsare suppliedfromnon-safetyrelatedpowersources.
84VoltageandfrequencyoftheHPCSdieselgeneratoriscompatiblewiththatavailablefromtheplantacpowersystem.8TheHPCSdieselgeneratorhasthecapabilitytorestorepower quicklytotheHPCSbusintheeventoffsitepowerisunavailable andtoprovideallrequiredpowerforthestartupandoperation oftheHPCSsystem,onestandbyservicewaterpumpmotor,and miscellaneousauxiliariesassociatedwithit.TheHPCSdiesel generatorstartsautomaticallyonaLOCAsignalfromtheplant protectionsystemorundervoltageontheHPCS4.16-kVbus (1E22*S004),andwillbeautomaticallyconnectedtotheHPCSbus whentheplantpreferredacpowersupplyisnotavailable.The failureofthisunitwillnotnegatethecapabilityofother powersources.Thereisnoprovisionforautomaticparalleling oftheHPCSdieselgeneratorwiththeauxiliarypowerorwith standbypowersources.Provisionsformanualparallelingwith normalpowersourcesaremadeforloadingthedieselgenerator duringtheexercisemode.Asynchronouscheckrelayisprovided topreventbreakerclosureduringparallelingunlessthebusses aresynchornizedwithinthetolerancesoftherelay.IfaLOCA signaloccurswhiletheHPCSdieselgeneratorisrunningin parallelwiththenormalbus,thedieselgeneratorbreakerwill automaticallytrip.Atleastoneinterlockisprovidedtoavoid accidentalparalleling.ThereisnosharingoftheHPCSpower systemwithotherstandbydieselgenerators.8TheHPCSpowersystemloadsconsistoftheHPCSpump/motorand associatedauxiliaries,motor-operatedvalves,onestandby servicewaterpump,andmiscellaneousauxiliaryloads.
Table8.3-3showstheDivisionIIIloads.TheHPCSpumpmotorisaGeneralElectric4-kVverticalinductionmotorratedat2500hp.Theverticalpumpwasmanufacturedby theBorg-WarnerByron-JacksonPumpDivision.Itisratedat 5,125gpmwith945ftofheadanditsmotorhasamaximum shaftbhpof2,500at1,780rpm.TheHPCSelectricsystemiscapableofperformingitsfunctionwhensubjectedtotheeffectsofdesignbases RBSUSARRevision88.3-17August1996naturalphenomena.ItisdesignedinaccordancewithSeismicCategoryIandhousedinaSeismicCategoryIstructure.ThedetaileddescriptionofthefueloilstorageandtransfersystemassociatedwiththeHPCSdieselgeneratorunitis describedinSection9.5.4.FuelfortheHPCSdieselengineis providedinaseparatedaytankandinastoragetank.Theday tankpermitsaminimumof1hrofoperationatratedload.The combinedcapacityofthedaytankandthestoragetankpermits theHPCSdieselenginetooperateatcontinuousratedload conditionsforatleast7days.8Theengineairstartingsystemcontainstwocompletesetsof startingcomponents,eitherofwhichiscapableofstartingthe engine.However,tofurtherensurestartingwithinthetime requirements,bothsetsareutilizedsimultaneouslytocrankthe engine.Eachsetofcomponentsconsistsofdualairstart motors,airrelayvalve,solenoidvalve,airreceivers,andair compressorassembly.Bothcompressorsarecapableofautomatic startandstopandarecontrolledbypressureswitchesto maintainrequiredpressureintheairreceivers.Thetwoair startingsystemsareredundant,independent,andarrangedsothat failuretostartinonesystemwillnotjeopardizestartingof thedieselgeneratorbytheothersystem.
8Manualcontrolsareprovidedtopermittheoperatortoselectthemostsuitabledistributionpathfromthepowersupplytothe load.Anautomaticstartsignaloverridestheexercisemode.
Provisionsaremadeforcontrolfromthemaincontrolroomand externaltothemaincontrolroomfromanHPCSdieselgenerator controlpanellocatedexternaltothemaincontrolroominthe dieselgeneratorbuildingasshowninFigure8.3-11.Thecontrol panelincludesfacilitiesforbreakercontrolofincomingfeeder andHPCSgeneratorbreakertogetherwithfrequencymeter, synchroscope,bus,andincomingvoltmetersandenginespeed controldevice.Exceptforsensorsandotherequipmentthatmustbedirectlymountedontheengineorassociatedpiping,thecontrolsand monitoringinstrumentationareinstalledonfree-standingfloor-mountedpanelslocatedinavibration-freefloorarea.ControlpowerfortheHPCSdieselgeneratorunitissuppliedfromitsown125-Vbatterysystem,whichconsistsofa RBS USARRevision 218.3-18battery with its own battery charger. The charger is designedto carry the continuous load in addition to normal battery charging current. Section 8.3.2.2 provides a discussion of the HPCS 125-V dc system. Tables 8.3-3 and 8.3-6 show the HPCS
 
diesel generator size and the 125-V dc load requirements.8.3.1.1.3.6.2.2 Starting and Loading A loss of normal potential at the HPCS bus is one of the threeinitiating signals which automatically starts the HPCS diesel generator. The other two signals are accident signals of reactor low water level and high drywell pressure which are described in detail in Section 7.3.1. On receipt of a start signal or HPCS supply bus undervoltage, the HPCS diesel
 
generator will start and accelerate to operating voltage and frequency as standby power supply for the HPCS system. On
 
reaching rated speed and voltage, the generator is automatically connected to the HPCS bus if ac power is not available at the bus. Once the diesel generator has been energized, the unit will continue to operate until manually deenergized or until the
 
protective devices of the HPCS diesel generator cause a trip.The HPCS diesel generator is capable of running unloaded for4.5 hours without degrading the performance or reliability of the engine, after which, it must be run at a minimum of 40
 
percent of nameplate rating for 30 minutes.The HPCS diesel generator has the capacity to start all motorsas required by the design basis so that the main pump is at rated speed and all required valve operations are completed within the time requirements described in Sections 6.3 and 9.2.7. All HPCS loads associated with the DBA are started
 
concurrently, except the DG room vent fan, the standby service water pump
, and its associated motor-operated valve 1SWP*MOV40C, which are sequenced to start as noted in Table 8.3-3.
An emergency demand start signal overrides all other operatingmodes including tests and then returns control to the sequencing system. Refer to Section 5 of NEDO 10905 for a description of
 
control and protection of the HPCS diesel generator.
8.3.1.1.3.7  120-Volt AC Uninterruptible Power Supply System The 120-V ac uninterruptible power supply system suppliescontrol power to vital computer and instrumentation loads for which power interruption must be avoided. These RBS USAR Revision 20 8.3-19 services are necessary for the normal operation of the plant.
Power from the uninterruptible power supplies is free from extraneous voltage spikes, switching surges, and momentary interruptions, and satisfies the voltage and frequency variation limits of the station computers and instrumentation systems. A high degree of power continuity is provided, with the uninterruptible power supply being able to switch automatically between two independent sources of input
 
power, or to transfer to an independent alternate source of regulated ac power with sufficient speed so the operation of the computer and
 
instrumentation is not affected. 13 Normally the uninterruptible power supply inverter (Figure 8.3-1 and 8.3-2) receives dc power from a 480-V ac motor control center (MCC) feeding an ac-to-dc rectifier, with a second source of dc power coming from the 125-V dc station battery. Any failure of the MCC feeding the rectifier results in the station battery carrying the uninterruptible power supply load without interruption. Malfunctions of both of the two dc sources of power to the inverter or the inverter itself causes
 
the static switch to automatically transfer the power source to an independent alternate source fed from a 480-V ac MCC feeder through a
 
voltage regulating transformer in all uninterruptible power supplies.
1BYS-INV06 furnishes power to DRMS, ERIS, and other support service  loads. A make-before-break manual bypass switch enables maintenance, inspection, and testing of the uninterruptible power supply components
 
to be safely performed while feeding the loads from the alternate
 
source voltage regulating transformer.
13  15  1 There are a total of eleven uninterruptible power supply systems in the plant.
ENB-INV01A and ENB-INV01A1 are associated with Division I, ENB-INV01B and ENB-INV01B1 are associated with Division II and the
 
remainder (BYS-INV01A, BYS-INV01B, BYS-INV02, BYS-INV04, BYS-INV06, and IHS-INV01) are connected to normal buses. BYS-INV03 is a
 
nonsafety-related swing inverter which supplies 120 VAC power to distribution panel. Through switches near the local inverter, BYS-INV03 may be utilized to supply backup power to the loads of BYS-
 
INV01A or BYS-INV01B.
Either ENB-INV01A (01B) or ENB-INV01A1 (01B1) (but not both simultaneously) may be selected to supply power to VBS-PNL01A (01B) through the use of manual transfer switch VBS-TRS02A (02B). Either unit may be in-service at any given time, with the other unit de-energized and available as a backup. Upon failure of the in-service UPS, the backup unit is energized and placed in service via operation of VBS-TRS02A (02B). This allows a rapid method of in service via operation of VBS-TRS02B. This allows a rapid method of restoring power to the Division I (II) 120 Volt AC Vital Bus in the event of a failure of the in-service UPS. The ac sources for the uninterruptible power supplies associated with the standby systems are derived from the standby diesel generators feeding buses 1ENS*SWG1A and 1ENS*SWG1B.
All uninterruptible power supplies and their associated distribution panels are completely independent (by division). Those panels associated with standby systems serve redundant safety-related
 
equipment. The distribution 1 15 RBSUSARRevision88.3-20August1996panelscontainfuseddisconnectswitchesforbranchcircuitprotection.Manualorautomaticdevicesforswitchingto interconnecttheredundantsafety-relateduninterruptiblepower suppliesarenotprovided.8.3.1.1.3.8ReactorProtectionSystem(RPS)PowerSystem 8.3.1.1.3.8.1General TheRPSpowersystemisdesignedtoprovidepowertothelogicsystemthatispartofthereactorprotectionsystem.Itprevents auxiliarypowersystemswitchingtransientsfromcausingan inadvertentreactorscramduetoatransientdisturbanceofpower tothereactorscramlogic.TheprincipalelementsoftheRPSpowersystemincludetwohighinertia,alternatingcurrent,motorgeneratorsetsand distributionequipment.Eachmotorgeneratorsetsuppliespowerforthenuclearsteamsupplyshutoffsystem,neutronmonitoringsystem,partsof processradiationmonitoringsystem,andreactorprotectiontrip system.TheRPSpowerisclassifiedasnonessentialbecause failureofthepowersupplycausesareactorscramandisolation.
However,thepowerfeedstoredundantlogicsarephysically separatedbyrunninginseparateconduits.RPSsafety-relatedsignalcables,powercables,andracewaysareidentifiedbynameplatesand/orcolorcodestodistinguishfrom nonsafety-relatedequipmentandtodistinguishbetweenredundant, safety-relatedequipment.RPSsafety-relatedinstrumentpanelsareidentifiedbycolorcodednameplatestodistinguishfromnonsafety-relatedequipment andtodistinguishamongredundant,safety-relatedequipment.RBSprovidesprotectionofRPSbusesAandBfromvoltageandfrequencyanomalieswhichcoulddamageRPScomponentsandthus precludeimproperoperationoftheRPS.Theprotectionis affordedbytheuseofelectricalprotectionassemblies(EPAs) whichareClass1E.TheEPAsprovideredundantprotectiontothe busesbyactingtodisconnectthebusesfromthepowersources notwithindesignspecifications.8TheEPA(Figure7.2-1)consistsofacircuitbreakerwithatrip coilcontrolledbythreeindividualsolidstaterelayswhich senselinevoltageandfrequencyandtripthebreakeropenon8 RBS USAR Revision 25 8.3-21 the conditions of overvoltage, undervoltage, and under-frequency.
Provision is made for setpoint verification, calibration, and
 
adjustment under administrative control. After tripping, the circuit breaker must be reset manually. Trip setpoints are based on providing 115-V ac, 60-Hz power at the RPS logic cabinets.
The protective circuit functional range is `10 percent of nominal
 
ac voltage and -5 percent of nominal frequency.
 
The four EPA enclosures for each RPS bus are mounted on a Seismic Category I structure separately from the motor generator sets and separate from the four EPAs of the other RPS bus. Two EPAs are
 
installed in series between each of the two RPS motor-generator
 
sets and the RPS buses and between the auxiliary power sources and RPS buses. Figure 7.2-1 provides an overview of the eight EPA
 
units and their connections between the power sources and the RPS buses. The EPA is designed as a Class 1E electrical component.
It is designed and fabricated to meet the quality assurance
 
requirements of 10CFR50 Appendix B.
 
8.3.1.1.3.8.2 Components
 
Each of these high inertia motor generator sets has a voltage regulator which is designed to respond to a step load change of 50 percent of rated load with an output voltage change of not more than 15 percent. High inertia is provided by a flywheel.
The inertia is sufficient to maintain the voltage and frequency of generated voltage within 5 percent of the rated values for a minimum of 1 sec following a total loss of power to the drive
 
motor.
 
8.3.1.1.3.8.3 Sources
 
The power to each of the RPS buses is supplied from two 120-V ac
 
sources. The primary source of power is the motor generator sets. The alternate source of 120-V ac power is Class 1E and
 
redundant, and consists of a 480-120-V voltage-regulating transformer. The two motor generator sets are supplied from
 
separate 480-V motor control centers normally energized from the normal station service transformers, and which also are connectable to the preferred station service transformers via the non-Class 1E distribution system. Indicating lights are provided in the main control room to monitor the status of both the motor
 
generator sets and the instrument buses.
 
RBS USAR Revision 25 8.3-22 8.3.1.1.3.8.4 Operating Configuration During operation, the reactor protection system buses are energized by their respective motor generator sets. Either motor
 
generator set can be taken out of service by manually operating
 
the power source selector switch which disconnects the motor generator set and connects the respective RPS bus to its alternate power source. Only one RPS bus may be placed on alternate power when in Modes 1 OR 2 except for limited emergent plant situations which require both RPS buses to be connected to their alternate supplies for short periods. Alignment of both RPS buses to their alternate supplies is not the normal line up because of increased vulnerability to grid perturbations that could result in inadvertent trip of both divisions of RPS connected loads. Short periods are not to exceed the time required to correct the limited emergent plant situation(s) to restore at least one RPS bus to normal power supply. A loss of power to either motor generator set is monitored in the main control room (white indicating lamp goes off) where the operator, on detecting such a condition, can switch over to the alternate power source. A loss of power to one motor generator set results in a single RPS trip system trip. A persistent loss of electrical power to both motor generator sets (1 sec minimum)
 
results in a scram. 8.3.1.1.3.9 Adequacy of Electrical Distribution System Voltages  16 Two completely separate schemes of undervoltage protection are provided on the Division I and II Class 1E buses at the 4.16-kV level. The selection of undervoltage and time delay setpoints has been determined from an analysis of the voltage requirements of the Class 1E loads. These setpoints are verified during
 
surveillance testing.
16 The first undervoltage scheme detects loss of power at the Class 1E buses. This undervoltage setpoint is set below any anticipated transient voltage condition, with a time delay of
 
approximately 3 seconds. The second level of undervoltage protection is set at approximately 90 percent and utilizes two separate time delays
 
based on the following conditions:
1.The first time delay is approximately 5 sec, which establishes a sustained degraded voltage condition (i.e., something longer than a motor starting transient).
Following this delay, an alarm in the main control room alerts the operator to the degraded condition.
The subsequent occurrence of a LOCA signal immediately separates the Class 1E distribution system RBS USAR Revision 25 8.3-22a from the offsite power system, starts load shed logic and load sequence timers, starts the diesel generator, and permits auto-close of the diesel generator breaker. 13 2.The second time delay is approximately 60 sec, which ensures that permanently connected Class 1E loads will
 
not be damaged. Following this time 13 RBSUSAR8.3-23August1987delay,iftheoperatorhasfailedtorestoreadequatevoltages,theClass1Esystemisautomatically separatedfromtheoffsitepowersystem,theloadshed logicandloadsequencetimersstart,andthediesel generatorstartsandpermitsauto-closeofthediesel generatorbreaker.Undervoltageprotectionisaffordedtotheacdistributionsystemdowntoandincludingthe480-Vmotorcontrolcenters(MCCs) level.Thetrippingofthe4.16-kVaircircuitbreakers(ACBs) discussedabovealsoresultsinnovoltageatthe480-Vload centersandMCCswhich,inturn,willcausemotorfeederACBsand contactstoopencircuit.Subsequentenergizationofthe4.16-kV busesbythedieselgeneratorresultsinthere-energizationof MCCmotorloadswiththeclosingoftheircontactsat approximately70percentvoltage.Thevoltagesensorsaredesignedtosatisfythefollowingapplicablerequirements:1.Class1EequipmentisutilizedandisphysicallylocatedatandelectricallyconnectedtotheClass1E
 
switchgear.2.AnindependentschemeisprovidedforDivisionIandIIoftheClass1Epowersystem.3.Theundervoltageprotectionincludescoincidencelogic(2outof3)onaper-busbasistoprecludespurious tripsoftheoffsitepowersource.4.Thevoltagesensorsautomaticallyinitiatethedisconnectionofoffsitepowersourceswheneverthe voltagesetpointandtimedelaylimitshavebeen
 
exceeded.5.Capabilityfortestandcalibrationduringpoweroperationisprovided.Undervoltagerelaysettingson theClass1E4.16-kVbusescanbecheckedduringplant operationbytestingonesingle-phaseundervoltage relayatatime.Disconnectingonephaseofthethree-phasesystemdoesnotimpairtheoperationofthe switchgear.Normallyatwo-out-of-threelogic,the removalofonerelayresultsinaneffectiveone-out-of-twologic,i.e.,anundervoltagedetectedbyanyone ofthetworemainingrelaysstillinthecircuitwould initiateanundervoltagetrippingsequence.The removedrelaycanthenbecheckedagainsta RBSUSARRevision68.3-24August1993variablevoltagetestinputtoverifyitsintended setpoint.6.Annunciationisprovidedinthecontrolroombyanybypassesincorporatedinthedesign.TheClass1Ebusloadsheddingschemeautomaticallypreventssheddingduringsequencingoftheemergencyloadstothebus.
Theloadsheddingfeatureisreinstateduponcompletionofthe loadsequencingaction.Thevoltagelevelsatthesafety-relatedbusesareoptimizedforthemaximumandminimumloadconditionsthatareexpected throughouttheanticipatedrangeofvoltagevariationsofthe offsitepowersources.Thetripsettingsselectedarebasedon ananalysisofthevoltageattheterminalsoftheClass1E loads.Theanalysesperformedtodetermineminimumoperating voltagesconsidermaximumunitsteadystateandtransientloads foreventssuchasaunittrip,lossofcoolantaccident, startup,orshutdown,withtheoffsitepowersupply(grid)at minimumanticipatedvoltageandonlytheoffsitesourcebeing consideredavailable.Maximumvoltagesareanalyzedwiththe offsitepowersupplyatmaximumexpectedvoltageconcurrentwith minimumunitloads.1Theanalyticaltechniquesandassumptionsusedinthevoltage analysiswereverifiedbyactualmeasurement.Theverification andtestwereperformedpriortoinitialfull-powerreactor operationonallsourcesofoffsitepowerby:
11.Loadingthestationdistributionbuses,includingallClass1Ebusesdowntothe120/240Vlevel,toatleast 30percent.2.RecordingtheexistinggridandClass1Ebusvoltagesandbusloadingdowntothe120/240Vlevelatsteady stateconditionsandduringthestartingofbotha largeClass1Eandnon-Class1Emotor(not
 
concurrently).63.Usingtheanalyticaltechniquesandassumptionsofthevoltageanalysisabove,andthemeasuredexistinggrid voltageandbuslosingconditionsrecordedduring conductofthetest,anewsetofvoltagesforallthe Class1Ebusesdowntothe120/240Vlevelwas
 
calculated.
6 RBS USAR Revision 17 8.3-25 6 4. The analytically derived voltage values were compared against the test results.
6Two completely separate schemes of undervoltage protection are provided on the Division III Class 1E HPCS bus at the 4.16-kV level. The selection of undervoltage and time delay setpoints has been determined from an analysis of the voltage requirements of the Class 1E loads. These setpoints will be verified during the actual system testing. The first and second level
 
undervoltage protection scheme senses voltage at the incoming
 
side of the normal supply breaker. 13The first level undervoltage setpoint is set below any anticipated transient voltage condition, with a time delay of
 
approximately 3 sec.
The second level of undervoltage protection is set at approximately 90 percent of normal voltage and utilizes two
 
separate time delays based on the following conditions: 1. The first time delay is approximately 5 sec and establishes a sustained degraded voltage condition (i.e., something longer than a motor starting transient). Following this delay, an alarm in the main
 
control room alerts the operator to the degraded condition. The subsequent occurrence of a LOCA signal immediately separates the Division III HPCS bus from the offsite power system. The Division III HPCS bus
 
will experience a loss of voltage and the primary
 
undervoltage relays and control circuit will start load shed logic, start the diesel generator, and permit
 
auto-close of the diesel generator breaker when the
 
diesel generator attains its rated speed, voltage, and
 
frequency.
132. The second time delay is approximately 60 sec and is set to ensure that permanently connected Class 1E loads will not be damaged. Following this time delay, if the operator has failed to restore adequate voltages, the Division III HPCS bus is automatically separated from the offsite power system. The Division III HPCS bus
 
will experience a loss of voltage and the primary
 
undervoltage relays and control circuit will start the
 
load shed logic, start the diesel generator, and permit
 
auto-close of the diesel generator breaker when the
 
diesel generator attains its rated speed, voltage, and
 
frequency.
RBSUSAR8.3-26August1987Undervoltageprotectionisaffordedtotheacdistributionsystemdowntoandincludingthe480-Vmotorcontrolcenter(MCC)level.
Thetrippingofthe4.16-kVoffsitepowersupplycircuitbreaker discussedabovealsoresultsinnovoltageatthe480-VMCCbus which,inturn,willcausemotorfeedercontactorstodropout.
Subsequentenergizationofthe4.16-kVHPCSbusbythediesel generatorresultsinthereenergizationof480-VMCCbus.Auto-closerinterlockswilloperatethecontactorsatapproximately 70percentvoltagetoenergizethemotorloads.Thevoltagesensorsaredesignedtosatisfythefollowingapplicablerequirements:1.Class1EequipmentisutilizedandisphysicallylocatedatandelectricallyconnectedtotheClass1E
 
switchgear.2.AnindependentschemeisprovidedfortheDivisionIIIClass1EHPCSpowersystem.3.Thesecondlevelofundervoltageprotectionincludescoincidencelogic(2outof2)toprecludespurious tripsoftheoffsitepowersource.4.Thevoltagesensorsautomaticallyinitiatethedisconnectionofoffsitepowersourceswheneverthe voltagesetpointandtimedelaylimitshavebeen
 
exceeded.5.Capabilityfortestandcalibrationduringpoweroperationisprovided.6.Annunciationisprovidedinthecontrolroombyanybypassesincorporatedinthedesign.TheClass1EHPCSbusloadsheddingschemeautomaticallypreventssheddingduringsequencingoftheemergencyloadstothebus.
Theloadsheddingfeatureisreinstateduponcompletionofthe loadsequencingaction.ThevoltagelevelsattheHPCSbusareoptimizedforthemaximumandminimumloadconditionsthatareexpectedthroughoutthe anticipatedrangeorvoltagevariationsoftheoffsitepower sources.Thetripsettingsselectedarebasedonananalysisof thevoltageattheterminalsoftheClass1Eloads.Theanalyses performedtodetermineminimumoperatingvoltagesconsider maximumunitsteadystateandtransientloadsforeventssuchas unittrip,lossofcoolantaccident,startup,orshutdown,with
 
the offsite RBSUSARRevision98.3-27November1997powersupply(grid)atminimumanticipatedvoltageandonlytheoffsitesourcebeingconsideredavailable.Maximumvoltagesare analyzedwiththeoffsitepowersupplyatmaximumexpected voltageconcurrentwithminimumunitloads.6Theanalyticaltechniquesandassumptionsusedinthevoltage analysiswereverifiedbyactualmeasurement.Theverification andtestwillbeperformedpriortoinitialfull-powerreactor operationonallsourcesofoffsitepowerby:
61.Loadingthestationdistributionbuses,includingallClass1Ebusesdowntothe120-Vlevel,toatleast30
 
percent.2.RecordingtheexistinggridandClass1Ebusvoltagesandbusloadingdowntothe120-Vlevelatsteady-state conditionsandduringthestartingofalargeClass1E HPCSpumpmotor.63.Usingtheanalyticaltechniquesandassumptionsofthevoltageanalysisabove,andthemeasuredexistinggrid voltageandbusloadingconditionsrecordedduring conductofthetest,anewsetofvoltagesforthe Class1EHPCSbusdowntothe120-Vlevelwas
 
calculated.4.Theanalyticallyderivedvoltagevalueswerecomparedagainstthetestresults.
68.3.1.1.3.10ControlInterlocksforACElectricalCircuitsControlcircuitsofall4.16-kVcircuitbreakersand480-Vloadcenterbreakersinsafety-relatedsystemswerereviewedto determineifinadvertentoperationofothercomponentsinthe sameorothersystemsresultedwhenthecircuitbreakerfora particularcomponentwasrackedouttothetestpositionor operatedinthetestposition.Theresultsofthisreviewhave beensummarizedandverifythatthepresentdesignofelectrical controlcircuitryforRBSdoesnotresultinanyinadvertent
 
operations.91.Inthecaseof4.16-kVcircuitbreakers,interlocktoothercomponentsisachievedusingbreakerauxiliary switchcontacts.Theoperationoftheinterlocked circuitryiscontrolledadministrativelywhenthe circuitbreakerisoperatedinthetestposition.
9 RBSUSAR8.3-28August19872.Inthecaseof480-Vloadcenterbreakers,interlocktoothercomponentsisachievedusingthecontactsofan auxiliaryrelayinthebreakercontrolcircuit.A breakerhousinglimitswitchcontactisusedtolock outthisrelayintherackedoutpositionofthe
 
breaker.3.13.8kVcircuitbreakersarenotusedtocontrolpowertoanysafety-relatedsystemsorcomponents.4.Inthecaseofmotorcontrolcenters,interlocktoothersystemcomponentsisachievedusingauxiliary relaysintheircontrolcircuits.Testingofmotor controlcentersdoesnotresultinanyinadvertent operationofothersystemcomponents.5.120-Vac/dccircuitbreakersdonotprovideanyinterlockstoothersystemcomponents.8.3.1.1.4SystemProtectionandSurveillance Transformerswiththeirlowvoltagewindingatorabove4.16kV,except1STX-XS3Aand1STX-XS3Batthemakeupwaterarea,have differentialprotection.All4.16-kVand13.8-kVacmotorcircuitshavephasetimeovercurrentrelayswithinstantaneoustripssetabovelocked rotorlevels.Also,4.16-kVand13.8-kVmotorshavetimeover-currentgroundrelaying.Thereactorfeedpumpmotorsandthe reactorrecirculatingpumpmotorswiththeirdedicated transformershavedifferentialprotection.Circuitrelaysare coordinatedwiththoseatthesource.Breakersatthe480-Vlevelhavetime-overcurrenttripping.Allmoldedcasebreakersinmotorcontrolcentersandthededicated motorsupplybreakersin480-Vloadcentershaveinstantaneous shortcircuittrippingdevicessetabovemotorinrushcurrent level.Breakersin480-Vloadcentersservingmotorcontrol centershaveminimumtimedelayonshortcircuits;thoseusedin bus-tieservicehaveintermediatetimedelay;andthoseinmain supplyservicehavemaximumtimedelayonshortcircuits.Load centersinstandbyservicehave480-Vbreakersinthemain supply.Thetrippingselectivityoutlinedandappropriatechoice ofrelaysandthermaltrippingdevicesfacilitateapplicationof therequiredcoordinationofprotection.
RBSUSAR8.3-29August19878.3.1.1.4.1StandbyDieselGeneratorsTheprotectionsystemofstandbydieselgeneratorsisdescribedasfollows(seelogicdiagrams,Figure7.3-23,sheets17through
 
28):1.Thestandbydieselgeneratorisrenderedincapableofrespondingtoanemergencyautostartsignalduringany dieselgeneratoroperationalcondition(including testingandoperationfromthelocalcontrolpanel)by thefollowingconditions:a.Dieselcontrolpanellossofcontrolpower b.Startingairpressurelow c.Stopsolenoid1EGS*SOV24Aor1EGS*SOV24B,for1EGS*EG1Aor1EGS*EG1B,respectively,energized.
Thedieselgeneratorstopsolenoidisenergized andsealedinwheneverthemanualstoppushbuttons areoperatedorthedieselgeneratorprimaryor backupprotectionrelaysaretripped.Thestop solenoidissealedintopreventanautomatic dieselgeneratoremergencystartoccurringbefore allthedieselgeneratorcontrolsandprotection devicesareresettonormaloperatingconditions.
Thelocalcontrolroomormaincontrolroom operatorcandeenergizethedieselgeneratorstop solenoidbyoperatingtheSTOPRESETpushbutton provided,oneineachcontrolroom.d.Dieselinthemaintenancemode(includesbarringdeviceengaged)e.Overspeedtripdeviceactuated f.Generatorbackupprotectionlockoutrelaytripped g.Generatorprimaryprotectionlockoutrelaytripped2.Thestandbydieselgeneratorunitistrippedunderthefollowingconditionsduringbothnormalandemergency
 
operation:
a.Engineoverspeed RBS USAR Revision 22 8.3-30 16 b. Both STOP pushbuttons manually operated. For each standby diesel generator unit, two pushbuttons are
 
located at both the main control room and at the
 
local control panel. The two pushbuttons are
 
arranged such that the operator must use both hands
 
to simultaneously operate both pushbuttons in the main control room. The operator can operate both
 
pushbuttons with one hand at the local panel.
16 c. Generator differential relay trip
: d. Extreme high jacket water temperature and high lube oil temperature trips are active unless a LOCA signal is present or manually bypassed by a local control switch (Applicable to EGS-EG1A and EGS-EG1B ONLY). 3. The standby diesel generator unit is tripped under the following conditions during normal operation only.
: a. Generator voltage controlled - inverse time phase overcurrent
: b. Generator reverse power
: c. Generator loss of field
: d. Extreme high jacket water temperature trip
: e. High bearing temperature trip
: f. Extreme low jacket water pressure trip
: g. High crankcase pressure trip
: h. Trip low turbo oil pressure
: i. Trip high vibration
: j. Trip high temperature lube oil
: k. Low lube oil pressure trip
: l. Generator ground overcurrent
: 4. Protective functions of each standby diesel generator are annunciated locally in each of the standby diesel
 
generator control rooms.
 
The following alarms are separated into subsystem groups. Each subsystem group is provided with a "first
 
out" indication as per Regulatory Guide 1.9.
RBS USAR Revision 16 8.3-31 March 2003 a. Diesel engine lube oil subsystem (see Figure 7.3-17)(1) Lube oil filter differential pressure high (2) Lube oil strainer differential pressure high (3) Turbo oil pressure low (4) Lube oil pressure low (5) Turbo oil low pressure - TRIP (6) Lube oil low pressure - TRIP (7) Crankcase high pressure - TRIP (8) Lube oil outlet temperature high (9) Lube oil inlet temperature high (10) Lube oil outlet temperature low (11) Lube oil inlet temperature low (12) Lube oil tank level high (13) Lube oil tank level low (14) Lube oil outlet high temperature - TRIP 16(15) Bearing oil high temperature - TRIP 16b. Diesel engine fuel oil subsystem (see Figure 7.3-15)(1) Fuel oil storage tank level low (2) Diesel engine strainer differential pressure high(3) Fuel oil day tank level extreme low (4) Fuel oil day tank level extreme high (5) Fuel oil filter differential pressure high (6) Fuel oil pump overspeed drive failure RBS USAR Revision 16 8.3-32 March 2003 (7) Fuel oil pressure low 1614c. Diesel engine jacket water subsystem (see Figure 7.3-23) 14 16(1) Jacket water pressure low (2) Jacket water extreme low pressure - TRIP (3) Jacket water outlet temperature extreme high  - TRIP  (4) Jacket water outlet temperature high (5) Jacket water inlet temperature high (6) Jacket water outlet temperature low (7) Jacket water inlet temperature low (8) Jacket water level low d. Diesel engine air start subsystem (see Figure 7.3-16) (1) Start air receiver pressure low (2) Control air pressure low (3) Diesel start air pressure low e. Diesel generator subsystem (see Figure 7.3-23, Sheets 22 and 28) (1) Standby generator differential - TRIP (2) Standby generator fault - TRIP (3) Standby generator ground fault (4) Standby generator loss of field The following standby diesel generator protective functions are annunciated individually: 15 a. DELETED
: b. DELETED 15c. Emergency exhaust fan trouble RBS USAR Revision 22 8.3-33 d. Auxiliary systems not in auto 16 e. Bearing high temperature - TRIP 16 f. Fuel oil strainer differential pressure high  
: g. Fuel oil dc pump running  
: h. After cooler water inlet temperature high  
: i. Barring device engaged  
: j. Diesel start air pressure high  
: k. Unit start failure  
: l. Vibration - TRIP  
: m. Overspeed - TRIP  
: n. 4160 Standby bus distribution breakers auto -TRIP  
: o. Diesel generator potential circuit blown fuse  
: p. 4160 Standby bus undervoltage  
 
In addition to the above-listed annunciators, the  
 
following standby diesel generator conditions are also  
 
indicated in each diesel generator control room: 14 a. Unit available emergency status - white light on
: b. AC control power - white light on
: c. DC control power - white light on
: d. Ready to load - white light on
: e. Unit tripped - amber light on 14 f. At synchronous speed - red light on
: g. Starting - red light on
: h. Shutdown system active - red light on
: i. High t emperature bypass switch, o perate - white light on, Bypass - amber light on (Applicable to EGS-EG1A and EGS-EG1B ONLY).
: 5. The following remote annunciation is provided in the main control room for each standby diesel RBS USAR Revision 16 8.3-34 March 2003 8 generator (1EGS*EG1A and 1EGS*EG1B). Window engraving for the cited condition is exact wording. The events
 
which cause the window to annunciate are also listed.
8a. "STANDBY DIESEL GENERATOR 1EGS*EG1A INOPERATIVE"  16 Actuated by the following conditions. These conditions are also provided with individual amber lights in the main control room (except for items 8 and 10 which have system level input only). The following describes the wording
 
engraved on the associated amber light window and
 
the failed or inoperative condition.
16(1) "LOSS OF CONT. PWR. FWD/REAR ST. CKT." -Both forward and rear air start 125-V dc control
 
power failed.(2) "LOSS OF FORWARD AND REAR ST. AIR" - Both forward and rear starting air failure.(3) "MAINT. MODE L.O. SOL. ENERGIZED" - Local control room maintenance mode selector switch
 
and main control room diesel engine mode
 
selector switch in the MAINTENANCE position.(4) "DSL. ENG. OVERSPEED TRIP" - Diesel engine overspeed device actuated.(5) "STBY GEN. DIFF./FAULT TRIP" - Diesel generator primary or backup protection
 
lockout relays tripped.(6) "DSL ENG. STOP SOLENOID ENERGIZED" -Manual stop pushbuttons operated, or diesel
 
generator primary, or backup protection
 
relays tripped. 1  1 RBS USAR  8.3-35 August 1988 1(7) "GEN/EXC. LOSS OF DC CONT. POWER" - Loss of the diesel generator exciter and regulator
 
125-V dc control circuit. (8) "LOSS OF EXCITER FIELD DC PWR." - Loss of 125-V dc power to the diesel generator field
 
winding.(9) "DIESEL GEN. MANUALLY BYPASSED" -Manually-operated switch, operated whenever any diesel
 
generator system controls or protection
 
devices are deliberately bypassed. (10) "AUX. CKT. LOSS OF CONTROL POWER" - Loss of 125-V dc to the diesel generator inoperative
 
annunciator control circuit.
1b. "DIESEL GEN. 1A PT BLOWN FUSE" - Actuated when the diesel generator breaker is closed, and the backup
 
protection lockout relay is reset, and any one of
 
the diesel generator potential transformer primary
 
fuses are blown.c. "4160-V STANDBY BUS DISTR. BREAKER INOPERATIVE" -
This annunciator window is a common alarm point actuated by any one of the following conditions. 
 
These conditions also actuate a common inoperative amber light titled, "4.16 STBY. BUS DISTR. BREAKER
 
INOPERATIVE." The conditions are: (1) Loss of 125-V dc control power.
(2) Loss of breaker control circuit blown fuse.
(3) Breaker not in operate position.
(4) Breaker lockout relay tripped.
 
The 4160-V standby bus distribution breakers associated with this common alarm point are: (1) 4.16-kV Bus 1A Normal Supply RBS USAR Revision 16 8.3-36 March 2003 (2) 4.16-kV Bus 1A Alternate Supply  (3) 4.16-kV Bus 1A Generator Supply (4) 4.16-kV Bus 1A Generator Neutral Breaker (5) 480 V LDC 1A Supply (6) 480 V LDC 2A Supply  d. "4160-V STANDBY BUS DISTR. BREAKER AUTO TRIP" - This annunciator window is a common
 
alarm actuated when the local or remote
 
breaker control switch is in the AFTER START
 
position and the breaker is automatically
 
tripped open.This condition also actuates the amber light associated with each breaker control switch.
 
The 4160-V standby bus distribution breakers are listed in Section 8.3.1.1.4.1, Item 5c
 
above.1615e. "STBY DIESEL GEN. TROUBLE" - This annunciator window is a common alarm actuated by the conditions listed in Section 8.3.1.1.4.1, Items 4.a.1 through 4.a.14, Item 4.b.2, Items 4.b.5 through 4.b.7, Items 4.c.1 through 4.c.8, Items 4.d.1 through
 
4.d.3, Items 4.e.1 through 4.e.4, plus items e
 
through m of the protective functions listed as
 
annunciated individually.
15 161f. "DIESEL FUEL OIL STORAGE TANK LEVEL LOW" 1g. "DIESEL FUEL OIL DAY TANK EXTREME LOW LEVEL" -This annunciator window is actuated from a switch receiving an input signal from the fuel oil day
 
tank level transmitter.h. "4 kV STBY BUS NORMAL & ALT SUPPLY BKRS CLOSED" -
This annunciator is actuated when 15 sec after both normal and alternative supply breakers close on 4-
 
kV standby bus.i. "4 kV STBY BUS DISTR BKR AUTO TRIP" - This annunciator is actuated when diesel generator
 
breaker trips automatically.
RBS USAR Revision 22 8.3-37 j. "4 kV STBY DSL GEN. NEUTRAL BKR AUT TRIP" -This annunciator is actuated when diesel generator
 
neutral breaker trips automatically. 
: k. "DSL. GEN BACKUP PROT. ACTIVATED" - This annunciator is actuated on reverse power, ground
 
overcurrent, controlled-inverse time phase
 
overcurrent, and loss-of-field faults (when diesel
 
generator breaker is closed). 
: l. "DSL GEN PROT CKT LOSS OF CONT. PWR" - This annunciator is actuated when control power of
 
diesel generator protection circuit is lost.
: m. "STBY DIESEL GEN HIGH TEMP TRIPS MAN BYPASSED" is actuated when the local bypass switch is in the "BYPASS" position (Applicable to EGS-EG1A and EGS-EG1B ONLY).
: 6. Each standby diesel generator set is capable of being emergency started in the operational mode from the main control room as well as the standby diesel generator control room near the engines. There is no transfer
 
scheme between these two locations, since the emergency start controls are in parallel. Normal start controls
 
are on the local engine control panel only in the
 
standby diesel generator control room near the engines (Fig. 8.3-11).
: 7. All standby diesel generator parameters that are bypassed under accident conditions are annunciated in each standby diesel generator control room. These
 
annunciators are located on the associated standby
 
diesel engine control panel.
: 8. All conditions that render the standby diesel generator incapable of responding to an automatic start signal
 
are annunciated in the main control room.
 
8.3.1.1.4.1.1 Qualification Testing
 
In accordance with Branch Technical Position EICSB-2, Diesel
 
Generator Reliability Qualification Testing, the standby diesel
 
generator manufacturer, Delaval Engine and Compressor Division, has performed a series of qualification tests to verify
 
compliance with the requirements of the above-referenced NRC BTP.
 
Surveillance instrumentation is provided to monitor the status of the power supply and starting equipment of each standby generator. Instrumentation and control are essential
 
requirements in the design, installation, testing, operation, and maintenance of the standby generator. All RBSUSAR8.3-38August1987conditionswhichcanaffectperformanceorindicateunavailabilityofeachstandbygeneratorareannunciatedinthe maincontrolroom.Localindicatorsandcontrolsofeachdiesel generatorarelocatedwithintheirrespectiverooms.Remote indicatorsandcontrolsarelocatedinthemaincontrolroomon separatesectionsofthecontrolboard.Additionalinformationon instrumentationandcontrolsispresentedinSection7.3.1.The controlsandinstrumentcablesareroutedtopreventcommon failure.Allcontrolswitchesonthemaincontrolboardare clearlyidentifiedastotheequipmentthateachswitchcontrols (Section7.1.2.3).FactorytestingofthestandbyacpowersystemswasperformedasdefinedinIEEE-387,CriteriaforDiesel-GeneratorUnitsApplied asStandbyPowerSuppliesforNuclearPowerGeneratingStations.Standbydieselgenerator1EGS*EG1Awasgiven37startqualificationtestsinaccordancewithIEEE387andIEEE323at theTDIfactory.Eachstartverificationtestwasperformedfrom astandbytemperatureof150°F-10°Fandincludedpickupof 1,750kWwithin10secofthestartsignal(therewerenostart failures).VariousadditionalTDIfactoryqualificationtests wereperformedforbothstandbydieselgeneratorsasdiscussedin Item2ofReference3.Inaddition,qualificationtestswere performedatRiverBendStationinaccordancewithRegulatory Guide1.9,ParagraphsC.13andC.14,andRegulatoryGuide1.108, asdiscussedinSection8.3.1.1.5.2.8.3.1.1.4.2HighPressureCoreSprayPowerSupplySystem TheprotectionsystemoftheHPCSdieselgeneratorisdescribedasfollows:1.ThefollowingconditionsrendertheHPCSdieselgeneratorincapableofrespondingtoanautomatic emergencystartsignal:a.Dieselgeneratorlockoutrelaysnotreset.
b.Dieselenginemodeswitchnotin"AUTO"position(modeswitchin"MAINTENANCE"or"TEST"position).c.Dieselgeneratoroutputbreakerclosedbeforestartofdiesel.
RBSUSAR8.3-39August1987d.Dieselgeneratoroutputbreakerinracked-out position.e.Dieselgeneratorregulatormodeswitchnotin"AUTO"position.f.Insufficientstartingairpressure.
g.Lossofdcpowertodieselgeneratorcontrolsorthe4,160Vswitchgear.h.Dieselenginetrip/lockoutrelaynotreset.
i.Lowfueloillevelindaytank.
Itemseandidonotelectricallyblockdieselgeneratorfromemergencystarting;however,these conditionsarechecked,andcorrectedifnecessary, priortoallowingdieselgeneratortorespondtoan automaticemergencystartsignal.2.Thefollowingalarmsareprovidedatthemaincontrolroomannunciatorforabove-listedconditions.a.Itemsa,b(modeswitchin"TEST"),d,e,f,andgareannunciatedas"HPCSSYSTEMNOTREADYFORAUTO
 
START".b.Itemcisindicatedbymeansofbreakerstatuslight(RED).c.Itemb(modeswitchin"MAINTENANCE")isannunciatedas"DIESELENGINEINMAINTENANCE."d.Itemhisannunciatedas"DIESELENGINETRIP" alarm.e.Itemiisannunciatedas"DIESELENGINETROUBLE"alarm(commonalarm).3.ThefollowingHPCSdieselgeneratoremergencyconditionsareannunciatedlocallyonthediesel generatorcontrolpanelandasacommon"DIESELENGINE TROUBLE"alarminthecontrolroom:a.Enginefailuretostart/run b.Engineoverspeed RBSUSAR8.3-40August1987c.Lowfuelleveld.Crankcasepressurehigh e.Highlubeoiltemperature f.Highwatertemperature g.Chargerfailure h.Enginetripped i.Mainfuelpumpfailure j.Lowlubeoiltemperature k.Lowexpansiontankwaterlevel l.Highstatortemperature m.Reservefuelpumpfailure n.Lowlubeoilpressure o.Lowcoolingwaterpressure p.Lowturbochargerlubeoilpressure q.Restrictedfueloilfilter r.Restrictedlubeoilfilter s.Lowstartingairpressure t.Controlpowerfailure u.DCturbolubeoilpumprunning v.DCcirculatinglubeoilpumprunning.4.Thefollowingadditionalalarmsalsoareprovidedinthecontrolroom:a.HPCS4-kVbusautotrip b.HPCSsystemundervoltage c.HPCSpumpmotorovercurrent d.Dieselenginerunning RBSUSAR8.3-41August1987e.125-Vdcsystemtroublef.HPCSbatterychargertrouble g.Generatortrip/lockout h.Dieselenginegeneratorovercurrent i.HPCSsystemground j.HPCS480-Vsystemundervoltage k.DivisionIIIdegradedvoltage l.Dieselengineoverspeed m.HPCScontrolpowerfailureorbreakerinlower positionn.Remoteshutdowntransferswitchinemergency position.WhentheHPCSdieselgeneratoriscalledupontooperateunderaccidentconditions,theonlyprotectivedevicesusedarethe generatordifferentialrelaysandengineoverspeedtripdevice.
Theengineoverspeedtripdeviceismechanicalandtripsthe enginedirectly.Thetripsareannunciatedinthemaincontrol room.Otherprotectiverelays,suchaslossofexcitation,anti-motoring(reversepower),overcurrentwithvoltagerestraint, highjacketwatertemperature,andlowlubeoilpressure,are usedtoprotectthemachinewhenitisoperatingduringperiodic tests.Theserelaysareautomaticallyremovedfromthetripping circuitsunderaccidentconditions.Inadditiontothese protectiverelays,anormaltimedelayovercurrentrelaysenses generatoroverloadandcausesanalarminthemaincontrolroom.
Thegeneratordifferentialrelaysandoverspeedtripdeviceare retainedunderaccidentconditionstoprotectagainstwhatcanbe majorfaultswhichcouldcausesignificantdamage.Allthe bypassedprotectivedevicescausealarmsinthemaincontrolroom andtheoperatorthenhassufficientinformationtotake necessarycorrectiveaction.Becauseduringaccidentconditions theHPCSdieselgeneratorisperformingasafety-related function,theseprotectivedevicesareinsignificantsofaras theengineconditionisconcerned.Theengineiscapableof operatingundertheseabnormalconditions,anditislefttothe operator'sjudgmentwhethertooperatetheengineortripit
 
manually.
RBS USAR Revision 16 8.3-42 March 2003 8.3.1.1.4.2.1  Qualification Testing A prototype test has been performed to establish the adequacy of the diesel generator unit to successfully accelerate the HPCS pump and system loads. The test consists of starting an HPCS


system in an actual HPCS pump loop test (HPCS system in  
RBS USAR Revision 16 8.3-34 March 2003
8 generator (1EGS*EG1A and 1EGS*EG1B). Window engraving for the cited condition is exact wording. The events which cause the window to annunciate are also listed.
8
: a.
"STANDBY DIESEL GENERATOR 1EGS*EG1A INOPERATIVE"
16 Actuated by the following conditions. These conditions are also provided with individual amber lights in the main control room (except for items 8 and 10 which have system level input only). The following describes the wording engraved on the associated amber light window and the failed or inoperative condition.
16
(1) "LOSS OF CONT. PWR. FWD/REAR ST. CKT." -Both forward and rear air start 125-V dc control power failed.
(2) "LOSS OF FORWARD AND REAR ST. AIR" - Both forward and rear starting air failure.
(3) "MAINT. MODE L.O. SOL. ENERGIZED" - Local control room maintenance mode selector switch and main control room diesel engine mode selector switch in the MAINTENANCE position.
(4) "DSL. ENG. OVERSPEED TRIP" - Diesel engine overspeed device actuated.
(5) "STBY GEN.
DIFF./FAULT TRIP" Diesel generator primary or backup protection lockout relays tripped.
(6) "DSL ENG. STOP SOLENOID ENERGIZED" -Manual stop pushbuttons
: operated, or diesel generator
: primary, or backup protection relays tripped.
1 1


condensate to condensate test mode) with auxiliary loads several times within the design time requirement. A topical report on
RBS USAR 8.3-35 August 1988
1 (7) "GEN/EXC. LOSS OF DC CONT. POWER" - Loss of the diesel generator exciter and regulator 125-V dc control circuit.
(8) "LOSS OF EXCITER FIELD DC PWR." - Loss of 125-V dc power to the diesel generator field winding.
(9) "DIESEL GEN. MANUALLY BYPASSED" -Manually-operated switch, operated whenever any diesel generator system controls or protection devices are deliberately bypassed.
(10) "AUX. CKT. LOSS OF CONTROL POWER" - Loss of 125-V dc to the diesel generator inoperative annunciator control circuit.
1
: b.
"DIESEL GEN. 1A PT BLOWN FUSE" - Actuated when the diesel generator breaker is closed, and the backup protection lockout relay is reset, and any one of the diesel generator potential transformer primary fuses are blown.
: c.
"4160-V STANDBY BUS DISTR. BREAKER INOPERATIVE" -
This annunciator window is a common alarm point actuated by any one of the following conditions.
These conditions also actuate a common inoperative amber light titled, "4.16 STBY. BUS DISTR. BREAKER INOPERATIVE." The conditions are:
(1) Loss of 125-V dc control power.
(2) Loss of breaker control circuit blown fuse.
(3) Breaker not in operate position.
(4) Breaker lockout relay tripped.
The 4160-V standby bus distribution breakers associated with this common alarm point are:
(1) 4.16-kV Bus 1A Normal Supply


HPCS power system unit, NEDO-10905, and subsequent amendments describe and show theoretical and experimental evidence as to the adequacy of the design. The topical report has been further
RBS USAR Revision 16 8.3-36 March 2003 (2) 4.16-kV Bus 1A Alternate Supply (3) 4.16-kV Bus 1A Generator Supply (4) 4.16-kV Bus 1A Generator Neutral Breaker (5) 480 V LDC 1A Supply (6) 480 V LDC 2A Supply
: d.
"4160-V STANDBY BUS DISTR.
BREAKER AUTO TRIP" - This annunciator window is a common alarm actuated when the local or remote breaker control switch is in the AFTER START position and the breaker is automatically tripped open.
This condition also actuates the amber light associated with each breaker control switch.
The 4160-V standby bus distribution breakers are listed in Section 8.3.1.1.4.1, Item 5c above.
16 15
: e.
"STBY DIESEL GEN. TROUBLE" - This annunciator window is a common alarm actuated by the conditions listed in Section 8.3.1.1.4.1, Items 4.a.1 through 4.a.14, Item 4.b.2, Items 4.b.5 through 4.b.7, Items 4.c.1 through 4.c.8, Items 4.d.1 through 4.d.3, Items 4.e.1 through 4.e.4, plus items e through m of the protective functions listed as annunciated individually.
15 16
1
: f.
"DIESEL FUEL OIL STORAGE TANK LEVEL LOW" 1
: g.
"DIESEL FUEL OIL DAY TANK EXTREME LOW LEVEL" -This annunciator window is actuated from a switch receiving an input signal from the fuel oil day tank level transmitter.
: h.
"4 kV STBY BUS NORMAL & ALT SUPPLY BKRS CLOSED" -
This annunciator is actuated when 15 sec after both normal and alternative supply breakers close on 4-kV standby bus.
: i.
"4 kV STBY BUS DISTR BKR AUTO TRIP" - This annunciator is actuated when diesel generator breaker trips automatically.  


amended to include the results of the prototype qualification  
RBS USAR Revision 22 8.3-37
: j.
"4 kV STBY DSL GEN. NEUTRAL BKR AUT TRIP" -This annunciator is actuated when diesel generator neutral breaker trips automatically.
: k.
"DSL.
GEN BACKUP PROT.
ACTIVATED" This annunciator is actuated on reverse power, ground overcurrent, controlled-inverse time phase overcurrent, and loss-of-field faults (when diesel generator breaker is closed).
: l.
"DSL GEN PROT CKT LOSS OF CONT. PWR" - This annunciator is actuated when control power of diesel generator protection circuit is lost.
: m.
"STBY DIESEL GEN HIGH TEMP TRIPS MAN BYPASSED" is actuated when the local bypass switch is in the BYPASS position (Applicable to EGS-EG1A and EGS-EG1B ONLY).
: 6.
Each standby diesel generator set is capable of being emergency started in the operational mode from the main control room as well as the standby diesel generator control room near the engines. There is no transfer scheme between these two locations, since the emergency start controls are in parallel. Normal start controls are on the local engine control panel only in the standby diesel generator control room near the engines (Fig. 8.3-11).
: 7.
All standby diesel generator parameters that are bypassed under accident conditions are annunciated in each standby diesel generator control room. These annunciators are located on the associated standby diesel engine control panel.
: 8.
All conditions that render the standby diesel generator incapable of responding to an automatic start signal are annunciated in the main control room.
8.3.1.1.4.1.1 Qualification Testing In accordance with Branch Technical Position EICSB-2, Diesel Generator Reliability Qualification Testing, the standby diesel generator manufacturer, Delaval Engine and Compressor Division, has performed a series of qualification tests to verify compliance with the requirements of the above-referenced NRC BTP.
Surveillance instrumentation is provided to monitor the status of the power supply and starting equipment of each standby generator.
Instrumentation and control are essential requirements in the design, installation, testing, operation, and maintenance of the standby generator.
All


test cited above. 16 In order to comply with the requirements, the tests described in NEDO-10905, Section 6.6 have been performed.
RBS USAR 8.3-38 August 1987 conditions which can affect performance or indicate unavailability of each standby generator are annunciated in the main control room.
16Start and Load Reliability Test 1. Prior to initial fuel loading of the reactor unit, a series of tests will be conducted to establish the
Local indicators and controls of each diesel generator are located within their respective rooms.
Remote indicators and controls are located in the main control room on separate sections of the control board. Additional information on instrumentation and controls is presented in Section 7.3.1.
The controls and instrument cables are routed to prevent common failure.
All control switches on the main control board are clearly identified as to the equipment that each switch controls (Section 7.1.2.3).
Factory testing of the standby ac power systems was performed as defined in IEEE-387, Criteria for Diesel-Generator Units Applied as Standby Power Supplies for Nuclear Power Generating Stations.
Standby diesel generator 1EGS*EG1A was given 37 start qualification tests in accordance with IEEE 387 and IEEE 323 at the TDI factory.
Each start verification test was performed from a
standby temperature of 150°F
-10°F and included pickup of 1,750 kW within 10 sec of the start signal (there were no start failures).
Various additional TDI factory qualification tests were performed for both standby diesel generators as discussed in Item 2 of Reference 3.
In
: addition, qualification tests were performed at River Bend Station in accordance with Regulatory Guide 1.9, Paragraphs C.13 and C.14, and Regulatory Guide 1.108, as discussed in Section 8.3.1.1.5.2.
8.3.1.1.4.2 High Pressure Core Spray Power Supply System The protection system of the HPCS diesel generator is described as follows:
1.
The following conditions render the HPCS diesel generator incapable of responding to an automatic emergency start signal:
a.
Diesel generator lockout relays not reset.
b.
Diesel engine mode switch not in "AUTO" position (mode switch in "MAINTENANCE" or "TEST" position).
c.
Diesel generator output breaker closed before start of diesel.


capability of the HPCS diesel generator unit to  
RBS USAR 8.3-39 August 1987 d.
Diesel generator output breaker in racked-out position.
e.
Diesel generator regulator mode switch not in "AUTO" position.
f.
Insufficient starting air pressure.
g.
Loss of dc power to diesel generator controls or the 4,160 V switchgear.
h.
Diesel engine trip/lockout relay not reset.
i.
Low fuel oil level in day tank.
Items e and i
do not electrically block diesel generator from emergency starting;
: however, these conditions are
: checked, and corrected if necessary, prior to allowing diesel generator to respond to an automatic emergency start signal.
2.
The following alarms are provided at the main control room annunciator for above-listed conditions.
a.
Items a, b (mode switch in "TEST"), d, e, f, and g are annunciated as "HPCS SYSTEM NOT READY FOR AUTO START".
b.
Item c is indicated by means of breaker status light (RED).
c.
Item b
(mode switch in "MAINTENANCE")
is annunciated as "DIESEL ENGINE IN MAINTENANCE."
d.
Item h
is annunciated as "DIESEL ENGINE TRIP" alarm.
e.
Item i is annunciated as "DIESEL ENGINE TROUBLE" alarm (common alarm).
3.
The following HPCS diesel generator emergency conditions are annunciated locally on the diesel generator control panel and as a common "DIESEL ENGINE TROUBLE" alarm in the control room:
a.
Engine failure to start/run b.
Engine overspeed


consistently start and load within the required time. 2. With the exception of those diesel engine/generator designs that are identical (minor changes may be
RBS USAR 8.3-40 August 1987 c.
Low fuel level d.
Crank case pressure high e.
High lube oil temperature f.
High water temperature g.
Charger failure h.
Engine tripped i.
Main fuel pump failure j.
Low lube oil temperature k.
Low expansion tank water level l.
High stator temperature m.
Reserve fuel pump failure n.
Low lube oil pressure o.
Low cooling water pressure p.
Low turbocharger lube oil pressure q.
Restricted fuel oil filter r.
Restricted lube oil filter s.
Low starting air pressure t.
Control power failure u.
DC turbo lube oil pump running v.
DC circulating lube oil pump running.
4.
The following additional alarms also are provided in the control room:
a.
HPCS 4-kV bus auto trip b.
HPCS system undervoltage c.
HPCS pump motor overcurrent d.
Diesel engine running


justified by analysis) to the diesel generator unit(s)
RBS USAR 8.3-41 August 1987 e.
125-V dc system trouble f.
HPCS battery charger trouble g.
Generator trip/lockout h.
Diesel engine generator overcurrent i.
HPCS system ground j.
HPCS 480-V system undervoltage k.
Division III degraded voltage l.
Diesel engine overspeed m.
HPCS control power failure or breaker in lower position n.
Remote shutdown transfer switch in emergency position.
When the HPCS diesel generator is called upon to operate under accident conditions, the only protective devices used are the generator differential relays and engine overspeed trip device.
The engine overspeed trip device is mechanical and trips the engine directly.
The trips are annunciated in the main control room.
Other protective relays, such as loss of excitation, anti-motoring (reverse power),
overcurrent with voltage restraint, high jacket water temperature, and low lube oil
: pressure, are used to protect the machine when it is operating during periodic tests. These relays are automatically removed from the tripping circuits under accident conditions.
In addition to these protective relays, a normal time delay overcurrent relay senses generator overload and causes an alarm in the main control room.
The generator differential relays and overspeed trip device are retained under accident conditions to protect against what can be major faults which could cause significant damage.
All the bypassed protective devices cause alarms in the main control room and the operator then has sufficient information to take necessary corrective action.
Because during accident conditions the HPCS diesel generator is performing a
safety-related
: function, these protective devices are insignificant so far as the engine condition is concerned.
The engine is capable of operating under these abnormal conditions, and it is left to the operator's judgment whether to operate the engine or trip it manually.


which have been previously qualified for the HPCS  
RBS USAR Revision 16 8.3-42 March 2003 8.3.1.1.4.2.1 Qualification Testing A prototype test has been performed to establish the adequacy of the diesel generator unit to successfully accelerate the HPCS pump and system loads. The test consists of starting an HPCS system in an actual HPCS pump loop test (HPCS system in condensate to condensate test mode) with auxiliary loads several times within the design time requirement. A topical report on HPCS power system unit, NEDO-10905, and subsequent amendments describe and show theoretical and experimental evidence as to the adequacy of the design. The topical report has been further amended to include the results of the prototype qualification test cited above.
16 In order to comply with the requirements, the tests described in NEDO-10905, Section 6.6 have been performed.
16
Start and Load Reliability Test
: 1.
Prior to initial fuel loading of the reactor unit, a series of tests will be conducted to establish the capability of the HPCS diesel generator unit to consistently start and load within the required time.
: 2.
With the exception of those diesel engine/generator designs that are identical (minor changes may be justified by analysis) to the diesel generator unit(s) which have been previously qualified for the HPCS application, all other different diesel engine/generator combinations will be individually qualified for reliable start and load acceptance requirements.
: 3.
An acceptable start and load reliability test is defined as follows: A total of 69/n (where n is the number of diesels, 1) valid start and loading tests with no failure or 128/n valid start and loading tests with a single failure will be performed. Failure of the unit to successfully complete this series of tests as prescribed will require a review of the system design adequacy, the cause of the failure to be corrected, and the tests continued until 128 valid tests are achieved without exceeding the one failure.
The start and load tests will be conducted for 69 cold fast starts.


application, all other different diesel engine/generator combinations will be individually
RBS USAR 8.3-43 August 1987 The fast starts are conducted with the engine in a
ready standby status and include a loading to at least 50 percent of the continuous load and operation at this load for at least 1 hr.
During and/or following this
: testing, some individual components of the diesel generator or its support systems may require maintenance and/or replacement. This maintenance and/or replacement due to wear does not require retesting.
If the cause for failure to start or accept load in accordance with the preceding sequence falls under any of the following categories, that particular test may be disregarded, and the test sequence resumed without penalty following identification of the cause for the unsuccessful attempt:
a.
Unsuccessful start attempts which can definitely be attributed to operator error including setting of alignment control
: switches, rheostats, potentiometers, or other adjustments that may have been changed inadvertently prior to that particular start test.
b.
A starting and/or loading test performed during routine maintenance or trouble-shooting.
All maintenance procedures are defined prior to conducting the start and load acceptance qualification tests and become a
part of the normal maintenance schedule after installation.
c.
Failure of any of the temporary service systems such as dc power source, output circuit breaker,
: load, interconnecting
: piping, and any other temporary setup which will not be part of the permanent installation.
d.
Failure to carry load which can be definitely attributed to loadings in excess of the HPCS diesel generator rating.
e.
Unsuccessful start attempts which were conducted with the intent of eventual
: failure, e.g.,
the last attempt when determining capacity of the air start system.


qualified for reliable start and load acceptance
RBS USAR 8.3-44 August 1987 8.3.1.1.4.3 Containment Electrical Penetration Protection Electric circuits penetrating the primary containment through Class 1E electrical penetrations are classified as follows:
1.
Medium voltage power 4.16-kV, three-phase 2.
Low voltage power:
a.
480-V three-phase feeders from load centers b.
480-V three-phase feeders from motor control centers c.
120/240-V single-phase feeders from lighting and distribution transformers.
3.
Low voltage control and signal power:
a.
120-V single-phase b.
125-V dc 4.
Instrumentation circuits Containment electrical penetration assemblies are designed to withstand, without loss of mechanical integrity, the maximum fault current versus time condition which could occur because of single random failure of circuit overload protective devices.
No single failure causes excessive current in penetration conductors which degrade penetration seals.
All protective devices automatically disconnect power to the penetration conductors when currents through the conductors exceed the established protection limits. Medium voltage power (4.16 kV) penetrations are protected against overload by two redundant breakers.
These breakers are qualified for their service environment and receive tripping signals from two independent
: channels, physically separated and powered by separate sources.
Short circuit protection is provided for low-voltage power penetrations by two devices - a primary protective device and a
backup protective device - with the electrical penetration rated for the most severe duty of the two devices.
Both protective devices are qualified for their service environment.
When the electrical penetration is rated to carry the available short circuit continuously, no backup protection device is
: required, e.g.,
in an instrument circuit which inherently has high impedance and is subjected to low short circuit currents.


requirements.3. An acceptable start and load reliability test is defined as follows: A total of 69/n (where n is the number of diesels, 1) valid start and loading tests
RBS USAR Revision 10 8.3-45 April 1998 Electrical penetrations containing power circuits listed in 2a and 2b above are nominally rated to carry 180 percent of full load current continuously with all other circuits in the same penetration operating at full load.
Overload protection of electrical penetration 480-V motor control center power circuits is provided by a
series-connected molded case circuit breaker and
: fuse, each rated to open the circuit during overload conditions, thus providing redundant protection.
Penetration protection for 120-V ac lighting and distribution panels are provided by series-connected molded case circuit breakers located between the lighting or distribution transformer secondary and the electrical penetration.
No redundant protection is provided for neutron monitor SRM and IRM motor module loads fed from 1NHS-MCC2C since the penetration assembly is designed to carry the maximum available fault current continuously.
*10 480-V load center load circuits are protected by redundant protection devices as in the case of the polar crane.
Redundant protection consists of either the feeder breaker backed up by the secondary main breaker (via time overcurrent relay logic tripping) for the containment unit cooler
: circuits, or, of a
power supply fuse backed up by the feeder
: breaker, as for the hydrogen recombiner circuits.
10*
Low-voltage control circuits evaluated fall into one of the following categories:
1.
The circuit is self-protecting due to the limited available short-circuit current at the penetration being less than the continuous rating of the penetration.
2.
Backup protection is provided.
3.
The circuit has been analyzed and it has been determined that backup protection is not warranted (i.e.,
CT leads on differential
: circuit, trip coil circuits).
*10 4.
Administratively deenergizing the circuitry during plant operation (i.e.,
ERF
: system, space heaters for motors, and LS compartments).
10*


with no failure or 128/n valid start and loading tests with a single failure will be performed. Failure of
RBS USAR 8.3-46 August 1987 8.3.1.1.5 Maintenance and Testing 8.3.1.1.5.1 Auxiliary Electrical Power Supply Systems Maintenance and testing of auxiliary electrical power system equipment are conducted to ensure that all components are operational within their design limits.
 
