CONTENTS AT A GLANCE Overview
Distribution Substations Primary Distribution Systems Secondary Distribution Systems Monitoring Distribution Systems
Local Distribution Connection Systems
Underground Distribution Systems Underground Distribution Cables Overhead Distribution Connections
Overview
A block diagram of an independent power generation, transmission, and distribution system is shown in Fig. 4-1. Completely self-contained public power systems no longer exist. They are now connected to power grids that cover most of the United States and extend into parts of Canada and Mexico. They permit the interchange of electrical energy from many different power sources. Following electric power dereg-ulation, electrical energy is now becoming more of a commodity that can be bought and sold on the open market. Moreover, the ownership of many power generation plants in North America is now being consolidated in corporations that specialize in that activity.
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As a result, most public electric power utilities are predominately power distribution companies. However, public utilities still own their own generation plants, which are capable of meeting routine customer demand when supplemented by purchased power, particularly in periods of heavy demand. Public utilities are free to purchase electrical power when and where it is needed to add to any existing capacity. Local power utili-ties typically purchase power from bulk sources if it is cheaper than the cost of gener-ating it themselves. Power from the grid can make up for losses in local generation capability during power station maintenance or as a result of disruptions caused by storms, fires, or floods.
In the past, electric utilities invested 30 to 50 percent of their equipment budgets in distribution equipment. With more power generation facilities being consolidated in the hands of national power generation corporations or brokers, shareholder-owned public utilities have been increasing the shares of their budgets for distribution equip-ment, operation, and maintenance. They now put more emphasis on meeting specific customer voltage requirements and improving the reliability of their service.
The blocks in Fig. 4-1 representing the generation and transmission systems and the bulk power substation were discussed in Chap. 2. This chapter focuses on the
Figure 4-1 Simplified diagram of a power system from generation to distibution.
distribution system, also called the subtransmission system.In this system high-voltage electrical energy from the bulk power substation is stepped down by distribution substations for local transmission at lower voltages to serve the local customer base.
Distribution Substations
Distribution substations serve a wide range of private and public customers in distrib-uting electric power. They can be shareholder, cooperatively, privately, and government owned. All substations contain power transformers and the voltage-regulating appara-tus required for converting the high incoming subtransmission voltages to lower pri-mary system voltagesand maintaining them within specified voltage tolerances. Those voltages, typically 11 to 15 kV, are then sent to distribution transformers and load sub-stations for serving regional and local customers.
Substations serve many purposes, including connecting generators, transmission or distribution lines, and loads to each other and generally stepping higher voltages down to lower voltages to meet specific customer requirements. They can also interconnect and switch alternative sources of power and control system voltage and power flow.
Power factor can be corrected and overvoltage can be regulated by substations. In addition, instruments in substations measure power, detect faults, and monitor and record system operational information.
The basic equipment in substations includes transformers, circuit breakers, discon-nect switches, bus bars, shunt reactors, power factor correction capacitors, lightning arresters, instrumentation, control devices, and other protective apparatus related to the specific functions in the power station.
Circuit breakers and other switching equipment in a substation can be organized to separate a bus, part of a transformer, or a control device from other equipment. The common system switching arrangements are shown in the one-line diagrams in Fig. 4-2. In these diagrams connections are indicated by arrowheads, switches by offset lines, and circuit breakers by boxes.
The single-bus switching system in Fig. 4-2ais bus protected by the circuit break-ers on the incoming and outgoing lines. The double-bus system in Fig. 4-2bhas two main buses, but only one is normally in operation; the other is a reserve bus. The ring bus in Fig. 4-2ehas the bus arranged in a loop with breakers placed so that the open-ing of one breaker does not interrupt the power through the substation.
A typical distribution system consists of
■ Subtransmission circuits,which carry voltages ranging from 12.47 to 245 kV (of these, 69, 115, and 138 kV are most common) for delivering electrical energy to the various distribution substations.
■ Three-phase primary circuits or feeders, which typically operate in the range of 4.16 to 34.5 kV (11 to 15 kV being most common) for supplying the load in des-ignated areas.
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■ Distribution transformersrated from 10 to 2500 kVA, installed on poles, on above-ground pads, or in underabove-ground vaults near customers. These transformers convert primary voltage to useful voltages for practical applications.
