It is doubtful anyone involved with the beginnings of the electric utility industry ever envisioned how the transmission grid would be used in today's world. Huge amounts of bulk power are transported across extremely long distances in an effort to meet ever-increasing demands for electricity. There are problems with congestion, reliability, cyber security, connecting variable renewable resources, the environment and economics. Interestingly, technological advancements applied in the electrical substation are playing an important role in addressing and solving these issues.
When substations first appeared on the scene, the electrical apparatus, for the most part, was bulky and primitive, requiring huge amounts of labor to keep them operational. As the industry matured, manufacturers, research groups and government laboratories invested huge amounts of time and money to improve the equipment, which drove the designs of the substations themselves. A good example of this is the power circuit breaker.
The power circuit breaker is the most basic component of the substation, but it has affected everything from bus configuration to voltage and current ratings of the system. The first breakers were little more than switches placed inside an open tank of oil, but from that simple device, engineers developed the oil-filled circuit breaker (OCB).
The OCB proved popular despite its many limitations, and it is still in use today — a testimony to the robustness of the early technology. OCBs hold huge quantities of mineral oil, operate slowly, and are electrically and mechanically complicated. They also require constant attention to keep them operational, which is expensive. Over and over, maintenance has been the chief cause of outages for the transmission system.
OCB maintenance isn't a simple process; it requires time, lots of time when the breaker and the area around it have to be de-energized. A couple of days of oil handling may be required just to get into the OCB. Normal maintenance can take a week or more, which led engineers to come up with configurations such as the breaker-and-a-half design, double-breaker arrangement, double-breaker/double-bus layout and many variations of those in an effort to improve system reliability.
Research led to several other technologies using new materials to compete with oil, such as the compressed air, magnetic interrupter, vacuum breaker and sulfur hexafluoride (SF6) breaker. Some were a step forward and others a step backward, but they all improved the overall condition. It was not long until the SF6 breaker became the device of choice. Interestingly, ABB recently announced its next-generation carbon dioxide (CO2) 72-kV live-tank circuit breaker at the 2012 International Council on Large Electric Systems (CIGRÉ) exhibition. CO2 gas is more economical than SF6. The CO2 breaker is based on the same principles and components as its SF6-based predecessor but offers excellent switching performance — technology moving forward again.
As manufacturers refined SF6 breaker technologies, rating boundaries moved forward. They developed live-tank and dead-tank designs, giving substation designers more design options. Just recently, Siemens announced it has developed the world's first 1,200-kV live-tank alternating-current SF6 power circuit breaker. It is for use on India's 1,200-kV transmission system. It is capable of carrying 8,000 MW, twice the capacity of the 800-kV line currently in use. The first installation of this breaker will be at a test installation in Bina, India.
Advancements in SF6 designs also made possible a reduction in maintenance requirements. ABB reports its latest SF6 breaker has a maintenance interval of 15 years, a huge improvement over the OCB with its three-year maintenance interval. It also has the breaker's interval greater than the disconnect switches around it, so ABB went a step further with the disconnecting circuit breaker. This device combines the function of the disconnect switch with the circuit breaker function. Combining the two devices not only improves the maintenance cycle, but it also reduces the number of disconnect switches around the breaker.
One survey by the Electric Power Research Institute (EPRI) suggests the typical life of a circuit breaker is 35 years. The EPRI data indicates it is reasonable to expect the circuit breaker to be removed from service twice in its expected service life. ABB says the advantages of using the disconnecting circuit breaker increase the availability of the substation and simplify the bus configuration. Taken altogether, this innovation could reduce costs substantially for land, equipment and maintenance.
Another offshoot of SF6 technology is the gas-insulated substation (GIS), introduced to the industry by ABB in 1966 with the 170-kV GIS substation installed in Zurich, Switzerland. By 1986, the voltage level was raised to 800 kV, installed in South Africa by ABB. The GIS facility uses SF6 gas at moderate pressure for phase-to-phase and phase-to-ground insulation. The high-voltage conductors, circuit breakers, disconnect switches and instrument transformers are in a SF6 environment, inside a grounded metal enclosure. Because of the improved dielectric properties, a substation using GIS technology requires one-third the space a conventional air-insulated substation uses.
The smaller footprint and the reduced electrical clearances have led to some interesting applications adapting GIS technology to solve the issue of providing increased capacity in a congested urban area where a substation is not always welcomed. Designers are referring to these stealthy installations as the invisible substations.
Several offerings fall into this stealthy category. There are underground or subterranean substations, substations constructed inside of buildings and on top of buildings. As hard as it is to believe, some segments of society miss all of the aesthetic beauty of substations and prefer not to see them, and that is where the invisible substation comes in to play.
The smaller installation allows the placing of a substation underground or building one inside a structure, and improves the reliability and availability of the substation. It is shielded from pollution, lightning strikes and animal incursion. It also reduces noise pollution associated with the substation in densely populated neighborhoods as well as security issues related to intruders, but it does come with some issues such as the potential for a transformer fire.
Granted, transformer fires are not a common occurrence, but when they happen, they are spectacular. Manufacturers have developed special insulation materials like dry-type insulation, SF6 gas insulation and vegetable-oil-based insulation to address this issue.