Maintenance and testing are performed periodically throughout station life in accordance with normal station operating procedures to:
the unit to successfully complete this series of tests
1.
 
Detect the deterioration of the components of the system toward an unacceptable condition and to take corrective action as required to bring the components to an acceptable condition.
as prescribed will require a review of the system
2.
 
Demonstrate the capability of the components which will normally be deenergized to perform properly when energized.
design adequacy, the cause of the failure to be corrected, and the tests continued until 128 valid tests are achieved without exceeding the one failure. 
The inherent redundancy of the standby electrical systems permits support of full functional testing of systems or subsystems.
 
Components of the standby systems can be made inoperable for short time test purposes without impairing the ultimate capability of the systems and the subsystems which they support.
The start and load tests will be conducted for 69 cold
Information concerning the ability of the power systems important to safety to meet the requirements of GDC 18 is given in Section 3.1.2.18.
 
The capability for testing and calibrating all actuation devices,
fast starts.
: circuits, electrical protective
RBSUSAR8.3-43August1987Thefaststartsareconductedwiththeengineinareadystandbystatusandincludealoadingtoatleast 50percentofthecontinuousloadandoperationatthis loadforatleast1hr.Duringand/orfollowingthis testing,someindividualcomponentsofthediesel generatororitssupportsystemsmayrequire maintenanceand/orreplacement.Thismaintenanceand/or replacementduetoweardoesnotrequireretesting.Ifthecauseforfailuretostartoracceptloadinaccordancewiththeprecedingsequencefallsunderany ofthefollowingcategories,thatparticulartestmay bedisregarded,andthetestsequenceresumedwithout penaltyfollowingidentificationofthecauseforthe unsuccessfulattempt:a.Unsuccessfulstartattemptswhichcandefinitelybeattributedtooperatorerrorincludingsetting ofalignmentcontrolswitches,rheostats, potentiometers,orotheradjustmentsthatmayhave beenchangedinadvertentlypriortothat particularstarttest.b.Astartingand/orloadingtestperformedduringroutinemaintenanceortrouble-shooting.All maintenanceproceduresaredefinedpriorto conductingthestartandloadacceptance qualificationtestsandbecomeapartofthe normalmaintenancescheduleafterinstallation.c.Failureofanyofthetemporaryservicesystemssuchasdcpowersource,outputcircuitbreaker, load,interconnectingpiping,andanyother temporarysetupwhichwillnotbepartofthe permanentinstallation.d.FailuretocarryloadwhichcanbedefinitelyattributedtoloadingsinexcessoftheHPCS dieselgeneratorrating.e.Unsuccessfulstartattemptswhichwereconductedwiththeintentofeventualfailure,e.g.,the lastattemptwhendeterminingcapacityoftheair startsystem.
: relays, and related instrumentation during normal operation is designed into the power systems important to safety and in accordance with the recommendations of Regulatory Guide 1.22.
RBSUSAR8.3-44August19878.3.1.1.4.3ContainmentElectricalPenetrationProtectionElectriccircuitspenetratingtheprimarycontainmentthroughClass1Eelectricalpenetrationsareclassifiedasfollows:1.Mediumvoltagepower4.16-kV,three-phase 2.Lowvoltagepower:a.480-Vthree-phasefeedersfromloadcentersb.480-Vthree-phasefeedersfrommotorcontrol centersc.120/240-Vsingle-phasefeedersfromlightinganddistributiontransformers.3.Lowvoltagecontrolandsignalpower:a.120-Vsingle-phase b.125-Vdc4.InstrumentationcircuitsContainmentelectricalpenetrationassembliesaredesignedtowithstand,withoutlossofmechanicalintegrity,themaximum faultcurrentversustimeconditionwhichcouldoccurbecauseof singlerandomfailureofcircuitoverloadprotectivedevices.No singlefailurecausesexcessivecurrentinpenetrationconductors whichdegradepenetrationseals.Allprotectivedevices automaticallydisconnectpowertothepenetrationconductorswhen currentsthroughtheconductorsexceedtheestablishedprotection limits.Mediumvoltagepower(4.16kV)penetrationsareprotected againstoverloadbytworedundantbreakers.Thesebreakersare qualifiedfortheirserviceenvironmentandreceivetripping signalsfromtwoindependentchannels,physicallyseparatedand poweredbyseparatesources.Shortcircuitprotectionis providedforlow-voltagepowerpenetrationsbytwodevices-a primaryprotectivedeviceandabackupprotectivedevice-with theelectricalpenetrationratedforthemostseveredutyofthe twodevices.Bothprotectivedevicesarequalifiedfortheir serviceenvironment.Whentheelectricalpenetrationisratedto carrytheavailableshortcircuitcontinuously,nobackup protectiondeviceisrequired,e.g.,inaninstrumentcircuit whichinherentlyhashighimpedanceandissubjectedtolowshort circuitcurrents.
Provisions to perform nondestructive tests under simulated fault conditions are provided.
RBSUSARRevision108.3-45April1998Electricalpenetrationscontainingpowercircuitslistedin2aand2babovearenominallyratedtocarry180percentoffull loadcurrentcontinuouslywithallothercircuitsinthesame penetrationoperatingatfullload.Overloadprotectionofelectricalpenetration480-Vmotorcontrolcenterpowercircuitsisprovidedbyaseries-connectedmolded casecircuitbreakerandfuse,eachratedtoopenthecircuit duringoverloadconditions,thusprovidingredundantprotection.
This includes but is not limited to the ability of the protection system to initiate the operation of the actuated equipment.
Penetrationprotectionfor120-Vaclightinganddistribution panelsareprovidedbyseries-connectedmoldedcasecircuit breakerslocatedbetweenthelightingordistributiontransformer secondaryandtheelectricalpenetration.Noredundant protectionisprovidedforneutronmonitorSRMandIRMmotor moduleloadsfedfrom1NHS-MCC2Csincethepenetrationassembly isdesignedtocarrythemaximumavailablefaultcurrent
8.3.1.1.5.2 Standby Electrical Power Supply Systems Maintenance and testing of the standby diesel generators are conducted to ensure that all components and auxiliaries are operational within their design limits.
 
In addition to the qualification tests conducted on each diesel generator set at the engine manufacturer's factory, the standby diesel generators are subjected to 69/n (where n is the number of diesels, 2) start and load tests with no single failure or 128/n start and load tests with a single failure.
continuously.10480-Vloadcenterloadcircuitsareprotectedbyredundant protectiondevicesasinthecaseofthepolarcrane.Redundant protectionconsistsofeitherthefeederbreakerbackedupbythe secondarymainbreaker(viatimeovercurrentrelaylogic tripping)forthecontainmentunitcoolercircuits,or,ofa powersupplyfusebackedupbythefeederbreaker,asforthe hydrogenrecombinercircuits.
Failure of a diesel to complete this series of
10Low-voltagecontrolcircuitsevaluatedfallintooneofthe followingcategories:1.Thecircuitisself-protectingduetothelimitedavailableshort-circuitcurrentatthepenetration beinglessthanthecontinuousratingofthe
 
penetration.2.Backupprotectionisprovided.
3.Thecircuithasbeenanalyzedandithasbeendeterminedthatbackupprotectionisnotwarranted (i.e.,CTleadsondifferentialcircuit,tripcoil
 
circuits).
*104.Administrativelydeenergizingthecircuitryduringplantoperation(i.e.,ERFsystem,spaceheatersfor motors,andLScompartments).
10 RBSUSAR8.3-46August19878.3.1.1.5MaintenanceandTesting8.3.1.1.5.1AuxiliaryElectricalPowerSupplySystems Maintenanceandtestingofauxiliaryelectricalpowersystemequipmentareconductedtoensurethatallcomponentsare operationalwithintheirdesignlimits.Maintenanceandtesting areperformedperiodicallythroughoutstationlifeinaccordance withnormalstationoperatingproceduresto:1.Detectthedeteriorationofthecomponentsofthesystemtowardanunacceptableconditionandtotake correctiveactionasrequiredtobringthecomponents toanacceptablecondition.2.Demonstratethecapabilityofthecomponentswhichwillnormallybedeenergizedtoperformproperlywhen
 
energized.Theinherentredundancyofthestandbyelectricalsystemspermitssupportoffullfunctionaltestingofsystemsorsubsystems.
Componentsofthestandbysystemscanbemadeinoperablefor shorttimetestpurposeswithoutimpairingtheultimate capabilityofthesystemsandthesubsystemswhichtheysupport.
Informationconcerningtheabilityofthepowersystemsimportant tosafetytomeettherequirementsofGDC18isgivenin Section3.1.2.18.Thecapabilityfortestingandcalibratingallactuationdevices,circuits,electricalprotectiverelays,andrelated instrumentationduringnormaloperationisdesignedintothe powersystemsimportanttosafetyandinaccordancewiththe recommendationsofRegulatoryGuide1.22.Provisionstoperform nondestructivetestsundersimulatedfaultconditionsare provided.Thisincludesbutisnotlimitedtotheabilityofthe protectionsystemtoinitiatetheoperationoftheactuated
 
equipment.8.3.1.1.5.2StandbyElectricalPowerSupplySystemsMaintenanceandtestingofthestandbydieselgeneratorsareconductedtoensurethatallcomponentsandauxiliariesare operationalwithintheirdesignlimits.Inadditiontothequalificationtestsconductedoneachdieselgeneratorsetattheenginemanufacturer'sfactory,thestandby dieselgeneratorsaresubjectedto69/n(wherenisthenumberof diesels,2)startandloadtestswithnosinglefailureor128/n startandloadtestswithasinglefailure.Failureofadiesel tocompletethisseriesof RBSUSARRevision88.3-47August1996testswillrequireareviewofsystemdesignadequacy,thecauseoffailuretobecorrected,andthetestscontinueduntil128/n validtestsareachievedwithoutexceedingtheonefailure criterion.Thestartandloadtestsareconductedwiththe engineinthereadystandbystatusandincludealoadingtoat least50percentofthecontinuousloadandoperationatthis loadforatleast1hr.Eachdieselgeneratorsetwasgivenaloadcapabilitytestattheirratedloadof3,500kWfor24hr.However,thestandby dieselgeneratorswillnotbeloadedabovetheloadsindicatedin Tables8.3-2aand8.3-2b.Therefore,the24-hr,3,500-kWload capabilitytestmorethansatisfiesthe110percentoverload requirementofparagraphC.2.a(3)ofRegulatoryGuide1.108when appliedtothequalifiedload.ThefollowingtestswereperformedinaccordancewithIEEE-387aftercompleteinstallationofthestandbydieselgenerator systematRiverBendStation.a.Startingtest b.Loadacceptancetest c.Ratedloadtests d.Designloadtests e.Loadrejectiontests f.Electricaltests g.Subsystemtests8Periodictestsareperformedtoverifythatsystemsand componentsofthestandbydieselgeneratorsperform satisfactorilyandtoensurethatthestandbydieselgenerator systemsmeettheiravailabilityrequirements.Thesetestsare performedduringnuclearplantoperationaccordingtoRegulatoryGuide1.108andaredescribedintheTechnicalSpecifications/


RBS USAR Revision 8 8.3-47 August 1996 tests will require a review of system design adequacy, the cause of failure to be corrected, and the tests continued until 128/n valid tests are achieved without exceeding the one failure criterion.
The start and load tests are conducted with the engine in the ready standby status and include a loading to at least 50 percent of the continuous load and operation at this load for at least 1 hr.
Each diesel generator set was given a
load capability test at their rated load of 3,500 kW for 24 hr.
: However, the standby diesel generators will not be loaded above the loads indicated in Tables 8.3-2a and 8.3-2b.
Therefore, the 24-hr, 3,500-kW load capability test more than satisfies the 110 percent overload requirement of paragraph C.2.a(3) of Regulatory Guide 1.108 when applied to the qualified load.
The following tests were performed in accordance with IEEE-387 after complete installation of the standby diesel generator system at River Bend Station.
a.
Starting test b.
Load acceptance test c.
Rated load tests d.
Design load tests e.
Load rejection tests f.
Electrical tests g.
Subsystem tests
*8 Periodic tests are performed to verify that systems and components of the standby diesel generators perform satisfactorily and to ensure that the standby diesel generator systems meet their availability requirements.
These tests are performed during nuclear plant operation according to Regulatory Guide 1.108 and are described in the Technical Specifications/
Requirements.
Requirements.
8Testingproceduresindicatethatno-loadandlight-loadconditionsaretobeavoidedandtestingshouldbeaccomplished withaminimumloadingof25percentofratedload.Some exceptionstothisareallowedsuchastimestartcheckswhen otherequipmentisfoundinoperable.Thenormalmaintenanceand surveillancescheduleprovidessufficientloadedrunningtimeto minimizedetrimentaleffectsoftheseexceptions.
8*
RBSUSARRevision88.3-48August1996Emergencydieselgeneratorequipmentfailuresarerepairedpromptly,andanevaluationastothecauseofthefailureis performedanddocumentedinequipmenthistory.Administrative proceduresprovideapprovedmethodsfordesignchangesor replacementofequipmentwithhighfailurerates.Aftermajormaintenanceorextendedoutageofthediesel,acompletesystemlineupperthesystemoperatingprocedureis performedpriortoastartattempt.Thisincludesvalve, electrical,instrument,andcontrolboardlineupsaswellasa visualinspectionofthedieselgeneratoranditsauxiliaries.
Testing procedures indicate that no-load and light-load conditions are to be avoided and testing should be accomplished with a
Inaddition,compliancewiththeprotectivetaggingandtemporary alterationsproceduresalongwithsystemrestorationsectionsof maintenanceandsurveillanceproceduresensuresystemreadiness.Uponcompletionofanymanual,test,orautostartofthediesel,theoperatorisdirectedbythesurveillanceorsystemoperating proceduretoplacethedieselinanautomaticstandbyreadiness
minimum loading of 25 percent of rated load.
 
Some exceptions to this are allowed such as time start checks when other equipment is found inoperable.
condition.CompliancewithTechnicalSpecifications,administrativeandsystemoperatingprocedures,andthepreventivemaintenanceand surveillancetestingscheduleensuresoptimumequipmentreadiness andavailabilityupondemand.8.3.1.1.5.3HighPressureCoreSprayPowerSupplySystem8ReadinessoftheHPCSdieselgeneratorisdemonstratedby periodictestingaccordingtoRegulatoryGuide1.108andis describedintheTechnicalSpecifications/Requirements.The testingprogramisdesignedtotesttheabilitytostartand accepttheHPCSdieselgeneratordesignloadsconnectedtobus 1E22*S004.TheHPCSdieselgeneratorisrunfor24hratits continuousratingof2,600kW,2hrofwhichitissubjectedtoa 110-percentoverloadtest(seeTable8.3-3).Thisensuresthat coolingandlubricationareadequateforextendedperiodsof operation.Fullfunctionaltestsoftheautomaticcontrol circuitryareconductedonaperiodicbasistodemonstrate correctoperation(Section7.3.2).
The normal maintenance and surveillance schedule provides sufficient loaded running time to minimize detrimental effects of these exceptions.
8Meansareprovidedforperiodicallytestingthechainofsystemelementsfromsensingdevicesthroughdrivenequipmenttoassure thattheHPCSpowersupplyisfunctioninginaccordancewith designrequirements.Thedrawoutfeatureofprotectiverelays allowsreplacementrelaystobeinstalledwhiletherelaythatis removedisbenchtestedandcalibrated.
RBS USAR Revision 23 8.3-49 Startup of onsite power units can be initiated by simulation of LOCA signal or loss of power to the plant auxiliary power system. 
 
Connection of the HPCS diesel generator to the HPCS bus takes
 
place automatically on loss of plant auxiliary power to the HPCS bus (HPCS bus low voltage). The HPCS diesel generator bus
 
directional overcurrent, ground overcurrent, and phase overcurrent protective relaying provides a trip to the offsite power feeder breaker in case of loss of offsite power while the
 
diesel generator is in the test mode operation.
 
8.3.1.1.5.4  Uninterruptible Power Supply Systems  13 Maintenance and testing are conducted to ensure that all components of the 120-V ac uninterruptible power supply systems are operational within their design ratings, and the testing can be performed without disconnecting the loads from their power sources by use of the manual bypass switch. Maintenance and testing of equipment and systems are conducted periodically to detect deterioration of equipment toward an unacceptable
 
condition and to take corrective action as required to bring the components to an acceptable condition. Preoperational and periodic testing complies with IEEE-308, Criteria for Class 1E
 
Electrical Systems for Nuclear Power Generating Stations.
 
8.3.1.1.5.5  Testability of Offsite/Onsite Power Systems  6 Testing the transfer from onsite power, of the main generator 1GMS-G1, through normal station service transformers, to offsite power, via the preferred station service transformers, can be performed when the reactor power is at a low load condition. The transfer from onsite power to offsite power is performed with
 
buses loaded and is limited to 13.8-kV buses 1NPS-SWG1A and 1NPS-
 
SWG1B as well as 4.16-kV buses 1NNS-SWG1A and 1NNS-SWG1B. Since 1NNS-SWG1C and E22-S004 are powered from either 1NNS-SWG1A or 1NNS-SWG1B, they will also transfer from onsite to offsite power as a result of the transfer of the bus it is aligned to (1NNS-SWG1A or 1NNS-SWG1B). Standby 4.16-kV buses 1ENS*SWG1A and 1ENS*SWG1B are always connected to preferred offsite power circuits and are therefore not affected in the transfer test.
Normal 13.8-kV buses 1NPS-SWG1C and 1NPS-SWG1D are always connected to preferred offsite power circuits and therefore not
 
affected in the transfer test.
13  7  4 Offsite power can be connected to 13.8-kV bus 1NPS-SWG1A via preferred transformer 1RTX-XSR1E and circuit breaker 1NPS-ACB11, and to 13.8-kV bus 1NPS-SWG1B via preferred transformer 1RTX-
 
XSR1F and circuit breaker 1NPS-ACB27.
4 6 7 RBS USAR Revision 23 8.3-49a  7  4 Onsite power can be connected to 13.8-kV bus 1NPS-SWG1A via normal transformer 1STX-XNS1A and circuit breaker 1NPS-ACB09, and to 13.8-kV bus 1NPS-SWG1B via normal transformer 1STX-XNS1B and circuit breaker 1NPS-ACB25.
Offsite power can be connected to 4.16-kV bus 1NNS-SWG1A via preferred transformer 1RTX-XSR1C and circuit breaker 1NNS-ACB07, and to 4.16-kV bus 1NNS-SWG1B via preferred transformer 1RTX-XSR1D and circuit breaker 1NNS-ACB15. Onsite power can be connected to 4.16-kV buses 1NNS-SWG1A and 1NNS-SWG1B via normal transformer 1STX-XNS1C and circuit breakers 1NNS-ACB06 and 1NNS-ACB14, respectively.
The logic that 4 7 RBSUSARRevision68.3-49bAugust1993THISPAGELEFTINTENTIONALLYBLANK RBS USAR Revision 23 8.3-50 automatically transfers a 13.8-kV or 4.16-kV bus from onsite to offsite power is the loss of voltage on the respective 13.8-kV or 4.16-kV bus. The test is performed by manually tripping the 13.8-kV or 4.16-kV breaker from the normal transformer. The voltage loss causes the 13.8-kV or 4.16-kV breaker from the preferred transformer to close onto the respective 13.8-kV or 4.16-kV bus. During the fast transfer, the outage is of such short duration that the motors remain running and the power system remains
 
intact. 6 Offsite power is connected to 13.8-kV bus 1NPS-SWG1C via preferred transformer 1RTX-XSR1E and normally closed circuit breaker 1NPS-ACB43 and to 13.8-kV bus 1NPS-SWG1D via preferred transformer 1RTX-XSR1F and normally closed circuit breaker 1NPS-ACB44. 13.8-kV switchgear 1NPS-SWG1C and 1NPS-SWG1D do not have
 
a back up source of power or transfer to another source.
6  13  7  7 Standby 4.16-kV bus 1ENS*SWG1A is connected to preferred transformer 1RTX-XSR1C via normally closed circuit breaker 1ENS*ACB06, to normal 4.16-kV bus 1NNS-SWG1B via normally open circuit breakers, and to standby diesel generator 1EGS*EG1A via
 
normally open circuit breaker 1ENS*ACB07. Standby 4.16-kV bus 1ENS*SWG1B is connected to preferred transformer 1RTX-XSR1D via normally closed circuit breaker 1ENS*ACB26, to normal 4.16-kV bus 1NNS-SWG1A via normally open circuit breakers, and to standby diesel generator 1EGS*EG1B via normally open circuit breaker 1ENS*ACB27. The transfer test is performed for each bus as
 
follows: 13 RBSUSARRevision138.3-50aSeptember2000THISPAGELEFTINTENTIONALLYBLANK RBSUSARRevision68.3-50bTHISPAGELEFTBLANKINTENTIONALLY RBS USAR Revision 20 8.3-51  813 The loading of a standby diesel generator is performed manually during testing while the reactor is in normal operation. The standby diesel generator is manually synchronized onto the standby bus and then carries selected standby loads. A synchronous check relay is provided to
 
prevent breaker closure during synchronizing operations unless the busses are synchronized within the tolerances of the relay. By opening the breaker from the preferred stat
 
ion service transformer and closing the breaker connecting
 
the standby 4.16-kV bus to the normal 4.16-kV bus, the
 
standby diesel generator load can be simulated to its
 
approximate qualified load. Selected motors are running on
 
the standby bus during the test.
8 138.3.1.1.5.6 Procedural Control of Jumpers and Other Temporary Forms of Bypassing Use of jumpers or other temporary forms of bypassing is controlled through implementation of the following procedures: 1. Surveillance Test Procedures - These are written so that in the body of the procedure specific steps direct
 
altering the system to accomplish testing; once testing is complete, specific steps also direct returning the system to the original condition. To ensure this is done properly, a second signoff by a qualified
 
individual is required to verify normal conditions.
2.The Temporary Modifications (Alterations)p rocedure establish es the requirements and methods for controlling activities that temporarily altered the design function of a system or component. The
 
requirements of this procedure applied to all activities that temporarily altered the design function
 
of any component or system after the
 
Preoperational/Acceptance Test Phase and the system or
 
component had been turned over to the plant operating
 
staff.8 The changes covered were as follows:  a change that inhibited or altered the intended operation of a plant component or system such as electrical jumpers, lifted
 
wires, open links, piping blocks and bypasses, papered
 
contacts, or temporary set points that were intended to
 
be returned to normal or permanently incorporated at
 
some later date and not otherwise covered by an
 
approved procedure which returned the system back to
 
normal.8 RBS USAR Revision 24 8.3-52  8 8 3. The maintenance work process uses several procedures that establish administrative controls for identifying, controlling, and documenting maintenance and
 
maintenance-related activities. These procedures
 
provides step-by-step instructions to ensure that troubleshooting and/or maintenance is accomplished properly. It also provides for testing by use of
 
approved surveillance test procedures to ensure the system or component has been properly repaired and
 
returned to service. 14  7  The S hift Manager has complete control of all activities that might alter or prevent a system from
 
performing as it is designed.
7 14 8.3.1.1.6 Safety-Related Systems Design Criteria
 
8.3.1.1.6.1 Electric Motors and Torque Considerations
 
Motors employed for Class 1E service are designed and constructed
 
to IEEE-323, -334, and -344 as well as all applicable industry standards in effect at the time of their purchase (Sections 3.9
 
and 3.11).
 
Motors are matched to the driven equipment so as to produce sufficient accelerating torque to successfully start the
 
equipment at minimum available motor terminal voltage. A start
 
is considered successful if rated speed can be obtained in less than 5 sec, and within the allowed motor heating curve. This has been generally achieved by requiring a minimum of 10 percent difference between the instantaneous available driver torque and
 
driven equipment demand torque.
 
8.3.1.1.6.2 Temperature Monitoring and Circuit Protection
 
The nature of Class 1E electrical equipment is such that protection of the equipment is secondary to accident mitigation and safe shutdown of the plant. Temperature monitors and overload heaters are set only to alarm on
 
overload/overtemperature conditions during LOCA operation of Class 1E MOVs. Trip circuits actuate only to prevent
 
catastrophic failure which could augment rather than mitigate an undesirable circumstance. Coordination calculations show that protective devices actuate at the lowest level necessary to isolate a fault. All protective devices are set for a minimum of 125 percent of the full load current rating of the equipment at
 
all Class 1E voltage RBSUSAR8.3-53August1987levels.Nocascadingofprotectivedeviceshasbeenemployed.SeealsoSection8.3.1.1.4.2regardingHPCScircuitprotection.TheRiverBendStationdesignhasbeenreviewedtoidentifyanylargehorsepower(rated100hpormore)safety-relatedmotor/pump combinationsthathavepressureswitchesorotherpermissive devicesincorporatedintothefinalactuationcontrolcircuitry.
Thesemotorsandpermissivedevices,alongwiththeredundancy anddiversityprovidedforsuchdevices,arediscussedinthe followingparagraphs.1.High-PressureCoreSpraySystem(E22)RedundantundervoltagedevicesmonitorbusvoltagesothatfailureofonedevicetodetectavailableHPCSpoweronthe busdoesnotpreventthemotorfromstarting.However,ifa lossofbusvoltageissensedbymorethanonechannelof undervoltagerelays,theHPCSpumpisinhibitedfrom
 
starting.CertainprotectivetripscaninhibitaHPCSDGstartundertestconditions;however,allbuttwooftheDGtripsare bypassedinthepresenceofanemergencystartsignal.The twoexceptionsaretheoverspeedtripandthegenerator differentialdevicetripwhichprotectsthedieselgenerator.
Thesedevicesarecapableofbeingtestedduringnormal
 
operations.AlthoughredundancyofcertaincomponentsisappliedwithinHPCSinordertoimprovereliability,theoverspeedand differentialtripsarenotredundantbycomponent.TheECCS networkisredundantbysystem.2.ResidualHeatRemovalSystem(E12)TherearenopressureswitchescapableofinhibitingamanualorautomaticstartoftheRHRsystem.TheRHRpumpmotor switchgearreceivesastopsignalifeitherthe1E12*MOVF004B or1E12*VF066Bvalveisfullopenandthevalve 1E12*MOVF006B,1E12*MOVF009,or1E12*MOVF008isnotfully open.Limitswitcheswhichsensethefullopenvalve positionandgenerateappropriatefullopenpermissiveare notredundant.TheECCSnetworkisredundantbysystemand cantoleratelossofanentireRHRtrain.
RBSUSAR8.3-54August19873.ServiceWaterSystem(SWP)Emergencystartofservicewaterpumps1SWP*P2A,1SWP*P2B,1SWP*P2C,and1SWP*P2Disinhibitediftherespective dischargevalveisnotfullyclosedorthestandbyservice waterinitiationsignalisnotpresent.Thelimitswitchsensingthefullclosedvalvepositiontogeneratetheappropriatefullclosedpermissiveisnot redundant.However,redundancydoesexistatthesystem level.Thestandbyservicewaterinitiationsignaliseither reactorplantcomponentcoolingwaterlooplossofpressure ornormalstandbyservicewaterlooplossofpressure.Each loopisprovidedwithfourpressuresensors.One-out-of-two-taken-twicelogicisusedingeneratingthestartpermissive, thusprovidingadequateredundancy.Theabilityofthestandbyservicewatersystemtoaccommodateanysinglecomponentfailurewithoutaffecting safeshutdownorcooldownorpost-accidentheatdissipation isdetailedinSection9.2.7.3andtheFMEA.Asforcommon modefailures,thesedevicesarequalifiedinaccordancewith RegulatoryGuide1.89.Duringshutdown,eachpumpcanbe verifiedtostartautomatically,onapressuretestsignalto thepressuretransmitters,tomaintainservicewaterpressure greaterthantechnicalspecificationrequirements.8.3.1.1.6.3InterruptingCapacityofSwitchgearandOtherProtectiveDevicesFaultcurrentavailableatallvoltagelevelshasbeenrestrictedtovalueswithinthecertifiedratingoftheinterrupting devicesemployedatthatlevel.Allpossiblesourcesoffault currentcontributionshavebeenconsidered,includingabnormal sourcessuchasanemergencydieselgeneratorontest.
Calculationsofavailableshortcircuitcurrentsarein accordancewithANSIC37.00-1964.8.3.1.1.6.4Grounding Thebalance-of-plantandClass1EDivisionsIandII,bothonsiteandoffsite,powerdistributionsystemsarelow-resistance
 
grounded.DiscussionofgroundingontheHPCSpowersupply(ESFDivisionIII)iscoveredinSection8.3.1.1.4.2.
RBSUSARRevision138.3-55September20008.3.1.2Analysis8.3.1.2.1GeneralFunctionalDesignBases 8.3.1.2.1.1AuxiliaryElectricalPowerSupplySystems Theauxiliaryelectricalpowersupplysystemsprovideacpowerrequiredfornormalplantoperation,shuttingdownthereactor safely,maintainingasafeshutdowncondition,andoperatingall auxiliariesrequiredforpublicsafetyunderallnormal, transient,andaccidentconditions.Thefollowinggeneral functionaldesignbasesapply:1.Thestandbyauxiliaryelectricalpowersupplysystemsdistributepowertoallloadswhichareessentialfor publicsafety.2.Thenormalandstandbyportionsoftheauxiliaryelectricalpowersupplysystemsarearrangedsothata singlefailuredoesnotpreventsafety-relatedsystems fromperformingtheirintendedsafetyfunctions.133.Thestandby4.16-kVbusesarearrangedsothattheycanbesuppliedfrompreferredorstandbypowersources.4.Sufficientinstrumentationisprovidedtoensureastateofreadinessandperformanceofthestandbyac powersystem.8.3.1.2.1.2StandbyElectricalPowerSupplySystemsThestandbyelectricalpowersupplysystemsaredesignedwithsufficientcapacityandcapabilitytoensurethattheyare capableto,insufficienttime,restoreacpowerintheevent thatthepreferredpowersupplybecomesunavailable.Theyhave theabilitytoreliablysupplytherequiredacloaddemandsof engineeredsafeguardequipmentandcontrolsforpost-accidentas wellassafeandorderlyshutdownoperationssothatthereactor coreiscooledandcontainmentintegrityandothervital functionsaremaintained.Thefollowinggeneralfunctional designbasesapply:
131.StandbyacdieselgeneratorsarehousedinaSeismicCategoryIstructurewithSeismicCategoryIwalls separatingthemsothatanaccidentinvolvingonedoes notinvolveanyothers.Eachfueloiltankiscontained inaseparate RBSUSARRevision138.3-56September2000SeismicCategoryIroom,filledwithsandtoreducethechanceoffirearoundtheoiltank.2.Eachstandbyacdieselgeneratorproducesacpoweratthesamevoltageandfrequencyastheassociated standbystationserviceacpowerdistributionsystem.
Eachiscapableofautomaticstartatanytimeandof continuousoperationatqualifiedload,voltage,and frequencyuntilmanuallystopped.133.Eachstandbyacdieselgeneratoriscapableofbeingmanuallyparalleledwithpreferredstationserviceac powersourceundernormalconditions.Provisionsare madeinthedesigntopreventtheelectrical interconnectionoftheredundantstandbyacdiesel
 
generators.4.Eachfueloilsystemhasastoragecapacitysuitableforoperatingeachstandbydieselsystematitsmaximum requiredpost-accidentloadconditionsforaminimumof 7days.Thefueloilsystemandstorageistornadoand earthquakeprotected.5.Controlpowerrequiredfortheoperationofeachstandbyacdieselgeneratorissuppliedfromits divisionalstandby125-Vbatterysystem.Standby auxiliaries,suchasfuelpumpsandventilation systems,necessaryforcontinuousoperationofstandby acdieselgeneratorsaresuppliedfromtheirassociated standbybuses.6.Uponlossofpreferredacpowersupplies,eachofthestandbybusesisisolatedfromitspreferredsources, andthestandbyacdieselgeneratorsstart automaticallyandarereadytoacceptloadwithin 10sec.Controls,bothlocalandinthemaincontrol room,areprovidedformanualstartandstopofeach standbyacdieselgenerator.Theoutputofeach standbydieselgeneratorismonitored,andabnormal conditionsarealarmedinthemaincontrolroom.
137.Theacdieselgeneratorsystemisdesignedsothatwithlossofanyoneofthreedieselgeneratorsthe remaininggeneratorsarecapableofsupplyingpowerto sufficientequipmentforasafeshutdownoftheunit undernormaloraccidentconditions.
RBS USAR Revision 16 8.3-57 March 2003  8. Standby bus voltage does not dip below 75 percent of motor-rated voltage at any time during the loading
 
sequence, and recovers to 90 percent of motor-rated voltage within 40 percent of each load sequence time interval. The ac diesel generator associated with the HPCS does not comply with this portion of Regulatory Guide 1.9; however, its voltage recovery
 
characteristics are operationally acceptable when
 
starting its loads (Section 8.3.1.2.2.2). 9. All Class 1E motors, except as noted below, are capable of starting and accelerating their driven equipment with 70 percent of motor nameplate voltage applied to
 
motor terminals without affecting performance or
 
equipment life. 16128 The exceptions to this are certain motor-operated valves, motor-operated dampers, Division I and II diesel generator starting air compressors EGA-C4A, EGA-C4B, EGA-C5A and EGA-C5B, 1HVR*UC5, and the motors
 
driving air compressors 1LSV*C3A and 1LSV*C3B. These
 
LSV compressors have been environmentally qualified
 
consistent with IEEE-323 and are capable of starting at 80 percent of motor nameplate voltage. Calculations
 
have determined, however, that the minimum starting
 
voltage available at the motor terminals will be 89.63 percent, well in excess of the motors'
 
capabilities.
16 These Class 1E motor-operated valves, motor-operated dampers, Division I and II diesel generator starting
 
air compressors EGA-C4A, EGA-C4B, EGA-C5A and EGA-C5B, and unit coolers are capable of starting and accelerating with 80 percent of motor nameplate voltage applied to motor terminals. Calculations have
 
determined that the minimum starting voltage available
 
at the motor terminals during the period required for
 
operation is in excess of the required starting


voltage.8 125 To ensure proper motor-operated valve function under design conditions, an analysis is performed to  
RBS USAR Revision 8 8.3-48 August 1996 Emergency diesel generator equipment failures are repaired
: promptly, and an evaluation as to the cause of the failure is performed and documented in equipment history.
Administrative procedures provide approved methods for design changes or replacement of equipment with high failure rates.
After major maintenance or extended outage of the
: diesel, a
complete system lineup per the system operating procedure is performed prior to a
start attempt.
This includes
: valve, electrical, instrument, and control board lineups as well as a
visual inspection of the diesel generator and its auxiliaries.
In addition, compliance with the protective tagging and temporary alterations procedures along with system restoration sections of maintenance and surveillance procedures ensure system readiness.
Upon completion of any manual, test, or auto start of the diesel, the operator is directed by the surveillance or system operating procedure to place the diesel in an automatic standby readiness condition.
Compliance with Technical Specifications, administrative and system operating procedures, and the preventive maintenance and surveillance testing schedule ensures optimum equipment readiness and availability upon demand.
8.3.1.1.5.3 High Pressure Core Spray Power Supply System
*8 Readiness of the HPCS diesel generator is demonstrated by periodic testing according to Regulatory Guide 1.108 and is described in the Technical Specifications/Requirements.
The testing program is designed to test the ability to start and accept the HPCS diesel generator design loads connected to bus 1E22*S004.
The HPCS diesel generator is run for 24 hr at its continuous rating of 2,600 kW, 2 hr of which it is subjected to a 110-percent overload test (see Table 8.3-3).
This ensures that cooling and lubrication are adequate for extended periods of operation.
Full functional tests of the automatic control circuitry are conducted on a
periodic basis to demonstrate correct operation (Section 7.3.2).
8*
Means are provided for periodically testing the chain of system elements from sensing devices through driven equipment to assure that the HPCS power supply is functioning in accordance with design requirements.
The drawout feature of protective relays allows replacement relays to be installed while the relay that is removed is bench tested and calibrated.


determine the torque or thrust that must be delivered
RBS USAR Revision 23 8.3-49 Startup of onsite power units can be initiated by simulation of LOCA signal or loss of power to the plant auxiliary power system.
Connection of the HPCS diesel generator to the HPCS bus takes place automatically on loss of plant auxiliary power to the HPCS bus (HPCS bus low voltage). The HPCS diesel generator bus directional overcurrent, ground overcurrent, and phase overcurrent protective relaying provides a trip to the offsite power feeder breaker in case of loss of offsite power while the diesel generator is in the test mode operation.
8.3.1.1.5.4 Uninterruptible Power Supply Systems x o13 Maintenance and testing are conducted to ensure that all components of the 120-V ac uninterruptible power supply systems are operational within their design ratings, and the testing can be performed without disconnecting the loads from their power sources by use of the manual bypass switch. Maintenance and testing of equipment and systems are conducted periodically to detect deterioration of equipment toward an unacceptable condition and to take corrective action as required to bring the components to an acceptable condition. Preoperational and periodic testing complies with IEEE-308, Criteria for Class 1E Electrical Systems for Nuclear Power Generating Stations.
8.3.1.1.5.5 Testability of Offsite/Onsite Power Systems x o6 Testing the transfer from onsite power, of the main generator 1GMS-G1, through normal station service transformers, to offsite power, via the preferred station service transformers, can be performed when the reactor power is at a low load condition. The transfer from onsite power to offsite power is performed with buses loaded and is limited to 13.8-kV buses 1NPS-SWG1A and 1NPS-SWG1B as well as 4.16-kV buses 1NNS-SWG1A and 1NNS-SWG1B. Since 1NNS-SWG1C and E22-S004 are powered from either 1NNS-SWG1A or 1NNS-SWG1B, they will also transfer from onsite to offsite power as a result of the transfer of the bus it is aligned to (1NNS-SWG1A or 1NNS-SWG1B). Standby 4.16-kV buses 1ENS*SWG1A and 1ENS*SWG1B are always connected to preferred offsite power circuits and are therefore not affected in the transfer test.
Normal 13.8-kV buses 1NPS-SWG1C and 1NPS-SWG1D are always connected to preferred offsite power circuits and therefore not affected in the transfer test.
13mx x o7 x o4 Offsite power can be connected to 13.8-kV bus 1NPS-SWG1A via preferred transformer 1RTX-XSR1E and circuit breaker 1NPS-ACB11, and to 13.8-kV bus 1NPS-SWG1B via preferred transformer 1RTX-XSR1F and circuit breaker 1NPS-ACB27.
4mx 6mx 7mx


to the valve stem by the motor operator under degraded
RBS USAR Revision 23 8.3-49a x o7 x o4 Onsite power can be connected to 13.8-kV bus 1NPS-SWG1A via normal transformer 1STX-XNS1A and circuit breaker 1NPS-ACB09, and to 13.8-kV bus 1NPS-SWG1B via normal transformer 1STX-XNS1B and circuit breaker 1NPS-ACB25. Offsite power can be connected to 4.16-kV bus 1NNS-SWG1A via preferred transformer 1RTX-XSR1C and circuit breaker 1NNS-ACB07, and to 4.16-kV bus 1NNS-SWG1B via preferred transformer 1RTX-XSR1D and circuit breaker 1NNS-ACB15.
Onsite power can be connected to 4.16-kV buses 1NNS-SWG1A and 1NNS-SWG1B via normal transformer 1STX-XNS1C and circuit breakers 1NNS-ACB06 and 1NNS-ACB14, respectively. The logic that 4mx 7mx


voltage conditions (the calculated minimum starting
RBS USAR Revision 6 8.3-49b August 1993 THIS PAGE LEFT INTENTIONALLY BLANK


voltage available).
RBS USAR Revision 23 8.3-50 automatically transfers a 13.8-kV or 4.16-kV bus from onsite to offsite power is the loss of voltage on the respective 13.8-kV or 4.16-kV bus. The test is performed by manually tripping the 13.8-kV or 4.16-kV breaker from the normal transformer. The voltage loss causes the 13.8-kV or 4.16-kV breaker from the preferred transformer to close onto the respective 13.8-kV or 4.16-kV bus.
5 10. All Class 1E motors are capable of continuous operation with 90 percent of motor nameplate voltage applied to  
During the fast transfer, the outage is of such short duration that the motors remain running and the power system remains intact.
x o6 Offsite power is connected to 13.8-kV bus 1NPS-SWG1C via preferred transformer 1RTX-XSR1E and normally closed circuit breaker 1NPS-ACB43 and to 13.8-kV bus 1NPS-SWG1D via preferred transformer 1RTX-XSR1F and normally closed circuit breaker 1NPS-ACB44. 13.8-kV switchgear 1NPS-SWG1C and 1NPS-SWG1D do not have a back up source of power or transfer to another source.
6mx x o13 x o7 7mx Standby 4.16-kV bus 1ENS*SWG1A is connected to preferred transformer 1RTX-XSR1C via normally closed circuit breaker 1ENS*ACB06, to normal 4.16-kV bus 1NNS-SWG1B via normally open circuit breakers, and to standby diesel generator 1EGS*EG1A via normally open circuit breaker 1ENS*ACB07. Standby 4.16-kV bus 1ENS*SWG1B is connected to preferred transformer 1RTX-XSR1D via normally closed circuit breaker 1ENS*ACB26, to normal 4.16-kV bus 1NNS-SWG1A via normally open circuit breakers, and to standby diesel generator 1EGS*EG1B via normally open circuit breaker 1ENS*ACB27. The transfer test is performed for each bus as follows:
13mx


motor terminals.
RBS USAR Revision 13 8.3-50a September 2000 THIS PAGE LEFT INTENTIONALLY BLANK
RBSUSARRevision58.3-57aAugust1992511.Thestandbyacdieselgeneratorsetswillnotbeusedforthepurposeofsupplyingadditionalpowertothe utilitypowersystem(peaking).12.Table8.3-7identifiesnon-Class1Ecircuits(loads)poweredfromClass1Ebusesthataretrippedoffthe busesduringLOCA.Alsoidentifiedarenon-Class1E loadswhichhavebeenevaluatednottoadverselyaffect theClass1Ebusestowhich 5
RBSUSARRevision58.3-57bAugust1992THISPAGELEFTINTENTIONALLYBLANK RBS USAR Revision 17 8.3-58  they are connected should a fault occur at the non-Class 1E load. This will ensure that the Class 1E systems are maintained at an acceptable level with


respect to the requirements of IEEE-308. 8.3.1.2.1.3 Standby Uninterruptible Power Supply Systems (120-V ac) 15 Each of the four (ENB-INV01A, ENB-INV01A1, ENB-INV01B, and ENB-INV01B1) standby 120-V ac uninterruptible power supply systems has two standby alternating current sources and a standby direct current source of power. A standby 125-V dc station battery, the dc source, is a backup to the primary ac source. The primary and alternate ac sources can be selected by an automatic static transfer switch or a manually operated make-before-break bypass switch. The primary ac source is rectified into direct current
RBS USAR Revision 6 8.3-50b THIS PAGE LEFT BLANK INTENTIONALLY


which in turn is paralleled with the 125-V dc station battery source. The resultant dc is conducted to an inverter where it is changed to 120-V 60-Hz ac, and then conducted to a static switch.
RBS USAR Revision 20 8.3-51
8 13 The loading of a standby diesel generator is performed manually during testing while the reactor is in normal operation. The standby diesel generator is manually synchronized onto the standby bus and then carries selected standby loads. A synchronous check relay is provided to prevent breaker closure during synchronizing operations unless the busses are synchronized within the tolerances of the relay. By opening the breaker from the preferred stat ion service transformer and closing the breaker connecting the standby 4.16-kV bus to the normal 4.16-kV bus, the standby diesel generator load can be simulated to its approximate qualified load. Selected motors are running on the standby bus during the test.
8 13
8.3.1.1.5.6 Procedural Control of Jumpers and Other Temporary Forms of Bypassing Use of jumpers or other temporary forms of bypassing is controlled through implementation of the following procedures:
: 1.
Surveillance Test Procedures - These are written so that in the body of the procedure specific steps direct altering the system to accomplish testing; once testing is complete, specific steps also direct returning the system to the original condition. To ensure this is done
: properly, a
second signoff by a
qualified individual is required to verify normal conditions.
2.
The Temporary Modifications (Alterations) procedure establishes the requirements and methods for controlling activities that temporarily altered the design function of a system or component. The requirements of this procedure applied to all activities that temporarily altered the design function of any component or system after the Preoperational/Acceptance Test Phase and the system or component had been turned over to the plant operating staff.
8 The changes covered were as follows: a change that inhibited or altered the intended operation of a plant component or system such as electrical jumpers, lifted wires, open links, piping blocks and bypasses, papered contacts, or temporary set points that were intended to be returned to normal or permanently incorporated at some later date and not otherwise covered by an approved procedure which returned the system back to normal.
8


The inverter frequency is synchronized with the alternate ac
RBS USAR Revision 24 8.3-52 x o8 8mx
: 3.
The maintenance work process uses several procedures that establish administrative controls for identifying, controlling, and documenting maintenance and maintenance-related activities.
These procedures provides step-by-step instructions to ensure that troubleshooting and/or maintenance is accomplished properly. It also provides for testing by use of approved surveillance test procedures to ensure the system or component has been properly repaired and returned to service.
x o14 x o7 The Shift Manager has complete control of all activities that might alter or prevent a system from performing as it is designed.
7mx 14mx 8.3.1.1.6 Safety-Related Systems Design Criteria 8.3.1.1.6.1 Electric Motors and Torque Considerations Motors employed for Class 1E service are designed and constructed to IEEE-323, -334, and -344 as well as all applicable industry standards in effect at the time of their purchase (Sections 3.9 and 3.11).
Motors are matched to the driven equipment so as to produce sufficient accelerating torque to successfully start the equipment at minimum available motor terminal voltage. A start is considered successful if rated speed can be obtained in less than 5 sec, and within the allowed motor heating curve. This has been generally achieved by requiring a minimum of 10 percent difference between the instantaneous available driver torque and driven equipment demand torque.
8.3.1.1.6.2 Temperature Monitoring and Circuit Protection The nature of Class 1E electrical equipment is such that protection of the equipment is secondary to accident mitigation and safe shutdown of the plant. Temperature monitors and overload heaters are set only to alarm on overload/overtemperature conditions during LOCA operation of Class 1E MOVs.
Trip circuits actuate only to prevent catastrophic failure which could augment rather than mitigate an undesirable circumstance. Coordination calculations show that protective devices actuate at the lowest level necessary to isolate a fault. All protective devices are set for a minimum of 125 percent of the full load current rating of the equipment at all Class 1E voltage


source, but it has its own internal frequency standard which it
RBS USAR 8.3-53 August 1987 levels.
No cascading of protective devices has been employed.
See also Section 8.3.1.1.4.2 regarding HPCS circuit protection.
The River Bend Station design has been reviewed to identify any large horsepower (rated 100 hp or more) safety-related motor/pump combinations that have pressure switches or other permissive devices incorporated into the final actuation control circuitry.
These motors and permissive
: devices, along with the redundancy and diversity provided for such
: devices, are discussed in the following paragraphs.
1.
High-Pressure Core Spray System (E22)
Redundant undervoltage devices monitor bus voltage so that failure of one device to detect available HPCS power on the bus does not prevent the motor from starting.
However, if a loss of bus voltage is sensed by more than one channel of undervoltage
: relays, the HPCS pump is inhibited from starting.
Certain protective trips can inhibit a
HPCS DG start under test conditions;
: however, all but two of the DG trips are bypassed in the presence of an emergency start signal.
The two exceptions are the overspeed trip and the generator differential device trip which protects the diesel generator.
These devices are capable of being tested during normal operations.
Although redundancy of certain components is applied within HPCS in order to improve reliability, the overspeed and differential trips are not redundant by component.
The ECCS network is redundant by system.
2.
Residual Heat Removal System (E12)
There are no pressure switches capable of inhibiting a manual or automatic start of the RHR system.
The RHR pump motor switchgear receives a stop signal if either the 1E12*MOVF004B or 1E12*VF066B valve is full open and the valve 1E12*MOVF006B, 1E12*MOVF009, or 1E12*MOVF008 is not fully open.
Limit switches which sense the full open valve position and generate appropriate full open permissive are not redundant.
The ECCS network is redundant by system and can tolerate loss of an entire RHR train.


uses when the alternate ac source goes beyond normal frequency tolerance. The alternate ac source originates on a 480-V 60-Hz standby bus and is transformed and regulated to 120-V ac. It is then brought to the static switch, and also fed to the manual
RBS USAR 8.3-54 August 1987 3.
Service Water System (SWP)
Emergency start of service water pumps 1SWP*P2A, 1SWP*P2B, 1SWP*P2C, and 1SWP*P2D is inhibited if the respective discharge valve is not fully closed or the standby service water initiation signal is not present.
The limit switch sensing the full closed valve position to generate the appropriate full closed permissive is not redundant.
: However, redundancy does exist at the system level.
The standby service water initiation signal is either reactor plant component cooling water loop loss of pressure or normal standby service water loop loss of pressure.
Each loop is provided with four pressure sensors.
One-out-of-two-taken-twice logic is used in generating the start permissive, thus providing adequate redundancy.
The ability of the standby service water system to accommodate any single component failure without affecting safe shutdown or cooldown or post-accident heat dissipation is detailed in Section 9.2.7.3 and the FMEA.
As for common mode failures, these devices are qualified in accordance with Regulatory Guide 1.89.
During
: shutdown, each pump can be verified to start automatically, on a pressure test signal to the pressure transmitters, to maintain service water pressure greater than technical specification requirements.
8.3.1.1.6.3 Interrupting Capacity of Switchgear and Other Protective Devices Fault current available at all voltage levels has been restricted to values within the certified rating of the interrupting devices employed at that level.
All possible sources of fault current contributions have been considered, including abnormal sources such as an emergency diesel generator on test.
Calculations of available short circuit currents are in accordance with ANSI C37.00-1964.
8.3.1.1.6.4 Grounding The balance-of-plant and Class 1E Divisions I and II, both onsite and
: offsite, power distribution systems are low-resistance grounded.
Discussion of grounding on the HPCS power supply (ESF Division III) is covered in Section 8.3.1.1.4.2.


bypass switch. The output of the static switch and the alternate ac source are the two inputs to the manual bypass switch (Fig. 8.3-1 and 8.3-
RBS USAR Revision 13 8.3-55 September 2000 8.3.1.2 Analysis 8.3.1.2.1 General Functional Design Bases 8.3.1.2.1.1 Auxiliary Electrical Power Supply Systems The auxiliary electrical power supply systems provide ac power required for normal plant operation, shutting down the reactor safely, maintaining a safe shutdown condition, and operating all auxiliaries required for public safety under all
: normal, transient, and accident conditions.
The following general functional design bases apply:
1.
The standby auxiliary electrical power supply systems distribute power to all loads which are essential for public safety.
2.
The normal and standby portions of the auxiliary electrical power supply systems are arranged so that a single failure does not prevent safety-related systems from performing their intended safety functions.
*13 3.
The standby 4.16-kV buses are arranged so that they can be supplied from preferred or standby power sources.
4.
Sufficient instrumentation is provided to ensure a
state of readiness and performance of the standby ac power system.
8.3.1.2.1.2 Standby Electrical Power Supply Systems The standby electrical power supply systems are designed with sufficient capacity and capability to ensure that they are capable to, in sufficient
: time, restore ac power in the event that the preferred power supply becomes unavailable.
They have the ability to reliably supply the required ac load demands of engineered safeguard equipment and controls for post-accident as well as safe and orderly shutdown operations so that the reactor core is cooled and containment integrity and other vital functions are maintained.
The following general functional design bases apply:
13*
1.
Standby ac diesel generators are housed in a
Seismic Category I structure with Seismic Category I walls separating them so that an accident involving one does not involve any others. Each fuel oil tank is contained in a separate


2).The static switch provides a high speed transfer upon loss of inverter power. The manual bypass switch allows the removal of  
RBS USAR Revision 13 8.3-56 September 2000 Seismic Category I room, filled with sand to reduce the chance of fire around the oil tank.
2.
Each standby ac diesel generator produces ac power at the same voltage and frequency as the associated standby station service ac power distribution system.
Each is capable of automatic start at any time and of continuous operation at qualified
: load, voltage, and frequency until manually stopped.
*13 3.
Each standby ac diesel generator is capable of being manually paralleled with preferred station service ac power source under normal conditions.
Provisions are made in the design to prevent the electrical interconnection of the redundant standby ac diesel generators.
4.
Each fuel oil system has a
storage capacity suitable for operating each standby diesel system at its maximum required post-accident load conditions for a minimum of 7 days.
The fuel oil system and storage is tornado and earthquake protected.
5.
Control power required for the operation of each standby ac diesel generator is supplied from its divisional standby 125-V battery system.
Standby auxiliaries, such as fuel pumps and ventilation systems, necessary for continuous operation of standby ac diesel generators are supplied from their associated standby buses.
6.
Upon loss of preferred ac power supplies, each of the standby buses is isolated from its preferred
: sources, and the standby ac diesel generators start automatically and are ready to accept load within 10 sec.
: Controls, both local and in the main control
: room, are provided for manual start and stop of each standby ac diesel generator.
The output of each standby diesel generator is monitored, and abnormal conditions are alarmed in the main control room.
13*
7.
The ac diesel generator system is designed so that with loss of any one of three diesel generators the remaining generators are capable of supplying power to sufficient equipment for a
safe shutdown of the unit under normal or accident conditions.


the inverter or the static transfer switch for maintenance or  
RBS USAR Revision 16 8.3-57 March 2003
: 8.
Standby bus voltage does not dip below 75 percent of motor-rated voltage at any time during the loading sequence, and recovers to 90 percent of motor-rated voltage within 40 percent of each load sequence time interval. The ac diesel generator associated with the HPCS does not comply with this portion of Regulatory Guide 1.9;
: however, its voltage recovery characteristics are operationally acceptable when starting its loads (Section 8.3.1.2.2.2).
: 9.
All Class 1E motors, except as noted below, are capable of starting and accelerating their driven equipment with 70 percent of motor nameplate voltage applied to motor terminals without affecting performance or equipment life.
16 12 8 The exceptions to this are certain motor-operated valves, motor-operated dampers, Division I and II diesel generator starting air compressors EGA-C4A, EGA-C4B, EGA-C5A and EGA-C5B, 1HVR*UC5, and the motors driving air compressors 1LSV*C3A and 1LSV*C3B. These LSV compressors have been environmentally qualified consistent with IEEE-323 and are capable of starting at 80 percent of motor nameplate voltage. Calculations have determined, however, that the minimum starting voltage available at the motor terminals will be 89.63 percent, well in excess of the motors' capabilities.
16
These Class 1E motor-operated valves, motor-operated dampers, Division I and II diesel generator starting air compressors EGA-C4A, EGA-C4B, EGA-C5A and EGA-C5B, and unit coolers are capable of starting and accelerating with 80 percent of motor nameplate voltage applied to motor terminals.
Calculations have determined that the minimum starting voltage available at the motor terminals during the period required for operation is in excess of the required starting voltage.
8 12
5 To ensure proper motor-operated valve function under design conditions, an analysis is performed to determine the torque or thrust that must be delivered to the valve stem by the motor operator under degraded voltage conditions (the calculated minimum starting voltage available).
5
: 10. All Class 1E motors are capable of continuous operation with 90 percent of motor nameplate voltage applied to motor terminals.


testing.15The following general functional design bases apply:  1. The 120-V ac uninterruptible power supply systems consist of independent and redundant power sources, with adequate capacity to supply all essential loads.
RBS USAR Revision 5 8.3-57a August 1992
*5 11.
The standby ac diesel generator sets will not be used for the purpose of supplying additional power to the utility power system (peaking).
12.
Table 8.3-7 identifies non-Class 1E circuits (loads) powered from Class 1E buses that are tripped off the buses during LOCA.
Also identified are non-Class 1E loads which have been evaluated not to adversely affect the Class 1E buses to which 5*


The loss of any one source will not affect the bus. 2. The standby 120-V ac uninterruptible power supply systems are structurally designed in accordance with Seismic Category I criteria and are located in Seismic
RBS USAR Revision 5 8.3-57b August 1992 THIS PAGE LEFT INTENTIONALLY BLANK


Category I structures.
RBS USAR Revision 17 8.3-58 they are connected should a fault occur at the non-Class 1E load. This will ensure that the Class 1E systems are maintained at an acceptable level with respect to the requirements of IEEE-308.
RBS USAR Revision 17 8.3-59  3. The standby 120-V ac uninterruptible power supply systems are designed to operate continuously without
8.3.1.2.1.3 Standby Uninterruptible Power Supply Systems (120-V ac)
15 Each of the four (ENB-INV01A, ENB-INV01A1, ENB-INV01B, and ENB-INV01B1) standby 120-V ac uninterruptible power supply systems has two standby alternating current sources and a standby direct current source of power. A standby 125-V dc station battery, the dc source, is a backup to the primary ac source. The primary and alternate ac sources can be selected by an automatic static transfer switch or a manually operated make-before-break bypass switch. The primary ac source is rectified into direct current which in turn is paralleled with the 125-V dc station battery source. The resultant dc is conducted to an inverter where it is changed to 120-V 60-Hz ac, and then conducted to a static switch.
The inverter frequency is synchronized with the alternate ac source, but it has its own internal frequency standard which it uses when the alternate ac source goes beyond normal frequency tolerance. The alternate ac source originates on a 480-V 60-Hz standby bus and is transformed and regulated to 120-V ac. It is then brought to the static switch, and also fed to the manual bypass switch.
The output of the static switch and the alternate ac source are the two inputs to the manual bypass switch (Fig. 8.3-1 and 8.3-2).
The static switch provides a high speed transfer upon loss of inverter power. The manual bypass switch allows the removal of the inverter or the static transfer switch for maintenance or testing.
15
The following general functional design bases apply:
: 1.
The 120-V ac uninterruptible power supply systems consist of independent and redundant power sources, with adequate capacity to supply all essential loads.
The loss of any one source will not affect the bus.
: 2.
The standby 120-V ac uninterruptible power supply systems are structurally designed in accordance with Seismic Category I criteria and are located in Seismic Category I structures.


anomaly during and after the maximum seismic  
RBS USAR Revision 17 8.3-59
: 3.
The standby 120-V ac uninterruptible power supply systems are designed to operate continuously without anomaly during and after the maximum seismic accelerations expected for the site.
15 1
: 4.
Standby 120-V ac uninterruptible power supply systems ENB*INV01A, ENB-INV01A1, and ENB*INV01B (or ENB-INV01B1) are physically and electrically independent (by division) and support redundant loads. It is not possible to parallel the outputs of these systems.
1 15
8.3.1.2.2 Design Criteria and Standards 8.3.1.2.2.1 ESF Divisions I and II Criterion 17 The ESF system is designed with sufficient
: capacity, independence, and redundancy to assure that core cooling, containment integrity, and other vital safety functions are performed in the event of postulated accidents, assuming a single failure. The design of the onsite and offsite electrical power systems provides compatible independence and redundancy to ensure an available source of power to the ESF loads. Electrical power from the 230-kV switchyard to the 230/13.8-kV and 230/4.16-kV preferred station service transformers is provided by physically and electrically independent transmission lines. This provides two independent offsite sources of power to the 4.16-kV standby buses.
Offsite preferred power circuits are connected via normally closed breakers to standby 4.16-kV buses 1ENS*SWG1A and 1ENS*SWG1B (Divisions I and II) at all times. Loss of normal plant auxiliary supply does not influence or affect the normal 4.16-kV buses 1NNS-SWG1A and 1NNS-SWG1B tie circuits to standby 4.16-kV buses 1ENS*SWG1A and 1ENS*SWG1B.
13 The standby 4.16-kV bus 1E22*S004 (Division III) is connected to one of the offsite circuits (Fig. 8.1-4). Loss of all offsite power from the network, although highly unlikely, would result in automatic starting and connection of diesel generator set 1E22*S001G1C to the associated bus within 13 sec.
13
The degree of reliability of the power sources required for safe shutdown is very high due to independence and redundancy; it equals or exceeds all the requirements of Criterion 17.


accelerations expected for the site. 151 4. Standby 120-V ac uninterruptible power supply systems ENB*INV01A , ENB-INV01A1, and ENB*INV01B (or ENB-INV01B1) are physically and electrically independent (by division) and support redundant loads. It is not possible to parallel the outputs of these systems.
RBS USAR 8.3-60 August 1987 Criterion 18 The auxiliary electrical system is designed to permit inspection and testing of all important areas and features, especially those which have a
1 158.3.1.2.2 Design Criteria and Standards 8.3.1.2.2.1 ESF Divisions I and II
standby function and whose operation is not normally demonstrated.
As detailed in the Technical Specifications, periodic component tests are supplemented by extensive functional tests during refueling outages (the latter based on simulation of action accident conditions).
These demonstrate the operability of diesel generator
: sets, battery system components, and logic
: systems, thus verifying the continuity of the systems and the operation of the components.
A complete preoperational test of the onsite ESF power distribution system is a prerequisite to initial fuel loading.
Regulatory Guide 1.6 The three standby ac power system divisions each consist of a
diesel generator set feeding its own ESF division load group.
Each load group has its own dc power
: system, energized by a
battery and battery chargers.
The three load groups possess complete independence.
The standby power system redundancy is based on the capability of any two of the three load groups to provide the minimum safety functions necessary to shut down the unit and maintain it in the safe shutdown condition.
In addition to the prohibition of sharing standby power system components between load
: groups, there is also no sharing of diesel generator power sources between units.
Each Division I
and II standby power source is composed of a
single generator driven by a
single diesel engine having fast-start characteristics and sized in accordance with Regulatory Guide 1.9.
The design of the standby power system is therefore in complete compliance with the regulations of Regulatory Guide 1.6.
Regulatory Guide 1.9 In accordance with Regulatory Guide 1.9, the ratings of standy diesel generators 1EGS*EG1A and 1EGS*EG1B are continuous load rating of 3,500 kW
: each, and a
2-hour rating of 3,850 kW
: each, which exceeds the sum of the loads required.