■ Secondary circuitsat useful voltage levels, which carry the energy from the distri-bution transformers along highways, streets, or rights-of-way. These can be either single- or three-phase lines.
■ Service dropsand service laterals,which deliver energy from the secondary circuits to the user’s service entrance equipment.
Power is switched from the substation transformers as shown in Fig. 4-1 to separate distribution buses. In some systems the buses distribute power to two separate sets of
Figure 4-2 One-line diagrams of substation switching arrangements:
(a) single bus; (b) double bus, single breaker; (c) double bus, double breaker; (d) main and transfer bus; (e) ring bus; (f) breaker-and-a-half;
(g) breaker-and-a-third.
distribution lines at two different voltages. Smaller transformers connected to the bus step the power down to a standard single-phase line voltage of about 7.2 kV for resi-dential and rural loads, while power from larger transformers can leave in another direc-tion at the higher three-phase voltages to serve large industrial and commercial loads.
SUBSTATION EQUIPMENT
Substation transformershave laminated steel cores and are built with isolated primary and secondary windings to permit the transfer of power from the primary side to the secondary side at different voltages. These transformers typically range in size from small units rated for 1 MVA to large units rated for 2000 MVA.
Most of these transformers are insulated and cooled with oil, making them vulnerable to fire. Adequate precautions must be taken to minimize the possibility of fire and to extinguish any fires that occur as rapidly as possible. In addition to the installation of fire extinguishers, they are located at safe distances from other equipment and positioned in pits to contain any oil leakage. Additionally, fire walls might be built between them.
Substation circuit breakers capable of interrupting the highest fault currents are installed in substations. They are typically rated for 20 to 50 times the normal current and are built to withstand high voltage surges that occur after interruption. Switches rated only for normal load interruption are called load-break switches.
Disconnect switcheshave isolation and connection capability but lack current inter-ruption capability.
Bus bars make connections between substation equipment. Flexible conductor buses connect insulators, but rigid buses, typically hollow aluminum alloy tubes, are installed on insulators in air or in gas-enclosed cylindrical pipes.
Shunt reactorscompensate for line capacitance in long lines, and shunt capacitors compensate for the inductive components of the load current.
Currentand potential transformersare used to measure currents and voltages, and they provide low-level currents and voltages at ground potential for control and protection.
Control and protective devicesinclude protective relays that can detect faults rapidly in substation equipment and lines, identify their locations, and provide appropriate sig-nals for opening circuit breakers. They also include equipment for controlling voltage and current and selecting optimum system configurations for the load conditions.
Included in this category are fault-logging and metering instruments, internal and external communications equipment, and auxiliary power supplies.
Solid-state digital instruments containing microprocessors have replaced many of the earlier-generation analog moving-coil instruments. Most substations are fully auto-mated yet have provision for manual override. Essential status information is trans-mitted via communications channels to the central office dispatcher and can be displayed on video terminals.
POWER DISTRIBUTION
Power can leave a typical substation in sets of three wires, each headed down the dis-tribution network in a different direction. Three wires at the top of the poles are
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required for three-phase power, and a fourth or neutral/ground wire is usually posi-tioned lower down on the utility pole.
Homes and small businesses (offices and stores) usually need only one of the three phases, so those requirements are met by tapping single-phase power from the three-phase transmission lines for distribution on individual conductors, at about 7.2 kV. The second wire, positioned lower on the utility pole, is the neutral/ground wire. In some locations two single-phase conductors and a neutral/ground wire are carried on the same pole. One of those phases serves nearby homes and offices, while the second phase continues on as an individual conductor to serve more distant loads.
In most newer residential subdivisions the single-phase power line is brought down from a pole near the entrance to the subdivision to pad-mounted transformers for underground distribution to homes. However, underground service has been provided for cities for many years in an effort to eliminate the jumble of poles and wires.
Voltage regulators are located along the routes of both overhead and underground power lines to regulate the voltage on the line, preventing undervoltage or overvoltage conditions. These regulators contain switches that allow them to be disconnected for maintenance. Regulator voltage is also typically about 7.2 kV.