The dry-type transformer has been around for many years, providing ratings up to 60 MVA and voltages up to 72 kV, but now higher ratings are needed. One such technology that has attracted attention is the vegetable-oil-based insulating fluid. These oils have a high flash point and fire point. In addition, vegetable-oil insulating fluid is biodegradable; if there's a spill, it's not hazardous. Cooper Power Systems introduced its Envirotran EF transformers filled with soy-based Envirotemp FR3 fluid years ago. ABB also developed a vegetable oil called BIOTEMP for high-voltage transformer applications.
Transformers also are available using SF6 gases. This insulation media offers the same excellent qualities found attractive in GIS installations equally attractive to power transformers with improved cooling, and the size of the transformer can be reduced. Toshiba and Mitsubishi have been providing SF6-insulated power transformers for several years.
Old Problem, New Solution
One of the most fascinating SF6 applications is the use of GIS technology to solve the problems of mobile substation deployment. A mobile substation is a fully equipped electrical substation that can be moved because it's completely mounted on a semi-trailer. Moving these devices can be anything but easy as regulations covering the movement of heavy equipment become more stringent. Bridges and overpasses have limited load-bearing capacities, and many regulating agencies are reluctant to allow anyone to move something like a transformer over them, which can be a problem when a utility is trying to respond to system emergency.
As mobile substation capacities increase above the 100-kV voltage level, providing suitable designs becomes a real challenge. Electrical clearances are enormous and the equipment itself takes on very large proportions. All these constraints make the manufacturer of mobile substations face a more complicated task than just placing the equipment of a normal transformer bay on a semi-trailer. GIS and hybrid GIS technology — a combination of air and SF6 insulation — are being used to meet this challenge.
Several suppliers such as ABB, Alstom, Siemens and Matelec Group report a growing market for their GIS and hybrid GIS mobile substations. ABB has supplied 115-kV and 220-kV mobile devices, as well as a 230-kV, 30-MVA mobile GIS substation for the Instituto Costarricense de Electricidad in Costa Rica. It was assembled on two semi-trailers using a specially designed power transformer. ABB reports this mobile substation has a very small footprint and can be placed into operation in less than 24 hours.
Siemens has a containerized mobile substation solution that uses GIS technology. By the strictest definition, this may not be exactly mobile, but it allows the substation to be moved easily to a location where it's required quickly. Siemens places the switchgear and transformer in steel containers, connecting them by a SF6 bus into any configuration needed. This modular design makes expansion easy and economic. It also can be relocated if the need arises.
Power transformers are not the only transformer applications benefiting from the advancement of technology. The instrument transformer has seen some cutting-edge technology advancements, too. Traditionally, this type of apparatus is composed of iron and copper with insulation using oil-paper or epoxy resin, but that's changing. Manufacturers such as ABB, Alstom, Siemens and Trench began applying SF6-insulation technology many years ago, which allowed for smaller footprints, less weight and an explosion proof design.
The optical instrument transformer uses light to measure voltage and current, and has some impressive ratings — up to 800 kV. Since it uses light technology, it has no magnetic distortion interfering with accurate faults records common with iron core transformers. The output uses fiber optics to get the data where it's needed, which isolates relays from voltage surges. In addition, there is no insulation medium (oil or SF6), which makes it extremely compact and lightweight, with few maintenance requirements.
Another cool development is a device created by Southern States that uses electromagnetic radio-frequency waves to measure current. The company calls it CMD-II, a current measuring device. What makes this application unique is the fact it's a noncontact device that can measure three-phase currents at full line potential without being in the circuit (no insulation required).
Controlling the System
The control building has not been missed by the proliferation of new technologies, either. Utilities have moved from totally manned substations to remotely operated and monitored facilities. Microprocessors and integrated intelligent electronic devices have changed the topography of the control house forever. These devices replaced racks and racks of relays with a few black boxes interconnected using computer-based technologies, turning the control building into a local area network (LAN).
LANs gather both operational and nonoperational data, and, when combined with other smart technology, have evolved into a wide area network (WAN) capable of being a network of intelligent substations. WANs necessitated improvements in the backbone communications systems, including sensors, monitors and peer-to-peer protocols.
Even the copper control cable, common in so many substations, is not safe from technological obsolescence; it's being replaced by fiber, both inside the control building and out in the yard. GE Energy says its HardFiber System eliminates the majority of copper wiring to better use power system protection and control. Add that to systems like generic object-oriented system event (GOOSE), and copper control wiring will be as hard to find as a vacuum tube.
The GOOSE system allows the copper wire connections between devices to be replaced with an Ethernet process bus. This virtual connection technology reduces the hundreds of hours of intensive labor spent to hardwire devices together to a plug-and-play installation. Not only does it reduce labor, but troubleshooting wiring mistakes during commissioning becomes a thing of the past.
Gone are the days when the substation was just a connection point whose highest priority was the detection and isolation of transmission system failures. That's still important, but the substation's role in the grid has become so much more with the smart grid deployment the industry is undergoing.
Utilities are taking advantage of advancements in technology to design and build substations with improved reliability, higher ratings, smaller footprints, increased automation and reduced requirements for maintenance labor. They are under a great deal of pressure from customers, regulators and stockholders to be more efficient and environmentally friendly, which the substation improvements definitely help.