Criterion 17 The ESF system is designed with sufficient capacity, independence, and redundancy to assure that core cooling, containment integrity, and other vital safety functions are performed in the event of postulated accidents, assuming a single failure. The design of the onsite and offsite electrical power
RBS USAR 8.3-61 August 1987 The sequencing of large loads at predetermined intervals (Table 8.3-2) ensures that large motors will have reached rated speed and that voltage and frequency will have stabilized before the succeeding loads are applied.
The decrease in frequency and voltage has been verified to be within 95 and 80 percent of nominal, respectively.
Recovery of voltage and frequency to within 10 percent and 2 percent of
: nominal, respectively, has been verified to be accomplished within 40 percent of the sequencing interval of 5 sec.
Step loading and disconnection of the total diesel generator nameplate-rating load does not cause the standby diesel generator to exceed 110 percent of normal speed, thus precluding an inadvertent overspeed trip.
The reliability of the standby diesel generators has been substantiated by an extensive test program.
The tests verify the following diesel functions:
1.
Diesel fast start capabilities 2.
Load carrying capabilities 3.
Load shedding capabilities 4.
Ability of the system to accept and carry the applied loads up to its rated capacity 5.
Long-term no load running of the diesel unit without any detrimental effects.
The reliability of the system to start and accept loads in a
prescribed time interval has been demonstrated by prototype qualification test data augumented by analysis to verify the ability of the River Bend Station standby diesel generators to perform their intended function, and has been further verified by preoperational tests.
The preoperational tests described in Section 8.3.1.1.5.2 verify reliability after plant installation.
Full-load tests have been performed during preoperational testing at the River Bend Station on each diesel generator set to demonstrate the start and load capability of the units within the design requirements.
Three hundred valid start and load tests have been performed at the Shoreham I unit with no failures.
A valid start and load test is defined as a
start from normal standby temperature conditions with loading to at least 50 percent of continuous rating within the required sequencing time intervals, and continued operation until operating temperatures are reached.
The fast start tests to verify the diesel reliability were conducted in the factory.
They


systems provides compatible independence and redundancy to ensure an available source of power to the ESF loads. Electrical power
RBS USAR 8.3-62 August 1987 are documented in the QA/QC verification data package, together with the results of other tests described, and provide a
permanent, onsite qualification record.
(Refer to NEDO 10905 May 1973, for reliability analysis of the HPCS standby power supply.)
Regulatory Guide 1.32 The design of the preferred power circuits provides for two immediately accessible circuits from the transmission network to the onsite power distribution system.
The sizing of Class 1E battery chargers is based on their ability to recharge the battery within 24 hr after discharge to a design minimum level of 105 V while supplying the maximum steady-state load which occurs in the post-accident period.
This is in accordance with the regulatory position of Regulatory Guide 1.32.
IEEE-308 All electrical system components supplying power to Class 1E electrical equipment are designed to meet their functional requirements under the conditions produced by the design basis events.
All redundant equipment is physically separated to maintain independence and eliminate the possibility of common mode failure.
All Class 1E equipment is located in Seismic Category I structures.
Class 1E equipment is uniquely identified by color coding of all components according to the division to which it is assigned, as detailed in Section 8.3.1.3.1.
Surveillance of Class 1E electric systems is in compliance with IEEE-308, as are all other aspects applicable to the station design.
This surveillance is detailed in the Technical Specifications.
IEEE-323 Conformance with IEEE-323 is described in Section 3.11.
8.3.1.2.2.2 High Pressure Core Spray Power Supply System -
Division III Criterion 17 The Class 1E system is designed with sufficient
: capacity, independence, and redundancy to ensure that core
: cooling, containment integrity, and other vital functions are


from the 230-kV switchyard to the 230/13.8-kV and 230/4.16-kV preferred station service transformers is provided by physically and electrically independent transmission lines. This provides
RBS USAR 8.3-63 August 1987 maintained in the event of a postulated accident.
The design of the onsite and offsite electrical power systems provides compatible independence and redundancy to ensure an available source of power to the HPCS system and its supporting auxiliaries.
Electrical power from the transmission network to the station is provided by two physically and electrically independent 230-kV circuits as required by the criterion.
The loss of all offsite power from the network, although highly unlikely, results in an automatic starting and connection of the HPCS diesel generator set to the HPCS bus.
The degree of reliability of the power sources required for safe shutdown is high, because of the independence and redundancy, and equals or exceeds requirements of the criterion.
Criterion 18 The auxiliary electrical system is designed to permit inspection and testing of all important areas and
: features, especially those that have a standby function and whose operation is not normally demonstrated.
As detailed in the Technical Specifications, periodic component tests are supplemented by extensive functional tests during the refueling
: outage, the latter based on simulation of actual accident conditions.
These tests demonstrate the operability of diesel generator
: sets, battery system components, and logic systems and thereby verify the continuity of the systems and the operability of the components.
Because the diesel generator is a standby unit, readiness is of prime importance.
Readiness is demonstrated by periodic testing.
The testing program is designed to test the ability of the HPCS diesel generator set to start as well as to run under equivalent load as required by Regulatory Guide 1.108.
This ensures that cooling and lubrication are adequate for extended periods of operation.
Full functional tests of the automatic control circuitry are conducted in accordance with the Technical Specification on a
periodic basis to demonstrate correct operation.
Criterion 21 The protection system of the HPCS power supply is designed to be highly reliable and testable during reactor operation. The HPCS diesel generator is only part of the high pressure core spray system.
If it
: fails, the redundant automatic


two independent offsite sources of power to the 4.16-kV standby
RBS USAR 8.3-64 August 1987 depressurization system reduces the reactor pressure so that flow from LPCI and LPCS systems enters the reactor vessel in time to cool the core and limit fuel cladding temperature.
Regulatory Guide 1.6 The HPCS diesel generator unit supplies power for the HPCS and other auxiliaries as shown in Table 8.3-3; therefore, failure of any single component of the HPCS diesel generator does not prevent the startup and operation of any other standby power supply.
The failure of any other standby diesel generator does not impede the operation of the HPCS diesel generator and its load
: group, thus meeting the requirements of Regulatory Guide 1.6.
Regulatory Guide 1.6, Position 1 Conformance The HPCS Class 1E loads are assigned to a single division of the load groups.
The assignment is determined by the nuclear safety functional redundancy of the loads such that the loss of any one division does not prevent the minimum safety functions from being performed.
Regulatory Guide 1.6, Position 2 Conformance The HPCS bus (Division III of the ac load groups) is connectable to two different (preferred) offsite power sources.
The HPCS bus is also connectable to the HPCS diesel generator as the standby onsite power source (Fig. 8.3-3).
The HPCS diesel generator breaker can be closed automatically only if all other source breakers to the HPCS bus are open.
There is no automatic connection to any other division load group.
Regulatory Guide 1.6, Position 3 Conformance There is no automatic or manual connection of the HPCS system dc load group to any other division load group.
Regulatory Guide 1.6, Position 4 Conformance 1.
The diesel generators connected to the other divisions of the load groups are physically and electrically independent of each other.
The diesel generator connected to the HPCS division load group cannot be automatically paralleled with the diesel generator that is connected to another division load group.


buses.Offsite preferred power circuits are connected via normally closed breakers to standby 4.16-kV buses 1ENS*SWG1A and 1ENS*SWG1B (Divisions I and II) at all times. Loss of normal
RBS USAR 8.3-65 August 1987 2.
The HPCS diesel generator is connected to one independent division.
No means exist for automatically connecting the HPCS load group with any other.
3.
The HPCS load group is fed from only one diesel generator, as shown in Fig. 8.3-3.
No means are provided for transferring its loads to any other diesel generator.
4.
No means exist for manually connecting the HPCS load group to those of another division.
The HPCS load group is physically and electrically independent of all others.
Regulatory Guide 1.6, Position 5 Conformance The HPCS diesel generator comprises of a single generator driven by a single engine.
This diesel generator set neither operates in parallel with any other diesel generator set nor has tandom engines driving the single generator.
Regulatory Guide 1.9 Conformance with Regulatory Guide 1.9 is described in the following subsections for each regulatory position of Paragraph C of the guide.
Regulatory Guide 1.9, Position 1 Conformance Table 8.3-3 shows that the continuous rating of the diesel generator is greater than the maximum coincidental steady-state loads requiring power at any time.
Intermittent loads such as motor-operated valves are not considered for long-term loads.
Regulatory Guide 1.9, Position 2 Conformance The long-term steady-state load shown in Table 8.3-3 is within the continuous rating of the diesel generator.
Regulatory Guide 1.9, Position 3 Conformance The load requirements were verified during the preoperational tests described in Sections 14.2.12.1.8 and 14.2.12.1.44.


plant auxiliary supply does not influence or affect the normal 4.16-kV buses 1NNS-SWG1A and 1NNS-SWG1B tie circuits to standby
RBS USAR 8.3-66 August 1987 Regulatory Guide 1.9, Position 4 Conformance The design function of the HPCS diesel generator unit is considered to be a justifiable departure from strict conformance to Regulatory Guide 1.9, regarding voltage and frequency limits during the initial loading transient.
The HPCS diesel generator loads consist of one large pump and motor combination (approximately 2,500 hp),
one medium size pump (450 hp),
and other miscellaneous loads; consequently, limiting the momentary voltage drop to 25 percent and the momentary frequency drop to 5 percent would not significantly enhance the reliability of HPCS operation.
To meet these regulatory guide requirements, a diesel generator unit approximately two to three times as large as that required to carry the continuous full load would be necessary.
: However, the frequency and voltage overshoot requirements of Regulatory Guide 1.9 are met.
A factory testing program on a
prototype unit has verified the following functions:
1.
System fast-start capabilities 2.
Load carrying capability 3.
Load rejection capability 4.
Ability of the system to accept and carry the required loads 5.
The mechanical integrity of the diesel-engine generator unit and all major system auxiliaries.
A detailed discussion of the calculated voltage and frequency transient response is given in Chapter 3 of the GE Licensing Topical Report NEDO 10905 (HPCS Power Supply Topical Report NEDO 10905, Section 6, describes prototype and reliability test requirements).
The design of the HPCS diesel generator conforms with the applicable sections of IEEE criteria for Class 1E electrical systems for nuclear power generation stations (IEEE-308).
In addition, a prototype test has been performed.
The generator has the capability of providing power for starting the required loads with operationally acceptable voltage and frequency recovery characteristics.
A partial or complete load rejection does not cause the diesel engine to trip on overspeed.


4.16-kV buses 1ENS*SWG1A and 1ENS*SWG1B. 13The standby 4.16-kV bus 1E22*S004 (Division III) is connected to one of the offsite circuits (Fig. 8.1-4). Loss of all offsite power from the network, although highly unlikely, would result in automatic starting and connection of diesel generator set
RBS USAR 8.3-67 August 1987 Regulatory Guide 1.29 The HPCS electric system is capable of performing its function when subjected to the effects of design bases natural phenomena at its location.
In particular, it is designed in accordance with the Seismic Category I criteria and is housed in a Seismic Category I structure.
Regulatory Guide 1.32 The design of the HPCS power supply system conforms with the applicable sections of IEEE criteria for Class 1E electrical systems for nuclear power generation stations IEEE-308.
Note:
GE Licensing Topical Report NEDO-10905 describes prototype and reliability test requirements.
Regulatory Guide 1.47 All the bypassed trip devices provide alarms in the main control room so that conditions which can render the HPCS diesel generator system unavailable for automatic start are automatically annunciated at the system level in the main control room.
See NEDO 10905, Amendment 1, p 20.
Regulatory Guide 1.62 Manual controls are provided to permit the operator to select the most suitable distribution path from the power supply to the HPCS load.
An automatic start signal overrides the test mode.
Provision is made for control of the system from the main control room as well as from an external location.
Regulatory Guide 1.75 The HPCS diesel generator is a
Division III device and is separated from equipment of other divisions.
It is marked with a Division III name tag.
Regulatory Guide 1.100 All Class 1E equipment of the HPCS system is seismically qualified to the requirements of IEEE-344-1971 which was the plant requirement for this equipment.
A re-evaluation to the requirements of IEEE 344-1975 and Regulatory Guide 1.100 is in progress and will be reported upon completion.


1E22*S001G1C to the associated bus within 13 sec.
RBS USAR 8.3-68 August 1987 Regulatory Guide 1.106 Electric motors on motor-operated valves have been identified as a significant intermittent load on the general ac power system.
13The degree of reliability of the power sources required for safe shutdown is very high due to independence and redundancy; it  
This regulatory guide describes acceptable methods of disabling thermal protective devices on motor-operated valve motors.
Thermal overload devices normally in force during normal plant operation are bypassed under accident conditions.
Regulatory Guide 1.118 This regulatory guide describes acceptable means for periodically testing the functional performance and responses of the electric power and protection systems.
The requirements of this regulatory guide are met with the following clarifications:
Position C.6 Trip of an associated protective channel or actuation of an associated Class 1E load group is required on removal of fuses or opening of a breaker only for the purpose of deactivating instrumentation or control circuit.
IEEE-279 The HPCS diesel generator and its supporting auxiliaries conform to all requirements of IEEE-279 which are applicable to singular diverse elements of a redundant set.
IEEE-308 All the electric system components supplying power to the HPCS system consist of Class 1E electric equipment and are designed to meet their functional requirements under the conditions produced by the design basis events.
All the redundant equipment is physically separated to maintain independence and to minimize the possibility of a common mode failure.
All Class 1E equipment is located in Seismic Category I structures.
The HPCS Class 1E equipment is uniquely identified by color coding of the components according to the division to which it is assigned, as detailed in Section 8.3.1.3.1.
Surveillance of the Class 1E electric systems is in compliance with the
: standard, as are all other aspects applicable to the station design.


equals or exceeds all the requirements of Criterion 17.
RBS USAR Revision 8 8.3-69 August 1996 IEEE-323 Conformance with IEEE-323 is described in Section 3.11.
RBSUSAR8.3-60August1987Criterion18Theauxiliaryelectricalsystemisdesignedtopermitinspectionandtestingofallimportantareasandfeatures,especiallythose whichhaveastandbyfunctionandwhoseoperationisnot normallydemonstrated.AsdetailedintheTechnical Specifications,periodiccomponenttestsaresupplementedby extensivefunctionaltestsduringrefuelingoutages(thelatter basedonsimulationofactionaccidentconditions).These demonstratetheoperabilityofdieselgeneratorsets,battery systemcomponents,andlogicsystems,thusverifyingthe continuityofthesystemsandtheoperationofthecomponents.A completepreoperationaltestoftheonsiteESFpowerdistribution systemisaprerequisitetoinitialfuelloading.RegulatoryGuide1.6ThethreestandbyacpowersystemdivisionseachconsistofadieselgeneratorsetfeedingitsownESFdivisionloadgroup.
IEEE-344 Conformance with IEEE-344 is described in Section 3.10.
Eachloadgrouphasitsowndcpowersystem,energizedbya batteryandbatterychargers.Thethreeloadgroupspossess completeindependence.Thestandbypowersystemredundancyis basedonthecapabilityofanytwoofthethreeloadgroupsto providetheminimumsafetyfunctionsnecessarytoshutdownthe unitandmaintainitinthesafeshutdowncondition.Inadditiontotheprohibitionofsharingstandbypowersystemcomponentsbetweenloadgroups,thereisalsonosharingof dieselgeneratorpowersourcesbetweenunits.EachDivisionIandIIstandbypowersourceiscomposedofasinglegeneratordrivenbyasingledieselenginehavingfast-startcharacteristicsandsizedinaccordancewithRegulatory Guide1.9.ThedesignofthestandbypowersystemisthereforeincompletecompliancewiththeregulationsofRegulatoryGuide1.6.RegulatoryGuide1.9InaccordancewithRegulatoryGuide1.9,theratingsofstandydieselgenerators1EGS*EG1Aand1EGS*EG1Barecontinuousload ratingof3,500kWeach,anda2-hourratingof3,850kWeach, whichexceedsthesumoftheloadsrequired.
IEEE-387 The HPCS power supply unit is completely independent of other standby power supply units and meets the applicable requirements of IEEE-387.
RBSUSAR8.3-61August1987Thesequencingoflargeloadsatpredeterminedintervals(Table8.3-2)ensuresthatlargemotorswillhavereachedrated speedandthatvoltageandfrequencywillhavestabilizedbefore thesucceedingloadsareapplied.Thedecreaseinfrequencyand voltagehasbeenverifiedtobewithin95and80percentof nominal,respectively.Recoveryofvoltageandfrequencytowithin10percentand2percentofnominal,respectively,hasbeenverifiedtobe accomplishedwithin40percentofthesequencingintervalof 5sec.Steploadinganddisconnectionofthetotaldiesel generatornameplate-ratingloaddoesnotcausethestandbydiesel generatortoexceed110percentofnormalspeed,thusprecluding aninadvertentoverspeedtrip.Thereliabilityofthestandbydieselgeneratorshasbeensubstantiatedbyanextensivetestprogram.Thetestsverifythe followingdieselfunctions:1.Dieselfaststartcapabilities 2.Loadcarryingcapabilities 3.Loadsheddingcapabilities 4.Abilityofthesystemtoacceptandcarrytheappliedloadsuptoitsratedcapacity5.Long-termnoloadrunningofthedieselunitwithoutanydetrimentaleffects.Thereliabilityofthesystemtostartandacceptloadsinaprescribedtimeintervalhasbeendemonstratedbyprototype qualificationtestdataaugumentedbyanalysistoverifythe abilityoftheRiverBendStationstandbydieselgeneratorsto performtheirintendedfunction,andhasbeenfurtherverifiedby preoperationaltests.Thepreoperationaltestsdescribedin Section8.3.1.1.5.2verifyreliabilityafterplantinstallation.
The HPCS diesel generator unit is designed to:
Full-loadtestshavebeenperformedduringpreoperationaltesting attheRiverBendStationoneachdieselgeneratorsetto demonstratethestartandloadcapabilityoftheunitswithinthe designrequirements.Threehundredvalidstartandloadtests havebeenperformedattheShorehamIunitwithnofailures.A validstartandloadtestisdefinedasastartfromnormal standbytemperatureconditionswithloadingtoatleast 50percentofcontinuousratingwithintherequiredsequencing timeintervals,andcontinuedoperationuntiloperating temperaturesarereached.Thefaststartteststoverifythe dieselreliabilitywereconductedinthefactory.They RBSUSAR8.3-62August1987aredocumentedintheQA/QCverificationdatapackage,togetherwiththeresultsofothertestsdescribed,andprovidea permanent,onsitequalificationrecord.(RefertoNEDO10905 May1973,forreliabilityanalysisoftheHPCSstandbypower
1.
Operate in its service environment during and after any design basis event without support from the preferred power supply.
2.
: Start, accelerate, and be loaded with the design load within an acceptable time:
a.
From the normal standby condition, b.
With no cooling available, for a time equivalent to that required to bring the cooling equipment into service with energy from the diesel generator unit, c.
On a
restart with an initial engine temperature equal to the continuous
: rating, full load engine temperature.
3.
Carry the long-term steady-state load continuously.
4.
Maintain voltage and frequency within limits that will not degrade the performance of any of the loads composing the design load below their minimum requirements, including the duration of transients caused by load application or load removal.
*8 5.
Withstand any anticipated vibration and overspeed conditions.
The generator and exciter are designed to withstand 25 percent overspeed without damage.
8*


supply.)RegulatoryGuide1.32Thedesignofthepreferredpowercircuitsprovidesfortwoimmediatelyaccessiblecircuitsfromthetransmissionnetworkto theonsitepowerdistributionsystem.ThesizingofClass1Ebatterychargersisbasedontheirabilitytorechargethebatterywithin24hrafterdischargetoadesign minimumlevelof105Vwhilesupplyingthemaximumsteady-state loadwhichoccursinthepost-accidentperiod.Thisisin accordancewiththeregulatorypositionofRegulatoryGuide1.32.
RBS USAR Revision 8 8.3-70 August 1996
*8 The HPCS diesel generator has continuous and short-term ratings consistent with the requirements of IEEE-387, Section 5.1.
8*
8.3.1.2.3 Conformance With Appropriate Quality Assurance Standards The quality assurance program outlined in Chapter 17 conforms with Regulatory Guide 1.30, Quality Assurance Requirements for the Installation, Inspection, and Testing of Instrumentation and Electric Equipment.
The program outlined in Chapter 17 includes a
comprehensive system to ensure that the purchased
: material, manufacture, fabrication, testing, and quality control of the equipment in the standby electric power system conforms to the evaluation of the standby electric power system equipment vendor quality assurance programs and preparation of procurement specifications incorporating quality assurance requirements.
The administrative responsibility and control provided are also described in Chapter 17.
These quality assurance requirements include an appropriate vendor quality assurance program and organization, purchaser surveillance as
: required, vendor preparation and maintenance of appropriate test and inspection
: records, certificates and other quality assurance documentation, and vendor submittal of quality control records considered necessary for purchaser retention to verify quality of completed work.
A necessary condition for receipt, installation, and placing of equipment in service has been the sighting and auditing of QA/QC verification data and the placing of this data in permanent onsite storage files.
8.3.1.2.4 Environmental Qualification for Electrical Equipment Located in a Harsh Environment See Section 3.11.


IEEE-308AllelectricalsystemcomponentssupplyingpowertoClass1E electricalequipmentaredesignedtomeettheirfunctional requirementsundertheconditionsproducedbythedesignbasis events.Allredundantequipmentisphysicallyseparatedto maintainindependenceandeliminatethepossibilityofcommon modefailure.AllClass1EequipmentislocatedinSeismic CategoryIstructures.Class1Eequipmentisuniquelyidentifiedbycolorcodingofallcomponentsaccordingtothedivisiontowhichitisassigned,as detailedinSection8.3.1.3.1.
RBS USAR
SurveillanceofClass1Eelectricsystemsisincompliancewith IEEE-308,asareallotheraspectsapplicabletothestation design.ThissurveillanceisdetailedintheTechnical

 
(1)T = cable tray; C = conduit Revision 17 8.3-71 8.3.1.3 Physical Identification of Safety-Related Equipment 8.3.1.3.1 Color Coding Color coded identification is provided for all safety-related equipment including cables, cable raceway, motors, panelboards, motor control centers, load centers, and switchgear. This identification may be by means of a letter, nameplate, paint, nondeteriorating self-adhesive tapes, permanently affixed tags, or similar means. Nonsafety-related equipment has no color identification.
Specifications.
IEEE-323ConformancewithIEEE-323isdescribedinSection3.11.8.3.1.2.2.2HighPressureCoreSprayPowerSupplySystem-DivisionIIICriterion17TheClass1Esystemisdesignedwithsufficientcapacity,independence,andredundancytoensurethatcorecooling, containmentintegrity,andothervitalfunctionsare RBSUSAR8.3-63August1987maintainedintheeventofapostulatedaccident.Thedesignoftheonsiteandoffsiteelectricalpowersystemsprovides compatibleindependenceandredundancytoensureanavailable sourceofpowertotheHPCSsystemanditssupporting
 
auxiliaries.Electricalpowerfromthetransmissionnetworktothestationisprovidedbytwophysicallyandelectricallyindependent230-kV circuitsasrequiredbythecriterion.Thelossofalloffsite powerfromthenetwork,althoughhighlyunlikely,resultsinan automaticstartingandconnectionoftheHPCSdieselgenerator settotheHPCSbus.Thedegreeofreliabilityofthepowersourcesrequiredforsafeshutdownishigh,becauseoftheindependenceandredundancy,and equalsorexceedsrequirementsofthecriterion.Criterion18Theauxiliaryelectricalsystemisdesignedtopermitinspectionandtestingofallimportantareasandfeatures,especially thosethathaveastandbyfunctionandwhoseoperationisnot normallydemonstrated.AsdetailedintheTechnical Specifications,periodiccomponenttestsaresupplementedby extensivefunctionaltestsduringtherefuelingoutage,the latterbasedonsimulationofactualaccidentconditions.These testsdemonstratetheoperabilityofdieselgeneratorsets, batterysystemcomponents,andlogicsystemsandtherebyverify thecontinuityofthesystemsandtheoperabilityofthe
 
components.Becausethedieselgeneratorisastandbyunit,readinessisofprimeimportance.Readinessisdemonstratedbyperiodictesting.
ThetestingprogramisdesignedtotesttheabilityoftheHPCS dieselgeneratorsettostartaswellastorununderequivalent loadasrequiredbyRegulatoryGuide1.108.Thisensuresthat coolingandlubricationareadequateforextendedperiodsof operation.Fullfunctionaltestsoftheautomaticcontrol circuitryareconductedinaccordancewiththeTechnical Specificationonaperiodicbasistodemonstratecorrect
 
operation.Criterion21TheprotectionsystemoftheHPCSpowersupplyisdesignedtobehighlyreliableandtestableduringreactoroperation.TheHPCS dieselgeneratorisonlypartofthehighpressurecorespray system.Ifitfails,theredundantautomatic RBSUSAR8.3-64August1987depressurizationsystemreducesthereactorpressuresothatflowfromLPCIandLPCSsystemsentersthereactorvesselintimeto coolthecoreandlimitfuelcladdingtemperature.RegulatoryGuide1.6TheHPCSdieselgeneratorunitsuppliespowerfortheHPCSandotherauxiliariesasshowninTable8.3-3;therefore,failureof anysinglecomponentoftheHPCSdieselgeneratordoesnot preventthestartupandoperationofanyotherstandbypower supply.Thefailureofanyotherstandbydieselgeneratordoes notimpedetheoperationoftheHPCSdieselgeneratorandits loadgroup,thusmeetingtherequirementsofRegulatory Guide1.6.RegulatoryGuide1.6,Position1ConformanceTheHPCSClass1Eloadsareassignedtoasingledivisionoftheloadgroups.Theassignmentisdeterminedbythenuclearsafety functionalredundancyoftheloadssuchthatthelossofanyone divisiondoesnotpreventtheminimumsafetyfunctionsfrombeing
 
performed.RegulatoryGuide1.6,Position2ConformanceTheHPCSbus(DivisionIIIoftheacloadgroups)isconnectabletotwodifferent(preferred)offsitepowersources.TheHPCSbus isalsoconnectabletotheHPCSdieselgeneratorasthestandby onsitepowersource(Fig.8.3-3).TheHPCSdieselgeneratorbreakercanbeclosedautomaticallyonlyifallothersourcebreakerstotheHPCSbusareopen.
Thereisnoautomaticconnectiontoanyotherdivisionload
 
group.RegulatoryGuide1.6,Position3ConformanceThereisnoautomaticormanualconnectionoftheHPCSsystemdcloadgrouptoanyotherdivisionloadgroup.RegulatoryGuide1.6,Position4Conformance1.Thedieselgeneratorsconnectedtotheotherdivisionsoftheloadgroupsarephysicallyandelectrically independentofeachother.Thedieselgenerator connectedtotheHPCSdivisionloadgroupcannotbe automaticallyparalleledwiththedieselgeneratorthat isconnectedtoanotherdivisionloadgroup.
RBSUSAR8.3-65August19872.TheHPCSdieselgeneratorisconnectedtooneindependentdivision.Nomeansexistforautomatically connectingtheHPCSloadgroupwithanyother.3.TheHPCSloadgroupisfedfromonlyonedieselgenerator,asshowninFig.8.3-3.Nomeansare providedfortransferringitsloadstoanyotherdiesel
 
generator.4.NomeansexistformanuallyconnectingtheHPCSloadgrouptothoseofanotherdivision.TheHPCSload groupisphysicallyandelectricallyindependentofall
 
others.RegulatoryGuide1.6,Position5ConformanceTheHPCSdieselgeneratorcomprisesofasinglegeneratordrivenbyasingleengine.Thisdieselgeneratorsetneitheroperates inparallelwithanyotherdieselgeneratorsetnorhastandom enginesdrivingthesinglegenerator.RegulatoryGuide1.9ConformancewithRegulatoryGuide1.9isdescribedinthefollowingsubsectionsforeachregulatorypositionofParagraphC oftheguide.RegulatoryGuide1.9,Position1ConformanceTable8.3-3showsthatthecontinuousratingofthediesel generatorisgreaterthanthemaximumcoincidentalsteady-state loadsrequiringpoweratanytime.Intermittentloadssuchas motor-operatedvalvesarenotconsideredforlong-termloads.RegulatoryGuide1.9,Position2ConformanceThelong-termsteady-stateloadshowninTable8.3-3iswithinthecontinuousratingofthedieselgenerator.RegulatoryGuide1.9,Position3ConformanceTheloadrequirementswereverifiedduringthepreoperationaltestsdescribedinSections14.2.12.1.8and14.2.12.1.44.
RBSUSAR8.3-66August1987RegulatoryGuide1.9,Position4ConformanceThedesignfunctionoftheHPCSdieselgeneratorunitisconsideredtobeajustifiabledeparturefromstrictconformance toRegulatoryGuide1.9,regardingvoltageandfrequencylimits duringtheinitialloadingtransient.TheHPCSdieselgenerator loadsconsistofonelargepumpandmotorcombination (approximately2,500hp),onemediumsizepump(450hp),and othermiscellaneousloads;consequently,limitingthemomentary voltagedropto25percentandthemomentaryfrequencydropto 5percentwouldnotsignificantlyenhancethereliabilityofHPCS operation.Tomeettheseregulatoryguiderequirements,adiesel generatorunitapproximatelytwotothreetimesaslargeasthat requiredtocarrythecontinuousfullloadwouldbenecessary.
However,thefrequencyandvoltageovershootrequirementsof RegulatoryGuide1.9aremet.Afactorytestingprogramona prototypeunithasverifiedthefollowingfunctions:1.Systemfast-startcapabilities 2.Loadcarryingcapability 3.Loadrejectioncapability 4.Abilityofthesystemtoacceptandcarrytherequired loads5.Themechanicalintegrityofthediesel-enginegeneratorunitandallmajorsystemauxiliaries.AdetaileddiscussionofthecalculatedvoltageandfrequencytransientresponseisgiveninChapter3oftheGELicensing TopicalReportNEDO10905(HPCSPowerSupplyTopicalReport NEDO10905,Section6,describesprototypeandreliabilitytest
 
requirements).ThedesignoftheHPCSdieselgeneratorconformswiththeapplicablesectionsofIEEEcriteriaforClass1Eelectrical systemsfornuclearpowergenerationstations(IEEE-308).In addition,aprototypetesthasbeenperformed.Thegeneratorhasthecapabilityofprovidingpowerforstartingtherequiredloadswithoperationallyacceptablevoltageand frequencyrecoverycharacteristics.Apartialorcompleteload rejectiondoesnotcausethedieselenginetotriponoverspeed.
RBSUSAR8.3-67August1987RegulatoryGuide1.29TheHPCSelectricsystemiscapableofperformingitsfunctionwhensubjectedtotheeffectsofdesignbasesnaturalphenomena atitslocation.Inparticular,itisdesignedinaccordance withtheSeismicCategoryIcriteriaandishousedinaSeismic CategoryIstructure.RegulatoryGuide1.32ThedesignoftheHPCSpowersupplysystemconformswiththeapplicablesectionsofIEEEcriteriaforClass1Eelectrical systemsfornuclearpowergenerationstationsIEEE-308.Note:GELicensingTopicalReportNEDO-10905describesprototypeandreliabilitytestrequirements.RegulatoryGuide1.47AllthebypassedtripdevicesprovidealarmsinthemaincontrolroomsothatconditionswhichcanrendertheHPCSdiesel generatorsystemunavailableforautomaticstartare automaticallyannunciatedatthesystemlevelinthemaincontrol room.SeeNEDO10905,Amendment1,p20.RegulatoryGuide1.62ManualcontrolsareprovidedtopermittheoperatortoselectthemostsuitabledistributionpathfromthepowersupplytotheHPCS load.Anautomaticstartsignaloverridesthetestmode.
Provisionismadeforcontrolofthesystemfromthemaincontrol roomaswellasfromanexternallocation.RegulatoryGuide1.75TheHPCSdieselgeneratorisaDivisionIIIdeviceandisseparatedfromequipmentofotherdivisions.Itismarkedwitha DivisionIIInametag.RegulatoryGuide1.100AllClass1EequipmentoftheHPCSsystemisseismicallyqualifiedtotherequirementsofIEEE-344-1971whichwasthe plantrequirementforthisequipment.Are-evaluationtothe requirementsofIEEE344-1975andRegulatoryGuide1.100isin progressandwillbereporteduponcompletion.
RBSUSAR8.3-68August1987RegulatoryGuide1.106Electricmotorsonmotor-operatedvalveshavebeenidentifiedasasignificantintermittentloadonthegeneralacpowersystem.
Thisregulatoryguidedescribesacceptablemethodsofdisabling thermalprotectivedevicesonmotor-operatedvalvemotors.
Thermaloverloaddevicesnormallyinforceduringnormalplant operationarebypassedunderaccidentconditions.RegulatoryGuide1.118Thisregulatoryguidedescribesacceptablemeansforperiodicallytestingthefunctionalperformanceandresponsesoftheelectric powerandprotectionsystems.Therequirementsofthis regulatoryguidearemetwiththefollowingclarifications:PositionC.6-TripofanassociatedprotectivechanneloractuationofanassociatedClass1Eloadgroupisrequiredon removaloffusesoropeningofabreakeronlyforthepurpose ofdeactivatinginstrumentationorcontrolcircuit.
IEEE-279TheHPCSdieselgeneratoranditssupportingauxiliariesconformtoallrequirementsofIEEE-279whichareapplicabletosingular diverseelementsofaredundantset.
 
IEEE-308AlltheelectricsystemcomponentssupplyingpowertotheHPCS systemconsistofClass1Eelectricequipmentandaredesignedto meettheirfunctionalrequirementsundertheconditionsproduced bythedesignbasisevents.Alltheredundantequipmentis physicallyseparatedtomaintainindependenceandtominimizethe possibilityofacommonmodefailure.AllClass1Eequipmentis locatedinSeismicCategoryIstructures.TheHPCSClass1Eequipmentisuniquelyidentifiedbycolorcodingofthecomponentsaccordingtothedivisiontowhichitis assigned,asdetailedinSection8.3.1.3.1.SurveillanceoftheClass1Eelectricsystemsisincompliancewiththestandard,asareallotheraspectsapplicabletothe stationdesign.
RBSUSARRevision88.3-69August1996 IEEE-323ConformancewithIEEE-323isdescribedinSection3.11.
IEEE-344ConformancewithIEEE-344isdescribedinSection3.10.
 
IEEE-387TheHPCSpowersupplyunitiscompletelyindependentofotherstandbypowersupplyunitsandmeetstheapplicablerequirements ofIEEE-387.TheHPCSdieselgeneratorunitisdesignedto:1.Operateinitsserviceenvironmentduringandafteranydesignbasiseventwithoutsupportfromthepreferred powersupply.2.Start,accelerate,andbeloadedwiththedesignloadwithinanacceptabletime:a.Fromthenormalstandbycondition, b.Withnocoolingavailable,foratimeequivalenttothatrequiredtobringthecoolingequipmentinto servicewithenergyfromthedieselgeneratorunit,c.Onarestartwithaninitialenginetemperatureequaltothecontinuousrating,fullloadengine
 
temperature.3.Carrythelong-termsteady-stateloadcontinuously.
4.Maintainvoltageandfrequencywithinlimitsthatwillnotdegradetheperformanceofanyoftheloads composingthedesignloadbelowtheirminimum requirements,includingthedurationoftransients causedbyloadapplicationorloadremoval.85.Withstandanyanticipatedvibrationandoverspeedconditions.Thegeneratorandexciteraredesignedto withstand25percentoverspeedwithoutdamage.
8 RBSUSARRevision88.3-70August19968TheHPCSdieselgeneratorhascontinuousandshort-termratingsconsistentwiththerequirementsofIEEE-387,Section5.1.
88.3.1.2.3ConformanceWithAppropriateQualityAssurance StandardsThequalityassuranceprogramoutlinedinChapter17conformswithRegulatoryGuide1.30,QualityAssuranceRequirementsfor theInstallation,Inspection,andTestingofInstrumentationand ElectricEquipment.TheprogramoutlinedinChapter17includesacomprehensivesystemtoensurethatthepurchasedmaterial,manufacture, fabrication,testing,andqualitycontroloftheequipmentinthe standbyelectricpowersystemconformstotheevaluationofthe standbyelectricpowersystemequipmentvendorqualityassurance programsandpreparationofprocurementspecifications incorporatingqualityassurancerequirements.Theadministrative responsibilityandcontrolprovidedarealsodescribedin Chapter17.Thesequalityassurancerequirementsincludeanappropriatevendorqualityassuranceprogramandorganization,purchaser surveillanceasrequired,vendorpreparationandmaintenanceof appropriatetestandinspectionrecords,certificatesandother qualityassurancedocumentation,andvendorsubmittalofquality controlrecordsconsiderednecessaryforpurchaserretentionto verifyqualityofcompletedwork.Anecessaryconditionforreceipt,installation,andplacingofequipmentinservicehasbeenthesightingandauditingofQA/QC verificationdataandtheplacingofthisdatainpermanent onsitestoragefiles.8.3.1.2.4EnvironmentalQualificationforElectricalEquipmentLocatedinaHarshEnvironmentSeeSection3.11.
RBS USAR (1)T = cable tray; C = conduit Revision 17 8.3-71 8.3.1.3 Physical Identification of Safety-Related Equipment 8.3.1.3.1 Color Coding  
 
Color coded identification is provided for all safety-related equipment including cables, cable raceway, motors, panelboards, motor control centers, load centers, and switchgear. This  
 
identification may be by means of a letter, nameplate, paint, nondeteriorating self-adhesive tapes, permanently affixed tags, or similar means. Nonsafety-related equipment has no color  
 
identification.
Color coding is in accordance with the following:
Color coding is in accordance with the following:
Equipment and   Identification Cable Function Color     Letter Raceway Type (1)Nonsafety-Related None (or     black)     N     T or C Safety-RelatedDiv. I   Red     R     T or C Div. II   Blue     B     T or C Div. III   Orange     O     T or C Reactor Protection System  
Equipment and Identification Cable Function Color Letter Raceway Type(1)
: a. Input Channels (Sensors and Logic)
Nonsafety-Related None (or black)
Channel A   Red/Yellow     S   C Channel B   Blue/Yellow   T   C Channel C   Orange/Yellow   U   C Channel D   Purple/Yellow   V   C b. Output Trip Logic Group 1   Red/Green     I   C Group 2   Blue/Green     J   C Group 3   Orange/Green   K   C Group 4   Purple/Green   L   C 8.3.1.3.2 Equipment Identification  
N T or C Safety-Related Div. I Red R
T or C Div. II Blue B
T or C Div. III Orange O
T or C Reactor Protection System
: a.
Input Channels (Sensors and Logic)
Channel A Red/Yellow S
C Channel B Blue/Yellow T
C Channel C Orange/Yellow U
C Channel D Purple/Yellow V
C
: b.
Output Trip Logic Group 1 Red/Green I
C Group 2 Blue/Green J
C Group 3 Orange/Green K
C Group 4 Purple/Green L
C 8.3.1.3.2 Equipment Identification Each piece of equipment, each scheduled tray or conduit, and each scheduled cable, both safety-related and nonsafety-related, has an alphanumeric identification.
A
: code,


Each piece of equipment, each scheduled tray or conduit, and each scheduled cable, both safety-related and nonsafety-related, has an alphanumeric identification. A code, RBS USAR Revision 17 8.3-72 has been created to identify equipment items.8 The equipment code format for mark numbers explained below is for historical purpose only. The mark numbers created by the  
RBS USAR Revision 17 8.3-72 has been created to identify equipment items.
8 The equipment code format for mark numbers explained below is for historical purpose only. The mark numbers created by the equipment code format have been changed to equipment numbers in the Equipment Data Base (EDB). The mark numbers are cross-referenced to the equipment numbers in the EDB. The asterisk (*)
was previously used in this equipment code format to indicate safety related. The equipment numbers have a separator which is a dash (-), however, this has no significance in relation to its safety classification. Refer to the EDB for the proper equipment number and safety classification.
8
The equipment code has the following format:
X XXX
-(or)*
XXXXXXXXXXX Unit System QA Category Equipment Code Classification Item identification Example:
1CWS-MOV104 1 - Unit CWS - System code (circulating water system)
- - equipment so designated is Quality Assurance Category II or III MOV - Equipment (motor-operated valve) 104 - Identification Example:
1ENS*SWG1A 1 - Unit ENS - System code (standby 4.160-V switchgear)
* - Equipment so designated is Quality Assurance Category I SWG - Equipment (switchgear) 1A - Identification Safety-related equipment and nonsafety-related equipment other than for the communications system are identified by nameplates which are permanently attached. The nameplates are made of laminated plastic or metal and engraved with the equipment identification number. The master nameplate for safety-related equipment is color coded. Communications system equipment is identified by stenciling the identification on or adjacent to the equipment.
The cable identification for scheduled cables has the following format:
X XXX X
X X
XXX Unit System Part Color Service Number Code Unit - Identifies the station's unit number.
System Code - Three characters identifying the system.


equipment code format have been changed to e quipme nt numbers in the Equipm ent Data Base (EDB). The mark numbers are cross-referenced to the equipm ent numbers in the EDB. The asterisk (*)
RBS USAR Revision 8 8.3-73 August 1996 Part One symbol which can be either an alpha or a
was previously used in this equipment code format to indicate safety related. The equipm ent numbers have a separator which is a dash (-), however, this has no significance in relation to its safety classification. Refer to the E DB for the proper equipm ent number and safety classification.
numeric designator, e.g.,
8The equipment code has the following format:   X  XXX  -(or)*  XXXXXXXXXXX Unit  System QA Category Equipment Code  Classification Item identification Example: 1CWS-MOV104  1  - Unit CWS - System code (circulating water system)
an MCC cubicle section or one pump of a group (A, B, C, etc).
-   - equipment so designated is Quality Assurance Category II or III MOV - Equipment (motor-operated valve) 104 - Identification Example: 1ENS*SWG1A  1  - Unit ENS - System code (standby 4.160-V switchgear)
Color
*   - Equipment so designated is Quality Assurance Category I SWG - Equipment (switchgear) 1A  - Identification Safety-related equipment and nonsafety-related equipment other than for the communications system are identified by nameplates which are permanently attached. The nameplates are made of
- An alpha symbol indicating whether the cable is safety-related or nonsafety-related.
Service An alpha character indicating the type of service for which the cable will be utilized.
Number Three characters assigned to specify each individual cable number.
Example:
1ENS AR H307 All scheduled cables are identified by permanent colored markers attached to the cable at each end adjacent to the cable alphanumeric identification marker.
The background color of the alphanumeric identification marker may be used as the permanent colored marker.
Except for the cables run entirely in
: conduit, color code identification of a circuit is either by the color coded jacket of the cable or by painting the cable jacket with the proper color at intervals not exceeding 5 ft.
Cables with red-or blue-colored jackets may be used on unscheduled non-Class 1E circuits that run exclusively in conduit, only when the following mandatory conditions have been implemented:
1.
Neutral tags indicating non-Class 1E circuits are permanently attached at each end of the cable run and wherever the cable is
: exposed, and field quality control has verified 100 percent that this condition has been met.
2.
No color-jacketed cable used for unscheduled non-Class 1E application is allowed to be terminated in or pass through an enclosure (pull
: box, junction
: box, cabinet) containing divisional Class 1E circuits.
*8 Cables with red-or blue-colored jackets may also be used for direct burial cable installations and for the following applications, in various types of raceways, where there are only nonsafety-related circuits:
a.
Inside the makeup water intake structure b.
On the sanitary waste and disposal system
*8


laminated plastic or metal and engraved with the equipment identification number. The master nameplate for safety-related equipment is color coded. Communications system equipment is identified by stenciling the identification on or adjacent to the  
RBS USAR
8
* The closed loop service water site includes all Service Water Cooling (SWC) and Normal Service Water (SWP) cables located outside the protected area throughout the entire cable length.
8
Revision 17 8.3-74
8
: c.
On the closed loop service water site *
: d.
Leading Edge Flow Meter (LEFM) transducer cables in the Turbine Building.
At these locations there are no safety-related Category I circuits. No safety-related circuits are installed in direct burial cable trenches.
8 The raceway identification has the following format:
X X
X XXX X
X X
Unit Type Service Number Color Condu/A Condu/N Unit
- Identifies the station's unit number.
Type
- Character indicating the type of raceway.
Service
- An alpha symbol which indicates the service of cable to be carried in the designated raceway.
Number
- Three numbers assigned to specify the individual raceway.
Color
- An alpha symbol which identifies the cable to be carried in the designated raceway, safety-related or nonsafety-related.
Condu/A
- Conduit identifier. It is a letter or blank when not used. When used for sleeves or duct, it is numeric or blank when not used.
All scheduled cable trays and conduits are identified by raceway identification numbers at each end, and at entries to and exits from enclosed areas. Tray sections longer than 50 ft have an additional raceway identification number at midspan and at intervals not exceeding 50 ft, while tray sections 15 ft or less have a raceway identification number at midspan. Exposed conduits 8 ft or less have a raceway identification number at midspan except that for those short sections of conduit where the identification will not fit in midspan, the conduit is color-coded only (e.g., a short nipple from a junction box to a piece of equipment). Color-coded markers are provided for all Class 1E raceways adjacent to each raceway identification number, or the numbers themselves may be painted in the appropriate color and at intervals not exceeding 15 ft.


equipment.The cable identification for scheduled cables has the following format:  X  XXX  X  X    X  XXX  Unit  System Part  Color Service Number Code Unit        - Identifies the station's unit number.
RBS USAR Revision 13 8.3-75 September 2000 8.3.1.4 Independence Of Redundant Systems 8.3.1.4.1 General
System Code - Three characters identifying the system.
*13 There are three basic safety-related power supply divisions that originate at the 4,160-V level.
RBSUSARRevision88.3-73August1996Part-Onesymbolwhichcanbeeitheranalphaoranumericdesignator,e.g.,anMCCcubicle sectionoronepumpofagroup(A,B,C,etc).Color-Analphasymbolindicatingwhetherthecableissafety-relatedornonsafety-related.Service-Analphacharacterindicatingthetypeofserviceforwhichthecablewillbeutilized.Number-Threecharactersassignedtospecifyeachindividualcablenumber.Example:1ENSARH307Allscheduledcablesareidentifiedbypermanentcoloredmarkersattachedtothecableateachendadjacenttothecable alphanumericidentificationmarker.Thebackgroundcolorofthe alphanumericidentificationmarkermaybeusedasthepermanent coloredmarker.Exceptforthecablesrunentirelyinconduit,colorcodeidentificationofacircuitiseitherbythecolorcodedjacket ofthecableorbypaintingthecablejacketwiththeproper coloratintervalsnotexceeding5ft.Cableswithred-orblue-coloredjacketsmaybeusedonunschedulednon-Class1Ecircuitsthatrunexclusivelyin conduit,onlywhenthefollowingmandatoryconditionshavebeen implemented:1.Neutraltagsindicatingnon-Class1Ecircuitsarepermanentlyattachedateachendofthecablerunand whereverthecableisexposed,andfieldquality controlhasverified100percentthatthiscondition hasbeenmet.2.Nocolor-jacketedcableusedforunschedulednon-Class1Eapplicationisallowedtobeterminatedinor passthroughanenclosure(pullbox,junctionbox, cabinet)containingdivisionalClass1Ecircuits.8Cableswithred-orblue-coloredjacketsmayalsobeusedfor directburialcableinstallationsandforthefollowing applications,invarioustypesofraceways,wherethereareonly nonsafety-relatedcircuits:a.Insidethemakeupwaterintakestructure b.Onthesanitarywasteanddisposalsystem8 RBS USAR 8________________
The Divisions I, II and III safety-related power supply systems can be energized from preferred power source and from their own diesel generator.
*The closed loop service water site includes all Service Water Cooling (SWC) and Normal Service Water (SWP) cables located
The systems serve equipment at the 4,160-V, 480-V, and 120/240-V ac levels, and through intervening equipment they power the 125-V dc system.
13*
A dedicated diesel generator serves each division.
Each diesel generator with its supporting auxiliaries is in a separate room, as shown in Fig. 8.3-11.
The 4160-kV switchgear, 480-V load centers, 480-V motor control centers, a battery charger for each battery, 125-V batteries, and uninterruptible power supplies are located in switchgear rooms within the control building and are separated by division as illustrated by Fig. 8.3-9 and 8.3-10.
Safety-related 4.16-kV motor
: loads, a
480-V load
: center, 480-V motor control centers, and loads subordinate to the 480-V ac and 125-V dc sources are located within the auxiliary building, and are separated by division to ensure independence of safety-related divisions.
Additional safety-related loads are within the containment structure and at the standby cooling
: towers, where separation between divisions is also maintained.
All the preceding equipment items are located within Seismic Category I structures.
Fire extinguishing systems are identified in Chapter 9.
8.3.1.4.2 Class 1E Electric Equipment Arrangement Redundant electrical equipment and wiring for the
: RPS, nuclear steam supply shutoff system (NSSSS), and the ESF functions are physically separated, electrically independent, and are located such that no single credible event is capable of disabling redundant equipment which would prevent reactor shutdown, removal of decay heat from the core, nor which would prevent isolation of the containment in the event of an accident.
Separation requirements were applied to control, power, and instrumentation for all systems concerned.
Rules governing separation apply for Class 1E to Class 1E, and for Class 1E to non-Class 1E systems.
In addition, the distance between the electrical portions of the HPCS and RCIC systems is maximized within the space available to ensure the


outside the protected area throughout the entire cable length.
RBS USAR Revision 16 8.3-76 March 2003 functional availability of high pressure water for core cooling immediately following a transient.
8Revision 17 8.3-748c. On the closed loop service water site
Arrangement and/or protective barriers are such that no locally generated force or missile can destroy any redundant RPS, NSSSS, or ESF functions. Arrangement and/or separation barriers are provided to ensure that such disturbances do not affect both HPCS and RCIC.  
* d. Leading Edge Flow Meter (LEFM) transducer cables in the Turbine Building.
16 Arrangement of wiring/cabling is such as to eliminate, insofar as practical, all potential for fire damage to redundant cables and to separate the RPS, NSSSS, and ESF divisions so that fire within one division will not damage another division. In addition, approved fire protection features separate wiring and cabling of the HPCS and RCIC systems from ADS and RHR in the LCPI mode so that one train of these redundant systems remain free from damage such that safe shutdown can be achieved as described in chapter
At these locations there are no safety-related Category I circuits. No safety-related circuits are installed in direct
 
burial cable trenches. 8 The raceway identification has the following format:  X X X XXX X X X  Unit Type Service Number Color Condu/A Condu/N Unit - Identifies the station's unit number.
Type - Character indicating the type of raceway.
Service - An alpha symbol which indicates the service of cable to be carried in the designated raceway. Number - Three numbers assigned to specify the individual raceway.Color - An alpha symbol which identifies the cable to be carried in the designated raceway, safety-related
 
or nonsafety-related. Condu/A - Conduit identifier. It is a letter or blank when not used. When used for sleeves or duct, it is
 
numeric or blank when not used. All scheduled cable trays and conduits are identified by raceway identification numbers at each end, and at entries to and exits from enclosed areas. Tray sections longer than 50 ft have an
 
additional raceway identification number at midspan and at intervals not exceeding 50 ft, while tray sections 15 ft or less have a raceway identification number at midspan. Exposed conduits 8 ft or less have a raceway identification number at
 
midspan except that for those short sections of conduit where the
 
identification will not fit in midspan, the conduit is color-coded only (e.g., a short nipple from a junction box to a piece of equipment). Color-coded markers are provided for all Class 1E raceways adjacent to each raceway identification number, or the
 
numbers themselves may be painted in the appropriate color and at
 
intervals not exceeding 15 ft.
RBSUSARRevision138.3-75September20008.3.1.4IndependenceOfRedundantSystems8.3.1.4.1General13Therearethreebasicsafety-relatedpowersupplydivisionsthat originateatthe4,160-Vlevel.TheDivisionsI,IIandIII safety-relatedpowersupplysystemscanbeenergizedfrom preferredpowersourceandfromtheirowndieselgenerator.The systemsserveequipmentatthe4,160-V,480-V,and120/240-Vac levels,andthroughinterveningequipmenttheypowerthe125-Vdc
 
system.13Adedicateddieselgeneratorserveseachdivision.Eachdiesel generatorwithitssupportingauxiliariesisinaseparateroom, asshowninFig.8.3-11.The4160-kVswitchgear,480-Vload centers,480-Vmotorcontrolcenters,abatterychargerforeach battery,125-Vbatteries,anduninterruptiblepowersuppliesare locatedinswitchgearroomswithinthecontrolbuildingandare separatedbydivisionasillustratedbyFig.8.3-9and8.3-10.
Safety-related4.16-kVmotorloads,a480-Vloadcenter,480-V motorcontrolcenters,andloadssubordinatetothe480-Vacand 125-Vdcsourcesarelocatedwithintheauxiliarybuilding,and areseparatedbydivisiontoensureindependenceofsafety-relateddivisions.Additionalsafety-relatedloadsarewithin thecontainmentstructureandatthestandbycoolingtowers, whereseparationbetweendivisionsisalsomaintained.AlltheprecedingequipmentitemsarelocatedwithinSeismicCategoryIstructures.Fireextinguishingsystemsareidentified inChapter9.8.3.1.4.2Class1EElectricEquipmentArrangement RedundantelectricalequipmentandwiringfortheRPS,nuclearsteamsupplyshutoffsystem(NSSSS),andtheESFfunctionsare physicallyseparated,electricallyindependent,andarelocated suchthatnosinglecredibleeventiscapableofdisabling redundantequipmentwhichwouldpreventreactorshutdown,removal ofdecayheatfromthecore,norwhichwouldpreventisolationof thecontainmentintheeventofanaccident.Separation requirementswereappliedtocontrol,power,andinstrumentation forallsystemsconcerned.Rulesgoverningseparationapplyfor Class1EtoClass1E,andforClass1Etonon-Class1Esystems.
Inaddition,thedistancebetweentheelectricalportionsofthe HPCSandRCICsystemsismaximizedwithinthespaceavailableto
 
ensure the RBS USAR Revision 16 8.3-76 March 2003functional availability of high pressure water for core cooling immediately following a transient. Arrangement and/or protective barriers are such that no locally generated force or missile can destroy any redundant RPS, NSSSS, or ESF functions. Arrangement and/or separation barriers are  
 
provided to ensure that such disturbances do not affect both HPCS  
 
and RCIC. 16Arrangement of wiring/cabling is such as to eliminate, insofar as practical, all potential for fire damage to redundant cables and  
 
to separate the RPS, NSSSS, and ESF divisions so that fire within one division will not damage another division. In addition, approved fire protection features separate wiring and cabling of  
 
the HPCS and RCIC systems from ADS and RHR in the LCPI mode so  
 
that one train of these redundant systems remain free from damage  
 
such that safe shutdown can be achieved as described in chapter  
: 9. The following general rules were followed:
: 9. The following general rules were followed:
16 1. Routing of Class 1E control, power, and instrumentation cables through rooms or spaces where there is potential for accumulation of large quantities (gallons) of oil  
16
 
: 1.
or other combustible fluids through leakage or rupture of lube oil or cooling systems is avoided. Where such routing is unavoidable, only one division of Class 1E  
Routing of Class 1E control, power, and instrumentation cables through rooms or spaces where there is potential for accumulation of large quantities (gallons) of oil or other combustible fluids through leakage or rupture of lube oil or cooling systems is avoided. Where such routing is unavoidable, only one division of Class 1E cabling is allowed in any such space.
 
: 2.
cabling is allowed in any such space. 2. In any room or compartment, other than the cable chases, in which the primary source of fire is of an  
In any room or compartment, other than the cable chases, in which the primary source of fire is of an electrical nature, cable trays of redundant systems have a minimum horizontal separation of 3 ft if no physical barrier exists between trays. If a horizontal separation of 3 ft is unattainable, a fire-resistant barrier is installed, extending at least 1 ft above (or to the ceiling) and 1 ft below (or to the floor) line-of-site communication between the two trays. Totally enclosed metallic raceway is occasionally used in lieu of barriers at least 1 inch under open cable trays, to a
 
point where the minimum separation is again maintained. Totally enclosed metallic raceway of redundant systems maintains a
electrical nature, cable trays of redundant systems have a minimum horizontal separation of 3 ft if no  
minimum separation distance of 1 in.
 