Substation voltage is controlled with tap changers on the distribution substation transformers, but some require separate voltage-regulating transformers, individual feeder-voltage regulators, or induction voltage regulators. Most distribution substa-tions perform metering, relaying, and power control automatically. The main units of equipment to be controlled are the feeder circuit breakers if the substation includes them. Metering is required to provide consumption data for billing customers if the power provider does not own the distribution system.
The American National Standards Institute (ANSI) has defined the voltage range for single-phase residential users as 114/228 V to 126/252 V at the user’s service entrance and 110/220 V to 126/252 V where it is being used. The difference in these values recognizes that there will be a voltage drop in the consumer’s system. Nominal voltage in the United States and Canada is 120/240 V, 60 Hz.
Dips in voltage large enough to cause incandescent lamps to flicker are expected to be limited to 4 to 6 percent if they occur infrequently and 3 to 4 percent if they occur several times an hour. Frequent dips caused by the start-up of large electrical machines such as motors or elevators should be limited to 1.5 or 2 percent.
Primary Distribution Systems
The primary distribution system is that part of the electric distribution system between the distribution substation and distribution transformers. It is made up of circuits called primary feedersor distribution feeders.These feeders include the pri-mary feeder main or main feeder, usually a three-phase, four-wire circuit, and branchesor laterals,which can be either three-phase or single-phase circuits. These are tapped from the primary feeder main, as shown in the simplified distribution
feeder diagram of Fig. 4-3. A typical power distribution feeder provides power for both primary and secondary circuits.
In primary system circuits, three-phase, four-wire, multigrounded common-neutral systems, such as 12.47Y/7.2 kV, 24.9Y/14.4 kV, and 34.5Y/19.92 kV, are used almost exclusively. The fourth wire of these Y-connected systems is the neutral, grounded at many locations for both primary and secondary circuits. Single-phase loads are served by distribution transformers with primary windings that are connected between a phase conductor and the neutral. Three-phase loads can be supplied by three-phase distribution transformers or by single-phase transformers connected to form a three-phase bank. Primary systems typically operate in the 15-kV range, but higher voltages are gaining acceptance.
The primary feeder main is usually sectionalized by reclosing devices positioned at various locations along the feeder. This arrangement minimizes the extent of primary circuitry that is taken out of service if a fault occurs. Thus the reclosing of these
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Figure 4-3 Simplified diagram of a power distribution feeder.
devices confines the outage to the smallest number of customers possible. This can be achieved by coordinating all the fuses and reclosers on the primary feeder main.
In block diagram Fig. 4.3, distribution substation voltage is 12.47 kV line-to-line and 7.2 kV line-to-neutral (this is conventionally written as 12,470Y/7200 V).
However, the trend is toward higher primary four-wire distribution voltages in the 25-to 35-kV range. Single-phase feeders such as those serving residential areas are con-nected line-to-neutral on the four-wire systems.
The use of underground primary feeders that are radial three-conductor cables is increasing. They are serving urban areas where load demand is heavy, particularly dur-ing the hot summer months, and newer suburban residential developments.
Both cost factors and the importance of reliability to the customers being served influence the design of primary systems. The simplest and least expensive (as well as least reliable) configuration is the radial distribution system shown in Fig. 4-4a, because it depends on a single power source. Despite their lower reliability, radial sys-tems remain the most economical and widely used distribution syssys-tems for serving homes because an electrical power outage there is less likely to have serious econom-ic or publeconom-ic safety consequences. As a hedge against outages, most utilities plan their distribution systems so that they will have backup if those events occur. The goal of
Figure 4-4 Simplified diagrams of the basic electrical distribution systems: (a) radial and (b) loop.
all electrical distribution systems is the economic and safe delivery of adequate elec-tric power to serve the elecelec-trical loads.
The reliability of the primary feeder can be improved with the installation of a loop distribution system,as shown in Fig. 4-4b.In loop systems the feeder, which originates at one bulk power source, “loops” through the service area and several substations before terminating at the original substation or another bulk source. The strategic placement of switches at the substations permits the electric utility to supply cus-tomers in either direction. If one power source fails, switches are opened or closed to bring an alternative power source online.
