Electric Power Substations
ELECTRIC POWER SUBSTATIONS
An electric power substation is a facility that provides a junction between parts of the power grid. The substation's functions, critical for the proper operation of the power system, include the interconnection of power lines from different parts of the system; the monitoring and control of system operating conditions; and the protection of the power system equipment.
CLASSIFICATION AND GENERAL DESCRIPTION
Substations may be classified into one of several categories depending on their location and function within the system. Generator substations are located at the site of power generating stations and provide the connection to the transmission system. Bulk power substations link the transmission system to the subtransmission system, stepping the voltage down through a transformer (transformer substation), or linking high-voltage transmission lines from different parts of the system without changing the voltage (switching substation). A distribution substation provides the link between the subtransmission system and the much lower voltages of the distribution system. A converter station is a unique type of bulk power substation that provides a link between high-voltage alternating-current transmission lines and high-voltage direct-current transmission lines.
The siting of substations, electrical, geographic, economic, political, and aesthetic factors must be considered. The high voltages of the transmission system are utilized because the reduced currents result in more efficient power transmission. Therefore, substations are placed as close to the system loads as possible to minimize losses. This is constrained by the value and availability of real estate, as well as by the requirement that terrain be relatively level within the substation. Care is taken in substation placement, particularly in areas of dense population, that the location not obstruct scenic views or aesthetically depreciate commercial or residential developments. The physical size of substations can cover large areas because the high-voltage components are insulated from each other by air and thus must be separated by significant distances. Historically, these issues have limited the installation of large substations to areas of relatively sparse population. However, since the 1980s, substations have been insulated with pressurized sulfurhexafluoride gas (SF 6). Because of the highly insulating quality of SF 6, the size of these gas-insulated substations may be well under 25 percent of the size of an air-insulated substation with the same power-handling capability. In some applications, particularly those in proximity to population centers, the entire substation may be enclosed within buildings, reducing aesthetic concerns and deterioration by the environment. Nevertheless, air-insulated substations are still generally preferred because of the higher cost and environmental concerns regarding the release of SF 6 (which is being investigated as a greenhouse gas).
The primary function of substations is to provide an interconnection between transmission lines extending to other geographical areas and between parts of the system that may be operating at different voltages. A principal aspect of the substation design is the arrangement of connections through circuit breakers to common nodes called busses. Circuit breakers are large electrical switches that provide the ability to disconnect the transmission lines or transformers from the bus. Transformers provide a change in voltage.
Busses are typically made of aluminum or copper and are rigid bars in the substation, insulated from ground and other equipment through ample insulating material, typically air or sulfurhexafluoride. The arrangement of the busses in the substation may fall into a number of different categories; the most common are illustrated and explained in Table 1. The appropriate selection of configuration is made by carefully balancing cost, reliability, control, and space
|Single Bus||• All connections are tied to a single bus, with one circuit breaker for each bus. This arrangement is favored for its simplicity and low cost, although it is least desirable with regards to reliability. Maintenance to substation equipment requires that connections be removed from service.||• This type of bus is usually the configuration of choice in substations at or below 130 kV.|
|Main and Transfer Bus||• As with the single bus arrangement, each connection is linked to the main bus through a circuit breaker, but the breaker may be bypassed using disconnect switches through a transfer bus and another breaker to the main bus. This permits isolation of the circuit breaker for maintenance without loss of service to the connection.||• Used in more critical applications at or below 130 kV, and occasionally at higher voltages.|
|Ring Bus||• This scheme has all circuit breakers linked in a closed loop, with connections entering at the junction between breakers. This way, any connection may be isolated or any single circuit breaker removed without interrupting the other connections. This provides a higher level of redundancy than the systems mentioned above. Control and protective relaying issues are somewhat more complicated for this arrangement.||• Usually found in substations above 130 kV, in smaller substations. Often installed with the expectation of future expansion to a breaker-and-a-half scheme.|
|Breaker-and-a-half Scheme||• This scheme has two equal busses, with three breakers connected between them. Each connection may be linked to one of the busses through one breaker, and in the event that one breaker is out of service or in need of maintenance, the connection may still be served through the two breakers to the other bus. The name of this arrangement comes from the fact that two connections are served by three breakers, so that there is an average of one and a half breakers per connection. This scheme is less complicated than the ring bus, with higher reliability, but is more costly.||• Most common on systems above 130 kV.|
|Double Bus||• A double bus, double breaker arrangement provides a link to each bus through an independent breaker for each connection. This provides full redundancy in case of malfunction, or the need to perform maintenance on a circuit breaker or bus, but is the most expensive configuration.||• Usually found in most critical transmission substations and in generator substations.|
|Bus Line, Transformer, or Load ↓||Disconnect Switch —⦧||Circuit Breaker □|
constraints. If the substation is providing service to critical loads, the need for high reliability may warrant the higher cost of a more complex bus arrangement, while for less critical loads, space constraints may dictate a minimal bus arrangement.