: 3.
physical barrier exists between trays. If a horizontal separation of 3 ft is unattainable, a fire-resistant barrier is installed, extending at least 1 ft above (or to the ceiling) and 1 ft below (or to the floor) line-
In any room or compartment, other than the cable chases, in which the primary source of fire is of an electrical nature, cable trays of redundant systems have a minimum vertical separation of 5 ft between vertically stacked trays of different divisions, or trays of different divisions one  
 
of-site communication between the two trays. Totally  
 
enclosed metallic raceway is occasionally used in lieu of barriers at least 1 inch under open cable trays, to  
 
a point where the minimum separation is again maintained. Totally enclosed metallic raceway of  
 
redundant systems maintains a minimum separation  
 
distance of 1 in. 3. In any room or compartment, other than the cable chases, in which the primary source of fire is of an  
 
electrical nature, cable trays of redundant systems have a minimum vertical separation of 5 ft between  
 
vertically stacked trays of different divisions, or  
 
trays of different divisions one RBSUSAR8.3-77August1987abovetheother;however,verticalorcrossstackingoftraysisavoidedwhereverpossible.Incaseswherethe redundanttraysmustbestackedorcrossedonestack abovetheother,andwhenthetraysdonotmeetthe5-ftverticalseparationrequirement,afirebarrieris installedbetweentheredundanttrays.Thebarrier extendsbeyondeithersideofthetraysystem,in accordancewithIEEE-384.Occasionally,totally enclosedmetallicraceway(e.g.,conduit)isusedin lieuofbarriersinthefollowingcases:a.Class1Eladdertypecabletraysarefittedwithprotectivecoverswherever480Vacnon-Class1E cablingor480VacClass1Ecablingofa differentdivisionthanthesubjecttraysis routedinconduitwithin1in.ofthesubject
 
trays.b.Lowvoltage(120V)power,control,andinstrumentationcabling,whenroutedinclose proximitytoClass1Eladdertypecabletrays,is routedinconduitandmaintainsatleast1-in.
 
separation.c.TotallyenclosedmetallicracewayofdifferentClass1Edivisionsmaintainsaminimumseparation distanceof1in.Conduitscontainingcablesof differentClass1Edivisionswhichperformthe sameredundantsafeshutdownfunctionsarenot routedincloseproximitytooneanother.4.Anyopeningsinfired-ratedfloorsorwallsforverticalorhorizontalrunsofClass1Ecablingare sealedwithfire-resistantmaterialofequalfire
 
rating.Theminimumhorizontalandverticalseparationand/orbarrierrequirementsinthecablechasesareasfollows(NOTE:Thereare nocablespreadingroomsinRBS):1.Wherecablesofdifferentdivisionsapproachthesameoradjacentcontrolpanelswithverticalspacingless thanthe3-ftminimum,atleastonedivision'scircuit isrunintotallyenclosedmetallicracewayora barrierisprovidedtoapointwhere3ftofseparation
 
exists.
RBSUSAR8.3-78August19872.Aminimumhorizontalseparationof1ftismaintainedbetweentrayscontainingcablesofdifferentdivisions wherenophysicalbarrierexistsbetweentrays.Where ahorizontalseparationof1ftisnotattainable, eitherafire-resistantbarrierisinstalledextending atleast1ftabove(ortotheceiling)and1ftbelow (ortothefloor)line-of-sightcommunicationbetween thetwotraysortotallyenclosedmetallicracewayis utilizedtomeetseparationrequirements.3.Verticalstackingorcrossingoftrayscarryingcablesofdifferentdivisionsisavoidedwhereverpossible.
Wherethisisnotpossible,however,thereisaminimum verticalseparationofnotlessthan3ftbetweentrays ofredundantsystems.4.Ifverticalstackingorcrossingofredundanttraysisnecessaryandtheminimum3-ftverticalseparation cannotbemaintained,afirebarrierisinstalled betweentheredundanttrays.Thebarrierextends1ft oneachsideofthetraysystem.Totallyenclosed metallicracewayisusedinlieuofthebarrier,with opencabletray,toapointwheretheminimum separationismaintained.Totallyenclosedmetallic racewaysofredundantsystemsmaintainaminimum separationof1in.WherespatialseparationdistancesarelessthanthosespecifiedaboveinaccordancewithIEEE-384,RBSplant-specific configurationsweretestedandanalysesperformedtojustify reducedseparation.Thetestprogrammethodologyandresultsare documentedinWyleTestReportNo.47618-3.Spatialseparation andbarrierrequirementsareshownondesigndrawingswhichare referencedinSection1.7.TheminimumallowableseparationdistancesarederivedfromthetestedconfigurationsasshowninTable8.3-9.Thefollowing summarizesandevaluatestestresultswhichvalidatetheminimum separationcriteria.InordertoperformatestprogramtoverifytheadequacyofRBSracewayseparationitwasnecessarytodefinetheworstcase electricalfailurethatcouldbepostulatedtooccurina raceway.TheRBSracewayseparationtestprogramwasbasedon thefollowingfailuremodeassumptions:
RBSUSAR8.3-79August19871.Thecableorequipmentinthecircuitdevelopsafaultthatisnotclearedduetothefailureoftheprimary protectivedevices.2.Theworstcaseelectricalfaultisthemostseverecredibleelectricalfaultthatcouldoccur.Theworst-casecurrentisthelesseroflockedrotorcurrent (6XFLA)orthefaultcurrentjustbelowthelongtime tripofthebackupcircuitbreaker.Anadditional10-percentcurrentisaddedtoallowforvarious inaccuraciesoftheinvolveddevices.Theworstcase cableexhibitsthehighesttemperatureforthelongest
 
duration.3.Forsustainedoverloads,theimpedanceofthefaultadjustsitselfautomaticallytomaintainthefault currentmagnitudeataconstantlevelastheresistance ofthewirechangesduetoheating.4.Theoverloadedcableinitsoverheatedconditionstaysundetectedprecludinganycorrectiveoperatoraction.5.Theworstcaseeffectonnearbyracewaysisestablishedbyacombinationoftemperatureandthefaultduration.Thefaultcurrentmagnitudeof440amperes(400amperes+10percentofuncertainty)usedinthetestprogramwasbasedon thefailuremodeassumptionsdiscussedabove.Thisassumesthat anovercurrentlockedrotorconditionoccursonacablebetweena 480-VacMCCanda480-Vload.Theprimaryovercurrent protectivedevicewhichisamoldedcasecircuitbreakeratthe MCCisassumedtofailtotrip.Thenexthigherlevel(upstream) overcurrentdeviceistheloadcentercircuitbreaker.This currentvaluewasusedforalltestsinvolvingcablesincable racewaysandinfreeair.Inordertoselectthesizeofcableto beusedforconfigurationtests,screeningtestswereperformed todeterminewhichsizecablewhenfaultedwoulddeliverthemost intensetemperatureriseforthelongestdurationtoadjacent cables.Thetestsshowedthatthe#2AWGtriplexcoppercable wastheworstcasecable.TheRBSMCCscontainmoldedcasebreakerswhichprovideoverloadand/orshort-circuitprotectionforeachloaddependinguponthe application.Theloadcenters(LDC)containaircircuitbreakers withsolid-statetripdevices.Thesolid-statetripdevices provideincreasedaccuracyandrepeatabilityoverconventional tripdevices.Theload RBSUSAR8.3-80August1987centerbreakersprovidebothlongandshorttimeovercurrentandinstantaneousshort-circuitprotection.BreakersoftheMCCand LDCaremaintainedonaperiodicbasis.Thismaintenanceensures thatthelikelihoodofacoincidentalfailureoftwoovercurrent devicesinseriesonthesamefeederlineisextremelysmall.Duringeachconfigurationtest,thetargetcableswereenergizedattheirratedcurrentandvoltage.Atthecompletionofeach configurationtest,insulationresistancetestandhighpotential testwereperformedforthetargetcables.Thetargetcables passedtheabovementionedfunctionaltestsinaccordancewith thespecifiedcriteria.Thetestprogramwithaboveassumptionsandinputsforthetargetcablesgeneratedthefollowingresults.600-Vcableinstalledinopenairtraysorconduitsandfaultedwiththeworstcaseinternalfault(440amperes)donotaffect functionability(ampacityorinsulationresistance)ofanytype ofcablesseparatedinaccordancewiththetestconfigurations.
Cablesweretestedinstalledinhorizontaland/orvertical raceways(includingbothcabletrayandconduits)andinfree air.Table8.3-9depictstestedseparationbetweencabletrays, conduits,andcablesinfreeair.Thistablealsoreflectsthe minimumacceptablespatialseparation,withoutuseofbarriers, usedatRBS.Theallowedspatialseparationincludesamarginin termsofdistanceand/ortemperature.AnindependentracewaysystemisprovidedforeachClass1Edivision.Thetraysarearrangedtoptobottombasedonthe cableratedvoltage.1.4.16-kVpower(5,000-Vinsulationclass) 2.Large480-Vpower(600-Vinsulationclass) 3.480-Vpower(600-Vinsulationclass) 4.Control(600-Vand300-Vinsulationclass) 5.Instrumentationcables(300-Vinsulationclass)Nonsafety-related,non-Class1Eelectricsystemsgenerallyhavethesamearrangementofcabletrayswiththeadditionofacable traypositionfor13.8-kVpower(15,000-Vinsulationclass) occupyingtheuppermosttrayposition.
RBSUSAR8.3-81August19878.3.1.4.3ControlofComplianceWithSeparationCriteriaDuringDesignandInstallationCompliancewiththecriteriawhichpreserveindependenceofredundantsystemsisasupervisoryresponsibilityduringboththe designandinstallationphases.Theresponsibilityisdischarged
 
by:1.Identifyingapplicablecriteria 2.Issuingworkingprocedurestoimplementthesecriteria3.Modifyingprocedurestokeepthemcurrentandworkable4.Checkingmanufacturerdrawingsandspecificationstoensurecompliancewithprocedures5.Controllinginstallationandprocurementtoassurecompliancewithapprovedandissueddrawingsand
 
specifications.ThenomenclatureusedforequipmentattheRiverBendStationistheprimarymechanismforensuringproperseparation.AllClass1Eelectricalequipmenthasanattachednameplateinscribedwiththeequipmentidentificationandcolor identificationofitsdivision.OtherClass1Epowersystemcomponents,suchascablesandraceways,haveuniquecolorassignmenttoidentifysafety-related systems.Thesecolorsarereadilyapparenttotheoperatorsor maintenancecraftsmensothesafety-relatedcable,raceways,or equipmentcanbeidentified.Nonsafetysystemcircuitsnot associatedwiththesafetycircuitsareeithercolorcodedblack orhavenocoloridentification.Ineverycaseitispossibletodeterminethequalitygroupandseparationclassificationofequipmentfromtheconstruction drawingsandspecifications.Nonessentialequipmenthasbeenseparatedwhereitwasdesiredtoenhancepowergenerationreliability,butsuchseparationisnot asafetyconsideration.Thiswasaccomplishedby administrativelydirectinguseofracewaysystemstoseparate criticalcompanionBOPinstallations,suchasthecondensate
 
pumps.
RBSUSAR8.3-82August1987Wherethesafety-relatedequipmenthasbeenidentifiedasanessentialsafetydivision,thenomenclatureindicatesa characteristiccolorforpositivevisualidentification.
Likewise,allancillaryequipment,cable,andracewaysmatchthe nomenclatureofthesystemwhichtheysupport.Therearecertainexceptionstotheabovewhereequipmentwhichisnotsafety-relatedisconnectedtoessentialpowersourcesfor functionaldesignreasons.Thesecircuitsareidentifiedin Table8.3-7.Cableusedtoconnectnonsafety-relatedequipment tosafety-relatedsourcesofpowerissafetygradeandqualified androutedasanonsafety-relatedcircuitafterfirsthavingbeen connectedtoaClass1Eprotectivedevice.Ithasnocolor assignment.Thisequipmentisdisconnectedandlockedoutduring anaccidentbyaLOCAsignal,orprotectedbytwoqualified isolationdevices.8.3.1.4.4CableDesign,Analysis,andRoutingofCircuits 8.3.1.4.4.1GeneralFunctionalDesignBases Theproperselectionofcablesandracewayspreservesthereliabilityofredundantsafety-relatedsystemsandconformsto thefollowingdesignbases:1.Thenormalcurrentloadingofallinsulatedconductorsislimitedtothatcontinuousvaluewhichdoesnot causeinsulationdeteriorationfromheating.Selection ofconductorsizesisbasedon"PowerCableAmpacities" and"Ampacities-CablesinOpen-topCableTrays" publishedbytheInsulatedPowerCableEngineers Association(IPCEAPublicationsP-46-426andP-54-440, respectively).Formaintainedspacingofcablesin cabletrays,plant-specifictestsandevaluationshave beenconductedtodemonstratethatspacinglessthan thatspecifiedintheIPCEApublicationsisacceptable aslongasrequiredspacingismaintainedatcabletie-pointintervalsof3ft.Thesetestsandevaluations demonstratedadequatecableampacityandtemperature consistentwithIPCEAguidelines.Forthesmallsizes notcoveredbythepreceding,theNationalElectric Code(NEC)ormorestringentregulationsshallgovern.2.Allcabletraysandsupportsaredesignedtocarrythecablesrequiredwithoutexceedingtheallowable deflectionandyieldstrengthofthematerialsusedin thetraysandtheirsupports.
RBS USAR Revision 22 8.3-83 All cable trays carrying cables for safeguard services are designed to meet Seismic Category I criteria. All raceways installed in Seismic Category I areas are
 
seismically supported.
: 3. Cables are specified with consideration of the optimum combination of insulation, fire-resistant, and
 
radiation-resistant characteristics.
: 4. Cables are sized and installed so as to limit the temperature rise of conductors to within the
 
temperature ratings of the cable for any expected overload condition. All power cables are sized and
 
installed to carry short circuit current until the
 
first protective device disconnects the source feeding
 
the short circuit.
 
8.3.1.4.4.2 Electrical Cable Arrangement
 
Physical separation is provided between similar components of redundant electrical systems and between power and control circuitry serving or being served from these components. 
 
Redundant protective power and control cables are run on
 
physically separate cable trays or conduits and follow different routes to and from power sources to loads, and from sensors and
 
controllers to protective devices. Therefore, an event which
 
might damage the cables in one set of cable trays or conduit does not affect the redundant cables in the other set of cable trays
 
or conduit.
 
Power cables for 15-kV and 5-kV service are stranded copper conductors. Power cables No. 2/0 AWG and larger for 600-V service are stranded aluminum or copper conductors. Smaller power cables and control cables have copper conductors. All cables, where required, are constructed with a radiation-
 
resistant, 90°C thermosetting-type insulation and an overall
 
flame-retardant, radiation-resistant jacket.
 
Cable trays used for 13.8-kV service are identified as "J" trays and those for 4.16-kV are identified as "H" trays. The "J" and the "H" trays are separate from one another. Trays for 600-V or
 
lower voltage large power cables and some low power cables are
 
designated "L." Trays for 600-V or lower voltage small power
 
cables and some control cables are designated "K." Control cables of 120-V ac or 125-V dc, are run in "C" trays or conduit. Low
 
level analog or digital instrumentation cables are run in "X" trays or in conduit.
In the Drywell, non-divisional, Augmented Quality (but not safety-related), analog instrumentation cables for the main steam line strain gauges are routed both in flexible stainless steel conduit and external to conduit. In the Containment building, the cables are routed in cable tray and rigid conduit.
Segregation in conduit is in a comparable fashion to that employed for trays.
 
RBSUSAR8.3-84August1987Cablesofredundantsafety-relatedsystemsareisolatedfromeachotherandfromnonsafety-relatedcables.Therearenomedium-orhigh-voltage(480-Vandabove)powercablesinthecontrolbuildingcablechases.ElectricalcablesfortheRPSandothersafety-relatedsystemslocatedinsidethecontainmentstructurearedesignedsothatthe cableisoperablefortherequiredperiodofusageduringall postulatedaccidentenvironments.Cablesinhazardous environmentsareprotectedfromtheenvironmentandagainst physicalorfiredamagetotheextentrequiredfortheservice eitherbyselectionofcableorbychoiceofraceway(e.g.,cable trayswithcovers,metallicconduit).CablesarederatedforgroupingandspacinginaccordancewithIPCEArecommendations.Mediumvoltagecabletraysdonothave morethanasinglelayerofcables.480-Vpowercontroland instrumentationcables,whenroutedincabletrays,areinstalled inaccordancewiththeapplicablecableampacityfactorsandin CategoryIareasdonotextendabovethesiderailsunlessthey areenclosedbyanextendedtraycoveroranengineeringanalysis hasdemonstratedthatelectricalseparationrequirementsarenot compromised.Galvanizedsteel,nonconductingsleevesorblockouts inwallsareusedtotransportcablesthroughconcretewalls.Firedetectionandprotectionsystems,eithermanuallyorautomaticallyinitiated,areprovidedinthoseareasrequiredto preservetheintegrityofthecircuitsforsafety-related services(Section9.5.1).
Theelectricalpenetrations,throughthereactorcontainment vessel,arearrangedingroupstomaintainseparationof electricalcablesandtocomplywiththesingle-failurecriteria.
Thedesignandfabricationofeachtypeofpenetrationassembly isinaccordancewithIEEE-317forElectricalPenetration AssembliesinContainmentStructuresforNuclearFueledPower GeneratingStations.Eachelectricalpenetrationisdesignedto withstandtheenvironmentconditionsatitslocationduringall postulatedDBAs.ConnectionsbetweenfieldwiresandpenetrationassemblyconductorsaremadeinsideSeismicCategoryItermination cabinetsdesignedtowithstandtheenvironmentalconditionsat itslocationduringallpostulatedDBAs.
RBSUSARRevision38.3-85August19903Wiresplicesinsidethereactorbuildingaremadeonlywhere necessaryandareprimarilymadeintheelectricalpenetration terminalcabinets.Allsplicesarequalifiedfortheirintended useasdescribedinSection3.11.Allsplicesaremadein accordancewiththemanufacturer'srecommendedproceduresor approvedequivalentinstructions,andaretestedafter installationbycontinuitymeasurements,andpowercablesplicesareadditionallytestedbyinsulationresistancemeasurements.
Therearenosplicesmadeincabletrays.
3Controlandinstrumentationcableconnectionsforsafety-related CategoryIsystemsandequipmentaremadeonterminatingdevices orbyspliceswhichhavebeenqualifiedfortheirintended functionpursuanttoIEEE-323.8.3.1.4.4.3CableandRacewayScheduling Cableroutingandracewaydesignisaccomplishedmanually.Acomputerprogramwasusedtoassistintheengineering,design, installation,andcontrolofcablerouting,identification,tray, andracewayfill.Themainfunctionsofthisprogramare:1.Thecomputationofallcablelengthsandtotalizingofcabletypes.2.Thecomputationofracewayfillandoverfill indication.3.Toavoidduplication,indicatenumberofrevisionsonaspecificitemandtocheckinformationwithrespectto system,service,andredundancy.4.Toprovideoutputtothefieldintheformofpullandinstallationticketswhichsuppliedallthenecessary informationforinstallationofcablesandracewayand weredesignedtoserveasQualityControl(QC)
 
documents.5.Toprovidefeedbackfromthefieldthroughsystemstatusinformationwhichalloweddesignerstorevise systemsasrequiredwithaminimumofreworkinthe
 
field.6.Toprovidestatusofanysystemwithregardtothenumberofcablepullsandtheoveralljobstatus.
RBS USAR Revision 16 8.3-86 March 20038.3.2 DC Power Systems 168.3.2.1 Description - Divisions I and II, Nonsafety 8.3.2.1.1 General 14Station service dc power is available at 125 V and 48 V. There are three ungrounded Class 1E safety-related 125-V dc systems, including Division III discussed in Section 8.3.2.2. There are also six non-Class 1E nonsafety-related ungrounded 125-V systems and one non-Class 1E nonsafety-related ungrounded 48-V system.
Fig. 8.3-6 illustrates these eight 125-V dc and one 48-V dc
 
systems.14Each system includes a 480-V ac to 125-V dc or 120-V ac to 48-V dc static battery charger with a control panel. Safety-related
 
chargers are powered from the standby system of their own division. Nonsafety-related chargers are also powered from
 
safety-related systems to obtain a more reliable source of power
 
during normal plant conditions, but are tripped on LOCA, with the following exceptions, which are furnished ac power from available
 
nonsafety-related sources:  a. One 480-V ac to 125-V dc battery charger located in the circulating water switchgear house  b. One 480-V ac to 125-V dc battery charger located in the services building  c. One 120-V ac to 48-V battery charger located in the makeup water switchgear house  d. One 480-V ac to 125-V dc battery charger located in the service water cooling switch gear house.
16The 125-V dc systems include a battery charger, a lead acid battery, a 125-V dc distribution switchgear energized from a
 
battery distribution panel, local and control room instrumentation, and alarm facilities. The battery system
 
surrenders the identity of its feeders to that of the controlled
 
equipment or supported system at the first termination after


leaving the distribution switchboard or panel. 7A separate battery  charger procured  and qualified to IEEE-323 requirements and powered from either a nonsafety-related (black)  
RBS USAR 8.3-77 August 1987 above the other; however, vertical or cross stacking of trays is avoided wherever possible.
In cases where the redundant trays must be stacked or crossed one stack above the other, and when the trays do not meet the 5-ft vertical separation requirement, a
fire barrier is installed between the redundant trays.
The barrier extends beyond either side of the tray
: system, in accordance with IEEE-384.
Occasionally, totally enclosed metallic raceway (e.g.,
conduit) is used in lieu of barriers in the following cases:
a.
Class 1E ladder type cable trays are fitted with protective covers wherever 480 V ac non-Class 1E cabling or 480 V ac Class 1E cabling of a
different division than the subject trays is routed in conduit within 1 in.
of the subject trays.
b.
Low voltage (120 V)
: power, control, and instrumentation
: cabling, when routed in close proximity to Class 1E ladder type cable trays, is routed in conduit and maintains at least 1-in.
separation.
c.
Totally enclosed metallic raceway of different Class 1E divisions maintains a minimum separation distance of 1 in.
Conduits containing cables of different Class 1E divisions which perform the same redundant safe shutdown functions are not routed in close proximity to one another.
4.
Any openings in fired-rated floors or walls for vertical or horizontal runs of Class 1E cabling are sealed with fire-resistant material of equal fire rating.
The minimum horizontal and vertical separation and/or barrier requirements in the cable chases are as follows (NOTE:
There are no cable spreading rooms in RBS):
1.
Where cables of different divisions approach the same or adjacent control panels with vertical spacing less than the 3-ft minimum, at least one division's circuit is run in totally enclosed metallic raceway or a
barrier is provided to a point where 3 ft of separation exists.


power source or a portable diesel generator is provided as a backup battery charger for the Division I, II and III safety-related  and three of the nonsafety-related battery chargers.
RBS USAR 8.3-78 August 1987 2.
The backup battery charger's rating is equal to the largest capacity battery charger which it must replace. When the backup
A minimum horizontal separation of 1 ft is maintained between trays containing cables of different divisions where no physical barrier exists between trays.
Where a
horizontal separation of 1 ft is not attainable, either a fire-resistant barrier is installed extending at least 1 ft above (or to the ceiling) and 1 ft below (or to the floor) line-of-sight communication between the two trays or totally enclosed metallic raceway is utilized to meet separation requirements.
3.
Vertical stacking or crossing of trays carrying cables of different divisions is avoided wherever possible.
Where this is not possible, however, there is a minimum vertical separation of not less than 3 ft between trays of redundant systems.
4.
If vertical stacking or crossing of redundant trays is necessary and the minimum 3-ft vertical separation cannot be maintained, a
fire barrier is installed between the redundant trays.
The barrier extends 1 ft on each side of the tray system.
Totally enclosed metallic raceway is used in lieu of the barrier, with open cable
: tray, to a
point where the minimum separation is maintained.
Totally enclosed metallic raceways of redundant systems maintain a
minimum separation of 1 in.
Where spatial separation distances are less than those specified above in accordance with IEEE-384, RBS plant-specific configurations were tested and analyses performed to justify reduced separation.
The test program methodology and results are documented in Wyle Test Report No. 47618-3.
Spatial separation and barrier requirements are shown on design drawings which are referenced in Section 1.7.
The minimum allowable separation distances are derived from the tested configurations as shown in Table 8.3-9.
The following summarizes and evaluates test results which validate the minimum separation criteria.
In order to perform a test program to verify the adequacy of RBS raceway separation it was necessary to define the worst case electrical failure that could be postulated to occur in a
raceway.
The RBS raceway separation test program was based on the following failure mode assumptions:


battery charger is to be used, the breaker of the battery 7
RBS USAR 8.3-79 August 1987 1.
RBS USAR Revision 24 8.3-87 charger being removed from service is tripped, removed and placed in the backup charger position. The backup charger breaker is taken from its storage position and placed in the position on its
The cable or equipment in the circuit develops a fault that is not cleared due to the failure of the primary protective devices.
2.
The worst case electrical fault is the most severe credible electrical fault that could occur.
The worst-case current is the lesser of locked rotor current (6XFLA) or the fault current just below the longtime trip of the backup circuit breaker. An additional 10-percent current is added to allow for various inaccuracies of the involved devices.
The worst case cable exhibits the highest temperature for the longest duration.
3.
For sustained overloads, the impedance of the fault adjusts itself automatically to maintain the fault current magnitude at a constant level as the resistance of the wire changes due to heating.
4.
The overloaded cable in its overheated condition stays undetected precluding any corrective operator action.
5.
The worst case effect on nearby raceways is established by a combination of temperature and the fault duration.
The fault current magnitude of 440 amperes (400 amperes +
10 percent of uncertainty) used in the test program was based on the failure mode assumptions discussed above.
This assumes that an overcurrent locked rotor condition occurs on a cable between a 480-V ac MCC and a
480-V load.
The primary overcurrent protective device which is a molded case circuit breaker at the MCC is assumed to fail to trip.
The next higher level (upstream) overcurrent device is the load center circuit breaker.
This current value was used for all tests involving cables in cable raceways and in free air. In order to select the size of cable to be used for configuration tests, screening tests were performed to determine which size cable when faulted would deliver the most intense temperature rise for the longest duration to adjacent cables.
The tests showed that the
#2 AWG triplex copper cable was the worst case cable.
The RBS MCCs contain molded case breakers which provide overload and/or short-circuit protection for each load depending upon the application.
The load centers (LDC) contain air circuit breakers with solid-state trip devices.
The solid-state trip devices provide increased accuracy and repeatability over conventional trip devices.
The load


bus which feeds the bus of the battery charger removed from
RBS USAR 8.3-80 August 1987 center breakers provide both long and short time overcurrent and instantaneous short-circuit protection.
Breakers of the MCC and LDC are maintained on a periodic basis.
This maintenance ensures that the likelihood of a coincidental failure of two overcurrent devices in series on the same feeder line is extremely small.
During each configuration test, the target cables were energized at their rated current and voltage.
At the completion of each configuration test, insulation resistance test and high potential test were performed for the target cables.
The target cables passed the above mentioned functional tests in accordance with the specified criteria.
The test program with above assumptions and inputs for the target cables generated the following results.
600-V cable installed in open air trays or conduits and faulted with the worst case internal fault (440 amperes) do not affect functionability (ampacity or insulation resistance) of any type of cables separated in accordance with the test configurations.
Cables were tested installed in horizontal and/or vertical raceways (including both cable tray and conduits) and in free air.
Table 8.3-9 depicts tested separation between cable trays, conduits, and cables in free air.
This table also reflects the minimum acceptable spatial separation, without use of
: barriers, used at RBS.
The allowed spatial separation includes a margin in terms of distance and/or temperature.
An independent raceway system is provided for each Class 1E division.
The trays are arranged top to bottom based on the cable rated voltage.
1.
4.16-kV power (5,000-V insulation class) 2.
Large 480-V power (600-V insulation class) 3.
480-V power (600-V insulation class) 4.
Control (600-V and 300-V insulation class) 5.
Instrumentation cables (300-V insulation class)
Nonsafety-related, non-Class 1E electric systems generally have the same arrangement of cable trays with the addition of a cable tray position for 13.8-kV power (15,000-V insulation class) occupying the uppermost tray position.


service. Manual closing of the two charger breaker completes the  
RBS USAR 8.3-81 August 1987 8.3.1.4.3 Control of Compliance With Separation Criteria During Design and Installation Compliance with the criteria which preserve independence of redundant systems is a supervisory responsibility during both the design and installation phases.
The responsibility is discharged by:
1.
Identifying applicable criteria 2.
Issuing working procedures to implement these criteria 3.
Modifying procedures to keep them current and workable 4.
Checking manufacturer drawings and specifications to ensure compliance with procedures 5.
Controlling installation and procurement to assure compliance with approved and issued drawings and specifications.
The nomenclature used for equipment at the River Bend Station is the primary mechanism for ensuring proper separation.
All Class 1E electrical equipment has an attached nameplate inscribed with the equipment identification and color identification of its division.
Other Class 1E power system components, such as cables and raceways, have unique color assignment to identify safety-related systems.
These colors are readily apparent to the operators or maintenance craftsmen so the safety-related
: cable, raceways, or equipment can be identified.
Nonsafety system circuits not associated with the safety circuits are either color coded black or have no color identification.
In every case it is possible to determine the quality group and separation classification of equipment from the construction drawings and specifications.
Nonessential equipment has been separated where it was desired to enhance power generation reliability, but such separation is not a
safety consideration.
This was accomplished by administratively directing use of raceway systems to separate critical companion BOP installations, such as the condensate pumps.


charging circuit.  
RBS USAR 8.3-82 August 1987 Where the safety-related equipment has been identified as an essential safety
: division, the nomenclature indicates a
characteristic color for positive visual identification.
Likewise, all ancillary equipment, cable, and raceways match the nomenclature of the system which they support.
There are certain exceptions to the above where equipment which is not safety-related is connected to essential power sources for functional design reasons.
These circuits are identified in Table 8.3-7.
Cable used to connect nonsafety-related equipment to safety-related sources of power is safety grade and qualified and routed as a nonsafety-related circuit after first having been connected to a
Class 1E protective device.
It has no color assignment.
This equipment is disconnected and locked out during an accident by a
LOCA
: signal, or protected by two qualified isolation devices.
8.3.1.4.4 Cable Design, Analysis, and Routing of Circuits 8.3.1.4.4.1 General Functional Design Bases The proper selection of cables and raceways preserves the reliability of redundant safety-related systems and conforms to the following design bases:
1.
The normal current loading of all insulated conductors is limited to that continuous value which does not cause insulation deterioration from heating.
Selection of conductor sizes is based on "Power Cable Ampacities" and "Ampacities -
Cables in Open-top Cable Trays" published by the Insulated Power Cable Engineers Association (IPCEA Publications P-46-426 and P-54-440, respectively).
For maintained spacing of cables in cable trays, plant-specific tests and evaluations have been conducted to demonstrate that spacing less than that specified in the IPCEA publications is acceptable as long as required spacing is maintained at cable tie-point intervals of 3 ft.
These tests and evaluations demonstrated adequate cable ampacity and temperature consistent with IPCEA guidelines.
For the small sizes not covered by the preceding, the National Electric Code (NEC) or more stringent regulations shall govern.
2.
All cable trays and supports are designed to carry the cables required without exceeding the allowable deflection and yield strength of the materials used in the trays and their supports.


The backup battery charger breaker's position is monitored in the
RBS USAR Revision 22 8.3-83 All cable trays carrying cables for safeguard services are designed to meet Seismic Category I criteria. All raceways installed in Seismic Category I areas are seismically supported.
: 3.
Cables are specified with consideration of the optimum combination of insulation, fire-resistant, and radiation-resistant characteristics.
: 4.
Cables are sized and installed so as to limit the temperature rise of conductors to within the temperature ratings of the cable for any expected overload condition. All power cables are sized and installed to carry short circuit current until the first protective device disconnects the source feeding the short circuit.
8.3.1.4.4.2 Electrical Cable Arrangement Physical separation is provided between similar components of redundant electrical systems and between power and control circuitry serving or being served from these components.
Redundant protective power and control cables are run on physically separate cable trays or conduits and follow different routes to and from power sources to loads, and from sensors and controllers to protective devices. Therefore, an event which might damage the cables in one set of cable trays or conduit does not affect the redundant cables in the other set of cable trays or conduit.
Power cables for 15-kV and 5-kV service are stranded copper conductors. Power cables No. 2/0 AWG and larger for 600-V service are stranded aluminum or copper conductors. Smaller power cables and control cables have copper conductors. All cables, where required, are constructed with a radiation-resistant, 90°C thermosetting-type insulation and an overall flame-retardant, radiation-resistant jacket.
Cable trays used for 13.8-kV service are identified as "J" trays and those for 4.16-kV are identified as "H" trays. The "J" and the "H" trays are separate from one another. Trays for 600-V or lower voltage large power cables and some low power cables are designated "L." Trays for 600-V or lower voltage small power cables and some control cables are designated "K." Control cables of 120-V ac or 125-V dc, are run in "C" trays or conduit. Low level analog or digital instrumentation cables are run in "X" trays or in conduit. In the Drywell, non-divisional, Augmented Quality (but not safety-related), analog instrumentation cables for the main steam line strain gauges are routed both in flexible stainless steel conduit and external to conduit. In the Containment building, the cables are routed in cable tray and rigid conduit. Segregation in conduit is in a comparable fashion to that employed for trays.


main control room, and is tripped upon receipt of a LOCA signal.  
RBS USAR 8.3-84 August 1987 Cables of redundant safety-related systems are isolated from each other and from nonsafety-related cables.
There are no medium-or high-voltage (480-V and above) power cables in the control building cable chases.
Electrical cables for the RPS and other safety-related systems located inside the containment structure are designed so that the cable is operable for the required period of usage during all postulated accident environments.
Cables in hazardous environments are protected from the environment and against physical or fire damage to the extent required for the service either by selection of cable or by choice of raceway (e.g., cable trays with covers, metallic conduit).
Cables are derated for grouping and spacing in accordance with IPCEA recommendations.
Medium voltage cable trays do not have more than a
single layer of cables.
480-V power control and instrumentation cables, when routed in cable trays, are installed in accordance with the applicable cable ampacity factors and in Category I areas do not extend above the siderails unless they are enclosed by an extended tray cover or an engineering analysis has demonstrated that electrical separation requirements are not compromised. Galvanized steel, nonconducting sleeves or blockouts in walls are used to transport cables through concrete walls.
Fire detection and protection
: systems, either manually or automatically initiated, are provided in those areas required to preserve the integrity of the circuits for safety-related services (Section 9.5.1).
The electrical penetrations, through the reactor containment
: vessel, are arranged in groups to maintain separation of electrical cables and to comply with the single-failure criteria.
The design and fabrication of each type of penetration assembly is in accordance with IEEE-317 for Electrical Penetration Assemblies in Containment Structures for Nuclear Fueled Power Generating Stations.
Each electrical penetration is designed to withstand the environment conditions at its location during all postulated DBAs.
Connections between field wires and penetration assembly conductors are made inside Seismic Category I termination cabinets designed to withstand the environmental conditions at its location during all postulated DBAs.


Operation of the backup battery charger is under strict administrative control. Credit is taken for this charger in mitigating the consequences of an accident, when used as a  
RBS USAR Revision 3 8.3-85 August 1990
*3 Wire splices inside the reactor building are made only where necessary and are primarily made in the electrical penetration terminal cabinets.
All splices are qualified for their intended use as described in Section 3.11.
All splices are made in accordance with the manufacturer's recommended procedures or approved equivalent instructions, and are tested after installation by continuity measurements, and power cable splices are additionally tested by insulation resistance measurements.
There are no splices made in cable trays.
3*
Control and instrumentation cable connections for safety-related Category I systems and equipment are made on terminating devices or by splices which have been qualified for their intended function pursuant to IEEE-323.
8.3.1.4.4.3 Cable and Raceway Scheduling Cable routing and raceway design is accomplished manually.
A computer program was used to assist in the engineering, design, installation, and control of cable routing, identification, tray, and raceway fill.
The main functions of this program are:
1.
The computation of all cable lengths and totalizing of cable types.
2.
The computation of raceway fill and overfill indication.
3.
To avoid duplication, indicate number of revisions on a specific item and to check information with respect to system, service, and redundancy.
4.
To provide output to the field in the form of pull and installation tickets which supplied all the necessary information for installation of cables and raceway and were designed to serve as Quality Control (QC) documents.
5.
To provide feedback from the field through system status information which allowed designers to revise systems as required with a
minimum of rework in the field.
6.
To provide status of any system with regard to the number of cable pulls and the overall job status.


substitute for a Division I or II safety-related battery charger.  
RBS USAR Revision 16 8.3-86 March 2003 8.3.2 DC Power Systems
16 8.3.2.1 Description - Divisions I and II, Nonsafety 8.3.2.1.1 General
14 Station service dc power is available at 125 V and 48 V. There are three ungrounded Class 1E safety-related 125-V dc systems, including Division III discussed in Section 8.3.2.2. There are also six non-Class 1E nonsafety-related ungrounded 125-V systems and one non-Class 1E nonsafety-related ungrounded 48-V system.
Fig. 8.3-6 illustrates these eight 125-V dc and one 48-V dc systems.
14
Each system includes a 480-V ac to 125-V dc or 120-V ac to 48-V dc static battery charger with a control panel. Safety-related chargers are powered from the standby system of their own division. Nonsafety-related chargers are also powered from safety-related systems to obtain a more reliable source of power during normal plant conditions, but are tripped on LOCA, with the following exceptions, which are furnished ac power from available nonsafety-related sources:
: a.
One 480-V ac to 125-V dc battery charger located in the circulating water switchgear house
: b.
One 480-V ac to 125-V dc battery charger located in the services building
: c.
One 120-V ac to 48-V battery charger located in the makeup water switchgear house
: d.
One 480-V ac to 125-V dc battery charger located in the service water cooling switch gear house.
16
The 125-V dc systems include a battery charger, a lead acid battery, a 125-V dc distribution switchgear energized from a battery distribution
: panel, local and control room instrumentation, and alarm facilities. The battery system surrenders the identity of its feeders to that of the controlled equipment or supported system at the first termination after leaving the distribution switchboard or panel.
7 A separate battery charger procured and qualified to IEEE-323 requirements and powered from either a nonsafety-related (black) power source or a portable diesel generator is provided as a backup battery charger for the Division I, II and III safety-related and three of the nonsafety-related battery chargers.
The backup battery charger's rating is equal to the largest capacity battery charger which it must replace. When the backup battery charger is to be used, the breaker of the battery 7


Where there is an electrical interface between safety-related switchgear and nonsafety-related equipment, such as chargers and switchgear, automatic breaker tripping by a LOCA signal at the  
RBS USAR Revision 24 8.3-87 charger being removed from service is tripped, removed and placed in the backup charger position. The backup charger breaker is taken from its storage position and placed in the position on its bus which feeds the bus of the battery charger removed from service. Manual closing of the two charger breaker completes the charging circuit.
 
The backup battery charger breaker's position is monitored in the main control room, and is tripped upon receipt of a LOCA signal.
safety-related switchgear is provided. 12 In the event of an Extended Loss of Alternating current Power (ELAP), at the distribution switchgear for the backup charger, a second breaker that is stored in a normal storage position is used to cross-tie Division I and Division II.
Operation of the backup battery charger is under strict administrative control. Credit is taken for this charger in mitigating the consequences of an accident, when used as a substitute for a Division I or II safety-related battery charger.
Where there is an electrical interface between safety-related switchgear and nonsafety-related equipment, such as chargers and switchgear, automatic breaker tripping by a LOCA signal at the safety-related switchgear is provided.
12 In the event of an Extended Loss of Alternating current Power (ELAP), at the distribution switchgear for the backup charger, a second breaker that is stored in a normal storage position is used to cross-tie Division I and Division II.
Operation of this breaker and the cross-tying of the Divisions are under strict administrative control. This includes bypassing the LOCA signal to enable closing of the breakers.
Operation of this breaker and the cross-tying of the Divisions are under strict administrative control. This includes bypassing the LOCA signal to enable closing of the breakers.
The Duty Cycle requirements for the standby batteries are identified in Tables 8.3-4, 8.3-5, and 8.3-6. All dc equipment  
The Duty Cycle requirements for the standby batteries are identified in Tables 8.3-4, 8.3-5, and 8.3-6. All dc equipment is rated to operate between 101 and 140 V dc.
12 The batteries, chargers, distribution switchgear, and certain subordinate equipment such as uninterruptible power supply systems are in separate ventilated enclosures. The enclosures for safety-related equipment are seismic Category I. The other electrical equipment in the room is safety-related and of the same division.
Those portions of Section 8.3.1.1.1 referring to the physical arrangement, continuity, and integrity of load function is applicable to the dc systems as well.
8.3.2.1.2 Function The objective of the safety-related 125-V dc systems (Fig. 8.3-6) is to provide a highly reliable source of dc power and control power for necessary dc loads, such as pumps, valves, relays, control devices, circuit breaker operating mechanisms, inverters of the uninterruptible power supply systems, and similar equipment requiring dc power. The preceding safety-related devices are required for safe operation of the station and for safe reactor shutdown under any DBA condition.
Three of the nonsafety-related 125-V dc systems support normal 13.8-kV, 4.16-kV, and 480-V switchgear, uninterruptible power supply systems, valves, and solenoids.


is rated to operate between 101 and 140 V dc.
RBS USAR Revision 13 8.3-88 September 2000 A
12 The batteries, chargers, distribution switchgear, and certain subordinate equipment such as uninterruptible power supply systems are in separate ventilated enclosures. The enclosures for safety-related equipment are seismic Category I. The other electrical equipment in the room is safety-related and of the
fourth nonsafety-related 125-V dc system supports the information handling
: system, while the 48-V dc system supports normal 4.16-kV switchgear and a remote supervisory cabinet.
8.3.2.1.3 System Capabilities
*12 *13 Each safety-related dc system has a
battery charger which is sized to supply all normal continuous steady-state loads and to restore simultaneously a
battery from its end of duty cycle condition to the fully charged condition in 24 hr.
The battery chargers have an equalizing charge voltage of 139 V nominal.
The stability of the battery charger output is not load dependent.
Each battery system is sized in conformance with principles set out in IEEE-308 and IEEE-485.
Battery capacities for Divisions I and II are 2100 or 2150 AH each.
Standby batteries 1ENB*BATO1A and 1ENB*BATO1B have the ability to supply all DBA loads and all other loads not automatically tripped on a
LOCA signal for 4 hours and have sufficient capacity remaining to perform the switching operations necessary to restore normal ac and dc power with the charger inoperable.
12* 13*
Standby batteries 1ENB*BAT01A and 1ENB*BAT01B furnish control power to standby 4.16-kV switchgear, 480-V load centers, 125-V dc switchgear, standby diesel generators, and standby instrument buses.
*13 *1 13* 1*
Each nonsafety-related system has a
charger with abilities as described in the preceding paragraphs.
Each battery has the ability to supply for a minimum of 2 hr normal continuous loads including uninterruptible power supply systems and all essential dc loads associated with turbine generator shutdown without offsite power.
The battery chargers have the
: ability, upon return of offsite preferred
: power, to perform the necessary switching operation to make that power available to the unit.
8.3.2.1.4 Support of Battery Systems The facilities available for normal operation of the 125-V dc safety-related systems are shown in Fig. 8.3-6.
Each system has its own battery charger for normal
: support, its


same division.  
RBS USAR Revision 24 8.3-89 battery for preferred support, and access to a backup battery charger.
The following paragraph is applicable to normal design basis conditions but may be procedurally changed as described in Section 8.3.2.1.1 in the event of an Extended Loss of Alternating current Power (ELAP).
A procedural configuration that maintains at least two empty circuit breaker cubicles or an empty cubicle and open circuit breaker is provided to prevent cross-connections between independent battery systems through the backup battery charger switchgear 1BYS-SWG01D. No single failure can jeopardize the safety of redundant loads.
The 125-V dc nonsafety-related systems are arranged similarly to the 125-V dc safety-related systems and are shown in Fig. 8.3-6.
8.3.2.1.5 Ventilation 8
Each battery associated with the Division I and II standby diesels is located in its own independently ventilated room to keep the gases produced due to the charging of batteries below an explosive concentration, and to keep the room temperature to a level that allows the battery to supply its required current.
The ratings of the batteries were initially established based on a 24-hour average electrolyte temperature of 77°F.
8 8.3.2.1.6 Instrumentation and Alarm Important system components are either alarmed on failure or capable of being tested during service to detect faults.
Indicators are provided to monitor their status in the main control room. The station operating procedures provide for system status checks at every shift change that include the charging status of batteries in the unlikely event that a battery charger should fail without annunciating the condition in the control room.
Control of the battery chargers and the distribution switchgear is local. The Division I and II dc power system includes the following monitors and alarms:
1.
Main Control Room Annunciation and Monitors a.
Battery current (ammeter-charge/discharge) b.
Dc bus voltage (voltmeter) c.
Dc bus voltage low alarm (set above the open circuit voltage) d.
Dc bus voltage low-low alarm e.
Dc bus ground fault alarm (for ungrounded systems)


Those portions of Section 8.3.1.1.1 referring to the physical arrangement, continuity, and integrity of load function is
RBS USAR Revision 8 8.3-90 August 1996 f.
Dc Bus battery breaker open alarm g.
Dc Bus battery charger output breaker open alarm h.
Battery charger trouble alarm i.
Backup charger breaker open alarm j.
Supply or distribution breaker overcurrent trip alarm
*6 k.
Voltage to ground for both polarities at switchgear 6*
2.
Local Annunciation and Monitors a.
Battery charger output current (ammeter) b.
Battery current (ammeter-charger/discharger) c.
Battery voltage (voltmeter) d.
Battery charger output voltage (voltmeter) e.
Battery charger overvoltage f.
Battery charger low ac supply voltage g.
Battery charger overcurrent h.
Battery charger temperature high
*6 3.
Local (Remote Shutdown Panel) a.
(1) White indicating light for local ENB 6*
The Non-Class 1E dc power system includes the following monitors and alarms:
*8 1.
"125 V dc battery charger trouble" alarm located in the main control room and local supervisory control panel (1BYS-CHGR1C) annunciates in the event of actuation of local alarms on the battery charger.
*8


applicable to the dc systems as well.  
RBS USAR Revision 10 8.3-91 April 1998
*8
*8
*10 2.
The Battery charger BXY-CHGR1 provides "48-V dc battery charger trouble" alarm located in the main control room and local supervisory control panel
*6 3.
The Battery chargers BYS-CHGR1A, 1B and IHS-CHGR1D provide "Battery charger trouble" alarm located in the main control room.
6*
10*
*6 "125-V dc battery trouble" alarm located in the main control room annunciate in the event of the following conditions on 1BYS*CHGR1D:
1.
460-V ac input undervoltage 2.
125-V charger overvoltage 3.
Charger cabinet temperature high 4.
Charger output overcurrent 5.
INJS-ACB 453 breaker in test position 6*
Uninterruptible power supplies have been specified to include protective circuitry which protects internal components from dc input voltage spikes which may have originated on the dc power system.
8.3.2.1.7 Maintenance and Testing The station batteries and other equipment associated with the 125-V dc systems are easily accessible for maintenance and testing.
The batteries will be periodically checked for specific gravity and individual cell voltages.
An equalizing (overvoltage)
: charge, where recommended by the battery manufacturer, is applied to bring all cells up to an equal voltage.
Over a period of time, the above-mentioned tests will reveal a weak or weakening trend in any cell and replacement is made if necessary.
Periodically, the battery charger is disconnected and the ability of the unit battery to maintain voltage and assume the dc load is verified. This test uncovers any high-resistance connections or cell internal malfunctions.
The normal station batteries and the standby batteries for Divisions I, II, and III have access to a battery load tester, as shown in Fig. 8.3-6.
Testing


8.3.2.1.2 Function
RBS USAR Revision 16 8.3-92 March 2003
16 complies with IEEE-308, Criteria for Class 1E Electrical Systems for Nuclear Power Generating Stations.
Periodic testing requirements of each safety related battery system during normal or accident periods of operation are described in the Technical Specifications.
16
The battery chargers may be operated with the battery disconnected since the charger's stability is not load dependent.
With the battery disconnected the charger's regulation is 0.5 percent from no load to full load and ripple does not exceed 105 millivolts (rms).
The only foreseen mode of electrical operation during which the battery chargers would supply power to the dc switchgear loads without the batteries also being connected to the dc switchgear load would occur during periodic battery discharge tests.
8.3.2.2 Description - Division III (HPCS) 8.3.2.2.1 General The objective of the 125-V dc power system (Division III) is to provide a reliable, continuous, and independent 125-V dc power source of control and motive power as required for the HPCS system logic, HPCS diesel generator set control and protection, and all Division III related control.
A Class 1E battery charger is provided for the battery. The 125-V dc system is classified as Class 1E. The Division III 125-V dc system is independent of all other divisional batteries and there is no manual or automatic connection to any other battery system.
The battery is not shared with any other unit.
8.3.2.2.2 HPCS DC Loads
12 The 125-V dc power is required for HPCS diesel generator field flashing, control logic, and for the control and switching function of breakers. The Duty Cycle requirements for the Division III battery are identified in Table 8.3-6.
8.3.2.2.3 Battery and Battery Charger
14 The 125-V dc system for the HPCS power supply has a 60 cell lead acid battery (825 AH at 8 hr), one battery charger and a distribution panel with molded case circuit breakers. The HPCS battery charger output capability is at least 50-A dc at a minimum float voltage of 130.2 Vdc. Independent calculations verify that the HPCS battery charger has the capability to supply all normal continuous steady-state 12 14


The objective of the safety-related 125-V dc systems (Fig. 8.3-6) is to provide a highly reliable source of dc power and control power for necessary dc loads, such as pumps, valves, relays, control devices, circuit breaker operating mechanisms, inverters of the uninterruptible power supply systems, and similar equipment requiring dc power. The preceding safety-related
RBS USAR Revision 13 8.3-93 September 2000
*13 *12 loads and simultaneously restore the Division III battery from its end of Duty Cycle condition to the fully charged condition in 8 hours.
13* 12*
The 125-V dc system equipment is designed as Class 1E in accordance with applicable clauses of IEEE-308.
It is designed so that no single failure in the system will result in conditions that prevent safe shutdown of the plant.
The plant design and circuit layout from the dc systems provides physical separation of the equipment, cabling, and instrumentation essential to plant safety.
As shown in Fig. 8.3-6, the battery is associated with its chargers and distribution panel.
The battery is located in its own ventilated room.
All the components of the dc systems are housed in a Seismic Category I structure.
8.3.2.2.4 125-V DC Systems Identification Fig. 8.3-6 shows the 125-V dc systems.
The battery feeds into distribution panel to serve the various dc loads for the HPCS system.
The battery charger is fed from the 480-V ac engineered safety features motor control center which is supplied by the HPCS diesel generator bus.
8.3.2.2.5 Battery Capacity
*12 The ampere-hour capacity and short time rating of the battery is in accordance with criteria given in IEEE-308 and IEEE-485, and is adequate to supply all electrical loads required until ac power is restored for the operation of the battery chargers.
The battery has sufficient stored energy to operate required connected essential loads for as long as each may be needed during a loss of the ac bus supplying the battery chargers under normal or emergency conditions. Capacity is large enough to cope with LOCA conditions or any other emergency shutdown.
Each distribution circuit is capable of transmitting sufficient energy to start and operate all required loads in that circuit.
12*
8.3.2.2.6 Charging The Class 1E charger 1E22*S001CGR for the HPCS dc system is fed from the HPCS motor control center (MCC) and is capable of carrying the normal direct-current system load and, at the same
: time, keeping the battery in a
fully charged condition.
The sizing of the battery charger meets IEEE-308.


devices are required for safe operation of the station and for
RBS USAR Revision 14 8.3-94 September 2001 14*
The maximum equalizing charge voltage for the HPCS battery is limited by the maximum operating voltage of the connected equipment to 140 Vdc.
Performance of an equalizing charge at maximum voltage will result in no damage to connected equipment.
14* *7 A
separate battery charger procured and qualified to IEEE-323 requirements and powered from either a non-safety-related (black) power source or a
portable diesel generator is provided as a
backup battery charger for the Division I,
II and III safety-related and three of the nonsafety-related battery chargers.
The backup battery charger's rating is equal to the largest capacity battery charger which it must replace.
When the backup battery charger is to be used, the breaker of the battery charger being removed from service is tripped, removed and placed in the backup charger position.
The backup charger breakers is taken from its storage position and placed in the position on its bus which feeds the bus of the battery charger removed from service.
Manual closing of the two charger breakers completes the charging circuit.
The backup battery charger breaker's position is monitored in the main control room, and is tripped upon receipt of a LOCA signal.
Operation of the backup battery charger is under strict administrative control.
No credit was taken for this charger in mitigating the consequences of an accident.
Where there is an electrical interface between safety-related switchgear and nonsafety-related equipment, such as chargers and switchgear, automatic breaker tripping by a
LOCA signal at the safety-related switchgear is provided.
*12 The Duty Cycle requirements for the standby batteries are identified in Tables 8.3-4, 8.3-5, and 8.3-6.
All dc equipment is rated to operate between 101 and 140 V dc.
12*
The batteries,
: chargers, distribution switchgear, and certain subordinate equipment such as uninterruptible power supply systems are in separate ventilated enclosures.
The enclosures for safety-related equipment are seismic Category I.
The other electrical equipment in the room is safety-related and of the same division.
Those portions of Section 8.3.1.1.1 referring to the physical arrangement, continuity, and integrity of load function is applicable to the dc systems as well.
7*


safe reactor shutdown under any DBA condition.  
RBS USAR Revision 12 8.3-94a December 1999 8.3.2.2.7 Ventilation The battery room is independently ventilated to keep the gases produced due to the charging of the battery below an explosive concentration.
8.3.2.2.8 Maintenance and Testing Design and installation of the 125-V dc system facilitates periodic maintenance tests to determine the condition of each individual cell.
Cells can be checked for liquid level, specific
: gravity, and cell voltage.
Performance discharge tests can be conducted as required.
Battery chargers are also periodically checked by visual inspection and performance tests.
Testing of the Division III 125-V dc batteries includes the following:
1.
The specific gravity, voltage, and temperature of the pilot cell of each battery are measured and logged in accordance with the technical specification.
*12 2.
Every 3 months, voltage measurements of each cell to the nearest 0.01 V, specific gravity of each cell, and temperature of representative (at least one out of six connected as discussed in TS SR Bases 3.8.6.3) cells are made.
These measurements are logged.
12*
3.
Once each refueling cycle, the batteries are subjected to a service test.
The specific gravity and voltage of each cell are measured after discharge and logged.
8.3.2.2.9 Test Requirements of Station Batteries Provisions are made in the dc power system so that surveillance and service tests can be performed in accordance with IEEE-450.
8.3.2.2.10 Instrumentation and Alarm Important system functions are either alarmed on failure or capable of being tested during service to detect faults.


Three of the nonsafety-related 125-V dc systems support normal 13.8-kV, 4.16-kV, and 480-V switchgear, uninterruptible power
RBS USAR Revision 7 8.3-94b January 1995 THIS PAGE INTENTIONALLY LEFT BLANK


supply systems, valves, and solenoids.  
RBS USAR Revision 16 8.3-95 March 2003 Indicators for critical parameters are provided to monitor their status in the main control room.
Additionally, station operating procedures provide for system status monitoring at every shift change that will include a check of the charging status of the battery in the unlikely event that the battery charger fails in a manner which is not alarmed in the control room.
Main control room instrumentation includes a voltmeter, and an ammeter for each dc system. Control of the battery chargers and the distribution switchgear is local. The dc power system includes the following alarms and monitors:
: 1.
"125 V dc System Trouble" alarm located in the main control room annunciates in the event of:
: a.
Battery output breaker trip
: b.
125 V dc bus ground, or
: c.
125 V dc bus undervoltage.
: 2.
"HPCS Battery Charger Trouble" alarm located in the main control room annunciates in the event of:
: a.
Battery charger output breaker trip
: b.
Battery charger high output voltage, or
: c.
Battery charger loss of ac power supply.
: 3.
"Battery Trouble" alarm located on the local diesel-generator control panel annunciates in the event of:
: a.
125 V dc bus ground, or
: b.
125-V dc bus undervoltage.
: 4.
The following voltmeters are provided to monitor 125 V dc supply voltage:
: a.
125 V dc voltmeter in the main control room
16
: b.
125 V dc voltmeter locally at battery charger 16


RBSUSARRevision138.3-88September2000Afourthnonsafety-related125-Vdcsystemsupportstheinformationhandlingsystem,whilethe48-Vdcsystemsupports normal4.16-kVswitchgearandaremotesupervisorycabinet.8.3.2.1.3SystemCapabilities1213Eachsafety-relateddcsystemhasabatterychargerwhichis sizedtosupplyallnormalcontinuoussteady-stateloadsandto restoresimultaneouslyabatteryfromitsendofdutycycle conditiontothefullychargedconditionin24hr.Thebattery chargershaveanequalizingchargevoltageof139Vnominal.The stabilityofthebatterychargeroutputisnotloaddependent.
RBS USAR Revision 16 8.3-96 March 2003
Eachbatterysystemissizedinconformancewithprinciplesset outinIEEE-308andIEEE-485.BatterycapacitiesforDivisionsI andIIare2100or2150AHeach.Standbybatteries1ENB*BATO1A and1ENB*BATO1BhavetheabilitytosupplyallDBAloadsandall otherloadsnotautomaticallytrippedonaLOCAsignalfor 4hoursandhavesufficientcapacityremainingtoperformthe switchingoperationsnecessarytorestorenormalacanddcpower withthechargerinoperable.
16
1213Standbybatteries1ENB*BAT01Aand1ENB*BAT01Bfurnishcontrol powertostandby4.16-kVswitchgear,480-Vloadcenters,125-Vdc switchgear,standbydieselgenerators,andstandbyinstrument
: c.
 
125 V dc voltmeter at local diesel-generator control panel.
buses.131 131Eachnonsafety-relatedsystemhasachargerwithabilitiesas describedintheprecedingparagraphs.Eachbatteryhasthe abilitytosupplyforaminimumof2hrnormalcontinuousloads includinguninterruptiblepowersupplysystemsandallessential dcloadsassociatedwithturbinegeneratorshutdownwithout offsitepower.Thebatterychargershavetheability,upon returnofoffsitepreferredpower,toperformthenecessary switchingoperationtomakethatpoweravailabletotheunit.8.3.2.1.4SupportofBatterySystems Thefacilitiesavailablefornormaloperationofthe125-Vdcsafety-relatedsystemsareshowninFig.8.3-6.Eachsystemhas itsownbatterychargerfornormalsupport,its RBS USAR Revision 24 8.3-89 battery for preferred support, and access to a backup battery charger. The following paragraph is applicable to normal design basis conditions but may be procedurally changed as described i n Section 8.3.2.1.1 in the event of an Extended Loss of Alternating current Pow er (ELAP) A procedural configuration that maintains at least two empty circuit breaker cubicles or an empty cubicle and open circuit breaker is provided to prevent cross-connections between
16
 
: 5.
independent battery systems through the backup battery charger switchgear 1BYS-SWG01D. No single failure can jeopardize the
The following ammeters are provided to monitor 125 V dc system load current:
 
: a.
safety of redundant loads. The 125-V dc nonsafety-related systems are arranged similarly to the 125-V dc safety-related systems and are shown in Fig. 8.3-6.
Ammeter in the main control room
8.3.2.1.5  Ventilation  8 Each battery associated with the Division I and II standby diesels is located in its own independently ventilated room to keep the gases produced due to the charging of batteries below an explosive concentration, and to keep the room temperature to a level that allows the battery to supply its required current.
: b.
The ratings of the batteries were initially established based on
Ammeter at local diesel-generator control panel
 
: c.
a 24-hour average electrolyte temperature of 77°F.
Ammeter locally at battery charger.
8 8.3.2.1.6  Instrumentation and Alarm Important system components are either alarmed on failure or capable of being tested during service to detect faults.
8.3.2.3 Analysis - Divisions I and II 8.3.2.3.1 Compliance 8.3.2.3.1.1 General Functional Design Requirements  
Indicators are provided to monitor their status in the main
13 During normal operation, the 125-V dc loads (Fig. 8.3-6) are fed from the battery chargers, with the batteries floating on the 125-V dc system. Upon loss of ac power to the battery chargers, the entire dc load is supported from the batteries until ac power is restored from the preferred transformers or standby diesel generators, to energize the battery chargers. The 125-V dc systems are designed on the following general functional bases:
 
13
control room. The station operating procedures provide for system status checks at every shift change that include the
: 1.
 
The 125-V dc systems are designed to meet the single failure criterion in which failure of any single component of the system does not result in a failure which could prevent any safety-related system from performing its function. This is accomplished by providing a separate battery, distribution panel, and battery charger for each system.
charging status of batteries in the unlikely event that a battery charger should fail without annunciating the condition in the
: 2.
 
Each battery serving a standby 4.16-kV ac bus is designed in accordance with Seismic Category I criteria.
control room.
: 3.
Control of the battery chargers and the distribution switchgear is local. The Division I and II dc power system includes the
Batteries serving standby 4.16-kV ac buses are housed in a
 
Seismic Category I structure with Seismic Category I walls separating them. Allowances are made for proper ventilation of the battery rooms.
following monitors and alarms: 1.Main Control Room Annunciation and Monitors a.Battery current (ammeter-charge/discharge)b.Dc bus voltage (voltmeter) c.Dc bus voltage low alarm (set above the open circuit voltage) d.Dc bus voltage low-low alarme.Dc bus ground fault alarm (for ungrounded systems)
: 4.
RBSUSARRevision88.3-90August1996f.DcBusbatterybreakeropenalarmg.DcBusbatterychargeroutputbreakeropenalarm h.Batterychargertroublealarm i.Backupchargerbreakeropenalarm j.Supplyordistributionbreakerovercurrenttrip alarm6k.Voltagetogroundforbothpolaritiesatswitchgear 62.LocalAnnunciationandMonitorsa.Batterychargeroutputcurrent(ammeter) b.Batterycurrent(ammeter-charger/discharger) c.Batteryvoltage(voltmeter) d.Batterychargeroutputvoltage(voltmeter) e.Batterychargerovervoltage f.Batterychargerlowacsupplyvoltage g.Batterychargerovercurrent h.Batterychargertemperaturehigh63.Local(RemoteShutdownPanel)a.(1)WhiteindicatinglightforlocalENB 6TheNon-Class1Edcpowersystemincludesthefollowingmonitors andalarms:81."125Vdcbatterychargertrouble"alarmlocatedinthemaincontrolroomandlocalsupervisorycontrolpanel (1BYS-CHGR1C)annunciatesintheeventofactuationof localalarmsonthebatterycharger.8 RBSUSARRevision108.3-91April199888102.TheBatterychargerBXY-CHGR1provides"48-Vdcbatterychargertrouble"alarmlocatedinthemaincontrolroomand localsupervisorycontrolpanel63.TheBatterychargersBYS-CHGR1A,1BandIHS-CHGR1Dprovide"Batterychargertrouble"alarmlocatedinthemaincontrol
There are no nonsafety-related loads on safety-related 125-V dc systems.  
 
room.6106"125-Vdcbatterytrouble"alarmlocatedinthemaincontrolroom annunciateintheeventofthefollowingconditionson
 
1BYS*CHGR1D:1.460-Vacinputundervoltage 2.125-Vchargerovervoltage 3.Chargercabinettemperaturehigh 4.Chargeroutputovercurrent 5.INJS-ACB453breakerintestposition 6Uninterruptiblepowersupplieshavebeenspecifiedtoinclude protectivecircuitrywhichprotectsinternalcomponentsfromdc inputvoltagespikeswhichmayhaveoriginatedonthedcpower
 
system.8.3.2.1.7MaintenanceandTesting Thestationbatteriesandotherequipmentassociatedwiththe125-Vdcsystemsareeasilyaccessibleformaintenanceand testing.Thebatterieswillbeperiodicallycheckedforspecific gravityandindividualcellvoltages.Anequalizing (overvoltage)charge,whererecommendedbythebattery manufacturer,isappliedtobringallcellsuptoanequal voltage.Overaperiodoftime,theabove-mentionedtestswill revealaweakorweakeningtrendinanycellandreplacementis madeifnecessary.Periodically,thebatterychargeris disconnectedandtheabilityoftheunitbatterytomaintain voltageandassumethedcloadisverified.Thistestuncovers anyhigh-resistanceconnectionsorcellinternalmalfunctions.
Thenormalstationbatteriesandthestandbybatteriesfor DivisionsI,II,andIIIhaveaccesstoabatteryloadtester,as showninFig.8.3-6.Testing RBS USAR Revision 16 8.3-92 March 2003 16complies with IEEE-308, Criteria for Class 1E Electrical Systems for Nuclear Power Generating Stations. Periodic testing
 
requirements of each safety related battery system during normal
 
or accident periods of operation are described in the Technical
 
Specifications.
16The battery chargers may be operated with the battery disconnected since the charger's stability is not load dependent.
With the battery disconnected the charger's regulation is
 
===0.5 percent===
from no load to full load and ripple does not exceed
 
105 millivolts (rms).
The only foreseen mode of electrical operation during which the battery chargers would supply power to the dc switchgear loads
 
without the batteries also being connected to the dc switchgear
 
load would occur during periodic battery discharge tests. 8.3.2.2 Description - Division III (HPCS)
 
8.3.2.2.1 General The objective of the 125-V dc power system (Division III) is to provide a reliable, continuous, and independent 125-V dc power
 
source of control and motive power as required for the HPCS
 
system logic, HPCS diesel generator set control and protection, and all Division III related control. A Class 1E battery charger is provided for the battery. The 125-V dc system is classified as Class 1E. The Division III 125-V dc
 
system is independent of all other divisional batteries and there is no manual or automatic connection to any other battery system. 
 