Loop systems provide better service continuity than radial systems, with only short service interruptions during switching. However, they are more expensive than radial systems because of the additional switching equipment requirements. As a result, loop systems are usually built to serve commercial and light industrial build-ings and shopping malls, where power outages are more likely to endanger human lives or result in property losses.
Reliability and service quality can be significantly improved at even higher cost with a multiple parallel circuit pattern.In these systems, two or more circuits are tapped at each substation. The circuits can be radial or they can terminate in a second bulk power source.
These interconnections permit each circuit to be supplied by many different substations.
Secondary Distribution Systems
The secondary distribution system is that part of the electrical power system between the primary system and the customer’s service entrance. This system includes distribu-tion transformers, secondary circuits (secondary mains), customer services (consumer drops), and watthour meters to measure customer power consumption. Secondary volt-ages are provided by distribution transformers that are connected to the primary system and sized for the voltages required for specific parts of the service area.
Heavy industries or mines, which require the most power, are usually supplied with three-phase power by privately owned or corporate industrial substations. They are typically located on land owned by those companies and close to the equipment being served. These substations are capable of providing a wide range of voltages from the 12.47- to 13.8-kV transformers located there.
Factories, high-rise buildings, shopping centers, and other large power consumers are furnished with three-phase power from load substations in the 480-V to 4.16-kV range. Many commercial and light industrial customers are supplied by 208Y/120-V or 480Y/277-V three-phase, four-wire systems.
The most reliable service in densely populated urban business and commercial areas is provided by grid-type secondary systems at 208Y/120 V or by spot networks,usually at 480Y/277 V. Spot networks are usually located in urban areas near high-rise office buildings, factories, hospitals, and dense commercial properties such as shopping malls, which have high load densities. In these networks the transformers and their pro-tective equipment are typically placed adjacent to or within the properties being served.
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Secondary network systems are used in about 90 percent of all cities in the United States with populations of 100,000 or more and in one-third of all cities with populations between 25,000 and 100,000. Despite the generally high reliability of these systems, many facilities such as hospitals, computer centers, and chemical or pharmaceutical industries performing critical processes that cannot tolerate power outages have backup power sources. These include standby or emergency generators and/or storage batteries together with automatic switching so that service to critical loads can be maintained if the normal utility supply is interrupted. Some of these facilities have automatic switch-ing that puts alternative utility power sources online without human intervention. This subject is covered in more detail in Chap. 11.
Monitoring Distribution Systems
The components of an electrical power distribution system are vulnerable to the vagaries of storms, fires, and accidents because of their exposed locations and wide dispersion throughout the distribution service area. Power lines can be brought down by ice storms, falling tree branches, or inadvertent severing by excavating machines.
Poles can be knocked down by heavy winds or vehicular collisions, and lightning strikes can disable status-monitoring and communications links.
The public expects electric utilities to maintain service near the 100 percent level at all times, even as its dependence on electricity for safety, physical comfort, and preservation of perishables increases. This has put pressure on utilities to improve their methods for locating faults and restoring service rapidly following all outages, regardless of cause.
The response time of electric utilities to faults or outages depends on their ability to identify and locate the source of the problem, determine a solution, and, if necessary, dispatch service crews to make repairs, all in a timely manner.
Electric utilities use different techniques to monitor the status of control components, and new technologies are assisting them in their efforts. “Smart” digital relays are replacing the older-style relays with induction disks, where only their contact positions indicate when a fault occurs that trips a circuit breaker. The digital relays not only monitor the status of the system, they also perform self-diagnosis. With these capabil-ities, the relay can signal the dispatchers that an equipment defect needs attention.
However, an ever-increasing number of relays or indicator lights is required to extend the coverage beyond simply monitoring the tripping of breakers.
New programmable monitoring controllers are being introduced that eliminate the need for large numbers of relays or lights. The controllers can perform comprehensive monitoring of the operational status of all critical control circuits on a continuous basis. The manual and visual checking of components in those critical circuits has long been labor-intensive. The programmable controllers monitor the presence of the proper operating voltages for circuit breakers, the continuity of circuits and device coils, the state of switch contacts, and condition of the sulfur hexafluoride (SF6) gas supply for arc quenching and insulating circuit breakers.