This article focuses on benefits of the electric meters capable of sharing real-time usage data with the company and customers alike. Creating the smart grid on a national scale will be perhaps the biggest change to the electrical system since the rural electrification effort of the 1930s. Companies are trying to get a more reliable energy system through, for example, outage management systems, rebalancing loads, and getting help with rebalancing through consumers controlling their usage. To provide real-time or near-real time information, which is needed for consumers to monitor and control their usage, the electric meters must communicate with each other frequently. Sensing and monitoring devices at customer premises that let customers control their electric use are explicit elements of smart grids The future smart grid, Smart Grid 2.0, is next-generation, interactive, self-healing, distributed everywhere, and has an innate capability to reach every device.
When Pacific Gas & Electric started deploying its technicians to install new electric meters in San Francisco and Oakland, most of the thinking \¥as about the benefits these meters could reap. The new meters would be capable of sharing real-time usage data with the company and customers alike, and the hope was that this information would lead to new ways to reduce not only peak power demand, but also total power consumption. It's this promise that is spurring utilities around the country to invest in the so-called smart grid. What few people anticipated was that the city itself would seemingly conspire against installing the smart grid.
"There are about one hundred years of meters in San Francisco," said William Deveraux, PG&E's senior director for the SmartMeter program. "Customers have built tightly around them, so there is no room to attach a network device."
Some residential customers, for example, enclosed meters in add-on rooms, leaving a window so they could be read. But there's no physical access, or clearance for an outside meter is so limited that only the meter fits.
And even if a new meter can be installed, there's no guarantee that it can relay any information. "If a meter .is in a metal or concrete room, it creates a whole host of engineering challenges to get the signal out," Deveraux said.
"In suburban areas, the ratio of meters to [data] collectors is about five thousand to one," Deveraux said. "In urban areas, the ratio drops, so we need either more relays or access points."
Either way, it's more headaches.
Creating the smart grid on a national scale will be perhaps the biggest change to the electrical system since the rural electrification effort of the 1930s. And the engineers involved with planning it always knew that it would be an enormous undertaking. But the challenges engineers are facing in implementing the new grid are forcing them to be more creative than they had anticipated.
UTILITIES HAD BEEN TALKING ABOUT UPGRADING THE ELECTRICAL GRID FOR DECADES. But the final push came from the Energy Independence and Security Act, which in 2007 mandated the improvement of the grid through the use of communications and sensor technology. The goal was to prevent future crippling blackouts, reduce energy consumption, and lower carbon dioxide emissions.
"Companies are trying to get a more reliable energy system through, for example, outage management systems, rebalancing loads, and getting help with rebalancing through consumers controlling their usage," said Marcus Torchia, a research manager specializing in electric power and the smart grid at Energy Insights, a division ofIDC.
The promise of smart grids isn't just in a better managed load, but a reduced one, as consumers, armed with real-time usage data, try to shave kilowatt-hours off their bills. "There is a concept," Torchia said, "that if consumers have more control over their electricity usage, they will control it."
Compared to previous additions to the electrical grid or proposals for a new set of transmission lines to bring, say, wind power from the Great Plains to East Coast consumers, the infrastructure needed to implement the smart grid won't require a lot of construction. "The smart grid is an information and communications technology overlay to the existing power grid," Torchia said. "There are operationally focused initiatives that center on the distribution and transmission equipment, the supervisory control and data acquisition systems, outage management systems-much less on generation to substation, that is, the core power equipment. The other [approach] is on distribution to the consumer-from the substation to the consumer or business-using automated or smart meters. Right now, distribution to the consumer is dominant globally. The vast majority of investment and money is going here."
But creating these overlays of sensors and communications atop existing electric grids is no easy task. Pacific Gas & Electric started deploying its two-way electric smart meter network near the end of 2006. By last fall, some 1.6 million to 1.7 million two-way smart meters were installed, and so were another two million oneway smart gas meters. By mid-2012, PG&E plans to install five million two-way electric meters.