The battery is not shared with any other unit. 8.3.2.2.2 HPCS DC Loads 12The 125-V dc power is required for HPCS diesel generator field flashing, control logic, and for the control and switching function of breakers. The Duty Cycle requirements for the
 
Division III battery are identified in Table 8.3-6. 8.3.2.2.3 Battery and Battery Charger 14The 125-V dc system for the HPCS power supply has a 60 cell lead acid battery (825 AH at 8 hr), one battery charger and a distribution panel with molded case circuit breakers. The HPCS battery charger output capability is at least 50-A dc at a minimum float voltage of 130.2 Vdc. Independent calculations
 
verify that the HPCS battery charger has the capability to supply
 
all normal continuous steady-state 12 14 RBSUSARRevision138.3-93September20001312loadsandsimultaneouslyrestoretheDivisionIIIbatteryfrom itsendofDutyCycleconditiontothefullychargedconditionin 8hours.1312The125-VdcsystemequipmentisdesignedasClass1Ein accordancewithapplicableclausesofIEEE-308.Itisdesigned sothatnosinglefailureinthesystemwillresultinconditions thatpreventsafeshutdownoftheplant.Theplantdesignand circuitlayoutfromthedcsystemsprovidesphysicalseparation oftheequipment,cabling,andinstrumentationessentialtoplant
 
safety.AsshowninFig.8.3-6,thebatteryisassociatedwithitschargersanddistributionpanel.Thebatteryislocatedinits ownventilatedroom.Allthecomponentsofthedcsystemsare housedinaSeismicCategoryIstructure.8.3.2.2.4125-VDCSystemsIdentification Fig.8.3-6showsthe125-Vdcsystems.ThebatteryfeedsintodistributionpaneltoservethevariousdcloadsfortheHPCS system.Thebatterychargerisfedfromthe480-Vacengineered safetyfeaturesmotorcontrolcenterwhichissuppliedbythe HPCSdieselgeneratorbus.8.3.2.2.5BatteryCapacity12Theampere-hourcapacityandshorttimeratingofthebatteryis inaccordancewithcriteriagiveninIEEE-308andIEEE-485,and isadequatetosupplyallelectricalloadsrequireduntilac powerisrestoredfortheoperationofthebatterychargers.The batteryhassufficientstoredenergytooperaterequired connectedessentialloadsforaslongaseachmaybeneeded duringalossoftheacbussupplyingthebatterychargersunder normaloremergencyconditions.Capacityislargeenoughtocope withLOCAconditionsoranyotheremergencyshutdown.Each distributioncircuitiscapableoftransmittingsufficientenergy tostartandoperateallrequiredloadsinthatcircuit.
128.3.2.2.6ChargingTheClass1Echarger1E22*S001CGRfortheHPCSdcsystemisfedfromtheHPCSmotorcontrolcenter(MCC)andiscapableof carryingthenormaldirect-currentsystemloadand,atthesame time,keepingthebatteryinafullychargedcondition.The sizingofthebatterychargermeetsIEEE-308.
RBSUSARRevision148.3-94September2001 14ThemaximumequalizingchargevoltagefortheHPCSbatteryis limitedbythemaximumoperatingvoltageoftheconnected equipmentto140Vdc.Performanceofanequalizingchargeat maximumvoltagewillresultinnodamagetoconnectedequipment.
14*7AseparatebatterychargerprocuredandqualifiedtoIEEE-323 requirementsandpoweredfromeitheranon-safety-related(black) powersourceoraportabledieselgeneratorisprovidedasa backupbatterychargerfortheDivisionI,IIandIIIsafety-relatedandthreeofthenonsafety-relatedbatterychargers.The backupbatterycharger'sratingisequaltothelargestcapacity batterychargerwhichitmustreplace.Whenthebackupbattery chargeristobeused,thebreakerofthebatterychargerbeing removedfromserviceistripped,removedandplacedinthebackup chargerposition.Thebackupchargerbreakersistakenfromits storagepositionandplacedinthepositiononitsbuswhich feedsthebusofthebatterychargerremovedfromservice.
Manualclosingofthetwochargerbreakerscompletesthecharging
 
circuit.Thebackupbatterychargerbreaker'spositionismonitoredinthemaincontrolroom,andistrippeduponreceiptofaLOCAsignal.Operationofthebackupbatterychargerisunderstrictadministrativecontrol.Nocreditwastakenforthischargerin mitigatingtheconsequencesofanaccident.Wherethereisanelectricalinterfacebetweensafety-relatedswitchgearandnonsafety-relatedequipment,suchaschargersand switchgear,automaticbreakertrippingbyaLOCAsignalatthe safety-relatedswitchgearisprovided.12TheDutyCyclerequirementsforthestandbybatteriesare identifiedinTables8.3-4,8.3-5,and8.3-6.Alldcequipment isratedtooperatebetween101and140Vdc.
12Thebatteries,chargers,distributionswitchgear,andcertain subordinateequipmentsuchasuninterruptiblepowersupply systemsareinseparateventilatedenclosures.Theenclosures forsafety-relatedequipmentareseismicCategoryI.Theother electricalequipmentintheroomissafety-relatedandofthe samedivision.ThoseportionsofSection8.3.1.1.1referringtothephysicalarrangement,continuity,andintegrityofloadfunctionis applicabletothedcsystemsaswell.
7 RBSUSARRevision128.3-94aDecember19998.3.2.2.7VentilationThebatteryroomisindependentlyventilatedtokeepthegasesproducedduetothechargingofthebatterybelowanexplosive
 
concentration.8.3.2.2.8MaintenanceandTesting Designandinstallationofthe125-Vdcsystemfacilitatesperiodicmaintenanceteststodeterminetheconditionofeach individualcell.Cellscanbecheckedforliquidlevel,specific gravity,andcellvoltage.Performancedischargetestscanbe conductedasrequired.Batterychargersarealsoperiodically checkedbyvisualinspectionandperformancetests.TestingoftheDivisionIII125-Vdcbatteriesincludesthe following:1.Thespecificgravity,voltage,andtemperatureofthepilotcellofeachbatteryaremeasuredandloggedin accordancewiththetechnicalspecification.122.Every3months,voltagemeasurementsofeachcelltothenearest0.01V,specificgravityofeachcell,and temperatureofrepresentative(atleastoneoutofsix connectedasdiscussedinTSSRBases3.8.6.3)cells aremade.Thesemeasurementsarelogged.
123.Onceeachrefuelingcycle,thebatteriesaresubjectedtoaservicetest.Thespecificgravityandvoltageof eachcellaremeasuredafterdischargeandlogged.8.3.2.2.9TestRequirementsofStationBatteries ProvisionsaremadeinthedcpowersystemsothatsurveillanceandservicetestscanbeperformedinaccordancewithIEEE-450.8.3.2.2.10InstrumentationandAlarm Importantsystemfunctionsareeitheralarmedonfailureorcapableofbeingtestedduringservicetodetectfaults.
RBSUSARRevision78.3-94bJanuary1995THISPAGEINTENTIONALLYLEFTBLANK RBS USAR Revision 16 8.3-95 March 2003 Indicators for critical parameters are provided to monitor their status in the main control room.Additionally, station operating procedures provide for system status monitoring at every shift change that will include a check of the charging status of the battery in the unlikely event that
 
the battery charger fails in a manner which is not alarmed in the
 
control room.
Main control room instrumentation includes a voltmeter, and an ammeter for each dc system. Control of the battery chargers and the distribution switchgear is local. The dc power system
 
includes the following alarms and monitors:  1. "125 V dc System Trouble" alarm located in the main control room annunciates in the event of:  a. Battery output breaker trip
: b. 125 V dc bus ground, or
: c. 125 V dc bus undervoltage.  
: 2. "HPCS Battery Charger Trouble" alarm located in the main control room annunciates in the event of:  a. Battery charger output breaker trip
: b. Battery charger high output voltage, or
: c. Battery charger loss of ac power supply.
: 3. "Battery Trouble" alarm located on the local diesel-generator control panel annunciates in the event of:  a. 125 V dc bus ground, or
: b. 125-V dc bus undervoltage.
: 4. The following voltmeters are provided to monitor 125 V dc supply voltage:  a. 125 V dc voltmeter in the main control room 16 b. 125 V dc voltmeter locally at battery charger 16 RBS USAR Revision 16 8.3-96 March 200316 c. 125 V dc voltmeter at local diesel-generator control panel.
16 5. The following ammeters are provided to monitor 125 V dc system load current: a. Ammeter in the main control room  
: b. Ammeter at local diesel-generator control panel  
: c. Ammeter locally at battery charger.
8.3.2.3 Analysis - Divisions I and II  
 
8.3.2.3.1 Compliance 8.3.2.3.1.1 General Functional Design Requirements 13During normal operation, the 125-V dc loads (Fig. 8.3-6) are fed from the battery chargers, with the batteries floating on the 125-V dc system. Upon loss of ac power to the battery chargers, the entire dc load is supported from the batteries until ac power  
 
is restored from the preferred transformers or standby diesel generators, to energize the battery chargers. The 125-V dc  
 
systems are designed on the following general functional bases:
13 1. The 125-V dc systems are designed to meet the single failure criterion in which failure of any single  
 
component of the system does not result in a failure  
 
which could prevent any safety-related system from performing its function. This is accomplished by  
 
providing a separate battery, distribution panel, and  
 
battery charger for each system. 2. Each battery serving a standby 4.16-kV ac bus is designed in accordance with Seismic Category I  
 
criteria. 3. Batteries serving standby 4.16-kV ac buses are housed in a Seismic Category I structure with Seismic Category I walls separating them. Allowances are made  
 
for proper ventilation of the battery rooms. 4. There are no nonsafety-related loads on safety-related 125-V dc systems.
RBSUSAR8.3-97August19878.3.2.3.1.2DesignCriteriaandStandardsCriterion17TheClass1Edcpowersystemisdesignedtopermitthefunctioningofstructures,systems,andcomponentsimportantto safety.Inaddition,thedcpowersourcesandthedc distributionsystemhavesufficientindependence,redundancy,and testabilitytoperformtheirsafetyfunctions,assumingasingle failure,tomeettherequirementsofGDC17.Criterion18TheClass1Edcpowersystemisdesignedtopermitperiodicinspectionandtestingtoassesstheconditionofthesystem's componentsandtheircapabilitytoperformtheirintended functionsinordertomeettherequirementsofGDC18.RegulatoryGuide1.6TheClass1Edcpowersystemconsistsofthreeredundantandindependentdcsystems,eachconsistingofabatterywithitsown chargeranddistributionsystem.TheClass1Edcredundantload groupshavenoautomaticconnectiontoanyotherloadgroupand noprovisionsforautomaticallytransferringloadsbetweenthese redundantloadgroups.Abackupbatterychargerisredundantto theoperatingchargersdescribedinSection8.3.2.1.1and supplies125-Vdcpowerrequirementsduringmaintenanceperiods.
ThedesignmeetstheindependencerequirementsofRegulatory Guide1.6.RegulatoryGuide1.32TheClass1Edcsystemisoperatedatanormalfloatchargevoltageleveltomaintainthebatteriesinafullycharged condition.Thebatterychargersassociatedwitheachstandby batteryareratedtosupplythelargestcombineddemandsofthe varioussteady-stateloadsandthechargingcapacitytorestore thebatteryfromthedesignminimumchargedstatetothefully chargedstateirrespectiveofthestatusoftheplantwhenthese demandsoccur,inordertomeettherequirementsofRegulatory Guide1.32.BothDivisionIandIIbatteriesaresizedtocarry safetyloadsforatleast4hrfollowinglossofallacpower.
Eachbatteryvoltageleveliscontinuouslymonitoredand displayedinthemaincontrolroom.Lowvoltageandlowcharging currentarealarmedinthemaincontrolroom.
RBS USAR Revision 22 8.3-98 IEEE-450 The reliability of the dc supplies are assured by periodic
 
discharge tests of the batteries, as described in IEEE-450. An exception has been taken to IEEE-450, in that, the specified maximum interval of 18 months between battery service tests has been extended to 30 months.
8.3.2.3.1.3 Conformance With Appropriate Quality Assurance Standards
 
See Section 8.3.1.2.3. 
 
8.3.2.3.2  Independence of Redundant Systems 
 
See Section 8.3.1.4. 
 
8.3.2.3.3  Physical Identification of Equipment 
 
See Section 8.3.1.3. 
 
8.3.2.3.4  Test Documentation to Qualify Electrical Equipment
 
See Section 8.3.1.2.4. 
 
8.3.2.4  Analysis 
 
8.3.2.4.1  General DC Power System 
 
8.3.2.4.1.1 Compliance With General Design Criteria and Regulatory Guides
 
The design of the 125-V dc system for the  engineered safety features provided for this plant are based on the criteria
 
described in IEEE-308 and Regulatory Guide 1.32. 
 
The 125-V dc systems, including the power supply, distribution system, and load groups, are arranged to provide dc electric power for control and switching of the components of Class 1E
 
systems. 


Batteries consist of industrial-type storage cells designed for the type of service in which they are to be used. Ample capacity is available to serve the loads connected to the system for the  
RBS USAR 8.3-97 August 1987 8.3.2.3.1.2 Design Criteria and Standards Criterion 17 The Class 1E dc power system is designed to permit the functioning of structures, systems, and components important to safety.
In
: addition, the dc power sources and the dc distribution system have sufficient independence, redundancy, and testability to perform their safety functions, assuming a single failure, to meet the requirements of GDC 17.
Criterion 18 The Class 1E dc power system is designed to permit periodic inspection and testing to assess the condition of the system's components and their capability to perform their intended functions in order to meet the requirements of GDC 18.
Regulatory Guide 1.6 The Class 1E dc power system consists of three redundant and independent dc systems, each consisting of a battery with its own charger and distribution system.
The Class 1E dc redundant load groups have no automatic connection to any other load group and no provisions for automatically transferring loads between these redundant load groups.
A backup battery charger is redundant to the operating chargers described in Section 8.3.2.1.1 and supplies 125-V dc power requirements during maintenance periods.
The design meets the independence requirements of Regulatory Guide 1.6.
Regulatory Guide 1.32 The Class 1E dc system is operated at a
normal float charge voltage level to maintain the batteries in a
fully charged condition.
The battery chargers associated with each standby battery are rated to supply the largest combined demands of the various steady-state loads and the charging capacity to restore the battery from the design minimum charged state to the fully charged state irrespective of the status of the plant when these demands
: occur, in order to meet the requirements of Regulatory Guide 1.32.
Both Division I and II batteries are sized to carry safety loads for at least 4 hr following loss of all ac power.
Each battery voltage level is continuously monitored and displayed in the main control room.
Low voltage and low charging current are alarmed in the main control room.


duration of the time the alternating current is not available to the battery charger. Each division of Class 1E equipment is provided with a separate 125-V dc system, so as to avoid a single  
RBS USAR Revision 22 8.3-98 IEEE-450 The reliability of the dc supplies are assured by periodic discharge tests of the batteries, as described in IEEE-450. An exception has been taken to IEEE-450, in that, the specified maximum interval of 18 months between battery service tests has been extended to 30 months.
8.3.2.3.1.3 Conformance With Appropriate Quality Assurance Standards See Section 8.3.1.2.3.
8.3.2.3.2 Independence of Redundant Systems See Section 8.3.1.4.
8.3.2.3.3 Physical Identification of Equipment See Section 8.3.1.3.
8.3.2.3.4 Test Documentation to Qualify Electrical Equipment See Section 8.3.1.2.4.
8.3.2.4 Analysis 8.3.2.4.1 General DC Power System 8.3.2.4.1.1 Compliance With General Design Criteria and Regulatory Guides The design of the 125-V dc system for the engineered safety features provided for this plant are based on the criteria described in IEEE-308 and Regulatory Guide 1.32.
The 125-V dc systems, including the power supply, distribution system, and load groups, are arranged to provide dc electric power for control and switching of the components of Class 1E systems.
Batteries consist of industrial-type storage cells designed for the type of service in which they are to be used. Ample capacity is available to serve the loads connected to the system for the duration of the time the alternating current is not available to the battery charger. Each division of Class 1E equipment is provided with a separate 125-V dc system, so as to avoid a single failure involving more than one system.
Each battery charger has enough power output capacity for the steady-state operation of connected loads required


failure involving more than one system.
RBS USAR 8.3-99 August 1987 during normal or emergency operation (whichever is larger), while maintaining its battery in a
fully charged state.
Each battery charger supply has enough capacity to restore the battery from the design minimum charge to its fully charged state while supplying normal steady-state loads. The normal battery charger supply is from engineered safety feature buses.
The backup battery charger is supplied from a non-ESF source.
Since the dc power systems are operated ungrounded, a ground detection feature is provided. Indicators are provided to monitor the status of the battery charger supply.
This instrumentation includes indication of output
: voltages, output
: current, battery ground
: status, and main circuit breaker position.
Bus undervoltage is annunciated in the main control room.
Battery chargers are provided with disconnecting means and feedback protection. Periodic tests are performed to assure the readiness of the system to deliver the power required.
8.3.2.4.2 HPCS - Division III - ESF DC System The 480-V ac feed to the Class 1E battery charger is from the HPCS motor control center to maintain functional association such that the battery can carry the HPCS dc load for 2 hr.
Probability of a system failure resulting in prolonged loss of dc power is extremely low.
Important system components are either self-alarming on failure or capable of being tested during service to detect faults.
The battery is located in its own ventilated battery room.
All abnormal conditions of selected system parameters important to surveillance of the system annunciate in the main control room.
Automatic cross connections between the HPCS 125-V dc systems and other dc systems are not provided. Control power for the breakers in the HPCS switchgear is from the HPCS battery ensuring the following:
1.
The unlikely loss of HPCS dc power supply will not jeopardize the supply of offsite or onsite power to other engineered safety feature buses.
2.
The differential relays and all the interlocks associated with HPCS are from the HPCS 125-V dc system only, thereby eliminating any cross connections between the redundant dc systems.
8.3.3 Fire Protection for Cable Systems The basic concept of fire protection for cable systems is that it should be designed into the installation rather than added on to the finished product.
Accordingly, the pertinent features have been previously discussed under the


Each battery charger has enough power output capacity for the  
RBS USAR 8.3-100 August 1987 analysis conducted to determine if the power system design met applicable criteria (Section 8.3.1.4.4).
By use of fire-resistant cables and conservative application as regards ampacity and careful
: routing, both with regard to path and raceway construction, fire resistance is built into the cable systems.
External fire protection and detection is discussed in Section 9.5.1.


steady-state operation of connected loads required RBSUSAR8.3-99August1987duringnormaloremergencyoperation(whicheverislarger),whilemaintainingitsbatteryinafullychargedstate.Eachbattery chargersupplyhasenoughcapacitytorestorethebatteryfrom thedesignminimumchargetoitsfullychargedstatewhile supplyingnormalsteady-stateloads.Thenormalbatterycharger supplyisfromengineeredsafetyfeaturebuses.Thebackup batterychargerissuppliedfromanon-ESFsource.Sincethedc powersystemsareoperatedungrounded,agrounddetectionfeature isprovided.Indicatorsareprovidedtomonitorthestatusofthe batterychargersupply.Thisinstrumentationincludesindication ofoutputvoltages,outputcurrent,batterygroundstatus,and maincircuitbreakerposition.Busundervoltageisannunciated inthemaincontrolroom.Batterychargersareprovidedwith disconnectingmeansandfeedbackprotection.Periodictestsare performedtoassurethereadinessofthesystemtodeliverthe powerrequired.8.3.2.4.2HPCS-DivisionIII-ESFDCSystem The480-VacfeedtotheClass1EbatterychargerisfromtheHPCSmotorcontrolcentertomaintainfunctionalassociationsuch thatthebatterycancarrytheHPCSdcloadfor2hr.
RBS USAR 8.3-101 August 1987 References - 8.3 1.
Probabilityofasystemfailureresultinginprolongedlossofdc powerisextremelylow.Importantsystemcomponentsareeither self-alarmingonfailureorcapableofbeingtestedduring servicetodetectfaults.Thebatteryislocatedinitsown ventilatedbatteryroom.Allabnormalconditionsofselected systemparametersimportanttosurveillanceofthesystem annunciateinthemaincontrolroom.Automaticcrossconnections betweentheHPCS125-Vdcsystemsandotherdcsystemsarenot provided.ControlpowerforthebreakersintheHPCSswitchgear isfromtheHPCSbatteryensuringthefollowing:1.TheunlikelylossofHPCSdcpowersupplywillnotjeopardizethesupplyofoffsiteoronsitepowerto otherengineeredsafetyfeaturebuses.2.ThedifferentialrelaysandalltheinterlocksassociatedwithHPCSarefromtheHPCS125-Vdcsystem only,therebyeliminatinganycrossconnectionsbetween theredundantdcsystems.8.3.3FireProtectionforCableSystemsThebasicconceptoffireprotectionforcablesystemsisthatitshouldbedesignedintotheinstallationratherthanaddedonto thefinishedproduct.Accordingly,thepertinentfeatureshave beenpreviouslydiscussedunderthe RBSUSAR8.3-100August1987analysisconductedtodetermineifthepowersystemdesignmetapplicablecriteria(Section8.3.1.4.4).Byuseoffire-resistantcablesandconservativeapplicationasregardsampacityandcarefulrouting,bothwithregardtopath andracewayconstruction,fireresistanceisbuiltintothecable systems.Externalfireprotectionanddetectionisdiscussedin Section9.5.1.
: Henrie, D.K.
RBSUSAR8.3-101August1987References-8.31.Henrie,D.K.andSubramanian,C.V.,SeismicQualificationReviewTeam(SQRT),TechnicalApproachforRe-Evaluationof Equipment,NEDE-24788-2,December1982.2.LetterfromJ.E.Booker,GulfStatesUtilitiesCompany,Beaumont,Texas,toH.R.Denton,U.S.NuclearRegulatory Commission,Washington,DC,February10,1984.3.LetterfromJ.E.Booker,GulfStatesUtilitiesCompany,Beaumont,Texas,toH.R.Denton,U.S.Nuclear RegulatoryCommission,Washington,DC,April11,1985(GSU LetterNo.RBG-20684).}}
and Subramanian, C.V.,
Seismic Qualification Review Team (SQRT), Technical Approach for Re-Evaluation of Equipment, NEDE-24788-2, December 1982.
2.
Letter from J. E. Booker, Gulf States Utilities
: Company, Beaumont,
: Texas, to H. R. Denton, U.S.
Nuclear Regulatory Commission, Washington, DC, February 10, 1984.
3.
Letter from J. E. Booker, Gulf States Utilities
: Company, Beaumont,
: Texas, to H. R. Denton, U.S.
Nuclear Regulatory Commission, Washington, DC, April 11, 1985 (GSU Letter No. RBG-20684).}}

Latest revision as of 14:05, 8 January 2025

5 to the Updated Safety Analysis Report, Chapter 8, Section 8.1 Through 8.3
ML17226A144
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Issue date: 07/28/2017
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To:
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Text

RBS USAR Revision 11 8.1-1 October 1998 CHAPTER 8 ELECTRIC POWER

8.1 INTRODUCTION

8.1.1 Utility Grid Description The Gulf States Utilities Company (GSU) electrical system consists of interconnected fossil fuel plants and future plants supplying electric energy over a 500/230/138-kV transmission system (Fig. 8.1-1 through 8.1-3).

11 GSU, a member of the Southeastern Electric Reliability Council, is interconnected with Arkansas Power and Light Company (AP&L),

Mississippi Power and Light Company (MP&L), Louisiana Power and Light Company (LP&L), and Central Louisiana Electric Company (CLECo). Prior to January 1, 1998, GSU was a member of the Southwest Power Pool.

11

The River Bend Station Unit 1 main generator is rated 1,151 MVA, 0.9 pf, 22-kV, 1,800 rpm, three-phase, 60 Hz.

The output of the station is delivered to Fancy Point Substation, a 230/500-kV substation (Fig. 8.1-4 and 8.1-5) via a 230-kV line.

This substation consists of 230-kV bays and 500-kV bays.

Transmission lines at 230-kV feed power to the GSU 230-kV system, the central part of Baton Rouge area by connecting to the Enjay Substation, the eastern part by connecting to the Coly Substation, and the northern part by connecting to the Port Hudson Substation. Power is also fed at 500-kV to the GSU system and to the power pool. The 500-kV, 230-kV, and 138-kV systems are interconnected at various locations.

8.1.2 Interconnections

11 The transmission system from GSU's generation facilities is closely integrated with those of other utilities in the Southwest Power Pool and the Southeastern Electric Reliability Council. As of the year 1984, GSU expects to have 11 interconnections to CLECo at 138-kV and 230-kV; 8 interconnections to Middle South System (MSS) at 115-kV, 138-kV, 230-kV, and 500-kV voltage levels; 1 interconnection at 345-kV to the Southwestern Electric Power Company (SWEPCo); and 3 interconnections at 230-kV and 500-kV to the Cajun Electric Power Cooperative, Incorporated (CEPCo).

Table 8.1-1 is a listing of the tie lines, voltage levels of interconnected buses, and utilities, which are projected for the year 1984.

In 11

RBS USAR Revision 22 8.1-2 addition to the listed interconnections, new transmission lines are expected to be placed in service with installation of future units.

8.1.3 Transmission System at Site Section 8.2.1, along with Fig. 8.1-4 through 8.1-7, and 8.2-2, describes the transmission system at the site.

8.1.4 Onsite AC Systems

  • 6 *4 River Bend Station is provided power from the 230-kV bays of the Fancy Point Substation via two physically and electrically independent lines. Each 230-kV line is terminated at a transformer yard. The two transformer yards, designated yard 1 and yard 2A, are physically separated from each other.

Transformer yard 1 is located adjacent to the east wall of the turbine building, while transformer yard 2A is located outside the security

fence, southwest of the turbine building.

Transformer yard 1 contains three normal station service transformers, 1STX-XNS1A, 1STX-XNS1B and 1STX-XNS1C, and two preferred station service transformers, 1RTX-XSR1C and 1RTX-XSR1E, in addition to the two main stepup transformers 1MTX-XM1 and 1MTX-XM2. Transformer yard 2A contains two preferred station service transformers, 1RTX-XSR1F and 1RTX-XSR1D.

The transformers in both transformer yards support the normal operation and safe shutdown of River Bend Station. See Fig. 8.2-2 for the configuration of the two transformer yards.

4* 6*

The main generator leads of River Bend Station are connected by means of isolated phase bus duct to two 518.6/788.5 MVA, 65°C, FOA, 21.45-kV delta 150-kV BIL to 230-kV grounded wye 750-kV BIL, three-phase, 60 Hz main stepup transformers, 1MTX-XM1 and 1MTX-XM2. These two half-size transformers are paralleled on both the low (input) and high (output) sides. Disconnecting means are provided to allow the removal of one transformer from service, thus permitting the unit to continue generating power. The single 230-kV output circuit has bundled conductors, and is routed on a double circuit steel tower line to the 230-kV bays of the Fancy Point Substation approximately 4,000 ft southwest of the plant.

The main generator leads of River Bend Station are also connected by means of isolated phase bus duct to three normal station service transformers with the following ratings:

RBS USAR Revision 22 8.1-3

1. Normal station service transformers 1STX-XNS1A and 1STX-XNS1B are rated 47.5 MVA, 65°C, FOA, 22-kV delta 150-kV BIL to 13.8-kV delta 110-kV BIL, three-phase, 60 Hz.
2. Normal station service transformer 1STX-XNS1C is rated 16 MVA, 65°C, FOA, 22-kV delta, 150-kV BIL primary with two secondary windings each rated 8 MVA with 4.16-kV resistance grounded wye 75-kV BIL, three-phase, 60 Hz.

All three normal station service transformers are paralleled on their high (input) sides while their low (output) sides are routed to their separate 13.8-kV and 4.16-kV buses.

Preferred plant ac station service power is provided by two physically and electrically independent 230-kV lines originating in the 230-kV bays of the Fancy Point Substation and terminating at transformer yards 1 and 2A. These 230-kV lines are installed on double circuit transmission towers, as shown in Fig. 8.2-1, with the station service power circuits located adjacent to the generator output circuits. Their function is to provide all power requirements when normal power is unavailable. Preferred station service transformers are rated as follows:

  • 13 *6 *4
1. Preferred station service transformer 1RTX-XSR1E is rated 51/68/85 MVA, 55°C OA/FOA/FOA 230-kV Delta 750-kV BIL to 13.8-kV ground wye 110-kV BIL, three-phase, 60 Hz and 1RTX-XSR1F is rated 51/68/85 MVA, 55°C OA/FOA/FOA 230-kV delta 750-kV BIL to 13.8 kV grounded wye 110-kV BIL, three-phase, 60Hz.

4* 6* 13*

2. Preferred station service transformers 1RTX-XSR1C and 1RTX-XSR1D are rated 10/12.5 MVA, 65° C OA/FA, 230-kV grounded wye 750-kV BIL to 4.16-kV resistance grounded wye 75-kV BIL, three-phase, 60 Hz.

The arrangement of the preferred and normal station service transformers is shown on Fig. 8.1-8 and 8.1-9. Each transformer is provided with its own fire barrier and a separate deluge valve and water spray fire protection line. Separate oil pits and retaining curbs are provided for the groups of transformers.

Oil pits and associated retention curbs have been sized to hold the oil from the largest transformer draining into the pit plus the water from the operation of fire protection systems of two transformers for 10 minutes.

RBS USAR Revision 22 8.1-4 This design prevents a fire or oil spill associated with one transformer from affecting the operability of other transformers.

Fire barriers are designed utilizing guidance from applicable NFPA requirements.

The secondaries of transformers located in both transformer yards are connected to 13.8-kV and 4.16-kV buses via cables installed in concrete-encased ductlines in the yard and cable tray inside the power plant. Fig. 8.1-4 and 8.1-6 illustrate the station service electrical system.

The two double-circuit tower lines from the Fancy Point Substation to the power plant are of the steel pole, H-frame structure design on the same right-of-way. These 230-kV tower structures are so designed and physically spaced that failure of one does not jeopardize the operation of the other (Fig. 8.2-1).

  • 7 *6 Each section of the 13.8-KV and 4.16-KV buses has access to the assigned normal and assigned preferred station transformers which are connected to the buses by circuit breakers controlled from the main control room. In addition, if the unit auxiliary loads are being supplied through the normal transformers, automated throw-over from normal to preferred source occurs (as described in Section 8.3.1.1.3) after unit trip or upon loss of normal power. Each of the two 13.8-kV buses, 1NPS-SWG1A and 1NPS-SWG1B, and each of the 4.16-kV buses, 1NNS-SWG1A and 1NNS-SWG1B, support redundant equipment. 13.8-kV buses 1NPS-SWG1C and 1NPS-SWG1D have access to the assigned preferred station service transformers 1RTX-XSR1E and 1RTX-XSR1F respectively, which are connected to the buses by circuit breakers controlled from the main control room.

6*

Each of the two primary 4.16-kV in-station normal buses, 1NNS-SWG1A and 1NNS-SWG1B, can be energized via the dual secondaries of normal station service transformer 1STX-XNS1C. NNS-SWG1A can also be energized from preferred station transformer 1RTX-XSR1C and NNS-SWG1B can also be energized from preferred station transformer 1RTX-XSR1D. A third 4.16-kV in-station normal swing bus, 1NNS-SWG1C, is subordinate to one or the other of the above 4.16-kV normal buses.

7*

Two of the standby 4.16-kV buses, 1ENS*SWG1A and 1ENS*SWG1B, are connected to preferred station service transformers, 1RTX-XSR1C and 1RTX-XSR1D, respectively.

The standby 4.16-kV

bus, 1E22*S004, is normally connected to the 4.16-kV in-station normal swing bus 1NNS-SWG1C. Each of these standby buses has a standby diesel generator capable of supporting it upon loss of normal and preferred power. Switching allows each of the 4.16-kV standby buses to have access to one of the two 4.16-kV in-station normal buses while the 4.16-kV standby bus 1E22*S004 is subordinate to the 4.16-kV in-station swing bus 1NNS-SWG1C. The 4.16-kV standby buses serve redundant loads and are electrically isolated from each other.

RBS USAR Revision 20 8.1-5 8.1.5 Onsite DC Systems

6 The onsite dc power systems provide power for

control, instrumentation, indication, valve operators, solenoid valves, uninterruptible power supplies, and essential dc motors. There are three physically and electrically independent standby 125-V dc systems (including buses 1ENB*SWG01A, 1ENB*SWG01B, and 1E22*S001, which supply power to the standby diesel auxiliary loads) and seven normal 125-V dc systems, including buses 1BYS-SWG01A, 1BYS-SWG01B, and 1IHS-SWG01D, and 125 VDC panels 1BYS-PNL01, 1BYS-PNL04, 1BYS-PNL06, and 1BXY-PNL01 which supply power to nonsafety-related loads as shown on Fig. 8.3-6.

6

8.1.6 Identification of Safety-Related Systems 8.1.6.1 System Functions Sections 8.3.1.1.2.1 and 8.3.1.3, and Table 8.3-1 identify safety-related systems and their functions.

8.1.6.2 Power Supply Sources Power supply sources to safety-related systems, as shown in Fig. 8.1-4, consist of the main generator through one three-winding normal station service transformer, the two redundant offsite 230-kV transmission lines through two preferred station service transformers, two standby ac diesel generators, and a high pressure core spray (HPCS) ac diesel generator. Standby power is not connected to or influenced by the 13.8-kV system.

13 Each of the three diesel generators 1EGS*EG1A, 1EGS*EG1B, and 1E22*S001G1C is connected to 4.16-kV standby buses 1ENS*SWG1A, 1ENS*SWG1B, and 1E22*S004, respectively. Electric power to the safety-related systems from the normal and preferred station service transformers is supplied as follows.

The dual secondaries of normal station service transformer 1STX-XNS1C can be connected to two normal 4.16-kV buses 1NNS-SWG1A and 1NNS-SWG1B through normally open breakers. The two normal 4.16-kV buses are connected to the preferred station service transformers through normally closed breakers. The normal 4.16-kV swing bus 1NNS-SWG1C is subordinate to one or the other of the above normal 4.16-kV buses. The normal 4.16-kV bus 1NNS-SWG1A has a normally open tie to standby 4.16-kV bus 1ENS*SWG1B at the standby bus.

Normal 4.16-kV bus 1NNS-SWG1B has a normally open tie to standby 4.16-kV bus 1ENS*SWG1A at the standby bus. Normal 4.16-kV swing bus 1NNS-SWG1C has two 4.16-kV sources of power from either normal 4.16-kV bus 1NNS-SWG1B or normal 4.16-kV bus 1NNS-SWG1A which is controlled by station operating procedure. Normal 4.16-kV 13

RBS USAR 8.1-6 August 1987 swing bus 1NNS-SWG1C has a 4.16-kV tie to standby bus 1E22*S004.

Standby 4.16-kV buses 1ENS*SWG1A and 1ENS*SWG1B are energized from the preferred station service transformers at all times via normally closed switchgear circuit breakers connected to the secondaries of the preferred station service transformers.

8.1.7 Identification of Safety Criteria 8.1.7.1 General Functional Design Basis Chapter 3 outlines the general engineering criteria for nuclear plant design and delineates several areas of general classification and/or conformance which are applicable to the electrical power systems and equipment. Further clarification of some specific standards and criteria related to electrical systems is given in Chapter 7. Section 7.1.2 outlines various standards and criteria for systems which may include electrical functions similar to electrical power systems.

Specific requirements for electrical power systems and equipment are given in the following paragraphs.

8.1.7.2 Design Basis General Design Criteria The conformance discussion provided in Section 3.1 for the General Design Criteria (GDC) applies to the electrical systems in Chapter 8, as identified in Table 8.1-2.

Branch Technical Positions The conformance discussion for the Branch Technical Positions (BTPs) is referenced in Table 8.1-3.

USNRC Regulatory Guides The following Regulatory Guides are specifically cited as applying to the safety-related electrical power systems and equipment. Safety-related systems and equipment are designed in accordance with the referenced Regulatory Guides as described in Section 1.8.

RBS USAR 8.1-7 August 1987 Regulatory Guide Title 1.6 Independence Between Redundant Standby (Onsite)

Power Sources and Between their Distribution Systems 1.9 Selection, Design and Qualification of Diesel-Generator Units Used as Standby (Onsite) Electric Power Systems at Nuclear Power Plants 1.22 Periodic Testing of Protection System Actuation Functions 1.29 Seismic Design Classification 1.30 Quality Assurance Requirements for the Installation, Inspection, and Testing of Instrumentation and Electric Equipment 1.32 Criteria for Electric Power Systems for Nuclear Safety-Related Power Plants 1.40 Qualification Tests of Continuous-Duty Motors Installed Inside the Containment of Water-Cooled Nuclear Power Plant 1.41 Preoperational Testing of Redundant Onsite Electric Power Systems to Verify Proper Load Group Assignments 1.47 Bypassed and Inoperable Status Indication for Nuclear Power Plant Safety Systems 1.53 Application of Single Failure Criterion to Nuclear Power Plant Protection Systems 1.62 Manual Initiation of Protective Action 1.63 Electric Penetration Assemblies in Containment Structures for Light-Water-Cooled Nuclear Power Plants 1.68 Initial Test Programs for Water-Cooled Nuclear Power Plants

RBS USAR 8.1-8 August 1987 Regulatory Guide Title 1.70 Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants 1.73 Qualification Tests of Electric Valve Operators Installed Inside the Containment of Nuclear Power Plants 1.75 Physical Independence of Electric Systems 1.81 Shared Emergency and Shutdown Electric Systems for Multi-Unit Nuclear Power Plants 1.89 Qualification of Class 1E Equipment for Nuclear Power Plants 1.93 Availability of Electric Power Sources 1.100 Seismic Qualification of Electric Equipment for Nuclear Power Plants 1.106 Thermal Overload Protection for Electric Motors on Motor-Operated Valves 1.108 Periodic Testing of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants 1.118 Periodic Testing of Electric Power and Protection Systems 1.120 Fire Protection Guidelines for Nuclear Power Plants 1.128 Installation Design and Installation of Large Lead Storage Batteries for Nuclear Power Plants 1.129 Maintenance, Testing, and Replacement of Large Lead Storage Batteries for Nuclear Power Plants

RBS USAR



  • Applies to Division III HPCS diesel generator only.

8.1-9 August 1987 Regulatory Guide Title 1.131 Qualification Test of Electric Cables, Field Splices, and Connections for Light-Water-Cooled Nuclear Power Plants IEEE Standards Electrical power systems and equipment comply with the following standards of the Institute of Electrical and Electronics Engineers (IEEE):

IEEE Standard Title 279-1971 Criterion for Protection Systems for Nuclear Power Generating Stations 308-1974 Criteria for Class 1E Electric Systems Nuclear 1971*

Power Generating Stations 317-1976 Electrical Penetration Assemblies in Containment Structures for Nuclear Fueled Power Generating Stations 323-1974**

General Guide for Qualifying Class I Electrical Equipment for Nuclear Powered Generating Stations 334-1974 Type Test of Continuous Duty Class 1E Motors for Nuclear-Power Generating Stations 336-1971 Installation, Inspection, and Testing Requirements for Instrumentation and Requirements for Instrumentation and Electric Equipment During the Construction of Nuclear Power Generating Stations 338-1977 Criteria for the Periodic Testing of Nuclear 1971*

Power Generating Station Protection Systems

RBS USAR



  • Applies to Division III HPCS diesel generator only.

8.1-10 August 1987 IEEE Standard Title 344-1975**

Seismic Qualification of Class I

Electric Equipment for Nuclear Power Generating Stations 379-1977 Trial Use Guide for the Application of the Single 1972*

Failure Criterion to Nuclear Power Generating Station Protection Systems 382-1972 Trial-Use Guide for the Type Test of Class I Electric Valve Operators for Nuclear Power Generating Stations 383-1974 Type Test of Class 1E Electric Cable Field

Splices, and Connections for Nuclear Power Generating Station 384-1974 Criteria for Separation of Class 1E Equipment and Circuits 387-1977 Criteria for Diesel-Generator Units Applied as 1972*

Standby Power Supplies for Nuclear Power Generating Stations 415-1976 Planning of Preoperational Testing Programs for Class 1E Power Systems for Nuclear Power Generating Stations 420-1973 Trial Use Guide for Class 1E Control Switchboards for Nuclear Power Generating Stations 450-1975 Recommended Practice for Maintenance, Testing, and Replacement of Large Stationary Type Power Plant and Substation Lead Storage Batteries 484-1975 Installation Design and Installation of Large Lead Storage Batteries for Generating Stations and Substations

RBS USAR 8.1-11 August 1987 Additional Standards Relevant standards, codes, etc, are referenced in text whenever special considerations warrant.

These are not generally applicable to electrical power systems and are not listed here.

RBS USAR Revision 22 8.2-1 8.2 OFFSITE POWER SYSTEM 8.2.1 Description 8.2.1.1 Transmission System and Switchyard

  • 16 *7 The offsite power system is designed to provide reliable and redundant sources of power for starting, operation, and safe shutdown of Unit 1 in accordance with General Design Criterion (GDC)

No. 17, Electric Power Systems (Table 8.1-2 and Section 3.1.2.17) and GDC No. 18, Inspection and Testing of Electric Power Systems. The offsite power system is shown in the following figures:

7* 16*

1.

Fig. 8.1-1 December 31, 1985, Utility Grid

2.

Fig. 8.1-3 January 1, 1987, Power Pool Map

3.

Fig. 8.1-4 Fancy Point Substation - 230-kV Bays and Peripheral Loads

4.

Fig. 8.1-5 Fancy Point Substation - 230-kV Bays

5.

Fig. 8.1-6 Station Service - One Line Diagram

6.

Fig. 8.1-7 Fancy Point Substation - 500-kV Bays

7.

Fig. 8.2-1 Transmission Towers to 230-kV Switchyard from the Station

8.

Fig. 8.2-2 Connection of Onsite 13.8-kV and 4.16-kV Distribution System to the Preferred Power Supply

9.

Fig. 8.2-3 Transmission System

10.

Figs. 8.2-4 Transmission Route Segments through 8.2-35

11.

Fig. 8.2-36 Fancy Point 500-kV and 230-kV Switchyard One-Line Diagram 8.2.1.1.1 230/500-kV Switchyard The 230-kV bays of the substation, Fig. 8.1-4 and 8.1-5, consist of two buses and positions for thirty 230-kV circuit breakers (OCB) in a breaker-and-a-half scheme, with each of the two buses being capable of carrying the total connected load. Voltage on the bus is a nominal 230 kV, with a maximum rating of 242 kV and a minimum rating of 224.25 kV. There are three 230-kV lines serving Unit 1 along the right-of-way shown in Fig. 8.2-1, and one line connecting the 230-kV bays to the 500-kV bays via transformers.

The 230-kV tie to the 500-kV switchyard consists of one 230-kV line of one span, strung between the transformer bay steel and the associated A-frame structure in the 230-kV switchyard. These 230-kV leads connect the 230-kV bays to a

RBS USAR Revision 19 8.2-2

15 bank of three single phase stepup transformers at the 500-kV bays. The 500-kV bays of the substation, Fig. 8.1-7, consists of two buses and positions for six 500-kV gas circuit breakers (GCB) in a folded breaker-and-a-half configuration. The two-bus 500-kV bays located on the northwest side of and adjacent to the 230-kV bays are initially constructed as a three-breaker ring bus and are to be developed into a breaker-and-a-half scheme with the installation of future power plant units. Each bus is capable of carrying the total connected load.

15

16 The two 230-kV lines previously described in Section 8.1 provide two physically and electrically independent sources of offsite power to the preferred station service transformers at the station from the 230-kV bay of the Fancy Point Substation.

The 230-kV bays are constructed with rigid aluminum tubing supported on insulators and galvanized steel towers and pedestals. The breakers are 230-kV dead tank, circuit breakers, using the breaker-and-a-half scheme. The layout of the 230-kV bays of the substation is shown in Fig. 8.1-5. The buses are constructed at 17-ft and 29-ft heights above ground. The buses are designed to withstand a maximum fault on any section with Unit 1 operating. This is the maximum force-loading to which the buses are expected to be subjected. Similar designs have been used in the past and have proven to be adequate under all electrical fault and environmental conditions. The breaker-and-a-half design provides for the isolation of any faulted line without affecting the operation of any other line. This scheme also provides for the isolation of any one breaker in the 230-kV bus for inspection or maintenance without affecting the operation of any of the connecting lines or any other connection to the buses. The buses have adequate capacity to carry their loads under any postulated switching sequences. The design provides for the isolation of any breaker connecting Unit 1 to the switchyard buses without limiting the operation of any line connecting to the 230-kV power grid. Either 230-kV offsite source circuit breaker can be isolated, inspected, and maintained as needed without affecting any line or unit input. Either of the 230-kV offsite source lines can be taken out of service for inspection or maintenance without jeopardizing the operation of the other 230-kV source of offsite power.

16

RBS USAR Revision 25 8.2-3 A fault of any section of the 230-kV bus is cleared by the adjacent breakers and does not interrupt operation of any of the remaining parts of the 230-kV switchyard bus. Only that element connected to the faulted section is interrupted.

The 500-kV bays of the substation are located northwest of and adjacent to the 230-kV bays and are constructed of SF6 components. The 500-kV bays are arranged in a folded breaker-and-a-half scheme, consisting of six 500-kV GCB positions. The initial installation for Unit 1 consists of three circuit breakers and three 500-kV lines in a ring bus configuration.

Fig.

8.1-7 illustrates the initial and final 500-kV configurations. There are two separate SF6 charging systems for the 500-kV bays: one to serve the 500-kV SF6 circuit breakers, and one to serve the 500-kV SF6 buses, disconnecting switches, and air bushings. The initial ring bus configuration provides for the isolation of any faulted line without affecting the operation of any other line. It also provides for the isolation of any one breaker in the 500-kV SF6 bus for inspection or maintenance without affecting the operation of any of the connecting lines or any other connections to the buses. The 500-kv buses terminate at the 500-kv SF6 air bushings. Connections are made to the 500-kV grid and to the 230-500-kV transformers via air-insulated, outdoor-constructed bus work and overhead lines from these air bushings.

7 The ac auxiliary power requirements of the 230-kV and 500-kV bays are provided by two 750-kVA, 13.8-kV to 480-V oil-filled transformers supplied from onsite 13.8-kV buses 1NPS-SWG1A and 1NPS-SWG1B.

7 The dc requirements for the Fancy Point Substation relay and control systems are provided by two 125-V batteries. Each battery system is supported by its own charger which is provided power from the auxiliary ac power system and by an existing source external to River Bend Station.

RBS USAR Revision 25 8.2-4 16 Control functions between the plant and the substation are provided by two diverse methods. Control cables are routed in a concrete-encased duct bank to the substation control house. Routing within the substation between the various relay panels and control equipment is accomplished via a protected cable trench. An optic cable underbuilt on the reserve station service steel pole lines provides another diverse method of transmitting control functions and information between the plant and substation. The optical information is decoded at the substation and forwarded to the appropriate piece of equipment via control cables routed in a cable trench or raceway that is physically separated by 5 ft or more from the other trench or raceway described herein. The routing separation is maintained over the route length except at termination points where the cables route to the same piece of equipment.

16 The 125-V battery system furnishes the control power for circuit breakers in both the 500-kV and 230-kV switchyard bays. A complete loss of both 125-V battery systems, including the battery charger, prevents the operation of all circuit breakers in the switchyard.

The loss of the battery system in conjunction with a fault in the switchyard or any incoming line would require the operation of backup relaying elsewhere within the grid to clear the fault.

Offsite power will be manually restored by isolating one of the reserve station service lines to an unfaulted line in the event of severe battery damage. The estimated time to perform the subject operation is 15 min after personnel arrive at the switchyard.

16 The battery systems are monitored remotely using a

SCADA (Supervisory Control and Data Acquisition) system which provides a low-voltage alarm to the Southwest-Transmission Operation Center (SWTOC) dispatcher in the event of malfunction. Additionally, the batteries receive a visual inspection weekly and a complete inspection for operability to manufacturer's specifications each 6 months.

The weekly inspection consists of checking the electrolyte levels, the battery voltage, and the charge rate. The 6-month inspection includes checking the voltage and specific gravity of each

cell, cleaning and retorquing the battery connectors, and if needed, the application of an equalize charge for about 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. A form containing each of the above-mentioned items is filled out for each inspection. Completed inspection forms are kept on file at the Baton Rouge Substation Department.

16 All 230-kV circuit breakers are equipped with two independent trip coils and breaker failure protection for redundant power circuit protection. All of the protective relay systems for the 230-kV bays are redundant. These systems are overlapping so that each high-voltage component is covered by at least two sets of protective relays. The primary and the backup relay systems are supplied from separate current inputs, separate dc circuits from each 125-V battery, and are connected to separate trip coils of

RBS USAR Revision 18 8.2-5 the power circuit breakers. Cross tripping between the trip coils is used. The potentials for the primary and backup relay systems associated with the three 230-kV lines serving Unit 1 are provided from one set of potential transformers on the north 230-kV bus (primary) or one set of potential transformers on the south 230-kV bus (alternate). A potential transfer scheme is provided between the primary potentials and the alternate potentials. The potentials for the primary and backup relay systems associated with the other 230-kV lines are provided from one set of coupling capacitor voltage transformers on each line terminal. The potentials for the 500 to 230-kV transformer backup relaying (230 kV) are provided from one set of coupling capacitors on the 230-kV side of the transformer.

The primary relay system for each of the three 230-kV lines serving Unit 1 is a pilot wire system over a primary pilot wire circuit. The backup relay system for each of the three 230-kV lines is a multiple-zone distance phase with directional overcurrent ground relay system over a backup pilot wire circuit.

Transfer tripping of switchyard breakers for in-plant relay operations uses either the primary or backup pilot wire circuits.

The redundant pilot wire circuits are monitored.

The primary relay system for each of the other 230-kV lines is a permissive, overreaching transfer trip system. The backup system for each of the other 230-kV lines is a three-zone distance phase and ground relay system that initiates local tripping.

16 The north and south 230-kV buses are protected with a primary restraint bus differential system and a backup restraint bus differential system.

16

The 500 to 230-kV transformer is protected on the 230-kV side by single-zone distance phase with directional overcurrent ground relaying that initiates local tripping.

All 500-kV circuit breakers are equipped with two independent trip coils and breaker-failure protection for redundant power circuit protection. All of the protective relay systems for the 500-kV bays are redundant. These systems are overlapping so that each switchyard high-voltage component is covered by at least two sets of protective

RBS USAR Revision 25 8.2-6 relays. The electromechanical backup relay system has separate current inputs and receives its power from one of the redundant 125-V battery systems. Cross tripping between the trip coils is used. The potentials for the primary and backup relay systems associated with the 500-kV lines are provided from one set of coupling capacitor voltage transformers on each line terminal.

The secondary potentials are separated into two systems of junction boxes in the switchyard and are treated as redundant systems from this point. The potentials for the 500 to 230-kV transformer backup relaying (500 kV) are provided from one set of bushing potential devices on the 500-kV side of the transformer.

The primary relay systems for the two 500-kV lines are: 1) phase comparison relaying over a CS26 power line carrier channel; and

2) directional comparison tripping with phase and ground distance relays using a frequency shift audio tone, modulated on a microwave channel. The backup relay system for the two 500-kV lines is a three-zone distance phase and ground relay system that initiates local tripping.

16 16 The primary relay system for the 500-kV line to the 500 to 230-kV transformer is a separate restraint bus differential system. The primary relay system for the 500 to 230-kV transformer is a separate restraint transformer differential system. The backup relay system (500 kV) for the 500 to 230-kV transformer is a single zone distance phase with directional overcurrent ground relaying that initiates local tripping.

RBS USAR Revision 19 8.2-7

16 The 230-kV and 500-kV circuit breakers can be operated either manually from the switchyard control house or remotely by either the Southwest-Transmission Operation Center dispatcher or the River Bend Station operator. Those remotely operable by the Southwest-Transmission Operation Center dispatcher are CBs 20650, 20660, 20735, 20740, 20745, 20765, 20770, and 20775. Those remotely operable by the River Bend Station operator are CBs 20610, 20620, 20635, 20640, 20670, and 20665.

The 500-kV circuit breakers have compressed air actuated mechanisms with stored capacity for three open and three close operations. The operations are contingent upon normal auxiliary power to the breaker during the 30 min preceding the initial operation. Switching operations from local stations upon loss of control or motive power require that the trip or close lever located directly on the GCB control cabinet be manually operated.

16

A mimic board of the Fancy Point Substation is located in the main control room to provide remote breaker status indication.

Physical separation of the offsite power sources to include the 230-kV bays through the preferred station transformers of the onsite Class 1E power system is maintained for all credible events.

The offsite power sources are non-Class 1E with all equipment manufactured to the accepted industrial standards. This design is considered to meet the requirements of GDC 1 as evoked for the offsite (preferred) power system.

In satisfaction of GDC 3, the two offsite power systems have either spatial separation or totally enclosed raceways over their entire length.

In satisfaction of GDC 4, the two offsite power sources are routed in such a manner as to permit continuous operation of one 230-kV offsite power line during a malfunction of the second 230-kV line.

8.2.1.1.2 Transmission System River Bend Station is connected to GSU's load demand area by a system of 230-kV and 500-kV overhead transmission lines. These lines were installed and erected from the River Bend Station's Fancy Point Substation to the Webre Substation,

RBS USAR 8.2-8 August 1987 Jaguar Bulk Substation, and McKnight Switching Station via three physically separate rights-of-way.

These three rights-of-way, designated Routes I, II, and III, provide the means to integrate River Bend Station into the existing GSU electrical system. Electric output from the station is transmitted to the electrical system via these three routes during normal plant operation.

Route I runs west from the Fancy Point Substation to the Big Cajun No. 2 Power Station switchyard and continues south to Webre Substation near Rosedale, Louisiana. Route I is 29.20 mi long.

Route II, 23.75 mi long, runs southeast and south from the Fancy Point Substation to the Jaguar Bulk Substation in Scotlandville, Louisiana.

Route III runs 27.20 mi east from the Fancy Point Substation to Point U, the McKnight Switching Station in McKnight, Louisiana.

The three transmission line routes are scheduled for completion as follows:

Route I - November 1980 (completed)

Route II - May 1981 (completed)

Route III - July 1983 (completed)

These transmission line routes are illustrated in Fig. 8.2-3.

There are no crossovers of the 230-kV or 500-kV transmission lines at any point along the three rights-of-way.

The 230-kV transmission lines run from the 230-kV bays along Routes I and II, as follows:

1.

230-kV; Fancy Point Substation to Port Hudson, 2 lines (Route II)

2.

230-kV; Fancy Point Substation to

Enjay, 1 line (Route II)
3.

230-kV; Fancy Point Substation to Cajun Electric Power Cooperative, 1 line (Route II)

4.

Future line, 7 lines (Routes I and II)

RBS USAR 8.2-9 August 1987 As shown on Fig. 8.1-5, there are additional 230-kV transmission lines associated with future units.

All the new 230-kV lines are of the steel pole, H-frame structure design except that portion of Route II along Highway 19 which is a single-pole, steel, double-circuit structure. The 230-kV power conductors primarily consist of two conductor bundles of 649.5 kCMIL aluminum conductor, alloy reinforced (ACAR), cable spaced 45.7 cm (18 in) on center, with a nominal power capacity of 750 MVA. The 230-kV lines 351 and 352, from the Fancy Point Substation to the Jaguar Bulk Substation, utilize two 1,650 kCMIL ACAR cables per phase with a nominal power capacity of 1,200 MVA.

The minimum design phase-to-phase spacing on the 230-kV transmission line system is 4.9 m (16 ft). Two static lines are provided on each 230-kV transmission tower and consist of 5/16-in extra high strength (EHS) steel cable.

The 500-kV transmission lines run from the 500-kV bays along Routes I and III as follows:

1.

500-kV; Fancy Point Substation to McKnight Substation, 1 line (Route III)

2.

500-kV; Fancy Point Substation to Big Cajun No. 2, 1 line (Route I)

3.

500-kV; Fancy Point Substation to 500-kV/230-kV transformers, 2 lines

4.

Future lines, 4 lines All 500-kV transmission lines are of the steel, lattice-type design.

Two configurations of power conductors are used at the 500-kV level. Three conductor bundles of 1,024.5 kCMIL ACAR per phase spaced 45.7 cm (18 in) on center are used along Routes I and III with a nominal power capacity of 2,500 MVA. The Route I Mississippi River crossing utilizes one 3,075 kCMIL aluminum conductor steel reinforced (ACSR) cable per phase with a nominal power capacity of 2,500 MVA. The minimum phase-to-phase spacing on the 500-kV transmission line system is 11.0 m (30 ft). Two 7/16-in EHS steel cable static lines are used on each 500-kV transmission tower, with the exception of the 19 static lines used on the Mississippi River crossing which are No. 9 alumoweld cables.

RBS USAR Revision 16 8.2-10 March 2003 All transmission lines of 230-kV and 500-kV associated with the Fancy Point Substation and River Bend Station are designed for medium loading conditions and high thunderstorm occurrence rate.

There are no unusual features of these lines. The terrain in the Gulf States system area is flat to gently sloping.

8.2.1.1.2.1 Route Descriptions Fig. 8.2-3 illustrates the three transmission line routes and identifies the route segments referenced below.

Route I Route I extends 29.2 mi from the Fancy Point Substation to the Webre Substation, and consists of lattice steel towers for 500-kV service with provisions for 230-kV underbuild lines, and steel pole H-frame 230-kV towers.

The 500-kV line 746 runs west from the switchyard to the Big Cajun No. 2 Power Station switchyard on twelve 500-kV lattice towers. From there, 500-kV line 745 proceeds south to the Webre Substation on 131 500-kV lattice towers with provisions for either one or two 230-kV underbuild circuits.

16 An existing 230-kV line 715 runs southwest to the Cajun Electric Power Company Substation near the False River cutoff, and from there to the Addis Substation with existing 230-kV line 731.

16

Segment A to B originates at the substation and continues south-southwest 1.07 mi. The segment shares the same right-of-way with the first part of Route II, and provides for seven 230-kV lines on four H-frame structures and one 500-kV line 746 on lattice steel towers with provisions for two 230-kV underbuild lines. The 500-kV line and four 230-kV lines on three H-frame structures are shown on Fig. 8.2-4. Facilities for the seven 230-kV lines and one 500-kV line were constructed in 1980.

Additional 230-kV lines will be installed at a later date when they are needed for additional capacity to support load growth in the Gulf States service area.

Segment B to C is 1.80 mi long and runs west to Point C, the Big Cajun No. 2 Power Plant switchyard. Since this segment crosses pasture land and water, different types of towers for 500-kV line 746 have been constructed. A typical tower is shown on Fig. 8.2-5.

RBS USAR 8.2-11 August 1987 From the switchyard at Big Cajun No. 2 (Point C) segment C to D of Route I extends 1.83 mi west and south to Point D carrying single circuit 500-kV line 745 (Fig. 8.2-6).

Segment D to E runs from Point D south and southeast to Point E.

The corridor is 7.22 mi long and runs parallel to an existing right-of-way. The right-of-way on this segment carries the one existing 230-kV line 731 constructed on 230-kV single circuit wood H-frame towers and the 500-kV line 745 with provisions for a future 230-kV underbuild line as shown on Fig. 8.2-7.

Segment E to F is 9.65 mi long and extends southwest and south parallel to existing rights-of-way. This right-of-way carries 500-kV line 745 with provisions for a future 230-kV underbuild line as shown on Fig. 8.2-8.

Segment F to G is 7.22 mi long and also runs parallel to an existing right-of-way. The 500-kV line 745 tower has provisions for two future 230-kV underbuild lines (Fig. 8.2-9 and 8.2-10).

Segment G to H of Route I is 0.41 mi long and extends south parallel to the Texas and Pacific Railroad terminating at Webre Substation, Point H. This segment carries the new 500-kV line 745 with provisions for two future 230-kV underbuild lines (Fig. 8.2-11).

Route II Route II extends 23.75 mi from the Fancy Point Substation to the Jaguar Bulk Substation and consists of 129 230-kV steel pole H-frame towers and 47 230-kV single steel pole towers for 230-kV lines 351, 352, and 354. Each tower has provisions for carrying two 230-kV circuits.

Line Route II begins at the substation, Point A, and runs southeast to Point Q, Jaguar Bulk Substation in Scotlandville, Louisiana. The total route length is 23.75 mi and is divided into 10 segments.

Segment A to B of Route II is shared with Segment A to B of Route I and has been previously discussed in this section.

Segment B to I is adjacent to an existing transmission corridor running south-southeast. The 0.71 mi segment has provisions for seven 230-kV lines on four H-frame structures, an existing 69-kV and future 230-kV lines on a fifth H-frame structure (Fig. 8.2-12).

RBS USAR 8.2-12 August 1987 Segment I to J is 1.0 mi long. It runs northeast adjacent to an existing pipeline right-of-way and consists of five 230-kV lines and existing 69-kV line 723 on four H-frame structures (Fig. 8.2-13).

Segment J to K is 1.76 mi long. It begins at Point J and runs southeast to a point 0.19 mi south of Thompson Creek. This segment is divided into three sections (0.86 mi, 0.68 mi, and 0.19 mi) with tower configurations shown on Fig. 8.2-14 through 8.2-16. This segment accommodates four H-frame structures which carry existing 230-, 138-, 69-kV lines, and three future 230-kV lines.