For every piece of equipment in a substation, manual switches—called disconnect switches—are provided to enforce complete electrical isolation from equipment before any service is performed. Disconnect switches are placed in clearly visible locations so maintenance personnel can continuously confirm that the equipment is isolated. The disconnect switch cannot interrupt current, so it is opened only when the current has already been interrupted by an automatic switch such as a circuit breaker.
Circuit breakers are switches that are operated by a signal, from a relay or from an operator. The circuit breaker is designed to interrupt the very large currents that may occur when the system experiences a fault, such as a lightning strike or arc to ground (e.g., a tree falling on a line, or a line falling to the ground). Because these extremely large currents can cause severe damage to equipment such as transformers or generators, and because these faults can disrupt the proper operation of the entire power system, the circuit breakers are designed to operate rapidly enough to prevent damage to equipment, often in 100 milliseconds or less.
The circuit breaker contacts consist of two pieces of metal that are able to move with respect to each other. When the circuit breaker is closed, the contacts are touching and current flows freely between them. When the circuit breaker opens, the two contacts are separated, typically by a high-strength spring or a pneumatic operator. As the contacts separate, current continues to flow through them, and the material between them is ionized, forming a conducting plasma. To provide isolation, the plasma must be eliminated and the contacts be separated a sufficient distance to prevent the reinitiation of an arc. Several different technologies are implemented to give four common types of circuit breakers.
Air blast circuit breakers are insulated by air, and the plasma is extinguished as a blast of compressed air is blown between the contacts. These are less common than the other types and generally are no longer applied in new installations because of size, and problems with the maintenance of the compressors. Oil-filled circuit breakers have the contacts enclosed within a sealed tank of highly refined oil, with oil ducts designed to force oil between the contacts to quench the arc when the contacts open. These are common, but decreasing in popularity due to the environmental concerns associated with the risk of an oil spill. Although breaker failures occur only rarely, hundreds of gallons of oil may be spilled in a single failure, requiring very costly remedial procedures. The more popular breakers for high-voltage systems are gas-filled breakers that have the contacts enclosed within a sealed tank of pressurized SF6. These have proved highly reliable, although there have been some environmental concerns about the release of the SF6 when maintaining the device or when the tank ruptures. For lower-voltage applications (less than 34 kV), vacuum breakers are often used. These eliminate arcing by enclosing the contacts within an evacuated chamber. Because there is no fluid to be ionized, there can be no plasma formed. Their major benefit is a very fast response time and elimination of environmental concerns.
In addition to circuit breakers, there are other classes of automatic switches that can be controlled or operated remotely, but with current-interrupting capability. These include circuit switchers, reclosers, and sectionalizers.
Power transformers perform the very important function of linking parts of the power system that are at different voltages. They are found exclusively in substations, except in the distribution system, where they may be mounted on poles or pads close to the loads they are serving.
SYSTEM MONITORING AND PROTECTION
The substation provides a monitoring point for system operating parameters. The power system is a highly complex and sensitive conglomeration of parts that must all be coordinated to function properly. For this reason, the operating conditions must be very closely observed and controlled. This is done by using specialized sensors to acquire the information and then communication systems to convey the information to a central point. For immediate response to system faults (such as damaged conductors, arcs to ground, or other undesirable operating conditions), a system of protective relaying (consisting of sensors and automated switches) is used to operate circuit breakers.
