This is Part 1 of a two-part series on SmartGrid 2.0. Part 2 will be published on Monday, Feb. 6.
Discussions of “smart grid” technology have largely focused on the distribution system and technology that will reach the retail customer – things like smart meters, smart appliances and plug-in hybrid cars. But there is a need to make the actual transmission system smarter, and there are initiatives underway that give the term “smart grid” a more literal meaning.
“Think of it as a two-layer smart grid,” Mark Maher, CEO of the Western Electricity Coordinating Council (WECC), told TransmissionHub. “Most of the talk is about [devices on the] distribution system: new meters on houses, plugging in your electric car, having smart appliances and [things like] that. The other level is what we’re operating in, and that’s at the transmission level.”
WECC and the Midwest ISO (MISO) are currently deploying one of the more cutting-edge technologies, called synchrophasors. The devices are installed on the transmission system and measure voltage, current and frequency at high sampling rates – 30 to 60 times per second – giving control rooms and system operators the ability to see what is happening on the grid in near real-time. Through the U.S. Department of Energy’s Smart Grid Investment Grant (SGIG), about 850 synchrophasors, or phasor measurement units (PMUs), are planned across the nation.
MISO plans to install 165 PMUs across the region in a $34.5m program, $17.3m of which is funded by a grant from the U.S. Department of Energy. As of January 2012, MISO had installed 85 PMUs. WECC is expected to install about 350 new or upgraded PMUs across the Western Interconnection by the end of the initiative’s funding period in March 2013.
“The amount of data that’s able to be collected and the speed at which that data is able to be ferried back to operator control rooms to give the folks operating the system insight into what’s going on on the grid, what could potentially be coming their way, and knowing that sooner than they were able to, is the exact definition of what the grid being smarter is about,” Brian Slocum, ITC Holdings’ vice president of engineering, told TransmissionHub.
Current technologies on the grid collect data once every two to four seconds.
“Synchrophasors represent an upgrade from the existing SCADA (supervisory control and data acquisition) system,” Maher said. “SCADA data is like looking in a rear-view mirror. It’s coming in at around a six-second lag into the system whereas phasor measurements are coming in 30 to 60 times a second.”
While some utilities poll their SCADA equipment at intervals as short as two seconds, Matt Olson, senior engineer with the engineering and consulting firm Burns & McDonnell, which recently dedicated a new Smart Grid laboratory, agrees that SCADA data has its limitations.
“If you have oscillating power flows and you’re only sampling every few seconds, you may see the power go up and down [several times, and] if you’ve got a blackout coming, you can’t really tell if that oscillation is dampening out or if it’s increasing,” Olson told TransmissionHub. “With a synchrophasor, you are going to get detailed enough information that you can see that impending doom coming and you can take appropriate action.”
Data from PMUs feeds into data concentrators on the systems of the various utilities. Additional software will take that data and turn it into information so that dispatchers and reliability coordinators can look at the PMUs, “bringing in voltage, frequency, phase angle, a number of technical parameters that we need to operate this system optimally,” Maher said.
Synchrophasor data can alert the operator that conditions are outside normal parameters. “[A utility’s system] would be monitoring the data continuously and if it sees a condition it deems abnormal, then it would alert the operator” who would then make the ultimate decision of the appropriate action to take, Olson said.
“The fact is that this is making the grid smarter. Everything else you hear about smart grid, ironically enough, is not really applied to the grid; it’s applied to the end user, or the substation before it goes to the end user,” Slocum said. “In my mind, that’s always been very ironic, that we tag these things as ‘smart grid,’ but none of them really applies to the grid.”
With the ability to gather and synthesize data in real time, Maher says the next logical step is automation.
“[PMUs] will eventually lead to automated control so that we can conceivably have a self-controlling, self-balancing transmission system,” Maher predicted.
While such a development is technologically possible, Olson cautions that utilities have valid concerns about placing too much trust in automation.
“The automation may come up with a proposed answer but are we going to let it implement that automatically, or are we going to have a human look at before it goes off and” takes an action such as shedding load that may not need to be shed, Olson asked.
“You’ve just to be cognizant that we don’t go the wrong way and end up with some of the lessons we learned from Three Mile Island where we relied too much on the computer and the information wasn’t getting to the humans fast enough,” Olson added.