Segment K to L of Route II is 2.75 mi long and is divided in two sections (Fig. 8.2-17 and 8.2-18).

Segment L to M runs for 4.2 mi south and west from Point L to Port Hudson Bulk Substation, Point M. This segment consists of two double circuit and one single circuit H-frame structures accommodating five 230-kV circuits (Fig. 8.2-19 through 8.2-24).

Segment M to N (Fig. 8.2-25) is 4.83 mi in length. The segment consists of two H-frame double circuit and one H-frame single circuit structures accommodating 69-kV line 700, 230-kV lines 352 and 712, future 230-kV line 353, and a future 138-kV or 230-kV line.

Segment N to O (Fig. 8.2-26) is 0.22 mi long and consists of one H-frame tower accommodating 230-kV line 352 and one future 230-kV line.

Segment O to P runs for 1.67 mi parallel to the right-of-way of the Illinois Central Gulf Railroad and State Highway 19. It accommodates one single-pole structure for 230-kV line 352 and one future 230-kV line (Fig. 8.2-27 and 8.2-28).

Segment P to Q is 5.68 mi long, runs parallel to the Illinois Central Gulf Railroad and State Highway 19, and terminates at Point Q, the Jaguar Bulk Substation.

The right-of-way accommodates 230-kV line 352, which becomes 230-kV line 351, and a future 230-kV line on a one-pole tower structure (Fig. 8.2-29 through 8.2-31).

Route III Route III extends 27.2 mi from the Fancy Point Substation to the McKnight Switching Station, and consists of an estimated 132 500-kV lattice steel towers accommodating 500-kV line

RBS USAR 8.2-13 August 1987 752. These towers can also accommodate either one or two 230-kV underbuild circuits.

Segment A to R starts at the substation and runs east-southeast 2.21 mi to Point R. The segment carries the 500-kV line 752 on a steel lattice tower with provisions for two future 230-kV underbuild lines (Fig. 8.2-32).

Segment R to S is 2.5 mi long, zigzagging northeast and east alongside of a

pipeline right-of-way.

The right-of-way accommodates the 500-kV line 752 with provisions for two future 230-kV underbuild lines (Fig. 8.2-33).

Segment S to T is 8.0 mi in length and consists of lattice steel towers accommodating 500-kV line 752 with provisions for the future addition of two 230-kV underbuild lines, as shown on Fig. 8.2-34.

Segment T to U is 14.51 mi long and follows a railroad right-of-way.

This segment consists of a

lattice steel tower accommodating 500-kV line 752 with provisions for the future addition of two 230-kV underbuild lines (Fig. 8.2-35).

8.2.1.1.3 Summary All features of the offsite power supply are designed to provide maximum practical reliability and redundancy in servicing the station safety load groups.

Compliance with GDC 17 is demonstrated by supplying the substation with offsite ac power by means of two 500-kV and four 230-kV physically independent circuits along two separate rights-of-way. Furthermore, the offsite power sources to the preferred station service transformers are then brought in by two physically independent circuits from this substation. Physical separation, the breaker-and-a-half switching configuration, redundant substation protection systems, and transmission system are designed on load flow and stability studies so as to minimize simultaneous failure of all offsite power sources.

8.2.1.2 Compliance with Design Criteria and Standards 8.2.1.2.1 General Design Criteria Criterion 17 The offsite power system conforms to the requirements of this criterion as follows.

RBS USAR Revision 16 8.2-14 March 2003 Two physically and electrically independent 230-kV circuits, providing two sources of power, are brought into the plant as shown in Fig. 8.1-4 and 8.2-2.

16 Either of the two 230-kV circuits provides sufficient offsite capacity and capability to ensure operation of all safety-related loads for the unit following a design basis accident with loss of normal (generator) power supply. With offsite power available, the standby 4.16-kV buses 1ENS*SWG1A and 1ENS*SWG1B are energized at all times, and are unaffected by loss of the normal (generator) power supply.

16

The normal 4.16-kV swing bus 1NNS-SWG1C, which has a normally closed tie to the standby 4.16-kV bus 1E22*S004, has access to the preferred sources via either normal 4.16-kV bus 1NNS-SWG1A or 1NNS-SWG1B upon loss of normal (generator) power supply.

8.2.1.2.2 Regulatory Guides Regulatory Guide 1.32 Conformance of the offsite power system with specific requirements delineated in Regulatory Guide 1.32 is as follows.

Two circuits from the transmission network are available to the safety systems. Offsite preferred power circuits are connected via normally closed breakers to standby 4.16-kV buses 1ENS*SWG1A and 1ENS*SWG1B at all times. Loss of normal plant auxiliary supply does not influence or affect the tie circuits of standby 4.16-kV buses 1ENS*SWG1A and 1ENS*SWG1B from the offsite sources.

16 Standby 4.16-kV bus 1E22*S004 is fed from NNS-SWGIC that can be fed from one of the two normal 4.16-kV buses INNS-SWG1A or INNS-SWG1B, which provides access (Section 8.3.1.1.3) to one of the offsite circuits (Fig. 8.1-4), via the preferred station service transformers, IRTX-XSRIC or IRTX-XSRID, respectively.

16

8.2.1.2.3 IEEE Standards IEEE Standard 308 The offsite power system conforms to the requirements of this standard (Fig. 8.1-3 and 8.1-4).

Requirements of Section 5.2.3 of IEEE Standard 308 are met by having two physically and electrically independent, and continuously available circuits from the transmission

RBS USAR Revision 8 8.2-15 August 1996 network to the Class 1E power system. Each of these circuits is capable of starting and operating all safety-related loads and is monitored in the main control room to verify its availability.

8.2.1.2.4 Additional Standards National Electrical Safety Code (NESC) - 1977 The offsite power system meets or exceeds the NESC requirements for a high density transmission system, Grade B.

8.2.1.3 Testing, Quality Assurance, and System Operability Surveillance Tests and Inspections The preoperational and initial startup test programs for the preferred power system is in accordance with Regulatory Guides 1.41 and 1.68 and GDC 1. The test program capabilities consider GDC 18 and 21 as discussed in Section 3.1.2.

During the preoperational stage, all components of the preferred power system are installed, tested, and inspected to demonstrate that all components are correct and properly mounted. All connections are verified as being correct and continuous, and all components as operational. All metering and protective devices are properly calibrated and adjusted. These tests are described in Section 14.

Following satisfactory checkout of all components of a system as previously described, the initial system tests are performed according to the technical specifications with all components installed. The initial system tests include operational tests conducted to demonstrate that the equipment operates within design limits and that the system is operational and meets its performance specifications.

8 The technical specifications/requirements include in-service test and surveillance requirements for the preferred power system following the preoperational and initial system tests and inspections. The particular tests and the frequency of these tests depend upon the specific components installed, their function and environment. These tests are directed at detecting deterioration of the system toward an unacceptable condition and demonstrating that standby components are operable.

8

RBS USAR Revision 16 8.2-16 March 2003 Circuit breakers and associated devices can be tested when their associated loads or systems are shut down or not in service.

Protective relays are tested under a simulated overload or fault condition, and their calibration is verified. The breaker opening and closing can also be demonstrated. Availability of power is indicated by breaker position lights.

The capability of the preferred power system to transmit sufficient energy to start and operate all required safety-related loads is confirmed during periodic tests.

These tests also confirm the capability of the supply breakers to operate and transmit the required energy upon receipt of a control input.

These tests are performed at scheduled intervals and verify the ability of the preferred power system to furnish electrical energy for the shutdown of the plant and for the operation of safety-related systems and engineered safety features.

Quality Assurance Quality Assurance for the offsite power system is based on industry standards applicable to normal systems.

It considers IEEE 336 and Regulatory Guide 1.30, where applicable, to non-Class 1E systems, to meet GDC 1 for equipment requirements.

System Operability Surveillance

16 Surveillance and status of the offsite power system operability are provided by automatic system indication in the main control room. A panel located in front of the principal plant control console provides a positive indication of breaker positions for the offsite switchyard. Inoperability of offsite power supplies either by event or deliberate action is annunciated to alert main control room operators to anomalies on the system grid.

Additionally, main control room operators have voice communication systems to contact the Southwest-Transmission Operation Center to ascertain system grid status.

16

Offsite Power System Monitoring and Surveillance

5 The transmission lines of GSU are inspected periodically by aerial patrol.

5

RBS USAR 8.2-17 August 1987 Routine maintenance of substation batteries includes a weekly visual inspection of charge rate and voltage level and a quarterly test of the batteries' ability to maintain voltage under normal station load.

Routine maintenance on power circuit breakers is performed as required to verify that all design criteria for operation are not exceeded.

Control and protective breakers are separated to the maximum extent possible to ensure that failure of any item does not impair system protection.

8.2.2 Analysis 8.2.2.1 Availability Considerations The 500-kV and 230-kV transmission lines and their associated structures, interconnecting the substation with the system, are designed to withstand the environmental loading conditions for the area with regard to wind, temperature, lightning, and flooding.

The transmission lines approach the substation on separate rights-of-way on the southeast and southwest sides of the substation. Due to this separation, failure of one line on one right-of-way does not cause failure of another line on the second right-of-way.

Two independent and redundant transmission lines are provided as offsite power sources for the power plant safety load groups which, as shown in Section 8.3, remain independent down to the lowest voltage level of distribution. These 230-kV sources supply the two 4.16-kV preferred transformers as shown in Fig. 8.1-6.

The 230-kV bays have a breaker-and-a-half configuration with breaker failure backup protection. Substation reliability and operating flexibility are achieved as follows:

1.

Any transmission line can be cleared under normal or fault conditions without affecting any other transmission line.

2.

Any system circuit breaker can be isolated for maintenance without interrupting the power or protection to any circuit.

RBS USAR Revision 16 8.2-18 March 2003

3.

Short circuits on a section of a bus are isolated without interrupting service to any circuit other than that connected to the faulted bus section.

The two independent circuits from the substation to the preferred transformers are routed separately as shown in Fig. 8.2-1. Due to this separation, a failure of one circuit does not cause the failure of the other circuit. Therefore, these two circuits provide separate and redundant sources to safety load groups.

While it is improbable that all transmission lines could be out of service simultaneously, such an event would not jeopardize a safe shutdown of the station because the onsite standby diesel generators would be able to supply the necessary power to systems required for safe shutdown or LOCA. The onsite power system, including automatic startup and load sequencing, is described in Section 8.3.

16 With any single line in service under its design condition of operation, sufficient offsite power would be available to handle a LOCA and safe shutdown of the unit.

16

Outage data on the 230-kV and 500-kV lines in GSU transmission of current experience is given in Tables 8.2-1, 8.2-2, 8.2-4, and 8.2-5.

8.2.2.2 Stability Considerations The design and operation of interconnected power systems must be such that they remain stable following severe faults. This is essential to avoid widespread or cascading interruptions to service, and requires that various stability studies be carried out using mathematical models for the components of electrical power systems.

11 A transient stability study (analysis of conditions within 1 sec after the fault) in compliance with the criteria of the Southwest Power Pool Coordination Council, which is comparable with Southeastern Electric Reliability Council criteria, was performed on River Bend Station Unit 1 using the 1984 summer peak as the base case. The generators were represented as constant voltages behind transient reactance, with no exciter-regulator and no turbine governor, so that conservative results were obtained.

Studies have also been performed (including consideration of regulation, excitation, and governor action) which verify that the system is dynamically stable.

Stability of the interconnected utilities, when Unit 1 goes

online, was investigated under the following conditions:

11

RBS USAR 8.2-19 August 1987

1.

Three-phase fault on GSU's Fancy Point Substation 230-kV bus, with a subsequent clearing of the fault in 6 cycles and tripping of River Bend Station Unit 1.

2.

Three-phase fault on CEPCO's Big Cajun 500-kV bus, with a subsequent clearing of the fault in 4.5 cycles and tripping of Big Cajun Unit No. 3.

3.

Three-phase fault on Grand Gulf Nuclear Station 500-kV bus, with a subsequent clearing of the fault in 4.5 cycles and tripping of Grand Gulf Unit No. 2 (1,250 MW).

4.

Three-phase fault on Arkansas Nuclear One 500-kV bus, with a subsequent clearing of the fault in 4.5 cycles and tripping of Arkansas Nuclear One Unit No. 2 (950 MW).

5.

Three-phase fault on Tennessee Valley Authority's Brown's Ferry Station 500-kV bus, with a subsequent clearing of the fault in 4.5 cycles and tripping of Brown's Ferry Station Unit No. 3 (1,050 MW).

6.

Three-phase fault on GSU's Willow Glen 230-kV bus, with a subsequent clearing of the fault in 6 cycles and tripping of Willow Glen Unit No. 4 (540 MW).

7.

Three-phase fault on the 230-kV line from the Fancy Point Substation to Enjay at the River Bend Station end, with a subsequent opening of the line at both ends in 6 cycles.

8.

Three-phase fault on the 230-kV line from the Fancy Point Substation to Port Hudson at the River Bend Station end, with a subsequent opening of the line at both ends in 6 cycles.

9.

Three-phase fault on the 230-kV line from the Fancy Point Substation to Cajun No. 1 at the River Bend Station end, with a subsequent clearing of the line at both ends in 6 cycles.

10. Three-phase fault on the 500-kV line from the Fancy Point Substation to Big Cajun at the River Bend Station end, with a subsequent clearing of the line at both ends in 4 cycles.
11. Three-phase fault on the 500-kV line from the Fancy Point Substation to McKnight at the River Bend

RBS USAR 8.2-20 August 1987 Station end, with a subsequent clearing of the line at both ends in 4 cycles.

12. Three-phase fault on the 230-kV line from the Fancy Point Substation to Enjay at the River Bend Station end, with a subsequent clearing of the Enjay end in 6 cycles and the Fancy Point Substation end in 12 cycles (stuck breaker).
13. Three-phase fault on the 230-kV line from the Fancy Point Substation to Port Hudson at the River Bend Station end, with a subsequent clearing of the Port Hudson end in 6 cycles and the River Bend Station end in 12 cycles (stuck breaker).
14. Three-phase fault on GSU's Enjay 230-kV bus, with a subsequent clearing of the fault in 6 cycles and tripping of 160 MW of load.
15. Three-phase fault on GSU's Esso 230-kV bus, with a subsequent clearing of the fault in 6 cycles and tripping of 350 MW of load.

The listed cases are conservative with respect to other unlisted less severe faults. Therefore a fault of any kind (loss of the River Bend Station Unit 1, loss of critical loads, loss of EHV transmission lines, or loss of a large unit inside GSU's system as well as neighboring systems) with successful clearing does not cause system instability or result in loss of offsite power to safety-related systems. In addition, load flow contingency analyses (Table 8.2-3) show that any line or 500 to 230-kV transformer outage in the Fancy Point Substation does not result in loss of offsite power supply.

Physical separation of the 230-kV offsite power sources, substation protection, redundancy, and transmission system design based on load flow and stability analysis minimizes the possibility of simultaneous failure of power sources (normal station service supply, preferred station service supply, and standby ac diesel generators).

This complies with the last paragraph of GDC 17.

RBS USAR 8.3-1 August 1987 8.3 ONSITE POWER SYSTEMS 8.3.1 AC Power Systems 8.3.1.1 Description 8.3.1.1.1 General The onsite ac power systems for River Bend Station are those systems which include electrical equipment and connections required to distribute power to station auxiliaries and service loads during all modes of plant operation.

Their objective is to provide reliable ac power required during a

normal

startup, operation, and shutdown, or during an emergency shutdown.

The ac power system must have adequate independence, redundancy, capacity, and testability to ensure its capability for performing the functions required of the engineered safety features (ESF) and other reactor protection systems.

The onsite electrical power systems (Fig. 8.1-4, 8.1-6, 8.3-1, and 8.3-2) extend from the onsite termination of incoming lines up to and including the electrical power utilization devices.

These consist of power sources (network interconnections, onsite standby power sources and their auxiliaries, uninterruptible power

sources, and battery systems),

distribution equipment (transformers, circuit

breakers, buses, and interconnecting cables),

instrumentation and controls (surveillance instrumentation, protective circuitry, and control circuitry),

and utilization devices (motors, solenoids, and heaters).

The physical arrangement of the onsite electrical safety systems is designed to preserve the independence of redundant ESFs.

Physical separation, achieved by distance or

barriers, is provided between similar components of redundant electrical systems.

In addition, separation is provided between redundant

power, instrumentation, and control circuitry serving or being served from these components.

The safety-related electrical systems are physically independent and are located within Seismic Category I structures or portions of structures designed to meet Seismic Category I criteria.

The continuity and integrity of load functions are maintained by redundant equipment supplied from separate sources via separate cable, cable tray, and conduit systems.

Transformers are sized for anticipated maximum normal load plus those normal loads which may be transferred to them by

RBS USAR 8.3-2 August 1987 the swing-bus or sections of split-bus unit substation load centers, by closure of the tie breakers.

These transformers are not intended to support total connected load.

Motors are sized to carry full load without encroachment on the service factor margin, and "run out" overloads, such as those caused by breaks in pipes downstream from

pumps, without exceeding the service factor load.

The diesel generators are sized to accept full standby requirements and to ensure frequency and voltage stability during starting periods in accordance with Regulatory Guide 1.9, except for the HPCS diesel which is described in Section 8.3.1.2.2.2.

Motors are sized for anticipated maximum load at a

given speed with consideration given to torque requirements. Motor insulation is chosen by taking into consideration the environment in which the motor is to operate.

These considerations include but are not limited to ambient temperature,

humidity, radiation
level, seismic requirements, and voltage level of operation.

The interrupting capacity of switchgear, load

centers, motor control centers, and distribution panels is based upon studies of the electrical system.

These studies consider, as a minimum, the size of the connected load, motor starting load, motor starting

current, and system and connected load contributions under faulted conditions.

8.3.1.1.2 Systems Identification 8.3.1.1.2.1 Safety-Related Systems and Identification These Class 1E ac power systems of the nuclear plant provide functions associated with mitigating the effects of accidents or providing for safe plant shutdown.

These systems are divided into three physically and electrically independent divisions which are identified by distinct means.

The three divisions are identified as follows:

Division I

- Red Division II

- Blue Division III - Orange See Section 8.3.1.3 for additional identification of these safety-related divisions.

The Class 1E ac power system divisions and their associated standby switchgears and load centers are delineated in Fig. 8.1-4 and 8.1-6.

RBS USAR 8.3-3 August 1987 These systems

include, but are not necessarily limited to, the following:

1.

Emergency core cooling systems (ECCS) 2.

Standby service water (SSW) system 3.

Standby gas treatment system (SGTS) 4.

Cooling systems a.

Main control room air-conditioning b.

Standby switchgear and standby battery rooms ventilation and cooling c.

Safeguard equipment in the auxiliary building ventilation d.

Standby diesel generator rooms ventilation 5.

Containment and reactor vessel isolation control system (CRVICS) 6.

Standby lighting system 7.

Instrumentation and control for the RPS and ESF functions.

Loads connected to these Class 1E safety-related systems are listed in Table 8.3-1.

8.3.1.1.2.2 Nonsafety-Related Power Generation Systems These systems of the nuclear plant are those which are not essential for safe shutdown.

Electrical failure of these systems cannot result in the release or failure to minimize release of radioactive material.

These normal non-Class 1E ac systems are nonsafety-related and therefore nondivisional.

They are identified as being part of the black system or are not given color identification as described in Section 8.3.1.3.

These systems

include, but are not necessarily limited to, the following:

1.

Main condensate system 2.

Reactor feedwater system 3.

Condensate makeup system

RBS USAR Revision 22 8.3-4

6

4.

Turbine plant component cooling water system

5.

Reactor plant component cooling water system

6.

Plant ventilation system

7.

Normal service water system

8.

Circulating water system

9.

Reactor water cleanup system

10.

Service water cooling system.

6

8.3.1.1.3 Power Supplies and Buses 8.3.1.1.3.1 Station Service Transformers

13 7 The normal ac power supply can provide electrical power for all station auxiliary loads when the main generator is operating. It consists of three normal station service transformers 1STX-XNS1A, 1STX-XNS1B and 1STX-XNS1C, electric power through STX-XNS1C is not used, energized by isolated phase bus duct from the generator terminals, as shown in Fig. 8.1-4.

13 6 4 The preferred ac power supply can provide for all station auxiliary loads.

This includes the maximum operational combination of full load power, startup power, hot standby maintenance power, shutdown power, and the safety-related loads.

Preferred power is taken from two physically and electrically independent 230-kV lines originating in the onsite 230-kV substation. The 230-kV line terminating at transformer yard 1 energizes transformers 1RTX-XSR1E and 1RTX-XSR1C. The 230-kV line terminating at the transformer yard 2A energizes transformers 1RTX-XSR1F and 1RTX-XSR1D. These preferred station service transformers have the following ratings:

7

1.

1RTX-XSR1E 230-13.8 KV, 51/68/85 MVA OA/FOA/FOA

2.

1RTX-XSR1F 230-13.8 kV, 51/68/85 MVA OA/FOA/FOA

3.

1RTX-XSR1C and 1RTX-XSR1D, 230-4.16 kV, 10/12.5 MVA, OA/FA 4 6

RBS USAR Revision 7 8.3-4a January 1995 The secondaries of normal and preferred station service transformers are routed into the plant via cables run in reinforced concrete ductlines and cable trays within the plant to their associated medium voltage switchgear buses as subsequently described.

7*

RBS USAR Revision 6 8.3-4b August 1993 THIS PAGE LEFT INTENTIONALLY BLANK

RBS USAR Revision 22 8.3-5 8.3.1.1.3.2 13.8-kV Systems (750-MVA Interrupting Capability)

7 6 4 RBS has two independent 13.8-kV buses, 1NPS-SWG1A and 1NPS-SWG1B, supporting most of the station auxiliary motor and transformer loads. Each bus supports half the load and has a manually controlled air circuit breaker (ACB) for access to its normal source transformers, 1STX-SNX1A and 1STX-XNS1B respectively, and an automatically or manually controlled ACB for access to its preferred source transformers 1RTX-XSR1E and 1RTX-XSR1F, respectively. The 13.8-kV bus 1NPS-SWG1A takes preferred power from transformer 1RTX-XSR1E located at transformer yard 1, while 13.8-kV bus 1NPS-SWG1B takes preferred power from transformer 1RTX-XSR1F located at transformer yard 2A.

4 6 7

Opening the normal supply breaker initiates closing the preferred supply breaker, subject to the following restrictions which prevent the breaker from closing:

1.

Overcurrent or ground fault trip of the normal breaker

2.

Manual trip of the normal breaker

3.

Loss of voltage of the preferred supply

4.

Preferred supply breaker locked-out.

7 A fast automatic transfer scheme and a slow automatic transfer scheme are provided. Unit protective relays initiate opening the normal supply breaker. Time delay contacts from the unit protective relays will block fast transfer if the transfer does not take place within 10 cycles. Manually opening the main generator output breakers at Fancy Point and/or from the Main Control Room will also block a fast transfer. If the fast transfer is unsuccessful, all motor breakers and normal supply breakers are automatically tripped. The slow transfer scheme is then initiated and permitted only when residual voltage on the bus reaches 25 percent or less of the rated voltage.

Return to the normal supply after an automatic throwover can only be done manually. Normal and preferred supply breakers are paralleled for a short period of time during manual throwover.

During manual throwover, the plant operator closes the normal supply breaker and immediately opens the preferred supply breaker. Closing both breakers alarms after a short time delay in the main control room.

7

RBS USAR Revision 20 8.3-6 Offsite power energizing standby 4.16-kV buses via the preferred station service transformers are not jeopardized during manual throwover.

Both the normal and preferred supply breakers to the normal 4.16-kV buses effectively isolate faults on the normal bus to protect the offsite sources of power to the standby 4.16-kV buses.

The 13.8-kV feeders from separate sources are routed to the following peripheral areas, as shown in Fig. 8.1-6:

1.

Cooling tower and water treatment areas - Four feeders, two on each 13.8-kV

bus, are used to service the six double-ended normal 480-V load centers.

Feeder 1NPS-ACB06 from 13.8-kV bus 1NPS-SWG1A provides power to two 1,000/1,150-kVA transformers, 1NJS-X2E and 1NJS-X2G, at cooling towers 1B and 1D and one 500-kVA transformer, 1NJS-X3A, at the clarifier area.

The second feeder 1NPS-ACB05, from 13.8-kV bus 1NPS-SWG1A provides power to two 1,000/1,150-kVA transformers, 1NJS-X2A and 1NJS-

X2C, at cooling towers 1A and 1C and one 750-kVA transformer 1NJS-X3C at the hypochlorite area.

Feeder 1NPS-ACB21 from 13.8-kV bus 1NPS-SWG1B provides power to two 1000/1150-kVA transformers, 1NJS-X2F and 1NJS-

X2H, at cooling towers 1B and 1D and one 500-kVA transformer, 1NJS-X3B, at the clarifier area.

The second feeder 1NPS-ACB22 from 13.8-kV bus 1NPS-SWG1B provides power to two 1000/1150-kVA transformers, 1NJS-X2B and 1NJS-X2D, at cooling towers 1A and 1C and one 750-kVA transformer, 1NJS-X3D, at the hypochlorite area.

2.

Circulating water pump area - Two 13.8-kV feeders, one from each 13.8-kV bus, provide power to a 4.16-kV split bus.

Feeder 1NPS-ACB07, from 13.8-kV bus 1NPS-SWG1A, provides power to 10/12.5-MVA transformer 1STX-XS2A which is connected to 4.16-kV bus 1NNS-SWG2A.

Bus 1NNS-SWG2A supports two circulating water pumps and two service water pumps.

The second feeder 1NPS-ACB23, from 13.8-kV bus 1NPS-SWG1B, provides power to 10/12.5-MVA transformer 1STX-XS2B which is connected to 4.16-kV bus 1NNS-SWG2B.

Bus 1NNS-SWG2B supports two circulating water pumps and one service water pump.

3.

The 230-kV and 500-kV switchyards and the makeup water intake structure -

Two 13.8-kV

feeders, one from each 13.8-kV
bus, provide power to the 230-kV and 500-kV switchyards and the river edge makeup

RBS USAR Revision 25 8.3-7 pumps. Feeder 1NPS-ACB10, from 13.8-kV bus 1NPS-SWG1A, is run to disconnecting switch 1YWC-SW2 at the switchyard where it is connected to a

750-kVA transformer, and then run to 2.5/3.125-MVA transformer 1STX-XS3A feeding 4.16-kV bus 1NNS-SWG3A, and 500-kVA transformer 1STX-XS4A feeding 480-V motor control center 1NHS-MCC12A. The second feeder 1NPS-ACB26, from 13.8-kV bus 1NPS-SWG1B, is run to disconnecting switch 1YWC-SW1 at the switchyard where it is connected to a 750-kVA transformer, and then run to 2.5/3.125-MVA transformer 1STX-XS3B feeding 4.16-kV bus 1NNS-SWG3B, and 288.5-kVA transformer 1STX-XS4B feeding 480-V motor control center 1NHS-MCC12B.

1 6

4.

Service Water Cooling Area - Two 13.8-kV feeders one each from 1NPS-SWG1C and 1NPS-SWG1D provide power to a 4.16-kV split bus. Feeder 1NPS-ACB43 from 1NPS-SWG1C provides power to 7.5 MVA OA transformer 1STX-XS5A which is connected to 1NNS-SWG6A. Bus 1NNS-SWG6A supports two service water cooling pumps and feeder to 1NJS-X4A. The second feeder 1NPS-ACB44 provides power to 7.5 MVA transformer 1STX-XS5B which is connected to 4.16-kV bus 1NNS-SWG6B. Bus 1NNS-SWG6B supports one service water cooling pump and feeder to 1NJS-X4B.

6 8.3.1.1.3.3 4.16-kV Systems (250-MVA Interrupting Capability) 13 7 Each of the two normal in-station 4.16-kV buses NNS-SWG1A and NNS-SWG1B are fed from either the normal station service transformer STX-XNS1C, which has dual secondary windings, one connected to each bus or from their associated preferred station service transformers, RTX-XSR1C and RTX-XSR1D, respectively. The above transformers have been sized for all load conditions on buses NNS-SWG1A and NNS-SWG1B.

13 For buses NNS-SWG1A, NNS-SWG1B, and NNS-SWG1C the control logic is identical to that described for buses NPS-SWG1A and NPS-SWG1B, except as noted below for bus NNS-SWG1C and the fast transfer is blocked on the NNS-SWG1A/B bus feeding bus NNS-SWG1C and E22-S004 when HPCS pump, E22-PC001, or the Division III standby service water pump, SWP-P2C, is running. For bus NNS-SWG1C only, a manual transfer capability is provided. When a sustained undervoltage on the bus is sensed, all motor circuit breakers are tripped. No automatic transfer of NNS-SWG1C alone is provided, it will fast transfer with NNS-SWG1A or NNS-SWG1B from the normal service transformer to the preferred station service transformer unless blocked as described above.

7

RBS USAR Revision 13 8.3-7a September 2000

  • 13 A 4.16-kV split bus and a 4.16-kV swing bus are energized from the normal 4.16-kV buses.

4.16-kV split buses 1NNS-SWG4A and 1NNS-SWG4B are connected to primary normal buses 1NNS-SWG1A and 1NNS-SWG1B, respectively.

4.16-kV swing bus 1NNS-SWG1C is connected to 1NNS-SWG1B via normally closed circuit breakers and to 1NNS-SWG1A via normally open circuit breakers.

13*

There are three standby 4.16-kV buses: 1ENS*SWG1A, 1ENS*SWG1B and 1E22*S004.

Buses 1ENS*SWG1A and 1ENS*SWG1B are energized from the preferred station service transformers 1RTX-XSR1C and 1RTX-XSR1D, respectively. Standby buses 1ENS*SWG1A and 1ENS*SWG1B also have manual

RBS USAR Revision 6 8.3-7b August 1993 THIS PAGE LEFT INTENTIONALLY BLANK

RBS USAR Revision 13 8.3-8 September 2000 access to normal primary buses 1NNS-SWG1B and 1NNS-SWG1A, respectively, if required during loss of preferred power. There is no automatic fast or slow transfer from the preferred transformers to the normal buses for either 1ENS*SWG1A or 1ENS*SWG1B.

The third standby 4.16-kV bus 1E22*S004 is energized from the normal 4.16-kV swing bus 1NNS-SWG1C.

7* *13 Each of these standby 4.16-kV buses has a standby 4.16-kV diesel generator capable of supporting its respective design load upon loss of preferred power.

The diesel generator 1EGS*EG1A supports standby 4.16-kV bus 1ENS*SWG1A and diesel generator 1EGS*EG1B supports standby 4.16-kV bus 1ENS*SWG1B.

The HPCS system diesel generator 1E22*S001G1C supports standby 4.16-kV bus 1E22*S004.

Each standby diesel generator is physically separated from the others and is located in the Seismic Category I diesel generator building. Failure of one diesel will not impede the operation of the other two diesel generators.

13*

Standby 4.16-kV bus 1ENS*SWG1A and normal 4.16-kV bus 1NNS-SWG1A may be fed from the preferred station service transformer 1RTX-XSRIC simultaneously.

If an undervoltage condition were to occur concurrently on both buses, a trip signal would be given to the normal supply breaker on 1NNS-SWG1A and to the motor feeder breakers on that bus.

If proper voltage is not available, a trip signal would be given to the preferred supply breaker on 1ENS*SWG1A and the standby diesel generator would start and would energize the standby 4.16-kV bus.

Division 2 equipment follows the same operation.

Reference 2 provides a

description of the standby bus transfers and tripping under loss of power conditions.

The standby 4.16-kV standby buses are electrically independent and physically isolated from one another.

Their loads are redundant as required and consist of standby motors and standby 480-V load centers.

An exception is the standby service water system.

The train A

pumps are powered by 1ENS*SWG1A and 1E22*S004 (one pump on each bus).

The train B pumps are both powered by 1ENS*SWG1B.

Dc control power for the standby 4.16-kV switchgear and for 1NNS-SWG1A, 1NNS-SWG1B, and 1NNS-SWG1C is supplied as shown in Table 8.3-8.

4.16-kV switchgear assemblies 1NNS-SWG2A and 1NNS-SWG2B at the circulating water pump area and 1NNS-SWG3A and 1NNS-SWG3B at the cooling tower makeup pump area and

RBS USAR Revision 6 8.3-9 August 1993

Under normal conditions the supply breaker on each bus is closed and the bus tie breaker is open.

No automatic closing of the tie breaker takes place after tripping either supply breaker.

Closing all breakers is by manual control.

When the supply breakers and bus tie breaker are to be closed to parallel two sources for a short period of time during throwover, closing of the last breaker is supervised by a synchronizing check relay.

Closure of the four tie breakers initiates an alarm.

6*

8.3.1.1.3.4 480-V Systems All normal load centers for nonsafety-related service are the split-bus design.

Two load center transformers of each load center are energized from normal 13.8-kV buses 1NPS-SWG1A and 1NPS-SWG1B.

In

turn, load center transformers supply opposite sides of the split bus.

These buses can be connected by closing the tie breaker.

There is no automatic transfer between the two load center 480-V power sources.

No interlocks are provided to prevent paralleling of the two load center 480-V power sources.

Closing the two load center supply main breakers and the split-bus tie breaker is indicated in the main control room.

  • 6 1NJS-LDC4A and 1NJS-LDC4B 480 VAC load-centers are of the same split design as the other non-safety related load centers.

Service water cooling load-center transformers are energized from normal 4.16-kV buses 1NNS-SWG6A and 1NNS-SWG6B.

In

turn, load center transformers supply opposite sides of the split bus.

These buses can be connected by closing the tie breaker.

There is no automatic transfer between the two load center 480-V power sources. No interlocks are provided to prevent paralleling of the two load center 480-V power sources.

Closing the two load center supply main breakers and the split-bus tie breaker is indicated in the main control room.

6*

The standby 480-V load centers are single-ended and have circuit breakers with an interrupting capability of not less than 30,000 amp symmetrical.

These standby load centers are fed from the standby 4.16-kV buses.

Standby 4.16-kV bus 1ENS*SWG1A provides power for standby 480-V load centers 1EJS*LDC1A and 1EJS*LDC2A.

Standby 4.16-kV bus 1ENS*SWG1B provides power for standby 480-V load centers 1EJS*LDC1B and 1EJS*LDC2B.

DC control power is supplied as shown in Table 8.3-8.

Standby 480-V load center loads are redundant

RBS USAR Revision 6 8.3-9a August 1993 and include standby motors and standby motor control centers.

There are several normal loads connected to the standby load centers identified in Table 8.3-7 and which are tripped off the bus during a

LOCA.

The standby 480-V load centers of Division I are electrically independent from those of Division II and are physically isolated from one another.

Molded case circuit breakers of both normal and standby motor control centers have an interrupting capability of 25,000 amp symmetrical.

Standby motor control centers of Division I are electrically independent and physically isolated from those of Division II.

Normal loads connected to the standby motor control centers and which are tripped off the bus during LOCA are identified in Table 8.3-7.

RBS USAR Revision 6 8.3-9b August 1993 THIS PAGE LEFT INTENTIONALLY BLANK

RBS USAR Revision 16 8.3-10 March 2003 8.3.1.1.3.5 Low Voltage Systems The instrumentation and control supply system consists of a 125-V dc system (Fig. 8.3-6), 120-V ac safety-related uninterruptible power supply systems (Fig. 8.3-2),

120-V ac normal uninterruptible power supply systems (Fig. 8.3-1), and 120-V ac regulated power supplies. The 125-V dc systems provide dc power for dc

loads, uninterruptible power
supplies, backup instrumentation and control, and are described in Section 8.3.2.

The 120-V ac uninterruptible power supplies provide ac power for security, control, and instrumentation systems for the nonsafety-related and engineered safeguard systems (Section 8.3.1.1.3.7).

The 120-V ac regulated power supplies provide ac power for instrumentation, security, and communication systems for the nonsafety-related and engineered safeguard systems.

The instrumentation and status indications of Class 1E switchgear aforementioned are described in Section 7.

8.3.1.1.3.6 Standby Electrical Power Systems The standby electrical power systems are designed to provide redundant sources of onsite ac electric power which are self-contained within the unit and which are not dependent on the normal and preferred sources of supply. The standby electrical power systems are capable of supplying ac power for electrical loads which are required for a safe shutdown of the reactor.

16 The standby system ac distribution buses are rated at 4.16-kV and 480-V. There are three standby 4.16-kV ac buses and four standby 480-V ac load centers. The bus configuration (Fig. 8.1-6) is described in Sections 8.3.1.1.3.3 and 8.3.1.1.3.4. Upon loss of voltage on associated standby 4.16-kV buses, or a LOCA signal initiated by an abnormally low water level in the reactor vessel or a high drywell pressure, or a manual start signal, the generators are started and brought up to rated frequency and voltage. If, at this time, the two redundant supply power lines to the buses are

open, the standby generator breakers automatically close on their associated dead buses. The diesel generators are not automatically connected to their respective standby 4.16-kV buses if the buses are still connected to either the preferred or normal station service transformers.

16

Unit 1 reactor has three diesel generators: 1EGS*EG1A, 1EGS*EG1B, and 1E22*S001G1C. Diesels 1EGS*EG1A and 1EGS*EG1B are devoted to safety-related equipment as shown

RBS USAR Revision 12 8.3-11 December 1999 in Fig. 8.1-6. Diesel 1E22*S001G1C energizes the HPCS system as described in Section 8.3.1.1.3.6.2.

8.3.1.1.3.6.1 Standby Diesel Generators 8.3.1.1.3.6.1.1 Description Each standby diesel generator is physically independent, located in a building structure designed to withstand earthquakes and to protect the standby diesel generators against tornadoes, floods, hurricanes, and tornado-generated missiles (Section 3.8). Within the protected structure, each standby diesel generator, including its associated starting equipment and other auxiliaries, is installed in a separate room of a Seismic Category I building so that an incident at one generator will not physically or electrically involve the others. Each standby diesel generator is provided with a separate missile-protected combustion air intake, room air intake and discharge, and diesel engine exhaust opening.

Seismic qualification of the standby diesel generators and associated equipment is discussed in Sections 3.9.2.2A and 3.10A.

In addition, the standby diesel generators can provide full rated load when subjected to extreme atmospheric conditions, e.g., due to a hurricane or tornado. The probability of a tornado striking a

point on the site is

low, about once in 3,415 yrs (Section 2.3.1.2.4).

Each standby diesel generator is provided with an independent fuel oil system consisting of a day tank with fuel capacity for 1-hr minimum operation at required load, and one 100 percent capacity Class 1E fuel oil transfer pump for automatically filling the day tank from its respective storage tank. One fuel oil storage tank for each standby diesel generator supplies fuel for continuous operation at its rated capacity for 7 days (Section 9.5.4).

12 Each standby diesel generator unit is provided with two independent and redundant air starting systems with separately powered air compressors to furnish air for automatic and manual starting and for control air. The starting systems for each standby diesel generator includes electrically driven compressors, primary air tanks, reserve air tanks, and necessary gears and valves for cranking the engine. The two starting systems (the HPCS diesel's air compressors are described in Section 8.3.1.1.3.6.2) are arranged so that failure of one will not jeopardize proper operation of the other. Each train of the starting system is capable of at least eight cranking cycles without the assistance of 12

RBS USAR Revision 16 8.3-12 March 2003

16 outside power. The time required by each air compressor to recharge its tank from minimum starting air pressure to operating air pressure is approximately 30 minutes. Each standby diesel engine is provided with cooling by means of a shell and tube heat exchanger cooled by water from the SSW system. Each generator is a self-cooled air-ventilated unit. All necessary auxiliaries directly associated with each standby diesel-generator unit, such as ventilating fans, battery chargers, fuel oil transfer pump, etc, are powered from their associated standby buses. Electrical power for starting and control is supplied from the 125-V dc system associated with that generator.

16

11 The standby diesels for 1EGS*EG1A and 1EGS*EG1B are Transamerica Delaval, Inc. type DSR 48 and provide 4869 bhp in continuous duty. However, special requirements are imposed by the Facility Operating License for continuous operation of these two standby diesels above 4197 bhp (3130 KW). The synchronous generators were manufactured by Parsons Peebles Electric Products, Inc.

11

The rating of each standby diesel generator is determined from plant design and power requirements and has the capability to ensure proper starting and operation of all required motor loads without excessive frequency or voltage drop. The rating of each of the standby diesel generators is adequate for the maximum required coincident loads during the unit design basis accident (DBA) in accordance with Regulatory Guide 1.9, except for the HPCS diesel. The philosophy applicable to the sizing of the HPCS diesel is defined in Section 8.3.1.1.3.6.2.

The nameplate ratings of the standby diesel generator sets are as follows:

Standby Standby Diesel Generator Diesel Generator Time 1EGS*EG1A 1EGS*EG1B (hr) 3,500 kW 3,500 kW 8,760 3,850 kW 3,850 kW 2

The 8,760-hr rating is on continuous duty under normal maintenance.

The standby diesel generators are specified to provide their rated output for combustion air temperatures ranging from 2°F to 110°F.

No derating is required for ambient atmospheric pressures down to 20.58 inches Hg - absolute (10.1 psia).

Humidity

RBS USAR Revision 16 8.3-13 March 2003 extremes are not expected to affect the operation of the standby diesel generators since the intake air is compressed and heated in the turbochargers prior to entering the engines.

16 8 The standby generator and the 4.16-kV preferred station service system are manually synchronized during periodic testing or upon restoration of preferred power. A synchronous check relay is provided to prevent breaker closure during synchronizing operations unless the busses are synchronized within the tolerances of the relay. A synchronous check relay is provided to prevent breaker closure during synchronizing operations unless the busses are synchronized within the tolerances of the relay.

If any safety-related switching equipment fails to operate automatically, manual operation is possible, remotely in the main control room or at the standby diesel generator control room.

Except for sensors and other equipment that must be directly mounted on the engine or associated piping, the controls and monitoring instrumentation are installed on free-standing floor-mounted panels located in a vibration-free floor area.

8 16

8.3.1.1.3.6.1.2 Starting and Loading

13 The standby diesel generator sets are designed for independent operation, but they may be operated in parallel with the plant auxiliary system for exercising and test purposes. Standby buses 1ENS*SWG1A and 1ENS*SWG1B are normally continuously energized from the preferred station service transformers. Standby bus 1E22*S004 is also normally continuously energized from the preferred station service system. The standby diesel generators are started upon receipt of an undervoltage signal from the standby bus source, upon receipt of a LOCA signal or on manual signal. The automatic transfer of each standby bus to its standby generator is done only on loss of voltage measured on the standby 4.16-kV bus. Transfer is accomplished by opening both the normal and preferred station service transformer supply circuit breakers and closing the standby generator's circuit breaker when the generator is at proper voltage and frequency.

13

Low voltage on a standby bus automatically disconnects all 4.16-kV motor loads on the bus. Sequencing of loads supplied from the standby diesel generators is required to prevent exceeding the motor starting and load pickup capability of the standby diesel generator. Provisions are made for automatic sequencing of all loads in accordance with Table 8.3-2. Other loads may be connected by the station operators (by manually controlled breakers) when load conditions permit. There is no automatic load shedding of the standby 4.16-kV buses when power is furnished by the standby diesel generator.

RBS USAR Revision 22 8.3-14 The load sequencing control for the onsite and offsite power sources for River Bend Station utilizes individual timers and permissive circuitry for individual feeder breakers being sequenced on standby buses. Although there is a logic which ties the operation of the entire load sequencing scheme together, failure of one or more breaker timers or permissive circuits to operate does not prevent other breaker timers and permissives from performing their intended functions. Timers and permissives are located in qualified switchgear and relay panel enclosures for the breakers they control. There are no credible sneak circuits or common failure modes in the sequencing design that could render either the onsite or offsite power sources unavailable.

An emergency demand start signal overrides all other operating modes including test and returns control of the diesel-generator unit to the automatic load sequencing system.

The standby diesel generator incorporates two modes of control, OPERATIONAL and MAINTENANCE.

a.

In the OPERATIONAL mode the diesel starts and comes up to speed when either of the following conditions is present:

1)

A MANUAL START SIGNAL generated from the local control panel and the units entire protective system is reset.

A Manual Start Signal, starts the diesel generator in the slow start mode of operation. This slow start, which is recommended by the manufacturer, extends the starting time of the diesel to minimize the aging effects associated with fast starts.

16

2)

An EMERGENCY START SIGNAL generated by either a LOCA signal or a sustained bus undervoltage or by depressing emergency START push button in the main control room or by pressing the emergency start button on the control panel.

The emergency start overrides all conditions and returns the unit to rated speed. (Refer to Section 3.1.1.4.1) Emergency start overrides all conditions such as:



Slow Start



Manual Running



Test



Tripping on fault conditions except for the following:

1. Overspeed
2. Generator Differential
3. Lube and Jacket Water high temperature trips unless the emergency start comes from a LOCA signal or the trips are bypassed by a local control switch (Applicable to EGS-EG1A and EGS-EG1B ONLY).

16

b.

In the MAINTENANCE mode only the engine ROLL pushbutton on the local panel is operative. This feature permits cranking the diesel without effecting a start.

c.

The standby diesel generators may be tested while in the operational mode by manually starting the engines and manually closing the circuit breakers connecting

RBS USAR Revision 16 8.3-15 March 2003 the standby diesel generators to the bus. In this manner, the standby diesel generators can be tested under load while in parallel with the grid.

Should the grid go to an undervoltage or underfrequency condition, the circuit breakers in the Fancy Point Substation trip and deenergize the circuit feeding the preferred station service transformers. The pilot wire system also initiates a trip of the 4.16-kV circuit breaker between the preferred station service transformer and the bus. With the preferred or alternate supply breakers in the open position, the generator setting would switch from the parallel operation mode to the isochronous mode, and the standby diesel generator picks up the entire load of the standby 4.16-kV bus sequentially.

The standby diesel generators are capable of running unloaded for 7 days without degrading the performance or reliability of the engine. The manufacturer has demonstrated this capability with a special no load endurance test.

8.3.1.1.3.6.2 High Pressure Core Spray Power Supply System 8.3.1.1.3.6.2.1 Description Fig. 8.3-3 shows the HPCS power system (Division III) simplified one-line diagram electrical arrangement, power distribution, protective relaying, and instrumentation for the HPCS power system.

The HPCS power supply system is self-contained except for the initiation signal source and access to the preferred source of offsite power through the plant ac power distribution system. It has a dedicated diesel generator, 1E22*S001G1C and is operable as an isolated system independent of electrical connection to any other system.

16 The HPCS diesel 1E22*S001G1C is a Stewart and Stevenson EMD 20645-E4, 20-cylinder vee type. It provides 3600 bhp in continuous duty. The synchronous generator was manufactured by Ideal. This SM-100 model has a 2,000-hr rating of 2850 kW.

16

Seismic qualification of the HPCS diesel generator and associated equipment is discussed in Section 3.9.2.2B and 3.10B. In addition, the HPCS diesel generator can provide full-rated load when subjected to extreme atmospheric conditions. No derating is required for operation in

RBS USAR Revision 8 8.3-16 August 1996 ambient temperatures up to 120°F, a

relative humidity of 90 percent, and an atmospheric pressure down to 28.25 inches Hg.

Low combustion air temperatures do not affect the operability of the HPCS diesel generator since the intake air is compressed and heated in the turbocharger prior to entering the engine.

  • 8 *4 The standby auxiliary equipment such as heaters and battery charger are supplied from the same power source as the HPCS motor.

The non-safety related HPCS DG air compressors are supplied from non-safety related power sources.

8* 4*

Voltage and frequency of the HPCS diesel generator is compatible with that available from the plant ac power system.

  • 8 The HPCS diesel generator has the capability to restore power quickly to the HPCS bus in the event offsite power is unavailable and to provide all required power for the startup and operation of the HPCS
system, one standby service water pump
motor, and miscellaneous auxiliaries associated with it.

The HPCS diesel generator starts automatically on a

LOCA signal from the plant protection system or undervoltage on the HPCS 4.16-kV bus (1E22*S004), and will be automatically connected to the HPCS bus when the plant preferred ac power supply is not available.

The failure of this unit will not negate the capability of other power sources.

There is no provision for automatic paralleling of the HPCS diesel generator with the auxiliary power or with standby power sources.

Provisions for manual paralleling with normal power sources are made for loading the diesel generator during the exercise mode.

A synchronous check relay is provided to prevent breaker closure during paralleling unless the busses are synchornized within the tolerances of the relay.

If a LOCA signal occurs while the HPCS diesel generator is running in parallel with the normal bus, the diesel generator breaker will automatically trip.

At least one interlock is provided to avoid accidental paralleling.

There is no sharing of the HPCS power system with other standby diesel generators.

  • 8 The HPCS power system loads consist of the HPCS pump/motor and associated auxiliaries, motor-operated
valves, one standby service water
pump, and miscellaneous auxiliary loads.

Table 8.3-3 shows the Division III loads.

The HPCS pump motor is a General Electric 4-kV vertical induction motor rated at 2500 hp.

The vertical pump was manufactured by the Borg-Warner Byron-Jackson Pump Division.

It is rated at 5,125 gpm with 945 ft of head and its motor has a

maximum shaft bhp of 2,500 at 1,780 rpm.

The HPCS electric system is capable of performing its function when subjected to the effects of design bases

RBS USAR Revision 8 8.3-17 August 1996 natural phenomena.

It is designed in accordance with Seismic Category I and housed in a Seismic Category I structure.

The detailed description of the fuel oil storage and transfer system associated with the HPCS diesel generator unit is described in Section 9.5.4.

Fuel for the HPCS diesel engine is provided in a separate day tank and in a storage tank.

The day tank permits a minimum of 1 hr of operation at rated load.

The combined capacity of the day tank and the storage tank permits the HPCS diesel engine to operate at continuous rated load conditions for at least 7 days.

  • 8 The engine air starting system contains two complete sets of starting components, either of which is capable of starting the engine.
However, to further ensure starting within the time requirements, both sets are utilized simultaneously to crank the engine.

Each set of components consists of dual air start motors, air relay valve, solenoid valve, air receivers, and air compressor assembly.

Both compressors are capable of automatic start and stop and are controlled by pressure switches to maintain required pressure in the air receivers.

The two air starting systems are redundant, independent, and arranged so that failure to start in one system will not jeopardize starting of the diesel generator by the other system.

8*

Manual controls are provided to permit the operator to select the most suitable distribution path from the power supply to the load.

An automatic start signal overrides the exercise mode.

Provisions are made for control from the main control room and external to the main control room from an HPCS diesel generator control panel located external to the main control room in the diesel generator building as shown in Figure 8.3-11.

The control panel includes facilities for breaker control of incoming feeder and HPCS generator breaker together with frequency

meter, synchroscope,
bus, and incoming voltmeters and engine speed control device.

Except for sensors and other equipment that must be directly mounted on the engine or associated

piping, the controls and monitoring instrumentation are installed on free-standing floor-mounted panels located in a vibration-free floor area.

Control power for the HPCS diesel generator unit is supplied from its own 125-V battery

system, which consists of a

RBS USAR Revision 21 8.3-18 battery with its own battery charger. The charger is designed to carry the continuous load in addition to normal battery charging current. Section 8.3.2.2 provides a discussion of the HPCS 125-V dc system. Tables 8.3-3 and 8.3-6 show the HPCS diesel generator size and the 125-V dc load requirements.

8.3.1.1.3.6.2.2 Starting and Loading A loss of normal potential at the HPCS bus is one of the three initiating signals which automatically starts the HPCS diesel generator. The other two signals are accident signals of reactor low water level and high drywell pressure which are described in detail in Section 7.3.1. On receipt of a start signal or HPCS supply bus undervoltage, the HPCS diesel generator will start and accelerate to operating voltage and frequency as standby power supply for the HPCS system. On reaching rated speed and voltage, the generator is automatically connected to the HPCS bus if ac power is not available at the bus. Once the diesel generator has been energized, the unit will continue to operate until manually deenergized or until the protective devices of the HPCS diesel generator cause a trip.

The HPCS diesel generator is capable of running unloaded for 4.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> without degrading the performance or reliability of the engine, after which, it must be run at a minimum of 40 percent of nameplate rating for 30 minutes.

The HPCS diesel generator has the capacity to start all motors as required by the design basis so that the main pump is at rated speed and all required valve operations are completed within the time requirements described in Sections 6.3 and 9.2.7. All HPCS loads associated with the DBA are started concurrently, except the DG room vent fan, the standby service water pump, and its associated motor-operated valve 1SWP*MOV40C, which are sequenced to start as noted in Table 8.3-3.

An emergency demand start signal overrides all other operating modes including tests and then returns control to the sequencing system. Refer to Section 5 of NEDO 10905 for a description of control and protection of the HPCS diesel generator.

8.3.1.1.3.7 120-Volt AC Uninterruptible Power Supply System The 120-V ac uninterruptible power supply system supplies control power to vital computer and instrumentation loads for which power interruption must be avoided.

These

RBS USAR Revision 20 8.3-19 services are necessary for the normal operation of the plant.

Power from the uninterruptible power supplies is free from extraneous voltage spikes, switching surges, and momentary interruptions, and satisfies the voltage and frequency variation limits of the station computers and instrumentation systems. A high degree of power continuity is provided, with the uninterruptible power supply being able to switch automatically between two independent sources of input power, or to transfer to an independent alternate source of regulated ac power with sufficient speed so the operation of the computer and instrumentation is not affected.

x o13 Normally the uninterruptible power supply inverter (Figure 8.3-1 and 8.3-2) receives dc power from a 480-V ac motor control center (MCC) feeding an ac-to-dc rectifier, with a second source of dc power coming from the 125-V dc station battery. Any failure of the MCC feeding the rectifier results in the station battery carrying the uninterruptible power supply load without interruption. Malfunctions of both of the two dc sources of power to the inverter or the inverter itself causes the static switch to automatically transfer the power source to an independent alternate source fed from a 480-V ac MCC feeder through a voltage regulating transformer in all uninterruptible power supplies.

1BYS-INV06 furnishes power to DRMS, ERIS, and other support service loads. A make-before-break manual bypass switch enables maintenance, inspection, and testing of the uninterruptible power supply components to be safely performed while feeding the loads from the alternate source voltage regulating transformer.

13mx x o15 x o1 There are a total of eleven uninterruptible power supply systems in the plant. ENB-INV01A and ENB-INV01A1 are associated with Division I, ENB-INV01B and ENB-INV01B1 are associated with Division II and the remainder (BYS-INV01A, BYS-INV01B, BYS-INV02, BYS-INV04, BYS-INV06, and IHS-INV01) are connected to normal buses. BYS-INV03 is a nonsafety-related swing inverter which supplies 120 VAC power to distribution panel. Through switches near the local inverter, BYS-INV03 may be utilized to supply backup power to the loads of BYS-INV01A or BYS-INV01B.

Either ENB-INV01A (01B) or ENB-INV01A1 (01B1)

(but not both simultaneously) may be selected to supply power to VBS-PNL01A (01B) through the use of manual transfer switch VBS-TRS02A (02B). Either unit may be in-service at any given time, with the other unit de-energized and available as a backup. Upon failure of the in-service UPS, the backup unit is energized and placed in service via operation of VBS-TRS02A (02B). This allows a rapid method of in service via operation of VBS-TRS02B. This allows a rapid method of restoring power to the Division I (II) 120 Volt AC Vital Bus in the event of a failure of the in-service UPS. The ac sources for the uninterruptible power supplies associated with the standby systems are derived from the standby diesel generators feeding buses 1ENS*SWG1A and 1ENS*SWG1B.

All uninterruptible power supplies and their associated distribution panels are completely independent (by division). Those panels associated with standby systems serve redundant safety-related equipment. The distribution 1mx 15mx

RBS USAR Revision 8 8.3-20 August 1996 panels contain fused disconnect switches for branch circuit protection.

Manual or automatic devices for switching to interconnect the redundant safety-related uninterruptible power supplies are not provided.

8.3.1.1.3.8 Reactor Protection System (RPS) Power System 8.3.1.1.3.8.1 General The RPS power system is designed to provide power to the logic system that is part of the reactor protection system. It prevents auxiliary power system switching transients from causing an inadvertent reactor scram due to a transient disturbance of power to the reactor scram logic.

The principal elements of the RPS power system include two high

inertia, alternating
current, motor generator sets and distribution equipment.

Each motor generator set supplies power for the nuclear steam supply shutoff

system, neutron monitoring
system, parts of process radiation monitoring system, and reactor protection trip system.

The RPS power is classified as nonessential because failure of the power supply causes a reactor scram and isolation.

However, the power feeds to redundant logics are physically separated by running in separate conduits.

RPS safety-related signal cables, power cables, and raceways are identified by nameplates and/or color codes to distinguish from nonsafety-related equipment and to distinguish between redundant, safety-related equipment.

RPS safety-related instrument panels are identified by color coded nameplates to distinguish from nonsafety-related equipment and to distinguish among redundant, safety-related equipment.

RBS provides protection of RPS buses A

and B

from voltage and frequency anomalies which could damage RPS components and thus preclude improper operation of the RPS.

The protection is afforded by the use of electrical protection assemblies (EPAs) which are Class 1E.

The EPAs provide redundant protection to the buses by acting to disconnect the buses from the power sources not within design specifications.

  • 8 The EPA (Figure 7.2-1) consists of a circuit breaker with a trip coil controlled by three individual solid state relays which sense line voltage and frequency and trip the breaker open on
  • 8

RBS USAR Revision 25 8.3-21 the conditions of overvoltage, undervoltage, and under-frequency.

Provision is made for setpoint verification, calibration, and adjustment under administrative control. After tripping, the circuit breaker must be reset manually. Trip setpoints are based on providing 115-V ac, 60-Hz power at the RPS logic cabinets.

The protective circuit functional range is `10 percent of nominal ac voltage and -5 percent of nominal frequency.

The four EPA enclosures for each RPS bus are mounted on a Seismic Category I structure separately from the motor generator sets and separate from the four EPAs of the other RPS bus. Two EPAs are installed in series between each of the two RPS motor-generator sets and the RPS buses and between the auxiliary power sources and RPS buses. Figure 7.2-1 provides an overview of the eight EPA units and their connections between the power sources and the RPS buses. The EPA is designed as a Class 1E electrical component.

It is designed and fabricated to meet the quality assurance requirements of 10CFR50 Appendix B.

8.3.1.1.3.8.2 Components Each of these high inertia motor generator sets has a voltage regulator which is designed to respond to a step load change of 50 percent of rated load with an output voltage change of not more than 15 percent. High inertia is provided by a flywheel.

The inertia is sufficient to maintain the voltage and frequency of generated voltage within 5 percent of the rated values for a minimum of 1 sec following a total loss of power to the drive motor.

8.3.1.1.3.8.3 Sources The power to each of the RPS buses is supplied from two 120-V ac sources. The primary source of power is the motor generator sets. The alternate source of 120-V ac power is Class 1E and redundant, and consists of a

480-120-V voltage-regulating transformer. The two motor generator sets are supplied from separate 480-V motor control centers normally energized from the normal station service transformers, and which also are connectable to the preferred station service transformers via the non-Class 1E distribution system. Indicating lights are provided in the main control room to monitor the status of both the motor generator sets and the instrument buses.

RBS USAR Revision 25 8.3-22 8.3.1.1.3.8.4 Operating Configuration During operation, the reactor protection system buses are energized by their respective motor generator sets. Either motor generator set can be taken out of service by manually operating the power source selector switch which disconnects the motor generator set and connects the respective RPS bus to its alternate power source. Only one RPS bus may be placed on alternate power when in Modes 1 OR 2 except for limited emergent plant situations which require both RPS buses to be connected to their alternate supplies for short periods. Alignment of both RPS buses to their alternate supplies is not the normal line up because of increased vulnerability to grid perturbations that could result in inadvertent trip of both divisions of RPS connected loads. Short periods are not to exceed the time required to correct the limited emergent plant situation(s) to restore at least one RPS bus to normal power supply. A loss of power to either motor generator set is monitored in the main control room (white indicating lamp goes off) where the operator, on detecting such a condition, can switch over to the alternate power source. A loss of power to one motor generator set results in a single RPS trip system trip. A persistent loss of electrical power to both motor generator sets (1 sec minimum) results in a scram.

8.3.1.1.3.9 Adequacy of Electrical Distribution System Voltages 16 Two completely separate schemes of undervoltage protection are provided on the Division I and II Class 1E buses at the 4.16-kV level. The selection of undervoltage and time delay setpoints has been determined from an analysis of the voltage requirements of the Class 1E loads. These setpoints are verified during surveillance testing.

16 The first undervoltage scheme detects loss of power at the Class 1E buses. This undervoltage setpoint is set below any anticipated transient voltage condition, with a time delay of approximately 3 seconds.

The second level of undervoltage protection is set at approximately 90 percent and utilizes two separate time delays based on the following conditions:

1.

The first time delay is approximately 5 sec, which establishes a sustained degraded voltage condition (i.e.,

something longer than a

motor starting transient). Following this delay, an alarm in the main control room alerts the operator to the degraded condition. The subsequent occurrence of a LOCA signal immediately separates the Class 1E distribution system

RBS USAR Revision 25 8.3-22a from the offsite power system, starts load shed logic and load sequence timers, starts the diesel generator, and permits auto-close of the diesel generator breaker.

xo13 2.

The second time delay is approximately 60 sec, which ensures that permanently connected Class 1E loads will not be damaged. Following this time 13mx

RBS USAR 8.3-23 August 1987 delay, if the operator has failed to restore adequate

voltages, the Class 1E system is automatically separated from the offsite power system, the load shed logic and load sequence timers
start, and the diesel generator starts and permits auto-close of the diesel generator breaker.

Undervoltage protection is afforded to the ac distribution system down to and including the 480-V motor control centers (MCCs) level.

The tripping of the 4.16-kV air circuit breakers (ACBs) discussed above also results in no voltage at the 480-V load centers and MCCs which, in turn, will cause motor feeder ACBs and contacts to open circuit. Subsequent energization of the 4.16-kV buses by the diesel generator results in the re-energization of MCC motor loads with the closing of their contacts at approximately 70 percent voltage.

The voltage sensors are designed to satisfy the following applicable requirements:

1.

Class 1E equipment is utilized and is physically located at and electrically connected to the Class 1E switchgear.

2.

An independent scheme is provided for Division I and II of the Class 1E power system.

3.