To provide real-time or near-real time information, which is needed for consumers to monitor and control their usage, the electric meters must communicate with each other frequently. Each new meter in the RF mesh network has an embedded communications card so it can function as a node, receiving and transmitting not only its own data but data from other meters as well. The network also requires a lot of access points and relays that collect data and transmit it across a wireless virtual private network back to the utility.
In urban areas, where physical access to a meter often requires entering a customer's home, getting to the old meters to replace them becomes as much of a public relations challenge as an engineering one.
"We've had some pushback where customers are unsure of why we're doing this," PG&E's Deveraux said. PG&E got out the messages of new meters and smart grid every way it could, from the usual bill inserts to media ads and meetings with community associations of every stripe. At the same time, it's come up with some RF engineering solutions to minimize customer disruption.
One solution is the installation of transponders on a house or other site. The transponder is connected to the meter by a wire, and it can transmit data to the next node in the network. Where that approach fails, PG&E installs powerful relays on the customer's premises. Wirelessly connected to the meters, these relays can "blast their way out of the site," Deveraux said. "In a mall, for example, we can put the relay in the parking lot."
PG&E is still working out solutions to these access problems. "We'll design the network and install the meters and then adjust access points and/or relays as needed," Deveraux said. "We are also designing and sizing the network for future types of sensors that will use the same network, such as a sensor on a secondary transformer to measure its temperature and load."
In 2010, PG&E will pilot its "Home Area Network," which will use in-home Zigbee devices to let customers see their realtime energy use. "We plan to distribute some of those devices next year and see how that information changes customer behavior," Deveraux said. "The goal is to lower demand and manage peak demand."
In contrast to other utilities, American Electric Power, headquartered in Columbus, Ohio, and serving customers in 11 states, did not choose smart meter installation as its first smart grid effort. Instead, the company focused on load-Ieveling, deferring capital expenditures and increasing the reliability of its multi-state electric grids. It accomplished this by installing seven megawatts of energy storage in the form of gigantic sodium-sulfur batteries manufactured by Japanese company NGK. It will soon install two more of the units, each about the size of a double-decker bus, in Texas for a total of 11 megawatts.
The utility's first sodium-sulfur battery installation was in West Virginia in 2006, where a transformer was in danger of being overwhelmed by heavy electric demands. A onemegawatt unit was installed. "The battery reduced the peak load by several percent over several years," said Tom Walker, the company's principal engineer in research and technology. Without the battery, American Electric Power would also have had to build a new 138 kilovolt line to the transformer station and expand the station to handle the load.
The other six megawatts of storage come in the form of three two-megawatt units, located on electrical distribution lines close to customers yet centrally located to accept remote loads. "They can support a portion of the load out on the line," Walker said. "They are associated with a distributed automation scheme known as 'dynamic islanding' that functions as a back-up supply. The load that's picked up is adjustable depending on demand."
Despite the success of the gigantic batteries, they present operating challenges. "The sulfur in the sodium-sulfur batteries must be kept liquid at 300 QC because they can't solidify," Walker said. "It's a very large and specialized installation. Normally, charging and discharging heats the sulfur, but there are separate heaters, and we have emergency back-up generators to keep the sulfur hot. It's appropriate for a multi-megawatt installation, but it requires constant monitoring and lots of maintenance."
That is one reason why American Electric Power is moving away from megawatt-sized sodium-sulfur batteries. Instead, the company is investing in kilowatt-level lithium ion batteries that can be installed much closer to the edge of the grid. "We get even better efficiency because the storage is closer to the customer, which reduces line losses and voltage instability and provides an even higher level of reliability," Walker said. "These batteries will provide back-up and will reduce an outage to barely a blink for the customer."
The suitcase-size lithium ion batteries will be similar or identical to those used for plug-in electric vehicles. "Wherever electric transportation goes, we'll follow because we want to take advantage of the density of energy, the economy of scale, and safety," Walker said.
Indeed, the utility expects to use batteries that don't work for cars any more because they can no longer provide the big, immediate electric oomph needed for acceleration. But they'll be fine for the electric grid.
"We expect to operate many of these batteries as a fleet, and we'll aggregate megawatts of them," Walker said. "On a given circuit, we'll have one or two megawatts of storage, but through many small units instead of one big one."