The high voltages and currents seen in a substation exceed the voltage and current ratings of monitoring equipment, so instrument transformers are used to convert them to lower values for monitoring purposes. Instrument transformers may be categorized as current transformers (CTs) or voltage transformers (VTs), which are also sometimes designated as potential transformers. CTs typically consist of a toroidal core of magnetic material wrapped with a relatively high number of turns of fine wire, with the current to be measured passing through the middle of the toroid. These devices are often located in the bushings of circuit breakers and transformers so as to be able to measure the current in those devices. Bushings are the special insulated connections that allow the current to pass from the outside air into a sealed metal enclosure. VTs serve the function of stepping the voltage down to a measurable level. There is usually one connected to each of the substation busses. Most of the time VTs are constructed in essentially the same fashion as other transformers, although sometimes a capacitive coupling may enhance or replace the electromagnetics. Recent advances in technology have developed a new class of CTs and VTs that are optical devices that use specialized materials and advanced signal processing techniques to determine current based on the polarization of light as influenced by magnetic field strength, and voltage based on the polarization of light as influenced by electric field strength. While these devices are significantly more expensive than the traditional technologies, they provide higher accuracy and reliability and better electrical isolation.
Once the operating conditions have been measured, the information is conveyed to a central location using a system known as SCADA (Supervisory Control and Data Acquisition). The SCADA system data are displayed in the regional dispatch center to assist operators to know what actions must be taken for the best operation of the system.
Instrument transformers provide inputs to the automatic protection system. To provide a quick response to faults, a group of devices called relays accept the voltage and current signals, determine when abnormal conditions exist, and open the circuit breakers in response to fault conditions. The protection system design opens only the circuit breakers closest to the problem so that all of the rest of the system may resume normal operation after the fault is isolated from the system. Historically, determining which breakers to open has been done using various electromechanical devices that had the necessary comparisons and delays built into their design. These include overcurrent relays, directional relays, distance relays, differential relays, undervoltage relays, and others. These electromechanical devices have proven rugged and reliable since the early 1900s. In the late 1950s a new class of relays, solid-state relays, using analog circuits and logic gates, provided basically the same performance, but without any moving parts and hence reduced maintenance requirements. With the advent of low-cost-high level microprocessors, a new generation of relays has been born in which a single microprocessor-based relay performs all of the functions of several different electromechanical or solid-state relays. The microprocessor provides the benefits of higher accuracy, improved sensitivity to faults, better selectivity, flexibility, ease of use and testing, and self-diagnostic capabilities. They can be integrated into the SCADA system to communicate the cause of breaker opening, and can be operated, reset, and updated through remote access. These advantages are why microprocessor-based relays are found in most new installations and are also being retrofitted into many existing substations.
In addition to protection against excessive currents, equipment must be protected against excessive voltages that commonly result from lightning strikes or switching transients. Because of the high speed of these surges, relays and circuit breakers are unable to respond in time. Instead, this type of protection is provided by surge arrestors, which are passive devices that prevent overvoltages without moving parts. An air gap was the earliest type of surge arrestor, in which a special set of contacts are set a distance apart specified by the maximum tolerable voltage. When the voltage exceeds that threshold an arc forms, essentially shorting out the overvoltage. The newer surge arrester technology is the metal-oxide varistor (MOV). This is a device that behaves like a very large resistor at voltages below the specified threshold, but at voltages above the threshold, the resistance of the device drops precipitously, effectively drawing enough current to limit the voltage, but without shorting it to ground.
SYSTEM VOLTAGE CONTROL
Another of the principal functions of a substation is to provide the means to control and regulate voltages and power flow. These functions are provided either by feedback from an automated system or by remote instruction from the dispatch center using an array of devices and systems within the substation.
A load tap changer, an integral part of a power transformer, is a special switch that adjusts the voltage ratio of the transformer up or down to keep the load side voltage at the desired level despite changing voltages on the source side. Capacitor banks are used to raise the voltage in a substation when it has dropped too low, particularly in areas of large industrial loads. Shunt reactors are used to lower voltages that have risen too high due to the capacitance in the transmission or distribution line.
Another class of devices used to control the voltage is operated using powered electronic switches to continuously adjust the capacitance and/or inductance in a substation to keep the voltage at precisely the voltage desired. These devices are relatively new in deployment, having been developed with the advent of inexpensive and robust power semiconductor components. These devices are part of a group broadly known as FACTS (Flexible AC Transmission System) devices and include static var compensators, static synchronous compensators, and dynamic voltage restorers.
John A. Palmer
See also: Capacitors and Ultracapacitors, Electric Motor Systems; Electric Powers, Generation of; Electric Powers, System Protection, Control, and Monitoring of; Electric Power, System Reliability and; Electric Power Transmission and Distribution Systems; Insulation; Transformers.
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