The undervoltage protection includes coincidence logic (2

out of 3) on a

per-bus basis to preclude spurious trips of the offsite power source.

4.

The voltage sensors automatically initiate the disconnection of offsite power sources whenever the voltage setpoint and time delay limits have been exceeded.

5.

Capability for test and calibration during power operation is provided.

Undervoltage relay settings on the Class 1E 4.16-kV buses can be checked during plant operation by testing one single-phase undervoltage relay at a time.

Disconnecting one phase of the three-phase system does not impair the operation of the switchgear.

Normally a

two-out-of-three

logic, the removal of one relay results in an effective one-out-of-two logic, i.e., an undervoltage detected by any one of the two remaining relays still in the circuit would initiate an undervoltage tripping sequence.

The removed relay can then be checked against a

RBS USAR Revision 6 8.3-24 August 1993 variable voltage test input to verify its intended setpoint.

6.

Annunciation is provided in the control room by any bypasses incorporated in the design.

The Class 1E bus load shedding scheme automatically prevents shedding during sequencing of the emergency loads to the bus.

The load shedding feature is reinstated upon completion of the load sequencing action.

The voltage levels at the safety-related buses are optimized for the maximum and minimum load conditions that are expected throughout the anticipated range of voltage variations of the offsite power sources.

The trip settings selected are based on an analysis of the voltage at the terminals of the Class 1E loads.

The analyses performed to determine minimum operating voltages consider maximum unit steady state and transient loads for events such as a

unit

trip, loss of coolant
accident, startup, or
shutdown, with the offsite power supply (grid) at minimum anticipated voltage and only the offsite source being considered available.

Maximum voltages are analyzed with the offsite power supply at maximum expected voltage concurrent with minimum unit loads.

  • 1 The analytical techniques and assumptions used in the voltage analysis were verified by actual measurement.

The verification and test were performed prior to initial full-power reactor operation on all sources of offsite power by:

1*

1.

Loading the station distribution

buses, including all Class 1E buses down to the 120/240 V level, to at least 30 percent.

2.

Recording the existing grid and Class 1E bus voltages and bus loading down to the 120/240 V level at steady state conditions and during the starting of both a

large Class 1E and non-Class 1E motor (not concurrently).

  • 6 3.

Using the analytical techniques and assumptions of the voltage analysis above, and the measured existing grid voltage and bus losing conditions recorded during conduct of the test, a new set of voltages for all the Class 1E buses down to the 120/240 V level was calculated.

6*

RBS USAR Revision 17 8.3-25

6

4.

The analytically derived voltage values were compared against the test results.

6

Two completely separate schemes of undervoltage protection are provided on the Division III Class 1E HPCS bus at the 4.16-kV level. The selection of undervoltage and time delay setpoints has been determined from an analysis of the voltage requirements of the Class 1E loads. These setpoints will be verified during the actual system testing. The first and second level undervoltage protection scheme senses voltage at the incoming side of the normal supply breaker.

13 The first level undervoltage setpoint is set below any anticipated transient voltage condition, with a time delay of approximately 3 sec.

The second level of undervoltage protection is set at approximately 90 percent of normal voltage and utilizes two separate time delays based on the following conditions:

1.

The first time delay is approximately 5 sec and establishes a sustained degraded voltage condition (i.e.,

something longer than a

motor starting transient). Following this delay, an alarm in the main control room alerts the operator to the degraded condition. The subsequent occurrence of a LOCA signal immediately separates the Division III HPCS bus from the offsite power system. The Division III HPCS bus will experience a loss of voltage and the primary undervoltage relays and control circuit will start load shed logic, start the diesel generator, and permit auto-close of the diesel generator breaker when the diesel generator attains its rated speed, voltage, and frequency.

13

2.

The second time delay is approximately 60 sec and is set to ensure that permanently connected Class 1E loads will not be damaged. Following this time delay, if the operator has failed to restore adequate voltages, the Division III HPCS bus is automatically separated from the offsite power system. The Division III HPCS bus will experience a loss of voltage and the primary undervoltage relays and control circuit will start the load shed logic, start the diesel generator, and permit auto-close of the diesel generator breaker when the diesel generator attains its rated speed, voltage, and frequency.

RBS USAR 8.3-26 August 1987 Undervoltage protection is afforded to the ac distribution system down to and including the 480-V motor control center (MCC) level.

The tripping of the 4.16-kV offsite power supply circuit breaker discussed above also results in no voltage at the 480-V MCC bus

which, in
turn, will cause motor feeder contactors to dropout.

Subsequent energization of the 4.16-kV HPCS bus by the diesel generator results in the reenergization of 480-V MCC bus.

Auto-closer interlocks will operate the contactors at approximately 70 percent voltage to energize the motor loads.

The voltage sensors are designed to satisfy the following applicable requirements:

1.

Class 1E equipment is utilized and is physically located at and electrically connected to the Class 1E switchgear.

2.

An independent scheme is provided for the Division III Class 1E HPCS power system.

3.

The second level of undervoltage protection includes coincidence logic (2

out of 2) to preclude spurious trips of the offsite power source.

4.

The voltage sensors automatically initiate the disconnection of offsite power sources whenever the voltage setpoint and time delay limits have been exceeded.

5.

Capability for test and calibration during power operation is provided.

6.

Annunciation is provided in the control room by any bypasses incorporated in the design.

The Class 1E HPCS bus load shedding scheme automatically prevents shedding during sequencing of the emergency loads to the bus.

The load shedding feature is reinstated upon completion of the load sequencing action.

The voltage levels at the HPCS bus are optimized for the maximum and minimum load conditions that are expected throughout the anticipated range or voltage variations of the offsite power sources.

The trip settings selected are based on an analysis of the voltage at the terminals of the Class 1E loads.

The analyses performed to determine minimum operating voltages consider maximum unit steady state and transient loads for events such as unit trip, loss of coolant accident, startup, or shutdown, with the offsite

RBS USAR Revision 9 8.3-27 November 1997 power supply (grid) at minimum anticipated voltage and only the offsite source being considered available.

Maximum voltages are analyzed with the offsite power supply at maximum expected voltage concurrent with minimum unit loads.

  • 6 The analytical techniques and assumptions used in the voltage analysis were verified by actual measurement.

The verification and test will be performed prior to initial full-power reactor operation on all sources of offsite power by:

6*

1.

Loading the station distribution

buses, including all Class 1E buses down to the 120-V level, to at least 30 percent.

2.

Recording the existing grid and Class 1E bus voltages and bus loading down to the 120-V level at steady-state conditions and during the starting of a large Class 1E HPCS pump motor.

  • 6 3.

Using the analytical techniques and assumptions of the voltage analysis above, and the measured existing grid voltage and bus loading conditions recorded during conduct of the

test, a

new set of voltages for the Class 1E HPCS bus down to the 120-V level was calculated.

4.

The analytically derived voltage values were compared against the test results.

6*

8.3.1.1.3.10 Control Interlocks for AC Electrical Circuits Control circuits of all 4.16-kV circuit breakers and 480-V load center breakers in safety-related systems were reviewed to determine if inadvertent operation of other components in the same or other systems resulted when the circuit breaker for a

particular component was racked out to the test position or operated in the test position.

The results of this review have been summarized and verify that the present design of electrical control circuitry for RBS does not result in any inadvertent operations.

  • 9 1.

In the case of 4.16-kV circuit breakers, interlock to other components is achieved using breaker auxiliary switch contacts.

The operation of the interlocked circuitry is controlled administratively when the circuit breaker is operated in the test position.

9*

RBS USAR 8.3-28 August 1987 2.

In the case of 480-V load center breakers, interlock to other components is achieved using the contacts of an auxiliary relay in the breaker control circuit.

A breaker housing limit switch contact is used to lock out this relay in the racked out position of the breaker.

3.

13.8 kV circuit breakers are not used to control power to any safety-related systems or components.

4.

In the case of motor control

centers, interlock to other system components is achieved using auxiliary relays in their control circuits.

Testing of motor control centers does not result in any inadvertent operation of other system components.

5.

120-V ac/dc circuit breakers do not provide any interlocks to other system components.

8.3.1.1.4 System Protection and Surveillance Transformers with their low voltage winding at or above 4.16 kV, except 1STX-XS3A and 1STX-XS3B at the makeup water

area, have differential protection.

All 4.16-kV and 13.8-kV ac motor circuits have phase time overcurrent relays with instantaneous trips set above locked rotor levels.

Also, 4.16-kV and 13.8-kV motors have time over-current ground relaying.

The reactor feed pump motors and the reactor recirculating pump motors with their dedicated transformers have differential protection.

Circuit relays are coordinated with those at the source.

Breakers at the 480-V level have time-overcurrent tripping. All molded case breakers in motor control centers and the dedicated motor supply breakers in 480-V load centers have instantaneous short circuit tripping devices set above motor inrush current level.

Breakers in 480-V load centers serving motor control centers have minimum time delay on short circuits; those used in bus-tie service have intermediate time delay; and those in main supply service have maximum time delay on short circuits.

Load centers in standby service have 480-V breakers in the main supply.

The tripping selectivity outlined and appropriate choice of relays and thermal tripping devices facilitate application of the required coordination of protection.

RBS USAR 8.3-29 August 1987 8.3.1.1.4.1 Standby Diesel Generators The protection system of standby diesel generators is described as follows (see logic diagrams, Figure 7.3-23, sheets 17 through 28):

1.

The standby diesel generator is rendered incapable of responding to an emergency auto start signal during any diesel generator operational condition (including testing and operation from the local control panel) by the following conditions:

a.

Diesel control panel loss of control power b.

Starting air pressure low c.

Stop solenoid 1EGS*SOV24A or 1EGS*SOV24B, for 1EGS*EG1A or 1EGS*EG1B, respectively, energized.

The diesel generator stop solenoid is energized and sealed in whenever the manual stop pushbuttons are operated or the diesel generator primary or backup protection relays are tripped.

The stop solenoid is sealed in to prevent an automatic diesel generator emergency start occurring before all the diesel generator controls and protection devices are reset to normal operating conditions.

The local control room or main control room operator can deenergize the diesel generator stop solenoid by operating the STOP RESET pushbutton provided, one in each control room.

d.

Diesel in the maintenance mode (includes barring device engaged) e.

Overspeed trip device actuated f.

Generator backup protection lockout relay tripped g.

Generator primary protection lockout relay tripped 2.

The standby diesel generator unit is tripped under the following conditions during both normal and emergency operation:

a.

Engine overspeed

RBS USAR Revision 22 8.3-30

16

b.

Both STOP pushbuttons manually operated. For each standby diesel generator unit, two pushbuttons are located at both the main control room and at the local control panel. The two pushbuttons are arranged such that the operator must use both hands to simultaneously operate both pushbuttons in the main control room. The operator can operate both pushbuttons with one hand at the local panel.

16

c.

Generator differential relay trip

d.

Extreme high jacket water temperature and high lube oil temperature trips are active unless a LOCA signal is present or manually bypassed by a local control switch (Applicable to EGS-EG1A and EGS-EG1B ONLY).

3.

The standby diesel generator unit is tripped under the following conditions during normal operation only.

a.

Generator voltage controlled - inverse time phase overcurrent

b.

Generator reverse power

c.

Generator loss of field

d.

Extreme high jacket water temperature trip

e.

High bearing temperature trip

f.

Extreme low jacket water pressure trip

g.

High crankcase pressure trip

h.

Trip low turbo oil pressure

i.

Trip high vibration

j.

Trip high temperature lube oil

k.

Low lube oil pressure trip

l.

Generator ground overcurrent

4.

Protective functions of each standby diesel generator are annunciated locally in each of the standby diesel generator control rooms.

The following alarms are separated into subsystem groups. Each subsystem group is provided with a "first out" indication as per Regulatory Guide 1.9.

RBS USAR Revision 16 8.3-31 March 2003

a.

Diesel engine lube oil subsystem (see Figure 7.3-17)

(1)

Lube oil filter differential pressure high (2)

Lube oil strainer differential pressure high (3)

Turbo oil pressure low (4)

Lube oil pressure low (5)

Turbo oil low pressure - TRIP (6)

Lube oil low pressure - TRIP (7)

Crankcase high pressure - TRIP (8)

Lube oil outlet temperature high (9)

Lube oil inlet temperature high (10) Lube oil outlet temperature low (11) Lube oil inlet temperature low (12) Lube oil tank level high (13) Lube oil tank level low (14) Lube oil outlet high temperature - TRIP

16 (15) Bearing oil high temperature - TRIP 16

b.

Diesel engine fuel oil subsystem (see Figure 7.3-15)

(1)

Fuel oil storage tank level low (2)

Diesel engine strainer differential pressure high (3)

Fuel oil day tank level extreme low (4)

Fuel oil day tank level extreme high (5)

Fuel oil filter differential pressure high (6)

Fuel oil pump overspeed drive failure

RBS USAR Revision 16 8.3-32 March 2003 (7)

Fuel oil pressure low

16 14

c.

Diesel engine jacket water subsystem (see Figure 7.3-23) 14 16

(1) Jacket water pressure low (2) Jacket water extreme low pressure - TRIP (3) Jacket water outlet temperature extreme high

- TRIP (4) Jacket water outlet temperature high (5) Jacket water inlet temperature high (6) Jacket water outlet temperature low (7) Jacket water inlet temperature low (8) Jacket water level low

d.

Diesel engine air start subsystem (see Figure 7.3-16)

(1) Start air receiver pressure low (2) Control air pressure low (3) Diesel start air pressure low

e.

Diesel generator subsystem (see Figure 7.3-23, Sheets 22 and 28)

(1) Standby generator differential - TRIP (2) Standby generator fault - TRIP (3) Standby generator ground fault (4) Standby generator loss of field The following standby diesel generator protective functions are annunciated individually:

15

a.

DELETED

b.

DELETED 15

c.

Emergency exhaust fan trouble

RBS USAR Revision 22 8.3-33

d.

Auxiliary systems not in auto

16

e.

Bearing high temperature - TRIP 16

f.

Fuel oil strainer differential pressure high

g.

Fuel oil dc pump running

h.

After cooler water inlet temperature high

i.

Barring device engaged

j.

Diesel start air pressure high

k.

Unit start failure

l.

Vibration - TRIP

m.

Overspeed - TRIP

n.

4160 Standby bus distribution breakers auto -TRIP

o.

Diesel generator potential circuit blown fuse

p.

4160 Standby bus undervoltage In addition to the above-listed annunciators, the following standby diesel generator conditions are also indicated in each diesel generator control room:

14

a.

Unit available emergency status - white light on

b.

AC control power - white light on

c.

DC control power - white light on

d.

Ready to load - white light on

e.

Unit tripped - amber light on 14

f.

At synchronous speed - red light on

g.

Starting - red light on

h.

Shutdown system active - red light on

i.

High temperature bypass switch, operate - white light on, Bypass - amber light on (Applicable to EGS-EG1A and EGS-EG1B ONLY).

5.

The following remote annunciation is provided in the main control room for each standby diesel

RBS USAR Revision 16 8.3-34 March 2003

8 generator (1EGS*EG1A and 1EGS*EG1B). Window engraving for the cited condition is exact wording. The events which cause the window to annunciate are also listed.

8

a.

"STANDBY DIESEL GENERATOR 1EGS*EG1A INOPERATIVE"

16 Actuated by the following conditions. These conditions are also provided with individual amber lights in the main control room (except for items 8 and 10 which have system level input only). The following describes the wording engraved on the associated amber light window and the failed or inoperative condition.

16

(1) "LOSS OF CONT. PWR. FWD/REAR ST. CKT." -Both forward and rear air start 125-V dc control power failed.

(2) "LOSS OF FORWARD AND REAR ST. AIR" - Both forward and rear starting air failure.

(3) "MAINT. MODE L.O. SOL. ENERGIZED" - Local control room maintenance mode selector switch and main control room diesel engine mode selector switch in the MAINTENANCE position.

(4) "DSL. ENG. OVERSPEED TRIP" - Diesel engine overspeed device actuated.

(5) "STBY GEN.

DIFF./FAULT TRIP" Diesel generator primary or backup protection lockout relays tripped.

(6) "DSL ENG. STOP SOLENOID ENERGIZED" -Manual stop pushbuttons

operated, or diesel generator
primary, or backup protection relays tripped.

1 1

RBS USAR 8.3-35 August 1988

1 (7) "GEN/EXC. LOSS OF DC CONT. POWER" - Loss of the diesel generator exciter and regulator 125-V dc control circuit.

(8) "LOSS OF EXCITER FIELD DC PWR." - Loss of 125-V dc power to the diesel generator field winding.

(9) "DIESEL GEN. MANUALLY BYPASSED" -Manually-operated switch, operated whenever any diesel generator system controls or protection devices are deliberately bypassed.

(10) "AUX. CKT. LOSS OF CONTROL POWER" - Loss of 125-V dc to the diesel generator inoperative annunciator control circuit.

1

b.

"DIESEL GEN. 1A PT BLOWN FUSE" - Actuated when the diesel generator breaker is closed, and the backup protection lockout relay is reset, and any one of the diesel generator potential transformer primary fuses are blown.

c.

"4160-V STANDBY BUS DISTR. BREAKER INOPERATIVE" -

This annunciator window is a common alarm point actuated by any one of the following conditions.

These conditions also actuate a common inoperative amber light titled, "4.16 STBY. BUS DISTR. BREAKER INOPERATIVE." The conditions are:

(1) Loss of 125-V dc control power.

(2) Loss of breaker control circuit blown fuse.

(3) Breaker not in operate position.

(4) Breaker lockout relay tripped.

The 4160-V standby bus distribution breakers associated with this common alarm point are:

(1) 4.16-kV Bus 1A Normal Supply

RBS USAR Revision 16 8.3-36 March 2003 (2) 4.16-kV Bus 1A Alternate Supply (3) 4.16-kV Bus 1A Generator Supply (4) 4.16-kV Bus 1A Generator Neutral Breaker (5) 480 V LDC 1A Supply (6) 480 V LDC 2A Supply

d.

"4160-V STANDBY BUS DISTR.

BREAKER AUTO TRIP" - This annunciator window is a common alarm actuated when the local or remote breaker control switch is in the AFTER START position and the breaker is automatically tripped open.

This condition also actuates the amber light associated with each breaker control switch.

The 4160-V standby bus distribution breakers are listed in Section 8.3.1.1.4.1, Item 5c above.

16 15

e.

"STBY DIESEL GEN. TROUBLE" - This annunciator window is a common alarm actuated by the conditions listed in Section 8.3.1.1.4.1, Items 4.a.1 through 4.a.14, Item 4.b.2, Items 4.b.5 through 4.b.7, Items 4.c.1 through 4.c.8, Items 4.d.1 through 4.d.3, Items 4.e.1 through 4.e.4, plus items e through m of the protective functions listed as annunciated individually.

15 16

1

f.

"DIESEL FUEL OIL STORAGE TANK LEVEL LOW" 1

g.

"DIESEL FUEL OIL DAY TANK EXTREME LOW LEVEL" -This annunciator window is actuated from a switch receiving an input signal from the fuel oil day tank level transmitter.

h.

"4 kV STBY BUS NORMAL & ALT SUPPLY BKRS CLOSED" -

This annunciator is actuated when 15 sec after both normal and alternative supply breakers close on 4-kV standby bus.

i.

"4 kV STBY BUS DISTR BKR AUTO TRIP" - This annunciator is actuated when diesel generator breaker trips automatically.

RBS USAR Revision 22 8.3-37

j.

"4 kV STBY DSL GEN. NEUTRAL BKR AUT TRIP" -This annunciator is actuated when diesel generator neutral breaker trips automatically.

k.

"DSL.

GEN BACKUP PROT.

ACTIVATED" This annunciator is actuated on reverse power, ground overcurrent, controlled-inverse time phase overcurrent, and loss-of-field faults (when diesel generator breaker is closed).

l.

"DSL GEN PROT CKT LOSS OF CONT. PWR" - This annunciator is actuated when control power of diesel generator protection circuit is lost.

m.

"STBY DIESEL GEN HIGH TEMP TRIPS MAN BYPASSED" is actuated when the local bypass switch is in the BYPASS position (Applicable to EGS-EG1A and EGS-EG1B ONLY).

6.

Each standby diesel generator set is capable of being emergency started in the operational mode from the main control room as well as the standby diesel generator control room near the engines. There is no transfer scheme between these two locations, since the emergency start controls are in parallel. Normal start controls are on the local engine control panel only in the standby diesel generator control room near the engines (Fig. 8.3-11).

7.

All standby diesel generator parameters that are bypassed under accident conditions are annunciated in each standby diesel generator control room. These annunciators are located on the associated standby diesel engine control panel.

8.

All conditions that render the standby diesel generator incapable of responding to an automatic start signal are annunciated in the main control room.

8.3.1.1.4.1.1 Qualification Testing In accordance with Branch Technical Position EICSB-2, Diesel Generator Reliability Qualification Testing, the standby diesel generator manufacturer, Delaval Engine and Compressor Division, has performed a series of qualification tests to verify compliance with the requirements of the above-referenced NRC BTP.

Surveillance instrumentation is provided to monitor the status of the power supply and starting equipment of each standby generator.

Instrumentation and control are essential requirements in the design, installation, testing, operation, and maintenance of the standby generator.

All

RBS USAR 8.3-38 August 1987 conditions which can affect performance or indicate unavailability of each standby generator are annunciated in the main control room.

Local indicators and controls of each diesel generator are located within their respective rooms.

Remote indicators and controls are located in the main control room on separate sections of the control board. Additional information on instrumentation and controls is presented in Section 7.3.1.

The controls and instrument cables are routed to prevent common failure.

All control switches on the main control board are clearly identified as to the equipment that each switch controls (Section 7.1.2.3).

Factory testing of the standby ac power systems was performed as defined in IEEE-387, Criteria for Diesel-Generator Units Applied as Standby Power Supplies for Nuclear Power Generating Stations.

Standby diesel generator 1EGS*EG1A was given 37 start qualification tests in accordance with IEEE 387 and IEEE 323 at the TDI factory.

Each start verification test was performed from a

standby temperature of 150°F

-10°F and included pickup of 1,750 kW within 10 sec of the start signal (there were no start failures).

Various additional TDI factory qualification tests were performed for both standby diesel generators as discussed in Item 2 of Reference 3.

In

addition, qualification tests were performed at River Bend Station in accordance with Regulatory Guide 1.9, Paragraphs C.13 and C.14, and Regulatory Guide 1.108, as discussed in Section 8.3.1.1.5.2.

8.3.1.1.4.2 High Pressure Core Spray Power Supply System The protection system of the HPCS diesel generator is described as follows:

1.

The following conditions render the HPCS diesel generator incapable of responding to an automatic emergency start signal:

a.

Diesel generator lockout relays not reset.

b.

Diesel engine mode switch not in "AUTO" position (mode switch in "MAINTENANCE" or "TEST" position).

c.

Diesel generator output breaker closed before start of diesel.

RBS USAR 8.3-39 August 1987 d.

Diesel generator output breaker in racked-out position.

e.

Diesel generator regulator mode switch not in "AUTO" position.

f.

Insufficient starting air pressure.

g.

Loss of dc power to diesel generator controls or the 4,160 V switchgear.

h.

Diesel engine trip/lockout relay not reset.

i.

Low fuel oil level in day tank.

Items e and i

do not electrically block diesel generator from emergency starting;

however, these conditions are
checked, and corrected if necessary, prior to allowing diesel generator to respond to an automatic emergency start signal.

2.

The following alarms are provided at the main control room annunciator for above-listed conditions.

a.

Items a, b (mode switch in "TEST"), d, e, f, and g are annunciated as "HPCS SYSTEM NOT READY FOR AUTO START".

b.

Item c is indicated by means of breaker status light (RED).

c.

Item b

(mode switch in "MAINTENANCE")

is annunciated as "DIESEL ENGINE IN MAINTENANCE."

d.

Item h

is annunciated as "DIESEL ENGINE TRIP" alarm.

e.

Item i is annunciated as "DIESEL ENGINE TROUBLE" alarm (common alarm).

3.

The following HPCS diesel generator emergency conditions are annunciated locally on the diesel generator control panel and as a common "DIESEL ENGINE TROUBLE" alarm in the control room:

a.

Engine failure to start/run b.

Engine overspeed

RBS USAR 8.3-40 August 1987 c.

Low fuel level d.

Crank case pressure high e.

High lube oil temperature f.

High water temperature g.

Charger failure h.

Engine tripped i.

Main fuel pump failure j.

Low lube oil temperature k.

Low expansion tank water level l.

High stator temperature m.

Reserve fuel pump failure n.

Low lube oil pressure o.

Low cooling water pressure p.

Low turbocharger lube oil pressure q.

Restricted fuel oil filter r.

Restricted lube oil filter s.

Low starting air pressure t.

Control power failure u.

DC turbo lube oil pump running v.

DC circulating lube oil pump running.

4.

The following additional alarms also are provided in the control room:

a.

HPCS 4-kV bus auto trip b.

HPCS system undervoltage c.

HPCS pump motor overcurrent d.

Diesel engine running

RBS USAR 8.3-41 August 1987 e.

125-V dc system trouble f.

HPCS battery charger trouble g.

Generator trip/lockout h.

Diesel engine generator overcurrent i.

HPCS system ground j.

HPCS 480-V system undervoltage k.

Division III degraded voltage l.

Diesel engine overspeed m.

HPCS control power failure or breaker in lower position n.

Remote shutdown transfer switch in emergency position.

When the HPCS diesel generator is called upon to operate under accident conditions, the only protective devices used are the generator differential relays and engine overspeed trip device.

The engine overspeed trip device is mechanical and trips the engine directly.

The trips are annunciated in the main control room.

Other protective relays, such as loss of excitation, anti-motoring (reverse power),

overcurrent with voltage restraint, high jacket water temperature, and low lube oil

pressure, are used to protect the machine when it is operating during periodic tests. These relays are automatically removed from the tripping circuits under accident conditions.

In addition to these protective relays, a normal time delay overcurrent relay senses generator overload and causes an alarm in the main control room.

The generator differential relays and overspeed trip device are retained under accident conditions to protect against what can be major faults which could cause significant damage.

All the bypassed protective devices cause alarms in the main control room and the operator then has sufficient information to take necessary corrective action.

Because during accident conditions the HPCS diesel generator is performing a

safety-related

function, these protective devices are insignificant so far as the engine condition is concerned.

The engine is capable of operating under these abnormal conditions, and it is left to the operator's judgment whether to operate the engine or trip it manually.

RBS USAR Revision 16 8.3-42 March 2003 8.3.1.1.4.2.1 Qualification Testing A prototype test has been performed to establish the adequacy of the diesel generator unit to successfully accelerate the HPCS pump and system loads. The test consists of starting an HPCS system in an actual HPCS pump loop test (HPCS system in condensate to condensate test mode) with auxiliary loads several times within the design time requirement. A topical report on HPCS power system unit, NEDO-10905, and subsequent amendments describe and show theoretical and experimental evidence as to the adequacy of the design. The topical report has been further amended to include the results of the prototype qualification test cited above.

16 In order to comply with the requirements, the tests described in NEDO-10905, Section 6.6 have been performed.

16

Start and Load Reliability Test

1.

Prior to initial fuel loading of the reactor unit, a series of tests will be conducted to establish the capability of the HPCS diesel generator unit to consistently start and load within the required time.

2.

With the exception of those diesel engine/generator designs that are identical (minor changes may be justified by analysis) to the diesel generator unit(s) which have been previously qualified for the HPCS application, all other different diesel engine/generator combinations will be individually qualified for reliable start and load acceptance requirements.

3.

An acceptable start and load reliability test is defined as follows: A total of 69/n (where n is the number of diesels, 1) valid start and loading tests with no failure or 128/n valid start and loading tests with a single failure will be performed. Failure of the unit to successfully complete this series of tests as prescribed will require a review of the system design adequacy, the cause of the failure to be corrected, and the tests continued until 128 valid tests are achieved without exceeding the one failure.

The start and load tests will be conducted for 69 cold fast starts.

RBS USAR 8.3-43 August 1987 The fast starts are conducted with the engine in a

ready standby status and include a loading to at least 50 percent of the continuous load and operation at this load for at least 1 hr.

During and/or following this

testing, some individual components of the diesel generator or its support systems may require maintenance and/or replacement. This maintenance and/or replacement due to wear does not require retesting.

If the cause for failure to start or accept load in accordance with the preceding sequence falls under any of the following categories, that particular test may be disregarded, and the test sequence resumed without penalty following identification of the cause for the unsuccessful attempt:

a.

Unsuccessful start attempts which can definitely be attributed to operator error including setting of alignment control

switches, rheostats, potentiometers, or other adjustments that may have been changed inadvertently prior to that particular start test.

b.

A starting and/or loading test performed during routine maintenance or trouble-shooting.

All maintenance procedures are defined prior to conducting the start and load acceptance qualification tests and become a

part of the normal maintenance schedule after installation.

c.

Failure of any of the temporary service systems such as dc power source, output circuit breaker,

load, interconnecting
piping, and any other temporary setup which will not be part of the permanent installation.

d.

Failure to carry load which can be definitely attributed to loadings in excess of the HPCS diesel generator rating.

e.

Unsuccessful start attempts which were conducted with the intent of eventual

failure, e.g.,

the last attempt when determining capacity of the air start system.

RBS USAR 8.3-44 August 1987 8.3.1.1.4.3 Containment Electrical Penetration Protection Electric circuits penetrating the primary containment through Class 1E electrical penetrations are classified as follows:

1.

Medium voltage power 4.16-kV, three-phase 2.

Low voltage power:

a.

480-V three-phase feeders from load centers b.

480-V three-phase feeders from motor control centers c.

120/240-V single-phase feeders from lighting and distribution transformers.

3.

Low voltage control and signal power:

a.

120-V single-phase b.

125-V dc 4.

Instrumentation circuits Containment electrical penetration assemblies are designed to withstand, without loss of mechanical integrity, the maximum fault current versus time condition which could occur because of single random failure of circuit overload protective devices.

No single failure causes excessive current in penetration conductors which degrade penetration seals.

All protective devices automatically disconnect power to the penetration conductors when currents through the conductors exceed the established protection limits. Medium voltage power (4.16 kV) penetrations are protected against overload by two redundant breakers.

These breakers are qualified for their service environment and receive tripping signals from two independent

channels, physically separated and powered by separate sources.

Short circuit protection is provided for low-voltage power penetrations by two devices - a primary protective device and a

backup protective device - with the electrical penetration rated for the most severe duty of the two devices.

Both protective devices are qualified for their service environment.

When the electrical penetration is rated to carry the available short circuit continuously, no backup protection device is

required, e.g.,

in an instrument circuit which inherently has high impedance and is subjected to low short circuit currents.

RBS USAR Revision 10 8.3-45 April 1998 Electrical penetrations containing power circuits listed in 2a and 2b above are nominally rated to carry 180 percent of full load current continuously with all other circuits in the same penetration operating at full load.

Overload protection of electrical penetration 480-V motor control center power circuits is provided by a

series-connected molded case circuit breaker and

fuse, each rated to open the circuit during overload conditions, thus providing redundant protection.

Penetration protection for 120-V ac lighting and distribution panels are provided by series-connected molded case circuit breakers located between the lighting or distribution transformer secondary and the electrical penetration.

No redundant protection is provided for neutron monitor SRM and IRM motor module loads fed from 1NHS-MCC2C since the penetration assembly is designed to carry the maximum available fault current continuously.

  • 10 480-V load center load circuits are protected by redundant protection devices as in the case of the polar crane.

Redundant protection consists of either the feeder breaker backed up by the secondary main breaker (via time overcurrent relay logic tripping) for the containment unit cooler

circuits, or, of a

power supply fuse backed up by the feeder

breaker, as for the hydrogen recombiner circuits.

10*

Low-voltage control circuits evaluated fall into one of the following categories:

1.

The circuit is self-protecting due to the limited available short-circuit current at the penetration being less than the continuous rating of the penetration.

2.

Backup protection is provided.

3.

The circuit has been analyzed and it has been determined that backup protection is not warranted (i.e.,

CT leads on differential

circuit, trip coil circuits).
  • 10 4.

Administratively deenergizing the circuitry during plant operation (i.e.,

ERF

system, space heaters for motors, and LS compartments).

10*

RBS USAR 8.3-46 August 1987 8.3.1.1.5 Maintenance and Testing 8.3.1.1.5.1 Auxiliary Electrical Power Supply Systems Maintenance and testing of auxiliary electrical power system equipment are conducted to ensure that all components are operational within their design limits.

Maintenance and testing are performed periodically throughout station life in accordance with normal station operating procedures to:

1.

Detect the deterioration of the components of the system toward an unacceptable condition and to take corrective action as required to bring the components to an acceptable condition.

2.

Demonstrate the capability of the components which will normally be deenergized to perform properly when energized.

The inherent redundancy of the standby electrical systems permits support of full functional testing of systems or subsystems.

Components of the standby systems can be made inoperable for short time test purposes without impairing the ultimate capability of the systems and the subsystems which they support.

Information concerning the ability of the power systems important to safety to meet the requirements of GDC 18 is given in Section 3.1.2.18.

The capability for testing and calibrating all actuation devices,

circuits, electrical protective
relays, and related instrumentation during normal operation is designed into the power systems important to safety and in accordance with the recommendations of Regulatory Guide 1.22.

Provisions to perform nondestructive tests under simulated fault conditions are provided.

This includes but is not limited to the ability of the protection system to initiate the operation of the actuated equipment.

8.3.1.1.5.2 Standby Electrical Power Supply Systems Maintenance and testing of the standby diesel generators are conducted to ensure that all components and auxiliaries are operational within their design limits.

In addition to the qualification tests conducted on each diesel generator set at the engine manufacturer's factory, the standby diesel generators are subjected to 69/n (where n is the number of diesels, 2) start and load tests with no single failure or 128/n start and load tests with a single failure.

Failure of a diesel to complete this series of

RBS USAR Revision 8 8.3-47 August 1996 tests will require a review of system design adequacy, the cause of failure to be corrected, and the tests continued until 128/n valid tests are achieved without exceeding the one failure criterion.

The start and load tests are conducted with the engine in the ready standby status and include a loading to at least 50 percent of the continuous load and operation at this load for at least 1 hr.

Each diesel generator set was given a

load capability test at their rated load of 3,500 kW for 24 hr.

However, the standby diesel generators will not be loaded above the loads indicated in Tables 8.3-2a and 8.3-2b.

Therefore, the 24-hr, 3,500-kW load capability test more than satisfies the 110 percent overload requirement of paragraph C.2.a(3) of Regulatory Guide 1.108 when applied to the qualified load.

The following tests were performed in accordance with IEEE-387 after complete installation of the standby diesel generator system at River Bend Station.

a.

Starting test b.

Load acceptance test c.

Rated load tests d.

Design load tests e.

Load rejection tests f.

Electrical tests g.

Subsystem tests

  • 8 Periodic tests are performed to verify that systems and components of the standby diesel generators perform satisfactorily and to ensure that the standby diesel generator systems meet their availability requirements.

These tests are performed during nuclear plant operation according to Regulatory Guide 1.108 and are described in the Technical Specifications/

Requirements.

8*

Testing procedures indicate that no-load and light-load conditions are to be avoided and testing should be accomplished with a

minimum loading of 25 percent of rated load.

Some exceptions to this are allowed such as time start checks when other equipment is found inoperable.

The normal maintenance and surveillance schedule provides sufficient loaded running time to minimize detrimental effects of these exceptions.

RBS USAR Revision 8 8.3-48 August 1996 Emergency diesel generator equipment failures are repaired

promptly, and an evaluation as to the cause of the failure is performed and documented in equipment history.

Administrative procedures provide approved methods for design changes or replacement of equipment with high failure rates.

After major maintenance or extended outage of the

diesel, a

complete system lineup per the system operating procedure is performed prior to a

start attempt.

This includes

valve, electrical, instrument, and control board lineups as well as a

visual inspection of the diesel generator and its auxiliaries.

In addition, compliance with the protective tagging and temporary alterations procedures along with system restoration sections of maintenance and surveillance procedures ensure system readiness.

Upon completion of any manual, test, or auto start of the diesel, the operator is directed by the surveillance or system operating procedure to place the diesel in an automatic standby readiness condition.

Compliance with Technical Specifications, administrative and system operating procedures, and the preventive maintenance and surveillance testing schedule ensures optimum equipment readiness and availability upon demand.

8.3.1.1.5.3 High Pressure Core Spray Power Supply System

  • 8 Readiness of the HPCS diesel generator is demonstrated by periodic testing according to Regulatory Guide 1.108 and is described in the Technical Specifications/Requirements.

The testing program is designed to test the ability to start and accept the HPCS diesel generator design loads connected to bus 1E22*S004.

The HPCS diesel generator is run for 24 hr at its continuous rating of 2,600 kW, 2 hr of which it is subjected to a 110-percent overload test (see Table 8.3-3).

This ensures that cooling and lubrication are adequate for extended periods of operation.

Full functional tests of the automatic control circuitry are conducted on a

periodic basis to demonstrate correct operation (Section 7.3.2).

8*

Means are provided for periodically testing the chain of system elements from sensing devices through driven equipment to assure that the HPCS power supply is functioning in accordance with design requirements.

The drawout feature of protective relays allows replacement relays to be installed while the relay that is removed is bench tested and calibrated.

RBS USAR Revision 23 8.3-49 Startup of onsite power units can be initiated by simulation of LOCA signal or loss of power to the plant auxiliary power system.

Connection of the HPCS diesel generator to the HPCS bus takes place automatically on loss of plant auxiliary power to the HPCS bus (HPCS bus low voltage). The HPCS diesel generator bus directional overcurrent, ground overcurrent, and phase overcurrent protective relaying provides a trip to the offsite power feeder breaker in case of loss of offsite power while the diesel generator is in the test mode operation.

8.3.1.1.5.4 Uninterruptible Power Supply Systems x o13 Maintenance and testing are conducted to ensure that all components of the 120-V ac uninterruptible power supply systems are operational within their design ratings, and the testing can be performed without disconnecting the loads from their power sources by use of the manual bypass switch. Maintenance and testing of equipment and systems are conducted periodically to detect deterioration of equipment toward an unacceptable condition and to take corrective action as required to bring the components to an acceptable condition. Preoperational and periodic testing complies with IEEE-308, Criteria for Class 1E Electrical Systems for Nuclear Power Generating Stations.

8.3.1.1.5.5 Testability of Offsite/Onsite Power Systems x o6 Testing the transfer from onsite power, of the main generator 1GMS-G1, through normal station service transformers, to offsite power, via the preferred station service transformers, can be performed when the reactor power is at a low load condition. The transfer from onsite power to offsite power is performed with buses loaded and is limited to 13.8-kV buses 1NPS-SWG1A and 1NPS-SWG1B as well as 4.16-kV buses 1NNS-SWG1A and 1NNS-SWG1B. Since 1NNS-SWG1C and E22-S004 are powered from either 1NNS-SWG1A or 1NNS-SWG1B, they will also transfer from onsite to offsite power as a result of the transfer of the bus it is aligned to (1NNS-SWG1A or 1NNS-SWG1B). Standby 4.16-kV buses 1ENS*SWG1A and 1ENS*SWG1B are always connected to preferred offsite power circuits and are therefore not affected in the transfer test.

Normal 13.8-kV buses 1NPS-SWG1C and 1NPS-SWG1D are always connected to preferred offsite power circuits and therefore not affected in the transfer test.

13mx x o7 x o4 Offsite power can be connected to 13.8-kV bus 1NPS-SWG1A via preferred transformer 1RTX-XSR1E and circuit breaker 1NPS-ACB11, and to 13.8-kV bus 1NPS-SWG1B via preferred transformer 1RTX-XSR1F and circuit breaker 1NPS-ACB27.

4mx 6mx 7mx

RBS USAR Revision 23 8.3-49a x o7 x o4 Onsite power can be connected to 13.8-kV bus 1NPS-SWG1A via normal transformer 1STX-XNS1A and circuit breaker 1NPS-ACB09, and to 13.8-kV bus 1NPS-SWG1B via normal transformer 1STX-XNS1B and circuit breaker 1NPS-ACB25. Offsite power can be connected to 4.16-kV bus 1NNS-SWG1A via preferred transformer 1RTX-XSR1C and circuit breaker 1NNS-ACB07, and to 4.16-kV bus 1NNS-SWG1B via preferred transformer 1RTX-XSR1D and circuit breaker 1NNS-ACB15.

Onsite power can be connected to 4.16-kV buses 1NNS-SWG1A and 1NNS-SWG1B via normal transformer 1STX-XNS1C and circuit breakers 1NNS-ACB06 and 1NNS-ACB14, respectively. The logic that 4mx 7mx

RBS USAR Revision 6 8.3-49b August 1993 THIS PAGE LEFT INTENTIONALLY BLANK

RBS USAR Revision 23 8.3-50 automatically transfers a 13.8-kV or 4.16-kV bus from onsite to offsite power is the loss of voltage on the respective 13.8-kV or 4.16-kV bus. The test is performed by manually tripping the 13.8-kV or 4.16-kV breaker from the normal transformer. The voltage loss causes the 13.8-kV or 4.16-kV breaker from the preferred transformer to close onto the respective 13.8-kV or 4.16-kV bus.

During the fast transfer, the outage is of such short duration that the motors remain running and the power system remains intact.

x o6 Offsite power is connected to 13.8-kV bus 1NPS-SWG1C via preferred transformer 1RTX-XSR1E and normally closed circuit breaker 1NPS-ACB43 and to 13.8-kV bus 1NPS-SWG1D via preferred transformer 1RTX-XSR1F and normally closed circuit breaker 1NPS-ACB44. 13.8-kV switchgear 1NPS-SWG1C and 1NPS-SWG1D do not have a back up source of power or transfer to another source.

6mx x o13 x o7 7mx Standby 4.16-kV bus 1ENS*SWG1A is connected to preferred transformer 1RTX-XSR1C via normally closed circuit breaker 1ENS*ACB06, to normal 4.16-kV bus 1NNS-SWG1B via normally open circuit breakers, and to standby diesel generator 1EGS*EG1A via normally open circuit breaker 1ENS*ACB07. Standby 4.16-kV bus 1ENS*SWG1B is connected to preferred transformer 1RTX-XSR1D via normally closed circuit breaker 1ENS*ACB26, to normal 4.16-kV bus 1NNS-SWG1A via normally open circuit breakers, and to standby diesel generator 1EGS*EG1B via normally open circuit breaker 1ENS*ACB27. The transfer test is performed for each bus as follows:

13mx

RBS USAR Revision 13 8.3-50a September 2000 THIS PAGE LEFT INTENTIONALLY BLANK

RBS USAR Revision 6 8.3-50b THIS PAGE LEFT BLANK INTENTIONALLY

RBS USAR Revision 20 8.3-51

8 13 The loading of a standby diesel generator is performed manually during testing while the reactor is in normal operation. The standby diesel generator is manually synchronized onto the standby bus and then carries selected standby loads. A synchronous check relay is provided to prevent breaker closure during synchronizing operations unless the busses are synchronized within the tolerances of the relay. By opening the breaker from the preferred stat ion service transformer and closing the breaker connecting the standby 4.16-kV bus to the normal 4.16-kV bus, the standby diesel generator load can be simulated to its approximate qualified load. Selected motors are running on the standby bus during the test.

8 13

8.3.1.1.5.6 Procedural Control of Jumpers and Other Temporary Forms of Bypassing Use of jumpers or other temporary forms of bypassing is controlled through implementation of the following procedures:

1.

Surveillance Test Procedures - These are written so that in the body of the procedure specific steps direct altering the system to accomplish testing; once testing is complete, specific steps also direct returning the system to the original condition. To ensure this is done

properly, a

second signoff by a

qualified individual is required to verify normal conditions.

2.

The Temporary Modifications (Alterations) procedure establishes the requirements and methods for controlling activities that temporarily altered the design function of a system or component. The requirements of this procedure applied to all activities that temporarily altered the design function of any component or system after the Preoperational/Acceptance Test Phase and the system or component had been turned over to the plant operating staff.

8 The changes covered were as follows: a change that inhibited or altered the intended operation of a plant component or system such as electrical jumpers, lifted wires, open links, piping blocks and bypasses, papered contacts, or temporary set points that were intended to be returned to normal or permanently incorporated at some later date and not otherwise covered by an approved procedure which returned the system back to normal.

8

RBS USAR Revision 24 8.3-52 x o8 8mx

3.

The maintenance work process uses several procedures that establish administrative controls for identifying, controlling, and documenting maintenance and maintenance-related activities.

These procedures provides step-by-step instructions to ensure that troubleshooting and/or maintenance is accomplished properly. It also provides for testing by use of approved surveillance test procedures to ensure the system or component has been properly repaired and returned to service.

x o14 x o7 The Shift Manager has complete control of all activities that might alter or prevent a system from performing as it is designed.

7mx 14mx 8.3.1.1.6 Safety-Related Systems Design Criteria 8.3.1.1.6.1 Electric Motors and Torque Considerations Motors employed for Class 1E service are designed and constructed to IEEE-323, -334, and -344 as well as all applicable industry standards in effect at the time of their purchase (Sections 3.9 and 3.11).

Motors are matched to the driven equipment so as to produce sufficient accelerating torque to successfully start the equipment at minimum available motor terminal voltage. A start is considered successful if rated speed can be obtained in less than 5 sec, and within the allowed motor heating curve. This has been generally achieved by requiring a minimum of 10 percent difference between the instantaneous available driver torque and driven equipment demand torque.

8.3.1.1.6.2 Temperature Monitoring and Circuit Protection The nature of Class 1E electrical equipment is such that protection of the equipment is secondary to accident mitigation and safe shutdown of the plant. Temperature monitors and overload heaters are set only to alarm on overload/overtemperature conditions during LOCA operation of Class 1E MOVs.

Trip circuits actuate only to prevent catastrophic failure which could augment rather than mitigate an undesirable circumstance. Coordination calculations show that protective devices actuate at the lowest level necessary to isolate a fault. All protective devices are set for a minimum of 125 percent of the full load current rating of the equipment at all Class 1E voltage

RBS USAR 8.3-53 August 1987 levels.

No cascading of protective devices has been employed.

See also Section 8.3.1.1.4.2 regarding HPCS circuit protection.

The River Bend Station design has been reviewed to identify any large horsepower (rated 100 hp or more) safety-related motor/pump combinations that have pressure switches or other permissive devices incorporated into the final actuation control circuitry.

These motors and permissive

devices, along with the redundancy and diversity provided for such
devices, are discussed in the following paragraphs.

1.

High-Pressure Core Spray System (E22)

Redundant undervoltage devices monitor bus voltage so that failure of one device to detect available HPCS power on the bus does not prevent the motor from starting.

However, if a loss of bus voltage is sensed by more than one channel of undervoltage

relays, the HPCS pump is inhibited from starting.

Certain protective trips can inhibit a

HPCS DG start under test conditions;

however, all but two of the DG trips are bypassed in the presence of an emergency start signal.

The two exceptions are the overspeed trip and the generator differential device trip which protects the diesel generator.

These devices are capable of being tested during normal operations.

Although redundancy of certain components is applied within HPCS in order to improve reliability, the overspeed and differential trips are not redundant by component.

The ECCS network is redundant by system.

2.

Residual Heat Removal System (E12)

There are no pressure switches capable of inhibiting a manual or automatic start of the RHR system.

The RHR pump motor switchgear receives a stop signal if either the 1E12*MOVF004B or 1E12*VF066B valve is full open and the valve 1E12*MOVF006B, 1E12*MOVF009, or 1E12*MOVF008 is not fully open.

Limit switches which sense the full open valve position and generate appropriate full open permissive are not redundant.

The ECCS network is redundant by system and can tolerate loss of an entire RHR train.

RBS USAR 8.3-54 August 1987 3.

Service Water System (SWP)

Emergency start of service water pumps 1SWP*P2A, 1SWP*P2B, 1SWP*P2C, and 1SWP*P2D is inhibited if the respective discharge valve is not fully closed or the standby service water initiation signal is not present.

The limit switch sensing the full closed valve position to generate the appropriate full closed permissive is not redundant.

However, redundancy does exist at the system level.

The standby service water initiation signal is either reactor plant component cooling water loop loss of pressure or normal standby service water loop loss of pressure.

Each loop is provided with four pressure sensors.

One-out-of-two-taken-twice logic is used in generating the start permissive, thus providing adequate redundancy.

The ability of the standby service water system to accommodate any single component failure without affecting safe shutdown or cooldown or post-accident heat dissipation is detailed in Section 9.2.7.3 and the FMEA.

As for common mode failures, these devices are qualified in accordance with Regulatory Guide 1.89.

During

shutdown, each pump can be verified to start automatically, on a pressure test signal to the pressure transmitters, to maintain service water pressure greater than technical specification requirements.

8.3.1.1.6.3 Interrupting Capacity of Switchgear and Other Protective Devices Fault current available at all voltage levels has been restricted to values within the certified rating of the interrupting devices employed at that level.

All possible sources of fault current contributions have been considered, including abnormal sources such as an emergency diesel generator on test.

Calculations of available short circuit currents are in accordance with ANSI C37.00-1964.

8Property "ANSI code" (as page type) with input value "ANSI C37.00-1964.</br></br>8" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process..3.1.1.6.4 Grounding The balance-of-plant and Class 1E Divisions I and II, both onsite and

offsite, power distribution systems are low-resistance grounded.

Discussion of grounding on the HPCS power supply (ESF Division III) is covered in Section 8.3.1.1.4.2.

RBS USAR Revision 13 8.3-55 September 2000 8.3.1.2 Analysis 8.3.1.2.1 General Functional Design Bases 8.3.1.2.1.1 Auxiliary Electrical Power Supply Systems The auxiliary electrical power supply systems provide ac power required for normal plant operation, shutting down the reactor safely, maintaining a safe shutdown condition, and operating all auxiliaries required for public safety under all

normal, transient, and accident conditions.

The following general functional design bases apply:

1.

The standby auxiliary electrical power supply systems distribute power to all loads which are essential for public safety.

2.

The normal and standby portions of the auxiliary electrical power supply systems are arranged so that a single failure does not prevent safety-related systems from performing their intended safety functions.

  • 13 3.

The standby 4.16-kV buses are arranged so that they can be supplied from preferred or standby power sources.

4.

Sufficient instrumentation is provided to ensure a

state of readiness and performance of the standby ac power system.

8.3.1.2.1.2 Standby Electrical Power Supply Systems The standby electrical power supply systems are designed with sufficient capacity and capability to ensure that they are capable to, in sufficient

time, restore ac power in the event that the preferred power supply becomes unavailable.

They have the ability to reliably supply the required ac load demands of engineered safeguard equipment and controls for post-accident as well as safe and orderly shutdown operations so that the reactor core is cooled and containment integrity and other vital functions are maintained.

The following general functional design bases apply:

13*

1.

Standby ac diesel generators are housed in a

Seismic Category I structure with Seismic Category I walls separating them so that an accident involving one does not involve any others. Each fuel oil tank is contained in a separate

RBS USAR Revision 13 8.3-56 September 2000 Seismic Category I room, filled with sand to reduce the chance of fire around the oil tank.

2.

Each standby ac diesel generator produces ac power at the same voltage and frequency as the associated standby station service ac power distribution system.

Each is capable of automatic start at any time and of continuous operation at qualified

load, voltage, and frequency until manually stopped.
  • 13 3.

Each standby ac diesel generator is capable of being manually paralleled with preferred station service ac power source under normal conditions.

Provisions are made in the design to prevent the electrical interconnection of the redundant standby ac diesel generators.

4.

Each fuel oil system has a

storage capacity suitable for operating each standby diesel system at its maximum required post-accident load conditions for a minimum of 7 days.

The fuel oil system and storage is tornado and earthquake protected.

5.

Control power required for the operation of each standby ac diesel generator is supplied from its divisional standby 125-V battery system.

Standby auxiliaries, such as fuel pumps and ventilation systems, necessary for continuous operation of standby ac diesel generators are supplied from their associated standby buses.

6.

Upon loss of preferred ac power supplies, each of the standby buses is isolated from its preferred

sources, and the standby ac diesel generators start automatically and are ready to accept load within 10 sec.
Controls, both local and in the main control
room, are provided for manual start and stop of each standby ac diesel generator.

The output of each standby diesel generator is monitored, and abnormal conditions are alarmed in the main control room.

13*

7.

The ac diesel generator system is designed so that with loss of any one of three diesel generators the remaining generators are capable of supplying power to sufficient equipment for a

safe shutdown of the unit under normal or accident conditions.

RBS USAR Revision 16 8.3-57 March 2003

8.

Standby bus voltage does not dip below 75 percent of motor-rated voltage at any time during the loading sequence, and recovers to 90 percent of motor-rated voltage within 40 percent of each load sequence time interval. The ac diesel generator associated with the HPCS does not comply with this portion of Regulatory Guide 1.9;

however, its voltage recovery characteristics are operationally acceptable when starting its loads (Section 8.3.1.2.2.2).
9.

All Class 1E motors, except as noted below, are capable of starting and accelerating their driven equipment with 70 percent of motor nameplate voltage applied to motor terminals without affecting performance or equipment life.

16 12 8 The exceptions to this are certain motor-operated valves, motor-operated dampers, Division I and II diesel generator starting air compressors EGA-C4A, EGA-C4B, EGA-C5A and EGA-C5B, 1HVR*UC5, and the motors driving air compressors 1LSV*C3A and 1LSV*C3B. These LSV compressors have been environmentally qualified consistent with IEEE-323 and are capable of starting at 80 percent of motor nameplate voltage. Calculations have determined, however, that the minimum starting voltage available at the motor terminals will be 89.63 percent, well in excess of the motors' capabilities.

16

These Class 1E motor-operated valves, motor-operated dampers, Division I and II diesel generator starting air compressors EGA-C4A, EGA-C4B, EGA-C5A and EGA-C5B, and unit coolers are capable of starting and accelerating with 80 percent of motor nameplate voltage applied to motor terminals.

Calculations have determined that the minimum starting voltage available at the motor terminals during the period required for operation is in excess of the required starting voltage.

8 12

5 To ensure proper motor-operated valve function under design conditions, an analysis is performed to determine the torque or thrust that must be delivered to the valve stem by the motor operator under degraded voltage conditions (the calculated minimum starting voltage available).

5

10. All Class 1E motors are capable of continuous operation with 90 percent of motor nameplate voltage applied to motor terminals.

RBS USAR Revision 5 8.3-57a August 1992

  • 5 11.

The standby ac diesel generator sets will not be used for the purpose of supplying additional power to the utility power system (peaking).

12.

Table 8.3-7 identifies non-Class 1E circuits (loads) powered from Class 1E buses that are tripped off the buses during LOCA.

Also identified are non-Class 1E loads which have been evaluated not to adversely affect the Class 1E buses to which 5*

RBS USAR Revision 5 8.3-57b August 1992 THIS PAGE LEFT INTENTIONALLY BLANK

RBS USAR Revision 17 8.3-58 they are connected should a fault occur at the non-Class 1E load. This will ensure that the Class 1E systems are maintained at an acceptable level with respect to the requirements of IEEE-308.

8.3.1.2.1.3 Standby Uninterruptible Power Supply Systems (120-V ac)

15 Each of the four (ENB-INV01A, ENB-INV01A1, ENB-INV01B, and ENB-INV01B1) standby 120-V ac uninterruptible power supply systems has two standby alternating current sources and a standby direct current source of power. A standby 125-V dc station battery, the dc source, is a backup to the primary ac source. The primary and alternate ac sources can be selected by an automatic static transfer switch or a manually operated make-before-break bypass switch. The primary ac source is rectified into direct current which in turn is paralleled with the 125-V dc station battery source. The resultant dc is conducted to an inverter where it is changed to 120-V 60-Hz ac, and then conducted to a static switch.

The inverter frequency is synchronized with the alternate ac source, but it has its own internal frequency standard which it uses when the alternate ac source goes beyond normal frequency tolerance. The alternate ac source originates on a 480-V 60-Hz standby bus and is transformed and regulated to 120-V ac. It is then brought to the static switch, and also fed to the manual bypass switch.

The output of the static switch and the alternate ac source are the two inputs to the manual bypass switch (Fig. 8.3-1 and 8.3-2).

The static switch provides a high speed transfer upon loss of inverter power. The manual bypass switch allows the removal of the inverter or the static transfer switch for maintenance or testing.

15

The following general functional design bases apply:

1.

The 120-V ac uninterruptible power supply systems consist of independent and redundant power sources, with adequate capacity to supply all essential loads.

The loss of any one source will not affect the bus.

2.

The standby 120-V ac uninterruptible power supply systems are structurally designed in accordance with Seismic Category I criteria and are located in Seismic Category I structures.

RBS USAR Revision 17 8.3-59

3.

The standby 120-V ac uninterruptible power supply systems are designed to operate continuously without anomaly during and after the maximum seismic accelerations expected for the site.

15 1

4.

Standby 120-V ac uninterruptible power supply systems ENB*INV01A, ENB-INV01A1, and ENB*INV01B (or ENB-INV01B1) are physically and electrically independent (by division) and support redundant loads. It is not possible to parallel the outputs of these systems.

1 15

8.3.1.2.2 Design Criteria and Standards 8.3.1.2.2.1 ESF Divisions I and II Criterion 17 The ESF system is designed with sufficient

capacity, independence, and redundancy to assure that core cooling, containment integrity, and other vital safety functions are performed in the event of postulated accidents, assuming a single failure. The design of the onsite and offsite electrical power systems provides compatible independence and redundancy to ensure an available source of power to the ESF loads. Electrical power from the 230-kV switchyard to the 230/13.8-kV and 230/4.16-kV preferred station service transformers is provided by physically and electrically independent transmission lines. This provides two independent offsite sources of power to the 4.16-kV standby buses.

Offsite preferred power circuits are connected via normally closed breakers to standby 4.16-kV buses 1ENS*SWG1A and 1ENS*SWG1B (Divisions I and II) at all times. Loss of normal plant auxiliary supply does not influence or affect the normal 4.16-kV buses 1NNS-SWG1A and 1NNS-SWG1B tie circuits to standby 4.16-kV buses 1ENS*SWG1A and 1ENS*SWG1B.

13 The standby 4.16-kV bus 1E22*S004 (Division III) is connected to one of the offsite circuits (Fig. 8.1-4). Loss of all offsite power from the network, although highly unlikely, would result in automatic starting and connection of diesel generator set 1E22*S001G1C to the associated bus within 13 sec.

13

The degree of reliability of the power sources required for safe shutdown is very high due to independence and redundancy; it equals or exceeds all the requirements of Criterion 17.

RBS USAR 8.3-60 August 1987 Criterion 18 The auxiliary electrical system is designed to permit inspection and testing of all important areas and features, especially those which have a

standby function and whose operation is not normally demonstrated.

As detailed in the Technical Specifications, periodic component tests are supplemented by extensive functional tests during refueling outages (the latter based on simulation of action accident conditions).

These demonstrate the operability of diesel generator

sets, battery system components, and logic
systems, thus verifying the continuity of the systems and the operation of the components.

A complete preoperational test of the onsite ESF power distribution system is a prerequisite to initial fuel loading.

Regulatory Guide 1.6 The three standby ac power system divisions each consist of a

diesel generator set feeding its own ESF division load group.

Each load group has its own dc power

system, energized by a

battery and battery chargers.

The three load groups possess complete independence.

The standby power system redundancy is based on the capability of any two of the three load groups to provide the minimum safety functions necessary to shut down the unit and maintain it in the safe shutdown condition.

In addition to the prohibition of sharing standby power system components between load

groups, there is also no sharing of diesel generator power sources between units.

Each Division I

and II standby power source is composed of a

single generator driven by a

single diesel engine having fast-start characteristics and sized in accordance with Regulatory Guide 1.9.

The design of the standby power system is therefore in complete compliance with the regulations of Regulatory Guide 1.6.

Regulatory Guide 1.9 In accordance with Regulatory Guide 1.9, the ratings of standy diesel generators 1EGS*EG1A and 1EGS*EG1B are continuous load rating of 3,500 kW

each, and a

2-hour rating of 3,850 kW

each, which exceeds the sum of the loads required.

RBS USAR 8.3-61 August 1987 The sequencing of large loads at predetermined intervals (Table 8.3-2) ensures that large motors will have reached rated speed and that voltage and frequency will have stabilized before the succeeding loads are applied.

The decrease in frequency and voltage has been verified to be within 95 and 80 percent of nominal, respectively.

Recovery of voltage and frequency to within 10 percent and 2 percent of

nominal, respectively, has been verified to be accomplished within 40 percent of the sequencing interval of 5 sec.

Step loading and disconnection of the total diesel generator nameplate-rating load does not cause the standby diesel generator to exceed 110 percent of normal speed, thus precluding an inadvertent overspeed trip.

The reliability of the standby diesel generators has been substantiated by an extensive test program.

The tests verify the following diesel functions:

1.

Diesel fast start capabilities 2.

Load carrying capabilities 3.

Load shedding capabilities 4.

Ability of the system to accept and carry the applied loads up to its rated capacity 5.

Long-term no load running of the diesel unit without any detrimental effects.

The reliability of the system to start and accept loads in a

prescribed time interval has been demonstrated by prototype qualification test data augumented by analysis to verify the ability of the River Bend Station standby diesel generators to perform their intended function, and has been further verified by preoperational tests.

The preoperational tests described in Section 8.3.1.1.5.2 verify reliability after plant installation.

Full-load tests have been performed during preoperational testing at the River Bend Station on each diesel generator set to demonstrate the start and load capability of the units within the design requirements.

Three hundred valid start and load tests have been performed at the Shoreham I unit with no failures.

A valid start and load test is defined as a

start from normal standby temperature conditions with loading to at least 50 percent of continuous rating within the required sequencing time intervals, and continued operation until operating temperatures are reached.

The fast start tests to verify the diesel reliability were conducted in the factory.

They

RBS USAR 8.3-62 August 1987 are documented in the QA/QC verification data package, together with the results of other tests described, and provide a

permanent, onsite qualification record.

(Refer to NEDO 10905 May 1973, for reliability analysis of the HPCS standby power supply.)

Regulatory Guide 1.32 The design of the preferred power circuits provides for two immediately accessible circuits from the transmission network to the onsite power distribution system.

The sizing of Class 1E battery chargers is based on their ability to recharge the battery within 24 hr after discharge to a design minimum level of 105 V while supplying the maximum steady-state load which occurs in the post-accident period.

