The Substation is the Critical Link Between Transmission, Distribution and Customers. This link must be robust and reliable. In the digital age, however, a robust substation is a strength and a weakness. Technological development is accelerating so fast that it almost seems to be planned obsolescence.

Although substations are built to last, utilities cannot just lock the gate and walk away. Once a substation becomes part of the grid, it will be modified and improved. Visit an older substation, and it is a sure bet old and new technologies are working in concert with multigenerational devices sharing the same control building. Last century's electromechanical relays will be sitting next to today's ultramodern digital microprocessors, and they all have to function collectively and perfectly.

Engineers and technicians from utilities and manufacturers have been working together to adapt each generation with the next.

IT STARTED SIMPLE

The evolution began when utilities introduced intelligence into the substation by staffing critical substations 24/7. The system operator called the station and gave operating instructions to station personnel. It was a human-machine interface in its simplest form.

Somewhere along the way, someone had an idea to use a timer, cam, relay or some combination of these to make a machine do some simple repetitive task, freeing up the human to do other things. Substation automation was born, which took a big step forward in the 1960s with the development of supervisory control and data acquisition (SCADA) systems, remote terminal units (RTUs) and high-speed communications systems. It gave utilities the ability to energize and de-energize transmission circuits remotely from great distances. This simplified operations as far as the logistics of moving technicians around to far-flung substations for switching procedures, but increased the complexity of the system with the need for elaborate schemes to make certain each part was reliable.

Computers found their way into the system in the form of programmable logic controllers (PLCs) a few years later. PLCs allowed for more-sophisticated sensors and actuators, which increased the SCADA system's abilities manifold. The microprocessor — a computer on a chip — followed shortly, along with Web-based access, Internet protocols and expert systems programs.

With all this control and interaction between components, someone noticed a great deal of information was being generated from each substation. It showed operational and nonoperational data, which utilities started to record and store.

UNIVERSAL TRANSLATOR

Here we are today with substations in various stages of evolution. Some have very limited cognitive abilities. Others can run self-diagnostics and anticipate problems, and some can correct those problems before the human operators even know a problem exists.

“The challenge is the fact that if a piece of technology has ever been used in a substation, it is still being used,” explained Jonathan Piel, global product director for Cooper Power Systems (Waukesha, Wisconsin, U.S.). “Utilities have decades of legacy devices operating throughout their systems. They can't afford to scrap and start over.”

Utilities must make those existing systems work with the newer technologies. Piel made the point that early intelligent electronic devices (IEDs) weren't made with interfaces to work with protocols developed for today's digital world. “They don't speak the same language,” Piel said.

Cooper's approach was to take data from the many generations of sensors and devices found in older substations and develop a black-box approach known as the data concentrator. “The data concentrator has become a universal translator for substations,” Piel noted.

The data concentrator bridges the generations of sensors and monitors found in the substation, allowing them to communicate with each other using their native protocols. Cooper's Cybectec division's Substation Modernization Platform (SMP) has the ability to interconnect all data-producing (sensors and monitors) devices and data-consuming (control, maintenance and engineering centers) clients easily. Data is converted to a standard format and stored in the SMP's Real-Time Data Exchange component with Web-based access from transmission control protocol/Internet protocol (TCP/IP) on serial or local area network connections for flexibility.

Cooper's Cannon division, working with Oklahoma Gas and Electric (Oklahoma City, Oklahoma, U.S.), has been doing some interesting things using IEDs to monitor circuit breakers and transformers for several years. The Cannon Advisor system provides equipment condition monitoring, alarm notification and trending, and it is Web-based for accessibility. It also uses wireless communication to monitor the equipment, which eliminates cabling between the equipment and the control building. Video is also installed as part of the monitoring system. “You can put a sensor on the equipment for data, but video allows you to see what is taking place in the substation,” Piel reported.