Utility tackles data integration, analysis

On Aug. 14, 2003, a blackout left 50 million people in eight U.S. states and Ontario, Canada, without electricity. It took four days to restore power to some of the affected areas of the United States, and parts of Ontario suffered rolling blackouts for more than a week.

That’s just the sort of crisis Michigan Electric Transmission Co. plans to avoid by adding real-time data analysis and alerting features to its network. Based in Grand Rapids, METC owns and operates 5,400 miles of transmission lines and 80 substations in Michigan’s Lower Peninsula. Via a network of high-voltage power lines, METC moves electric power from its source – nuclear or fossil-fuel power-generating stations – and hands it off to local distribution companies, which transmit it from METC substations to 6 million people in METC’s territory. “We’re like the tollway, or the superhighway. We take the energy from the generators and deliver it to the local distribution companies,” says Julie Couillard, METC’s executive vice president and COO.

Application integration, message brokering, data warehousing and business intelligence are the cornerstones of METC’s multi-million dollar project to improve the reliability and efficiency of its core systems. After two years of planning – begun before the 2003 blackout – the company launched the first, $5 million phase early last year with IBM and GE Energy.

To safeguard and streamline the process, METC is overhauling its protection and control relay system. The project aggregates real-time data collected from systems and devices in the electric network, and transforms it into something useful for the people who run the system, says Paul Myrda, chief technologist and director of operations at Trans-Elect, METC’s parent company.

METC expects to complete its project in seven to eight years – though it won’t take that long to realize benefits of the upgrades. The long buildout is caused by the substantial upgrades in METC’s substations. “We have to manage outages. We can’t take all of our lines out at the same time,” Couillard says. “It’s staggered in order to minimize the impact on the grid.”

GE Energy is handling the upgrade of METC’s physical assets, including its control buildings; relays; and battery, communication and security systems at each company substation.

IBM provides consulting and integration services, data center services and software. Among the technologies METC is deploying are IBM’s DB2 database and content-management applications. IBM also will manage a hosted environment for storing and analyzing data collected from microprocessor relays, digital fault recorders, equipment monitoring devices and weather stations.

IBM is also developing software – business intelligence tools and dashboards – to give METC staff a real-time view of operational and business data, down to the level of each substation’s devices. For the data crunching, METC uses eDNA, a real-time data monitoring and analysis product from InStep Software.

IBM’s WebSphere Message Broker software makes the links and transports messages between the applications that feed data to the data warehouse and analytic dashboards. METC plans to use the WebSphere integration software as an enterprise service bus to provide connectivity and handle the data transformation required for a service-oriented architecture.

“The component that actually protects the grid – the microprocessor-based relays – will sense if there’s a problem on the line, and do the tripping of the line to keep things safe,” Myrda says. The technology behind that is from GE Energy, and it’s been around for about a decade, he says.

Many companies have put in microprocessor relays, but not a lot are taking advantage of the relays’ capabilities, he says. He compares it with someone who upgrades from a rotary to a push-button phone but never uses the star or pound key. “What’s really innovative in this project is the way we’re streaming all this data in, turning it into information, and really enabling the organization to operate better.”

One of METC’s goals is to respond proactively to potential power losses and unexpected spikes. When failures do occur, the company wants to be able to detect and at least partially diagnose the failures remotely before sending staff to investigate.

Electric utilities today usually rely on staff to inspect substations in person when a problem occurs. Common reasons for power outages on METC’s transmission lines are tree damage, car accidents and, most frequently, weather-related incidents such as lightning and ice.

“There is some technology in the existing METC grid that we can access electronically, but it’s very limited,” Myrda says. For example, METC has legacy Supervisory Control and Data Acquisition software from the 1950s and 1960s for monitoring remote equipment. “It can tell us, for example, a circuit breaker or a line is out of service. What we don’t know is what caused it necessarily,” Myrda says. “The majority of the information still requires a trained technician to go out in the field and obtain intelligence about what went on.”

This project will change that. Data now will be electronically gathered, analyzed and presented to those who run the transmission system, Myrda says. “So if something happens, or is about to happen, that intelligence will be put in front of the operator so they can begin to mitigate the issues.”

In addition, when METC does have to dispatch someone, the new technology will be able to zero in on a trouble spot with greater accuracy. In the past, METC would know something had happened on a length of the line – but if a line is 100 miles long, that’s not a very focused target. “With some of the modern technologies today, we’ll know the line tripped, and we’ll be able to go in, look at the information and see that the accident occurred 27 miles down the line from the endpoint,” he says.

Another addition to the transmission network is video monitoring at the substations. METC uses video technology for physical security and as a remote-systems monitoring tool. “METC covers about 33,000 square miles. It takes hours to get from substation to substation,” Myrda says. With video links, remote operators can tap into the video feed, pan and zoom cameras from their desks, and see what’s going on without dispatching a crew, Myrda says.

METC’s new technologies also will help the company improve operational decision making, Couillard says. The data collected will aid METC plan for and prioritize future system upgrades, for example. By analyzing load patterns in greater detail, METC can upgrade specific circuits that need it instead of doing unnecessarily broad network upgrades. “We wanted an integrated solution so that we could not only reduce our maintenance costs but also obtain more and better data to help us operate and manage the system,” Couillard says.

Meanwhile, as regulatory initiatives aimed at utilities unfold, METC will be a good position to handle what’s required. The U.S. Energy Policy Act of 2005, for example, will require utilities to provide a higher level of remote-asset monitoring.