The first installation of the lithium ion batteries is planned for 2010 in Columbus, where American Electric Power has also proposed a large smart grid project that will likely include renewables. "One of the challenges facing utilities is the integration of renewables like wind and solar," Walker said. "They are unreliable. The sun. isn't always shining and the wind doesn't always blow at peak times. So we must deploy batteries not only for load-Ieveling, but also to handle renewables. We can take the DC output from a solar panel and use it directly to store DC-to-DC power on the batteries from the solar cells. Without batteries, customers would have to provide their own DC-to-AC inverter. Storage can make the renewables dispatchable."
IT WILL TAKE THEUTILITIES HAD BEEN TALKING SMART GRID, HOWEVER, TO FULLY REALIZE THE BENEFITS OF STORAGE."The smart grid technologies of communications and controls are required for the aggregation of the batteries," Walker said. "So Columbus is the reason for the first deployment of smaller batteries."
Austin Energy, the municipal utility serving the Texas capital, has arguably the most complete city-wide smart grid in the United States today. With 410,000 meters installed since 2003, along with a brand new information technology system, everything is in place from the meter back to the utility-except a new billing system. That will be finished in 2011.
Smart Grid 1.0 is what Austin Energy CIO Andres Carvallo calls the utility's efforts to date. "It's the view in front of the meter to the utility," he said. "It's generation, distribution, and transmission, to the meters and back. It's the purview of the utility."
Austin Energy installed the first 155,000 meters in apartment complexes, rental housing and the like, so they are one-way units. The remaining 255,000 are two-way units, and they came with some bugs to work out.
"The most challenging pieces [of implementing the smart grid] is that not all of the systems are in place," said Cheryl Mele, chief operating officer and deputy general manager for Austin Energy. "So it's a struggle to do a two-way upgrade of meters in the field. It's been a challenge to get the meters plug-and-play ready."
A major piece of that challenge was the puzzle of the disappearing meters-meters that were installed correctly, but refused to show up when the network looked for them. The problem wasn't immediately obvious, either; it took some time to realize the meters appeared to be missing.
Replacing the old meters with the new smart meters was straightforward enough. Technicians went out to the sites of existing meters, removed them, and replaced them with the new units. Then technicians programmed the new meters with hand-held devices that contained a GPS receiver and an advanced metering network radio required to complete the installation. Once some of the meters were discovered by the network, automated reads started to come in and were delivered to Austin Energy. Technicians had to truck back to the meters to figure out why all the meters weren't showing up. First, the company discovered that some of the hand-held programming devices were not operating correctly, which resulted in routing corruption in the mesh network.
"To untangle the sources of errors, we used diagnostics and analysis to isolate the hand-helds with problems," said Trac.y Moore, senior vice president and general manager for managed services at Landis & Gyr, the company that makes the meters and provides the RF network they use. "The bugs were found through end-to-end testing of input vs. output." Where the two differed, the hand-. held was clearly at fault.
But that wasn't the whole story. Once the hand-held problems were identified and corrected, the disappearing meters were still missing. "By a process of elimination, we'd show that the GPS input and output coordinates were correct, and the geocodes were wrong," Moore said. "We went back out and fixed the geocodes, and then we knew there was a problem." Afte,r that, when the technicians went out to install the meters-all 255,000 of them-they updated the geocodes using the reprogramm hand-held devices.
By capturing good GPS coordinates at the time of installation, the problem was ultimately solved. The last of the 255,000 two-way meters was installed in September, after about a year of work.
Sensing and monitoring devices at customer premises that let customers control their electric use are explicit elements of smart grids, and that consumer side will be the next step for Austin Energy, Pacific Gas & Electric, American Electric Power, and most utilities working on improving the electric grid. It's not the final chapter in the story, however.
"The future smart grid, Smart Grid 2.0, is next-generation, interactive, self-healing, distributed everywhere, and has an innate capability to reach every device," said Austin Energy's Carvallo. "That's the end game, and it will take ten to fifteen years for us to get there."
Expect it to be ten to fifteen years of unexpected headaches and hiccups-and clever engineering solutions.