This is in accordance with the regulatory position of Regulatory Guide 1.32.

IEEE-308 All electrical system components supplying power to Class 1E electrical equipment are designed to meet their functional requirements under the conditions produced by the design basis events.

All redundant equipment is physically separated to maintain independence and eliminate the possibility of common mode failure.

All Class 1E equipment is located in Seismic Category I structures.

Class 1E equipment is uniquely identified by color coding of all components according to the division to which it is assigned, as detailed in Section 8.3.1.3.1.

Surveillance of Class 1E electric systems is in compliance with IEEE-308, as are all other aspects applicable to the station design.

This surveillance is detailed in the Technical Specifications.

IEEE-323 Conformance with IEEE-323 is described in Section 3.11.

8.3.1.2.2.2 High Pressure Core Spray Power Supply System -

Division III Criterion 17 The Class 1E system is designed with sufficient

capacity, independence, and redundancy to ensure that core
cooling, containment integrity, and other vital functions are

RBS USAR 8.3-63 August 1987 maintained in the event of a postulated accident.

The design of the onsite and offsite electrical power systems provides compatible independence and redundancy to ensure an available source of power to the HPCS system and its supporting auxiliaries.

Electrical power from the transmission network to the station is provided by two physically and electrically independent 230-kV circuits as required by the criterion.

The loss of all offsite power from the network, although highly unlikely, results in an automatic starting and connection of the HPCS diesel generator set to the HPCS bus.

The degree of reliability of the power sources required for safe shutdown is high, because of the independence and redundancy, and equals or exceeds requirements of the criterion.

Criterion 18 The auxiliary electrical system is designed to permit inspection and testing of all important areas and

features, especially those that have a standby function and whose operation is not normally demonstrated.

As detailed in the Technical Specifications, periodic component tests are supplemented by extensive functional tests during the refueling

outage, the latter based on simulation of actual accident conditions.

These tests demonstrate the operability of diesel generator

sets, battery system components, and logic systems and thereby verify the continuity of the systems and the operability of the components.

Because the diesel generator is a standby unit, readiness is of prime importance.

Readiness is demonstrated by periodic testing.

The testing program is designed to test the ability of the HPCS diesel generator set to start as well as to run under equivalent load as required by Regulatory Guide 1.108.

This ensures that cooling and lubrication are adequate for extended periods of operation.

Full functional tests of the automatic control circuitry are conducted in accordance with the Technical Specification on a

periodic basis to demonstrate correct operation.

Criterion 21 The protection system of the HPCS power supply is designed to be highly reliable and testable during reactor operation. The HPCS diesel generator is only part of the high pressure core spray system.

If it

fails, the redundant automatic

RBS USAR 8.3-64 August 1987 depressurization system reduces the reactor pressure so that flow from LPCI and LPCS systems enters the reactor vessel in time to cool the core and limit fuel cladding temperature.

Regulatory Guide 1.6 The HPCS diesel generator unit supplies power for the HPCS and other auxiliaries as shown in Table 8.3-3; therefore, failure of any single component of the HPCS diesel generator does not prevent the startup and operation of any other standby power supply.

The failure of any other standby diesel generator does not impede the operation of the HPCS diesel generator and its load

group, thus meeting the requirements of Regulatory Guide 1.6.

Regulatory Guide 1.6, Position 1 Conformance The HPCS Class 1E loads are assigned to a single division of the load groups.

The assignment is determined by the nuclear safety functional redundancy of the loads such that the loss of any one division does not prevent the minimum safety functions from being performed.

Regulatory Guide 1.6, Position 2 Conformance The HPCS bus (Division III of the ac load groups) is connectable to two different (preferred) offsite power sources.

The HPCS bus is also connectable to the HPCS diesel generator as the standby onsite power source (Fig. 8.3-3).

The HPCS diesel generator breaker can be closed automatically only if all other source breakers to the HPCS bus are open.

There is no automatic connection to any other division load group.

Regulatory Guide 1.6, Position 3 Conformance There is no automatic or manual connection of the HPCS system dc load group to any other division load group.

Regulatory Guide 1.6, Position 4 Conformance 1.

The diesel generators connected to the other divisions of the load groups are physically and electrically independent of each other.

The diesel generator connected to the HPCS division load group cannot be automatically paralleled with the diesel generator that is connected to another division load group.

RBS USAR 8.3-65 August 1987 2.

The HPCS diesel generator is connected to one independent division.

No means exist for automatically connecting the HPCS load group with any other.

3.

The HPCS load group is fed from only one diesel generator, as shown in Fig. 8.3-3.

No means are provided for transferring its loads to any other diesel generator.

4.

No means exist for manually connecting the HPCS load group to those of another division.

The HPCS load group is physically and electrically independent of all others.

Regulatory Guide 1.6, Position 5 Conformance The HPCS diesel generator comprises of a single generator driven by a single engine.

This diesel generator set neither operates in parallel with any other diesel generator set nor has tandom engines driving the single generator.

Regulatory Guide 1.9 Conformance with Regulatory Guide 1.9 is described in the following subsections for each regulatory position of Paragraph C of the guide.

Regulatory Guide 1.9, Position 1 Conformance Table 8.3-3 shows that the continuous rating of the diesel generator is greater than the maximum coincidental steady-state loads requiring power at any time.

Intermittent loads such as motor-operated valves are not considered for long-term loads.

Regulatory Guide 1.9, Position 2 Conformance The long-term steady-state load shown in Table 8.3-3 is within the continuous rating of the diesel generator.

Regulatory Guide 1.9, Position 3 Conformance The load requirements were verified during the preoperational tests described in Sections 14.2.12.1.8 and 14.2.12.1.44.

RBS USAR 8.3-66 August 1987 Regulatory Guide 1.9, Position 4 Conformance The design function of the HPCS diesel generator unit is considered to be a justifiable departure from strict conformance to Regulatory Guide 1.9, regarding voltage and frequency limits during the initial loading transient.

The HPCS diesel generator loads consist of one large pump and motor combination (approximately 2,500 hp),

one medium size pump (450 hp),

and other miscellaneous loads; consequently, limiting the momentary voltage drop to 25 percent and the momentary frequency drop to 5 percent would not significantly enhance the reliability of HPCS operation.

To meet these regulatory guide requirements, a diesel generator unit approximately two to three times as large as that required to carry the continuous full load would be necessary.

However, the frequency and voltage overshoot requirements of Regulatory Guide 1.9 are met.

A factory testing program on a

prototype unit has verified the following functions:

1.

System fast-start capabilities 2.

Load carrying capability 3.

Load rejection capability 4.

Ability of the system to accept and carry the required loads 5.

The mechanical integrity of the diesel-engine generator unit and all major system auxiliaries.

A detailed discussion of the calculated voltage and frequency transient response is given in Chapter 3 of the GE Licensing Topical Report NEDO 10905 (HPCS Power Supply Topical Report NEDO 10905, Section 6, describes prototype and reliability test requirements).

The design of the HPCS diesel generator conforms with the applicable sections of IEEE criteria for Class 1E electrical systems for nuclear power generation stations (IEEE-308).

In addition, a prototype test has been performed.

The generator has the capability of providing power for starting the required loads with operationally acceptable voltage and frequency recovery characteristics.

A partial or complete load rejection does not cause the diesel engine to trip on overspeed.

RBS USAR 8.3-67 August 1987 Regulatory Guide 1.29 The HPCS electric system is capable of performing its function when subjected to the effects of design bases natural phenomena at its location.

In particular, it is designed in accordance with the Seismic Category I criteria and is housed in a Seismic Category I structure.

Regulatory Guide 1.32 The design of the HPCS power supply system conforms with the applicable sections of IEEE criteria for Class 1E electrical systems for nuclear power generation stations IEEE-308.

Note:

GE Licensing Topical Report NEDO-10905 describes prototype and reliability test requirements.

Regulatory Guide 1.47 All the bypassed trip devices provide alarms in the main control room so that conditions which can render the HPCS diesel generator system unavailable for automatic start are automatically annunciated at the system level in the main control room.

See NEDO 10905, Amendment 1, p 20.

Regulatory Guide 1.62 Manual controls are provided to permit the operator to select the most suitable distribution path from the power supply to the HPCS load.

An automatic start signal overrides the test mode.

Provision is made for control of the system from the main control room as well as from an external location.

Regulatory Guide 1.75 The HPCS diesel generator is a

Division III device and is separated from equipment of other divisions.

It is marked with a Division III name tag.

Regulatory Guide 1.100 All Class 1E equipment of the HPCS system is seismically qualified to the requirements of IEEE-344-1971 which was the plant requirement for this equipment.

A re-evaluation to the requirements of IEEE 344-1975 and Regulatory Guide 1.100 is in progress and will be reported upon completion.

RBS USAR 8.3-68 August 1987 Regulatory Guide 1.106 Electric motors on motor-operated valves have been identified as a significant intermittent load on the general ac power system.

This regulatory guide describes acceptable methods of disabling thermal protective devices on motor-operated valve motors.

Thermal overload devices normally in force during normal plant operation are bypassed under accident conditions.

Regulatory Guide 1.118 This regulatory guide describes acceptable means for periodically testing the functional performance and responses of the electric power and protection systems.

The requirements of this regulatory guide are met with the following clarifications:

Position C.6 Trip of an associated protective channel or actuation of an associated Class 1E load group is required on removal of fuses or opening of a breaker only for the purpose of deactivating instrumentation or control circuit.

IEEE-279 The HPCS diesel generator and its supporting auxiliaries conform to all requirements of IEEE-279 which are applicable to singular diverse elements of a redundant set.

IEEE-308 All the electric system components supplying power to the HPCS system consist of Class 1E electric equipment and are designed to meet their functional requirements under the conditions produced by the design basis events.

All the redundant equipment is physically separated to maintain independence and to minimize the possibility of a common mode failure.

All Class 1E equipment is located in Seismic Category I structures.

The HPCS Class 1E equipment is uniquely identified by color coding of the components according to the division to which it is assigned, as detailed in Section 8.3.1.3.1.

Surveillance of the Class 1E electric systems is in compliance with the

standard, as are all other aspects applicable to the station design.

RBS USAR Revision 8 8.3-69 August 1996 IEEE-323 Conformance with IEEE-323 is described in Section 3.11.

IEEE-344 Conformance with IEEE-344 is described in Section 3.10.

IEEE-387 The HPCS power supply unit is completely independent of other standby power supply units and meets the applicable requirements of IEEE-387.

The HPCS diesel generator unit is designed to:

1.

Operate in its service environment during and after any design basis event without support from the preferred power supply.

2.

Start, accelerate, and be loaded with the design load within an acceptable time:

a.

From the normal standby condition, b.

With no cooling available, for a time equivalent to that required to bring the cooling equipment into service with energy from the diesel generator unit, c.

On a

restart with an initial engine temperature equal to the continuous

rating, full load engine temperature.

3.

Carry the long-term steady-state load continuously.

4.

Maintain voltage and frequency within limits that will not degrade the performance of any of the loads composing the design load below their minimum requirements, including the duration of transients caused by load application or load removal.

  • 8 5.

Withstand any anticipated vibration and overspeed conditions.

The generator and exciter are designed to withstand 25 percent overspeed without damage.

8*

RBS USAR Revision 8 8.3-70 August 1996

  • 8 The HPCS diesel generator has continuous and short-term ratings consistent with the requirements of IEEE-387, Section 5.1.

8*

8.3.1.2.3 Conformance With Appropriate Quality Assurance Standards The quality assurance program outlined in Chapter 17 conforms with Regulatory Guide 1.30, Quality Assurance Requirements for the Installation, Inspection, and Testing of Instrumentation and Electric Equipment.

The program outlined in Chapter 17 includes a

comprehensive system to ensure that the purchased

material, manufacture, fabrication, testing, and quality control of the equipment in the standby electric power system conforms to the evaluation of the standby electric power system equipment vendor quality assurance programs and preparation of procurement specifications incorporating quality assurance requirements.

The administrative responsibility and control provided are also described in Chapter 17.

These quality assurance requirements include an appropriate vendor quality assurance program and organization, purchaser surveillance as

required, vendor preparation and maintenance of appropriate test and inspection
records, certificates and other quality assurance documentation, and vendor submittal of quality control records considered necessary for purchaser retention to verify quality of completed work.

A necessary condition for receipt, installation, and placing of equipment in service has been the sighting and auditing of QA/QC verification data and the placing of this data in permanent onsite storage files.

8.3.1.2.4 Environmental Qualification for Electrical Equipment Located in a Harsh Environment See Section 3.11.

RBS USAR



(1)T = cable tray; C = conduit Revision 17 8.3-71 8.3.1.3 Physical Identification of Safety-Related Equipment 8.3.1.3.1 Color Coding Color coded identification is provided for all safety-related equipment including cables, cable raceway, motors, panelboards, motor control centers, load centers, and switchgear. This identification may be by means of a letter, nameplate, paint, nondeteriorating self-adhesive tapes, permanently affixed tags, or similar means. Nonsafety-related equipment has no color identification.

Color coding is in accordance with the following:

Equipment and Identification Cable Function Color Letter Raceway Type(1)

Nonsafety-Related None (or black)

N T or C Safety-Related Div. I Red R

T or C Div. II Blue B

T or C Div. III Orange O

T or C Reactor Protection System

a.

Input Channels (Sensors and Logic)

Channel A Red/Yellow S

C Channel B Blue/Yellow T

C Channel C Orange/Yellow U

C Channel D Purple/Yellow V

C

b.

Output Trip Logic Group 1 Red/Green I

C Group 2 Blue/Green J

C Group 3 Orange/Green K

C Group 4 Purple/Green L

C 8.3.1.3.2 Equipment Identification Each piece of equipment, each scheduled tray or conduit, and each scheduled cable, both safety-related and nonsafety-related, has an alphanumeric identification.

A

code,

RBS USAR Revision 17 8.3-72 has been created to identify equipment items.

8 The equipment code format for mark numbers explained below is for historical purpose only. The mark numbers created by the equipment code format have been changed to equipment numbers in the Equipment Data Base (EDB). The mark numbers are cross-referenced to the equipment numbers in the EDB. The asterisk (*)

was previously used in this equipment code format to indicate safety related. The equipment numbers have a separator which is a dash (-), however, this has no significance in relation to its safety classification. Refer to the EDB for the proper equipment number and safety classification.

8

The equipment code has the following format:

X XXX

-(or)*

XXXXXXXXXXX Unit System QA Category Equipment Code Classification Item identification Example:

1CWS-MOV104 1 - Unit CWS - System code (circulating water system)

- - equipment so designated is Quality Assurance Category II or III MOV - Equipment (motor-operated valve) 104 - Identification Example:

1ENS*SWG1A 1 - Unit ENS - System code (standby 4.160-V switchgear)

  • - Equipment so designated is Quality Assurance Category I SWG - Equipment (switchgear) 1A - Identification Safety-related equipment and nonsafety-related equipment other than for the communications system are identified by nameplates which are permanently attached. The nameplates are made of laminated plastic or metal and engraved with the equipment identification number. The master nameplate for safety-related equipment is color coded. Communications system equipment is identified by stenciling the identification on or adjacent to the equipment.

The cable identification for scheduled cables has the following format:

X XXX X

X X

XXX Unit System Part Color Service Number Code Unit - Identifies the station's unit number.

System Code - Three characters identifying the system.

RBS USAR Revision 8 8.3-73 August 1996 Part One symbol which can be either an alpha or a

numeric designator, e.g.,

an MCC cubicle section or one pump of a group (A, B, C, etc).

Color

- An alpha symbol indicating whether the cable is safety-related or nonsafety-related.

Service An alpha character indicating the type of service for which the cable will be utilized.

Number Three characters assigned to specify each individual cable number.

Example:

1ENS AR H307 All scheduled cables are identified by permanent colored markers attached to the cable at each end adjacent to the cable alphanumeric identification marker.

The background color of the alphanumeric identification marker may be used as the permanent colored marker.

Except for the cables run entirely in

conduit, color code identification of a circuit is either by the color coded jacket of the cable or by painting the cable jacket with the proper color at intervals not exceeding 5 ft.

Cables with red-or blue-colored jackets may be used on unscheduled non-Class 1E circuits that run exclusively in conduit, only when the following mandatory conditions have been implemented:

1.

Neutral tags indicating non-Class 1E circuits are permanently attached at each end of the cable run and wherever the cable is

exposed, and field quality control has verified 100 percent that this condition has been met.

2.

No color-jacketed cable used for unscheduled non-Class 1E application is allowed to be terminated in or pass through an enclosure (pull

box, junction
box, cabinet) containing divisional Class 1E circuits.
  • 8 Cables with red-or blue-colored jackets may also be used for direct burial cable installations and for the following applications, in various types of raceways, where there are only nonsafety-related circuits:

a.

Inside the makeup water intake structure b.

On the sanitary waste and disposal system

  • 8

RBS USAR

8

8

Revision 17 8.3-74

8

c.

On the closed loop service water site *

d.

Leading Edge Flow Meter (LEFM) transducer cables in the Turbine Building.

At these locations there are no safety-related Category I circuits. No safety-related circuits are installed in direct burial cable trenches.

8 The raceway identification has the following format:

X X

X XXX X

X X

Unit Type Service Number Color Condu/A Condu/N Unit

- Identifies the station's unit number.

Type

- Character indicating the type of raceway.

Service

- An alpha symbol which indicates the service of cable to be carried in the designated raceway.

Number

- Three numbers assigned to specify the individual raceway.

Color

- An alpha symbol which identifies the cable to be carried in the designated raceway, safety-related or nonsafety-related.

Condu/A

- Conduit identifier. It is a letter or blank when not used. When used for sleeves or duct, it is numeric or blank when not used.

All scheduled cable trays and conduits are identified by raceway identification numbers at each end, and at entries to and exits from enclosed areas. Tray sections longer than 50 ft have an additional raceway identification number at midspan and at intervals not exceeding 50 ft, while tray sections 15 ft or less have a raceway identification number at midspan. Exposed conduits 8 ft or less have a raceway identification number at midspan except that for those short sections of conduit where the identification will not fit in midspan, the conduit is color-coded only (e.g., a short nipple from a junction box to a piece of equipment). Color-coded markers are provided for all Class 1E raceways adjacent to each raceway identification number, or the numbers themselves may be painted in the appropriate color and at intervals not exceeding 15 ft.

RBS USAR Revision 13 8.3-75 September 2000 8.3.1.4 Independence Of Redundant Systems 8.3.1.4.1 General

  • 13 There are three basic safety-related power supply divisions that originate at the 4,160-V level.

The Divisions I, II and III safety-related power supply systems can be energized from preferred power source and from their own diesel generator.

The systems serve equipment at the 4,160-V, 480-V, and 120/240-V ac levels, and through intervening equipment they power the 125-V dc system.

13*

A dedicated diesel generator serves each division.

Each diesel generator with its supporting auxiliaries is in a separate room, as shown in Fig. 8.3-11.

The 4160-kV switchgear, 480-V load centers, 480-V motor control centers, a battery charger for each battery, 125-V batteries, and uninterruptible power supplies are located in switchgear rooms within the control building and are separated by division as illustrated by Fig. 8.3-9 and 8.3-10.

Safety-related 4.16-kV motor

loads, a

480-V load

center, 480-V motor control centers, and loads subordinate to the 480-V ac and 125-V dc sources are located within the auxiliary building, and are separated by division to ensure independence of safety-related divisions.

Additional safety-related loads are within the containment structure and at the standby cooling

towers, where separation between divisions is also maintained.

All the preceding equipment items are located within Seismic Category I structures.

Fire extinguishing systems are identified in Chapter 9.

8.3.1.4.2 Class 1E Electric Equipment Arrangement Redundant electrical equipment and wiring for the

RPS, nuclear steam supply shutoff system (NSSSS), and the ESF functions are physically separated, electrically independent, and are located such that no single credible event is capable of disabling redundant equipment which would prevent reactor shutdown, removal of decay heat from the core, nor which would prevent isolation of the containment in the event of an accident.

Separation requirements were applied to control, power, and instrumentation for all systems concerned.

Rules governing separation apply for Class 1E to Class 1E, and for Class 1E to non-Class 1E systems.

In addition, the distance between the electrical portions of the HPCS and RCIC systems is maximized within the space available to ensure the

RBS USAR Revision 16 8.3-76 March 2003 functional availability of high pressure water for core cooling immediately following a transient.

Arrangement and/or protective barriers are such that no locally generated force or missile can destroy any redundant RPS, NSSSS, or ESF functions. Arrangement and/or separation barriers are provided to ensure that such disturbances do not affect both HPCS and RCIC.

16 Arrangement of wiring/cabling is such as to eliminate, insofar as practical, all potential for fire damage to redundant cables and to separate the RPS, NSSSS, and ESF divisions so that fire within one division will not damage another division. In addition, approved fire protection features separate wiring and cabling of the HPCS and RCIC systems from ADS and RHR in the LCPI mode so that one train of these redundant systems remain free from damage such that safe shutdown can be achieved as described in chapter

9. The following general rules were followed:

16

1.

Routing of Class 1E control, power, and instrumentation cables through rooms or spaces where there is potential for accumulation of large quantities (gallons) of oil or other combustible fluids through leakage or rupture of lube oil or cooling systems is avoided. Where such routing is unavoidable, only one division of Class 1E cabling is allowed in any such space.

2.

In any room or compartment, other than the cable chases, in which the primary source of fire is of an electrical nature, cable trays of redundant systems have a minimum horizontal separation of 3 ft if no physical barrier exists between trays. If a horizontal separation of 3 ft is unattainable, a fire-resistant barrier is installed, extending at least 1 ft above (or to the ceiling) and 1 ft below (or to the floor) line-of-site communication between the two trays. Totally enclosed metallic raceway is occasionally used in lieu of barriers at least 1 inch under open cable trays, to a

point where the minimum separation is again maintained. Totally enclosed metallic raceway of redundant systems maintains a

minimum separation distance of 1 in.

3.

In any room or compartment, other than the cable chases, in which the primary source of fire is of an electrical nature, cable trays of redundant systems have a minimum vertical separation of 5 ft between vertically stacked trays of different divisions, or trays of different divisions one

RBS USAR 8.3-77 August 1987 above the other; however, vertical or cross stacking of trays is avoided wherever possible.

In cases where the redundant trays must be stacked or crossed one stack above the other, and when the trays do not meet the 5-ft vertical separation requirement, a

fire barrier is installed between the redundant trays.

The barrier extends beyond either side of the tray

system, in accordance with IEEE-384.

Occasionally, totally enclosed metallic raceway (e.g.,

conduit) is used in lieu of barriers in the following cases:

a.

Class 1E ladder type cable trays are fitted with protective covers wherever 480 V ac non-Class 1E cabling or 480 V ac Class 1E cabling of a

different division than the subject trays is routed in conduit within 1 in.

of the subject trays.

b.

Low voltage (120 V)

power, control, and instrumentation
cabling, when routed in close proximity to Class 1E ladder type cable trays, is routed in conduit and maintains at least 1-in.

separation.

c.

Totally enclosed metallic raceway of different Class 1E divisions maintains a minimum separation distance of 1 in.

Conduits containing cables of different Class 1E divisions which perform the same redundant safe shutdown functions are not routed in close proximity to one another.

4.

Any openings in fired-rated floors or walls for vertical or horizontal runs of Class 1E cabling are sealed with fire-resistant material of equal fire rating.

The minimum horizontal and vertical separation and/or barrier requirements in the cable chases are as follows (NOTE:

There are no cable spreading rooms in RBS):

1.

Where cables of different divisions approach the same or adjacent control panels with vertical spacing less than the 3-ft minimum, at least one division's circuit is run in totally enclosed metallic raceway or a

barrier is provided to a point where 3 ft of separation exists.

RBS USAR 8.3-78 August 1987 2.

A minimum horizontal separation of 1 ft is maintained between trays containing cables of different divisions where no physical barrier exists between trays.

Where a

horizontal separation of 1 ft is not attainable, either a fire-resistant barrier is installed extending at least 1 ft above (or to the ceiling) and 1 ft below (or to the floor) line-of-sight communication between the two trays or totally enclosed metallic raceway is utilized to meet separation requirements.

3.

Vertical stacking or crossing of trays carrying cables of different divisions is avoided wherever possible.

Where this is not possible, however, there is a minimum vertical separation of not less than 3 ft between trays of redundant systems.

4.

If vertical stacking or crossing of redundant trays is necessary and the minimum 3-ft vertical separation cannot be maintained, a

fire barrier is installed between the redundant trays.

The barrier extends 1 ft on each side of the tray system.

Totally enclosed metallic raceway is used in lieu of the barrier, with open cable

tray, to a

point where the minimum separation is maintained.

Totally enclosed metallic raceways of redundant systems maintain a

minimum separation of 1 in.

Where spatial separation distances are less than those specified above in accordance with IEEE-384, RBS plant-specific configurations were tested and analyses performed to justify reduced separation.

The test program methodology and results are documented in Wyle Test Report No. 47618-3.

Spatial separation and barrier requirements are shown on design drawings which are referenced in Section 1.7.

The minimum allowable separation distances are derived from the tested configurations as shown in Table 8.3-9.

The following summarizes and evaluates test results which validate the minimum separation criteria.

In order to perform a test program to verify the adequacy of RBS raceway separation it was necessary to define the worst case electrical failure that could be postulated to occur in a

raceway.

The RBS raceway separation test program was based on the following failure mode assumptions:

RBS USAR 8.3-79 August 1987 1.

The cable or equipment in the circuit develops a fault that is not cleared due to the failure of the primary protective devices.

2.

The worst case electrical fault is the most severe credible electrical fault that could occur.

The worst-case current is the lesser of locked rotor current (6XFLA) or the fault current just below the longtime trip of the backup circuit breaker. An additional 10-percent current is added to allow for various inaccuracies of the involved devices.

The worst case cable exhibits the highest temperature for the longest duration.

3.

For sustained overloads, the impedance of the fault adjusts itself automatically to maintain the fault current magnitude at a constant level as the resistance of the wire changes due to heating.

4.

The overloaded cable in its overheated condition stays undetected precluding any corrective operator action.

5.

The worst case effect on nearby raceways is established by a combination of temperature and the fault duration.

The fault current magnitude of 440 amperes (400 amperes +

10 percent of uncertainty) used in the test program was based on the failure mode assumptions discussed above.

This assumes that an overcurrent locked rotor condition occurs on a cable between a 480-V ac MCC and a

480-V load.

The primary overcurrent protective device which is a molded case circuit breaker at the MCC is assumed to fail to trip.

The next higher level (upstream) overcurrent device is the load center circuit breaker.

This current value was used for all tests involving cables in cable raceways and in free air. In order to select the size of cable to be used for configuration tests, screening tests were performed to determine which size cable when faulted would deliver the most intense temperature rise for the longest duration to adjacent cables.

The tests showed that the

  1. 2 AWG triplex copper cable was the worst case cable.

The RBS MCCs contain molded case breakers which provide overload and/or short-circuit protection for each load depending upon the application.

The load centers (LDC) contain air circuit breakers with solid-state trip devices.

The solid-state trip devices provide increased accuracy and repeatability over conventional trip devices.

The load

RBS USAR 8.3-80 August 1987 center breakers provide both long and short time overcurrent and instantaneous short-circuit protection.

Breakers of the MCC and LDC are maintained on a periodic basis.

This maintenance ensures that the likelihood of a coincidental failure of two overcurrent devices in series on the same feeder line is extremely small.

During each configuration test, the target cables were energized at their rated current and voltage.

At the completion of each configuration test, insulation resistance test and high potential test were performed for the target cables.

The target cables passed the above mentioned functional tests in accordance with the specified criteria.

The test program with above assumptions and inputs for the target cables generated the following results.

600-V cable installed in open air trays or conduits and faulted with the worst case internal fault (440 amperes) do not affect functionability (ampacity or insulation resistance) of any type of cables separated in accordance with the test configurations.

Cables were tested installed in horizontal and/or vertical raceways (including both cable tray and conduits) and in free air.

Table 8.3-9 depicts tested separation between cable trays, conduits, and cables in free air.

This table also reflects the minimum acceptable spatial separation, without use of

barriers, used at RBS.

The allowed spatial separation includes a margin in terms of distance and/or temperature.

An independent raceway system is provided for each Class 1E division.

The trays are arranged top to bottom based on the cable rated voltage.

1.

4.16-kV power (5,000-V insulation class) 2.

Large 480-V power (600-V insulation class) 3.

480-V power (600-V insulation class) 4.

Control (600-V and 300-V insulation class) 5.

Instrumentation cables (300-V insulation class)

Nonsafety-related, non-Class 1E electric systems generally have the same arrangement of cable trays with the addition of a cable tray position for 13.8-kV power (15,000-V insulation class) occupying the uppermost tray position.

RBS USAR 8.3-81 August 1987 8.3.1.4.3 Control of Compliance With Separation Criteria During Design and Installation Compliance with the criteria which preserve independence of redundant systems is a supervisory responsibility during both the design and installation phases.

The responsibility is discharged by:

1.

Identifying applicable criteria 2.

Issuing working procedures to implement these criteria 3.

Modifying procedures to keep them current and workable 4.

Checking manufacturer drawings and specifications to ensure compliance with procedures 5.

Controlling installation and procurement to assure compliance with approved and issued drawings and specifications.

The nomenclature used for equipment at the River Bend Station is the primary mechanism for ensuring proper separation.

All Class 1E electrical equipment has an attached nameplate inscribed with the equipment identification and color identification of its division.

Other Class 1E power system components, such as cables and raceways, have unique color assignment to identify safety-related systems.

These colors are readily apparent to the operators or maintenance craftsmen so the safety-related

cable, raceways, or equipment can be identified.

Nonsafety system circuits not associated with the safety circuits are either color coded black or have no color identification.

In every case it is possible to determine the quality group and separation classification of equipment from the construction drawings and specifications.

Nonessential equipment has been separated where it was desired to enhance power generation reliability, but such separation is not a

safety consideration.

This was accomplished by administratively directing use of raceway systems to separate critical companion BOP installations, such as the condensate pumps.

RBS USAR 8.3-82 August 1987 Where the safety-related equipment has been identified as an essential safety

division, the nomenclature indicates a

characteristic color for positive visual identification.

Likewise, all ancillary equipment, cable, and raceways match the nomenclature of the system which they support.

There are certain exceptions to the above where equipment which is not safety-related is connected to essential power sources for functional design reasons.

These circuits are identified in Table 8.3-7.

Cable used to connect nonsafety-related equipment to safety-related sources of power is safety grade and qualified and routed as a nonsafety-related circuit after first having been connected to a

Class 1E protective device.

It has no color assignment.

This equipment is disconnected and locked out during an accident by a

LOCA

signal, or protected by two qualified isolation devices.

8.3.1.4.4 Cable Design, Analysis, and Routing of Circuits 8.3.1.4.4.1 General Functional Design Bases The proper selection of cables and raceways preserves the reliability of redundant safety-related systems and conforms to the following design bases:

1.

The normal current loading of all insulated conductors is limited to that continuous value which does not cause insulation deterioration from heating.

Selection of conductor sizes is based on "Power Cable Ampacities" and "Ampacities -

Cables in Open-top Cable Trays" published by the Insulated Power Cable Engineers Association (IPCEA Publications P-46-426 and P-54-440, respectively).

For maintained spacing of cables in cable trays, plant-specific tests and evaluations have been conducted to demonstrate that spacing less than that specified in the IPCEA publications is acceptable as long as required spacing is maintained at cable tie-point intervals of 3 ft.

These tests and evaluations demonstrated adequate cable ampacity and temperature consistent with IPCEA guidelines.

For the small sizes not covered by the preceding, the National Electric Code (NEC) or more stringent regulations shall govern.

2.

All cable trays and supports are designed to carry the cables required without exceeding the allowable deflection and yield strength of the materials used in the trays and their supports.

RBS USAR Revision 22 8.3-83 All cable trays carrying cables for safeguard services are designed to meet Seismic Category I criteria. All raceways installed in Seismic Category I areas are seismically supported.

3.

Cables are specified with consideration of the optimum combination of insulation, fire-resistant, and radiation-resistant characteristics.

4.

Cables are sized and installed so as to limit the temperature rise of conductors to within the temperature ratings of the cable for any expected overload condition. All power cables are sized and installed to carry short circuit current until the first protective device disconnects the source feeding the short circuit.

8.3.1.4.4.2 Electrical Cable Arrangement Physical separation is provided between similar components of redundant electrical systems and between power and control circuitry serving or being served from these components.

Redundant protective power and control cables are run on physically separate cable trays or conduits and follow different routes to and from power sources to loads, and from sensors and controllers to protective devices. Therefore, an event which might damage the cables in one set of cable trays or conduit does not affect the redundant cables in the other set of cable trays or conduit.

Power cables for 15-kV and 5-kV service are stranded copper conductors. Power cables No. 2/0 AWG and larger for 600-V service are stranded aluminum or copper conductors. Smaller power cables and control cables have copper conductors. All cables, where required, are constructed with a radiation-resistant, 90°C thermosetting-type insulation and an overall flame-retardant, radiation-resistant jacket.

Cable trays used for 13.8-kV service are identified as "J" trays and those for 4.16-kV are identified as "H" trays. The "J" and the "H" trays are separate from one another. Trays for 600-V or lower voltage large power cables and some low power cables are designated "L." Trays for 600-V or lower voltage small power cables and some control cables are designated "K." Control cables of 120-V ac or 125-V dc, are run in "C" trays or conduit. Low level analog or digital instrumentation cables are run in "X" trays or in conduit. In the Drywell, non-divisional, Augmented Quality (but not safety-related), analog instrumentation cables for the main steam line strain gauges are routed both in flexible stainless steel conduit and external to conduit. In the Containment building, the cables are routed in cable tray and rigid conduit. Segregation in conduit is in a comparable fashion to that employed for trays.

RBS USAR 8.3-84 August 1987 Cables of redundant safety-related systems are isolated from each other and from nonsafety-related cables.

There are no medium-or high-voltage (480-V and above) power cables in the control building cable chases.

Electrical cables for the RPS and other safety-related systems located inside the containment structure are designed so that the cable is operable for the required period of usage during all postulated accident environments.

Cables in hazardous environments are protected from the environment and against physical or fire damage to the extent required for the service either by selection of cable or by choice of raceway (e.g., cable trays with covers, metallic conduit).

Cables are derated for grouping and spacing in accordance with IPCEA recommendations.

Medium voltage cable trays do not have more than a

single layer of cables.

480-V power control and instrumentation cables, when routed in cable trays, are installed in accordance with the applicable cable ampacity factors and in Category I areas do not extend above the siderails unless they are enclosed by an extended tray cover or an engineering analysis has demonstrated that electrical separation requirements are not compromised. Galvanized steel, nonconducting sleeves or blockouts in walls are used to transport cables through concrete walls.

Fire detection and protection

systems, either manually or automatically initiated, are provided in those areas required to preserve the integrity of the circuits for safety-related services (Section 9.5.1).

The electrical penetrations, through the reactor containment

vessel, are arranged in groups to maintain separation of electrical cables and to comply with the single-failure criteria.

The design and fabrication of each type of penetration assembly is in accordance with IEEE-317 for Electrical Penetration Assemblies in Containment Structures for Nuclear Fueled Power Generating Stations.

Each electrical penetration is designed to withstand the environment conditions at its location during all postulated DBAs.

Connections between field wires and penetration assembly conductors are made inside Seismic Category I termination cabinets designed to withstand the environmental conditions at its location during all postulated DBAs.

RBS USAR Revision 3 8.3-85 August 1990

  • 3 Wire splices inside the reactor building are made only where necessary and are primarily made in the electrical penetration terminal cabinets.

All splices are qualified for their intended use as described in Section 3.11.

All splices are made in accordance with the manufacturer's recommended procedures or approved equivalent instructions, and are tested after installation by continuity measurements, and power cable splices are additionally tested by insulation resistance measurements.

There are no splices made in cable trays.

3*

Control and instrumentation cable connections for safety-related Category I systems and equipment are made on terminating devices or by splices which have been qualified for their intended function pursuant to IEEE-323.

8.3.1.4.4.3 Cable and Raceway Scheduling Cable routing and raceway design is accomplished manually.

A computer program was used to assist in the engineering, design, installation, and control of cable routing, identification, tray, and raceway fill.

The main functions of this program are:

1.

The computation of all cable lengths and totalizing of cable types.

2.

The computation of raceway fill and overfill indication.

3.

To avoid duplication, indicate number of revisions on a specific item and to check information with respect to system, service, and redundancy.

4.

To provide output to the field in the form of pull and installation tickets which supplied all the necessary information for installation of cables and raceway and were designed to serve as Quality Control (QC) documents.

5.

To provide feedback from the field through system status information which allowed designers to revise systems as required with a

minimum of rework in the field.

6.

To provide status of any system with regard to the number of cable pulls and the overall job status.

RBS USAR Revision 16 8.3-86 March 2003 8.3.2 DC Power Systems

16 8.3.2.1 Description - Divisions I and II, Nonsafety 8.3.2.1.1 General

14 Station service dc power is available at 125 V and 48 V. There are three ungrounded Class 1E safety-related 125-V dc systems, including Division III discussed in Section 8.3.2.2. There are also six non-Class 1E nonsafety-related ungrounded 125-V systems and one non-Class 1E nonsafety-related ungrounded 48-V system.

Fig. 8.3-6 illustrates these eight 125-V dc and one 48-V dc systems.

14

Each system includes a 480-V ac to 125-V dc or 120-V ac to 48-V dc static battery charger with a control panel. Safety-related chargers are powered from the standby system of their own division. Nonsafety-related chargers are also powered from safety-related systems to obtain a more reliable source of power during normal plant conditions, but are tripped on LOCA, with the following exceptions, which are furnished ac power from available nonsafety-related sources:

a.

One 480-V ac to 125-V dc battery charger located in the circulating water switchgear house

b.

One 480-V ac to 125-V dc battery charger located in the services building

c.

One 120-V ac to 48-V battery charger located in the makeup water switchgear house

d.

One 480-V ac to 125-V dc battery charger located in the service water cooling switch gear house.

16

The 125-V dc systems include a battery charger, a lead acid battery, a 125-V dc distribution switchgear energized from a battery distribution

panel, local and control room instrumentation, and alarm facilities. The battery system surrenders the identity of its feeders to that of the controlled equipment or supported system at the first termination after leaving the distribution switchboard or panel.

7 A separate battery charger procured and qualified to IEEE-323 requirements and powered from either a nonsafety-related (black) power source or a portable diesel generator is provided as a backup battery charger for the Division I, II and III safety-related and three of the nonsafety-related battery chargers.

The backup battery charger's rating is equal to the largest capacity battery charger which it must replace. When the backup battery charger is to be used, the breaker of the battery 7

RBS USAR Revision 24 8.3-87 charger being removed from service is tripped, removed and placed in the backup charger position. The backup charger breaker is taken from its storage position and placed in the position on its bus which feeds the bus of the battery charger removed from service. Manual closing of the two charger breaker completes the charging circuit.

The backup battery charger breaker's position is monitored in the main control room, and is tripped upon receipt of a LOCA signal.

Operation of the backup battery charger is under strict administrative control. Credit is taken for this charger in mitigating the consequences of an accident, when used as a substitute for a Division I or II safety-related battery charger.

Where there is an electrical interface between safety-related switchgear and nonsafety-related equipment, such as chargers and switchgear, automatic breaker tripping by a LOCA signal at the safety-related switchgear is provided.

12 In the event of an Extended Loss of Alternating current Power (ELAP), at the distribution switchgear for the backup charger, a second breaker that is stored in a normal storage position is used to cross-tie Division I and Division II.

Operation of this breaker and the cross-tying of the Divisions are under strict administrative control. This includes bypassing the LOCA signal to enable closing of the breakers.

The Duty Cycle requirements for the standby batteries are identified in Tables 8.3-4, 8.3-5, and 8.3-6. All dc equipment is rated to operate between 101 and 140 V dc.

12 The batteries, chargers, distribution switchgear, and certain subordinate equipment such as uninterruptible power supply systems are in separate ventilated enclosures. The enclosures for safety-related equipment are seismic Category I. The other electrical equipment in the room is safety-related and of the same division.

Those portions of Section 8.3.1.1.1 referring to the physical arrangement, continuity, and integrity of load function is applicable to the dc systems as well.

8.3.2.1.2 Function The objective of the safety-related 125-V dc systems (Fig. 8.3-6) is to provide a highly reliable source of dc power and control power for necessary dc loads, such as pumps, valves, relays, control devices, circuit breaker operating mechanisms, inverters of the uninterruptible power supply systems, and similar equipment requiring dc power. The preceding safety-related devices are required for safe operation of the station and for safe reactor shutdown under any DBA condition.

Three of the nonsafety-related 125-V dc systems support normal 13.8-kV, 4.16-kV, and 480-V switchgear, uninterruptible power supply systems, valves, and solenoids.

RBS USAR Revision 13 8.3-88 September 2000 A

fourth nonsafety-related 125-V dc system supports the information handling

system, while the 48-V dc system supports normal 4.16-kV switchgear and a remote supervisory cabinet.

8.3.2.1.3 System Capabilities

  • 12 *13 Each safety-related dc system has a

battery charger which is sized to supply all normal continuous steady-state loads and to restore simultaneously a

battery from its end of duty cycle condition to the fully charged condition in 24 hr.

The battery chargers have an equalizing charge voltage of 139 V nominal.

The stability of the battery charger output is not load dependent.

Each battery system is sized in conformance with principles set out in IEEE-308 and IEEE-485.

Battery capacities for Divisions I and II are 2100 or 2150 AH each.

Standby batteries 1ENB*BATO1A and 1ENB*BATO1B have the ability to supply all DBA loads and all other loads not automatically tripped on a

LOCA signal for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and have sufficient capacity remaining to perform the switching operations necessary to restore normal ac and dc power with the charger inoperable.

12* 13*

Standby batteries 1ENB*BAT01A and 1ENB*BAT01B furnish control power to standby 4.16-kV switchgear, 480-V load centers, 125-V dc switchgear, standby diesel generators, and standby instrument buses.

  • 13 *1 13* 1*

Each nonsafety-related system has a

charger with abilities as described in the preceding paragraphs.

Each battery has the ability to supply for a minimum of 2 hr normal continuous loads including uninterruptible power supply systems and all essential dc loads associated with turbine generator shutdown without offsite power.

The battery chargers have the

ability, upon return of offsite preferred
power, to perform the necessary switching operation to make that power available to the unit.

8.3.2.1.4 Support of Battery Systems The facilities available for normal operation of the 125-V dc safety-related systems are shown in Fig. 8.3-6.

Each system has its own battery charger for normal

support, its

RBS USAR Revision 24 8.3-89 battery for preferred support, and access to a backup battery charger.

The following paragraph is applicable to normal design basis conditions but may be procedurally changed as described in Section 8.3.2.1.1 in the event of an Extended Loss of Alternating current Power (ELAP).

A procedural configuration that maintains at least two empty circuit breaker cubicles or an empty cubicle and open circuit breaker is provided to prevent cross-connections between independent battery systems through the backup battery charger switchgear 1BYS-SWG01D. No single failure can jeopardize the safety of redundant loads.

The 125-V dc nonsafety-related systems are arranged similarly to the 125-V dc safety-related systems and are shown in Fig. 8.3-6.

8.3.2.1.5 Ventilation 8

Each battery associated with the Division I and II standby diesels is located in its own independently ventilated room to keep the gases produced due to the charging of batteries below an explosive concentration, and to keep the room temperature to a level that allows the battery to supply its required current.

The ratings of the batteries were initially established based on a 24-hour average electrolyte temperature of 77°F.

8 8.3.2.1.6 Instrumentation and Alarm Important system components are either alarmed on failure or capable of being tested during service to detect faults.

Indicators are provided to monitor their status in the main control room. The station operating procedures provide for system status checks at every shift change that include the charging status of batteries in the unlikely event that a battery charger should fail without annunciating the condition in the control room.

Control of the battery chargers and the distribution switchgear is local. The Division I and II dc power system includes the following monitors and alarms:

1.

Main Control Room Annunciation and Monitors a.

Battery current (ammeter-charge/discharge) b.

Dc bus voltage (voltmeter) c.

Dc bus voltage low alarm (set above the open circuit voltage) d.

Dc bus voltage low-low alarm e.

Dc bus ground fault alarm (for ungrounded systems)

RBS USAR Revision 8 8.3-90 August 1996 f.

Dc Bus battery breaker open alarm g.

Dc Bus battery charger output breaker open alarm h.

Battery charger trouble alarm i.

Backup charger breaker open alarm j.

Supply or distribution breaker overcurrent trip alarm

  • 6 k.

Voltage to ground for both polarities at switchgear 6*

2.

Local Annunciation and Monitors a.

Battery charger output current (ammeter) b.

Battery current (ammeter-charger/discharger) c.

Battery voltage (voltmeter) d.

Battery charger output voltage (voltmeter) e.

Battery charger overvoltage f.

Battery charger low ac supply voltage g.

Battery charger overcurrent h.

Battery charger temperature high

  • 6 3.

Local (Remote Shutdown Panel) a.

(1) White indicating light for local ENB 6*

The Non-Class 1E dc power system includes the following monitors and alarms:

  • 8 1.

"125 V dc battery charger trouble" alarm located in the main control room and local supervisory control panel (1BYS-CHGR1C) annunciates in the event of actuation of local alarms on the battery charger.

  • 8

RBS USAR Revision 10 8.3-91 April 1998

  • 8
  • 8
  • 10 2.

The Battery charger BXY-CHGR1 provides "48-V dc battery charger trouble" alarm located in the main control room and local supervisory control panel

  • 6 3.

The Battery chargers BYS-CHGR1A, 1B and IHS-CHGR1D provide "Battery charger trouble" alarm located in the main control room.

6*

10*

  • 6 "125-V dc battery trouble" alarm located in the main control room annunciate in the event of the following conditions on 1BYS*CHGR1D:

1.

460-V ac input undervoltage 2.

125-V charger overvoltage 3.

Charger cabinet temperature high 4.

Charger output overcurrent 5.

INJS-ACB 453 breaker in test position 6*

Uninterruptible power supplies have been specified to include protective circuitry which protects internal components from dc input voltage spikes which may have originated on the dc power system.

8.3.2.1.7 Maintenance and Testing The station batteries and other equipment associated with the 125-V dc systems are easily accessible for maintenance and testing.

The batteries will be periodically checked for specific gravity and individual cell voltages.

An equalizing (overvoltage)

charge, where recommended by the battery manufacturer, is applied to bring all cells up to an equal voltage.

Over a period of time, the above-mentioned tests will reveal a weak or weakening trend in any cell and replacement is made if necessary.

Periodically, the battery charger is disconnected and the ability of the unit battery to maintain voltage and assume the dc load is verified. This test uncovers any high-resistance connections or cell internal malfunctions.

The normal station batteries and the standby batteries for Divisions I, II, and III have access to a battery load tester, as shown in Fig. 8.3-6.

Testing

RBS USAR Revision 16 8.3-92 March 2003

16 complies with IEEE-308, Criteria for Class 1E Electrical Systems for Nuclear Power Generating Stations.

Periodic testing requirements of each safety related battery system during normal or accident periods of operation are described in the Technical Specifications.

16

The battery chargers may be operated with the battery disconnected since the charger's stability is not load dependent.

With the battery disconnected the charger's regulation is 0.5 percent from no load to full load and ripple does not exceed 105 millivolts (rms).

The only foreseen mode of electrical operation during which the battery chargers would supply power to the dc switchgear loads without the batteries also being connected to the dc switchgear load would occur during periodic battery discharge tests.

8.3.2.2 Description - Division III (HPCS) 8.3.2.2.1 General The objective of the 125-V dc power system (Division III) is to provide a reliable, continuous, and independent 125-V dc power source of control and motive power as required for the HPCS system logic, HPCS diesel generator set control and protection, and all Division III related control.

A Class 1E battery charger is provided for the battery. The 125-V dc system is classified as Class 1E. The Division III 125-V dc system is independent of all other divisional batteries and there is no manual or automatic connection to any other battery system.

The battery is not shared with any other unit.

8.3.2.2.2 HPCS DC Loads

12 The 125-V dc power is required for HPCS diesel generator field flashing, control logic, and for the control and switching function of breakers. The Duty Cycle requirements for the Division III battery are identified in Table 8.3-6.

8.3.2.2.3 Battery and Battery Charger

14 The 125-V dc system for the HPCS power supply has a 60 cell lead acid battery (825 AH at 8 hr), one battery charger and a distribution panel with molded case circuit breakers. The HPCS battery charger output capability is at least 50-A dc at a minimum float voltage of 130.2 Vdc. Independent calculations verify that the HPCS battery charger has the capability to supply all normal continuous steady-state 12 14

RBS USAR Revision 13 8.3-93 September 2000

  • 13 *12 loads and simultaneously restore the Division III battery from its end of Duty Cycle condition to the fully charged condition in 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

13* 12*

The 125-V dc system equipment is designed as Class 1E in accordance with applicable clauses of IEEE-308.

It is designed so that no single failure in the system will result in conditions that prevent safe shutdown of the plant.

The plant design and circuit layout from the dc systems provides physical separation of the equipment, cabling, and instrumentation essential to plant safety.

As shown in Fig. 8.3-6, the battery is associated with its chargers and distribution panel.

The battery is located in its own ventilated room.

All the components of the dc systems are housed in a Seismic Category I structure.

8.3.2.2.4 125-V DC Systems Identification Fig. 8.3-6 shows the 125-V dc systems.

The battery feeds into distribution panel to serve the various dc loads for the HPCS system.

The battery charger is fed from the 480-V ac engineered safety features motor control center which is supplied by the HPCS diesel generator bus.

8.3.2.2.5 Battery Capacity

  • 12 The ampere-hour capacity and short time rating of the battery is in accordance with criteria given in IEEE-308 and IEEE-485, and is adequate to supply all electrical loads required until ac power is restored for the operation of the battery chargers.

The battery has sufficient stored energy to operate required connected essential loads for as long as each may be needed during a loss of the ac bus supplying the battery chargers under normal or emergency conditions. Capacity is large enough to cope with LOCA conditions or any other emergency shutdown.

Each distribution circuit is capable of transmitting sufficient energy to start and operate all required loads in that circuit.

12*

8.3.2.2.6 Charging The Class 1E charger 1E22*S001CGR for the HPCS dc system is fed from the HPCS motor control center (MCC) and is capable of carrying the normal direct-current system load and, at the same

time, keeping the battery in a

fully charged condition.

The sizing of the battery charger meets IEEE-308.

RBS USAR Revision 14 8.3-94 September 2001 14*

The maximum equalizing charge voltage for the HPCS battery is limited by the maximum operating voltage of the connected equipment to 140 Vdc.

Performance of an equalizing charge at maximum voltage will result in no damage to connected equipment.

14* *7 A

separate battery charger procured and qualified to IEEE-323 requirements and powered from either a non-safety-related (black) power source or a

portable diesel generator is provided as a

backup battery charger for the Division I,

II and III safety-related and three of the nonsafety-related battery chargers.

The backup battery charger's rating is equal to the largest capacity battery charger which it must replace.

When the backup battery charger is to be used, the breaker of the battery charger being removed from service is tripped, removed and placed in the backup charger position.

The backup charger breakers is taken from its storage position and placed in the position on its bus which feeds the bus of the battery charger removed from service.

Manual closing of the two charger breakers completes the charging circuit.

The backup battery charger breaker's position is monitored in the main control room, and is tripped upon receipt of a LOCA signal.

Operation of the backup battery charger is under strict administrative control.

No credit was taken for this charger in mitigating the consequences of an accident.

Where there is an electrical interface between safety-related switchgear and nonsafety-related equipment, such as chargers and switchgear, automatic breaker tripping by a

LOCA signal at the safety-related switchgear is provided.

  • 12 The Duty Cycle requirements for the standby batteries are identified in Tables 8.3-4, 8.3-5, and 8.3-6.

All dc equipment is rated to operate between 101 and 140 V dc.

12*

The batteries,

chargers, distribution switchgear, and certain subordinate equipment such as uninterruptible power supply systems are in separate ventilated enclosures.

The enclosures for safety-related equipment are seismic Category I.

The other electrical equipment in the room is safety-related and of the same division.

Those portions of Section 8.3.1.1.1 referring to the physical arrangement, continuity, and integrity of load function is applicable to the dc systems as well.

7*

RBS USAR Revision 12 8.3-94a December 1999 8.3.2.2.7 Ventilation The battery room is independently ventilated to keep the gases produced due to the charging of the battery below an explosive concentration.

8.3.2.2.8 Maintenance and Testing Design and installation of the 125-V dc system facilitates periodic maintenance tests to determine the condition of each individual cell.

Cells can be checked for liquid level, specific

gravity, and cell voltage.

Performance discharge tests can be conducted as required.

Battery chargers are also periodically checked by visual inspection and performance tests.

Testing of the Division III 125-V dc batteries includes the following:

1.

The specific gravity, voltage, and temperature of the pilot cell of each battery are measured and logged in accordance with the technical specification.

  • 12 2.

Every 3 months, voltage measurements of each cell to the nearest 0.01 V, specific gravity of each cell, and temperature of representative (at least one out of six connected as discussed in TS SR Bases 3.8.6.3) cells are made.

These measurements are logged.

12*

3.

Once each refueling cycle, the batteries are subjected to a service test.

The specific gravity and voltage of each cell are measured after discharge and logged.

8.3.2.2.9 Test Requirements of Station Batteries Provisions are made in the dc power system so that surveillance and service tests can be performed in accordance with IEEE-450.

8.3.2.2.10 Instrumentation and Alarm Important system functions are either alarmed on failure or capable of being tested during service to detect faults.

RBS USAR Revision 7 8.3-94b January 1995 THIS PAGE INTENTIONALLY LEFT BLANK

RBS USAR Revision 16 8.3-95 March 2003 Indicators for critical parameters are provided to monitor their status in the main control room.

Additionally, station operating procedures provide for system status monitoring at every shift change that will include a check of the charging status of the battery in the unlikely event that the battery charger fails in a manner which is not alarmed in the control room.

Main control room instrumentation includes a voltmeter, and an ammeter for each dc system. Control of the battery chargers and the distribution switchgear is local. The dc power system includes the following alarms and monitors:

1.

"125 V dc System Trouble" alarm located in the main control room annunciates in the event of:

a.

Battery output breaker trip

b.

125 V dc bus ground, or

c.

125 V dc bus undervoltage.

2.

"HPCS Battery Charger Trouble" alarm located in the main control room annunciates in the event of:

a.

Battery charger output breaker trip

b.

Battery charger high output voltage, or

c.

Battery charger loss of ac power supply.

3.

"Battery Trouble" alarm located on the local diesel-generator control panel annunciates in the event of:

a.

125 V dc bus ground, or

b.

125-V dc bus undervoltage.

4.

The following voltmeters are provided to monitor 125 V dc supply voltage:

a.

125 V dc voltmeter in the main control room

16

b.

125 V dc voltmeter locally at battery charger 16

RBS USAR Revision 16 8.3-96 March 2003

16

c.

125 V dc voltmeter at local diesel-generator control panel.

16

5.

The following ammeters are provided to monitor 125 V dc system load current:

a.

Ammeter in the main control room

b.

Ammeter at local diesel-generator control panel

c.

Ammeter locally at battery charger.

8.3.2.3 Analysis - Divisions I and II 8.3.2.3.1 Compliance 8.3.2.3.1.1 General Functional Design Requirements

13 During normal operation, the 125-V dc loads (Fig. 8.3-6) are fed from the battery chargers, with the batteries floating on the 125-V dc system. Upon loss of ac power to the battery chargers, the entire dc load is supported from the batteries until ac power is restored from the preferred transformers or standby diesel generators, to energize the battery chargers. The 125-V dc systems are designed on the following general functional bases:

13

1.

The 125-V dc systems are designed to meet the single failure criterion in which failure of any single component of the system does not result in a failure which could prevent any safety-related system from performing its function. This is accomplished by providing a separate battery, distribution panel, and battery charger for each system.

2.

Each battery serving a standby 4.16-kV ac bus is designed in accordance with Seismic Category I criteria.

3.

Batteries serving standby 4.16-kV ac buses are housed in a

Seismic Category I structure with Seismic Category I walls separating them. Allowances are made for proper ventilation of the battery rooms.

4.

There are no nonsafety-related loads on safety-related 125-V dc systems.

RBS USAR 8.3-97 August 1987 8.3.2.3.1.2 Design Criteria and Standards Criterion 17 The Class 1E dc power system is designed to permit the functioning of structures, systems, and components important to safety.

In

addition, the dc power sources and the dc distribution system have sufficient independence, redundancy, and testability to perform their safety functions, assuming a single failure, to meet the requirements of GDC 17.

Criterion 18 The Class 1E dc power system is designed to permit periodic inspection and testing to assess the condition of the system's components and their capability to perform their intended functions in order to meet the requirements of GDC 18.

Regulatory Guide 1.6 The Class 1E dc power system consists of three redundant and independent dc systems, each consisting of a battery with its own charger and distribution system.

The Class 1E dc redundant load groups have no automatic connection to any other load group and no provisions for automatically transferring loads between these redundant load groups.

A backup battery charger is redundant to the operating chargers described in Section 8.3.2.1.1 and supplies 125-V dc power requirements during maintenance periods.

The design meets the independence requirements of Regulatory Guide 1.6.

Regulatory Guide 1.32 The Class 1E dc system is operated at a

normal float charge voltage level to maintain the batteries in a

fully charged condition.

The battery chargers associated with each standby battery are rated to supply the largest combined demands of the various steady-state loads and the charging capacity to restore the battery from the design minimum charged state to the fully charged state irrespective of the status of the plant when these demands

occur, in order to meet the requirements of Regulatory Guide 1.32.

Both Division I and II batteries are sized to carry safety loads for at least 4 hr following loss of all ac power.

Each battery voltage level is continuously monitored and displayed in the main control room.

Low voltage and low charging current are alarmed in the main control room.

RBS USAR Revision 22 8.3-98 IEEE-450 The reliability of the dc supplies are assured by periodic discharge tests of the batteries, as described in IEEE-450. An exception has been taken to IEEE-450, in that, the specified maximum interval of 18 months between battery service tests has been extended to 30 months.

8.3.2.3.1.3 Conformance With Appropriate Quality Assurance Standards See Section 8.3.1.2.3.

8.3.2.3.2 Independence of Redundant Systems See Section 8.3.1.4.

8.3.2.3.3 Physical Identification of Equipment See Section 8.3.1.3.

8.3.2.3.4 Test Documentation to Qualify Electrical Equipment See Section 8.3.1.2.4.

8.3.2.4 Analysis 8.3.2.4.1 General DC Power System 8.3.2.4.1.1 Compliance With General Design Criteria and Regulatory Guides The design of the 125-V dc system for the engineered safety features provided for this plant are based on the criteria described in IEEE-308 and Regulatory Guide 1.32.

The 125-V dc systems, including the power supply, distribution system, and load groups, are arranged to provide dc electric power for control and switching of the components of Class 1E systems.

Batteries consist of industrial-type storage cells designed for the type of service in which they are to be used. Ample capacity is available to serve the loads connected to the system for the duration of the time the alternating current is not available to the battery charger. Each division of Class 1E equipment is provided with a separate 125-V dc system, so as to avoid a single failure involving more than one system.

Each battery charger has enough power output capacity for the steady-state operation of connected loads required

RBS USAR 8.3-99 August 1987 during normal or emergency operation (whichever is larger), while maintaining its battery in a

fully charged state.

Each battery charger supply has enough capacity to restore the battery from the design minimum charge to its fully charged state while supplying normal steady-state loads. The normal battery charger supply is from engineered safety feature buses.

The backup battery charger is supplied from a non-ESF source.

Since the dc power systems are operated ungrounded, a ground detection feature is provided. Indicators are provided to monitor the status of the battery charger supply.

This instrumentation includes indication of output

voltages, output
current, battery ground
status, and main circuit breaker position.

Bus undervoltage is annunciated in the main control room.

Battery chargers are provided with disconnecting means and feedback protection. Periodic tests are performed to assure the readiness of the system to deliver the power required.

8.3.2.4.2 HPCS - Division III - ESF DC System The 480-V ac feed to the Class 1E battery charger is from the HPCS motor control center to maintain functional association such that the battery can carry the HPCS dc load for 2 hr.

Probability of a system failure resulting in prolonged loss of dc power is extremely low.

Important system components are either self-alarming on failure or capable of being tested during service to detect faults.

The battery is located in its own ventilated battery room.

All abnormal conditions of selected system parameters important to surveillance of the system annunciate in the main control room.

Automatic cross connections between the HPCS 125-V dc systems and other dc systems are not provided. Control power for the breakers in the HPCS switchgear is from the HPCS battery ensuring the following:

1.

The unlikely loss of HPCS dc power supply will not jeopardize the supply of offsite or onsite power to other engineered safety feature buses.

2.

The differential relays and all the interlocks associated with HPCS are from the HPCS 125-V dc system only, thereby eliminating any cross connections between the redundant dc systems.

8.3.3 Fire Protection for Cable Systems The basic concept of fire protection for cable systems is that it should be designed into the installation rather than added on to the finished product.

Accordingly, the pertinent features have been previously discussed under the

RBS USAR 8.3-100 August 1987 analysis conducted to determine if the power system design met applicable criteria (Section 8.3.1.4.4).

By use of fire-resistant cables and conservative application as regards ampacity and careful

routing, both with regard to path and raceway construction, fire resistance is built into the cable systems.

External fire protection and detection is discussed in Section 9.5.1.

RBS USAR 8.3-101 August 1987 References - 8.3 1.

Henrie, D.K.

and Subramanian, C.V.,

Seismic Qualification Review Team (SQRT), Technical Approach for Re-Evaluation of Equipment, NEDE-24788-2, December 1982.

2.

Letter from J. E. Booker, Gulf States Utilities

Company, Beaumont,
Texas, to H. R. Denton, U.S.

Nuclear Regulatory Commission, Washington, DC, February 10, 1984.

3.

Letter from J. E. Booker, Gulf States Utilities

Company, Beaumont,
Texas, to H. R. Denton, U.S.

Nuclear Regulatory Commission, Washington, DC, April 11, 1985 (GSU Letter No. RBG-20684).

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