Tackling the Smart Grid Challenge

Electric utilities and others around the nation are deploying a range of Smart Grid automation and communication technologies as a way to save energy, reduce costs and boost reliability.

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In a recent report, the Electric Power Research Institute (EPRI) defines the Smart Grid as “a modernization of the electricity delivery system so it monitors, protects, and automatically optimizes the operation of its interconnected elements—from the central and distributed generator through the high-voltage network and distribution system, to industrial users and building automation systems, to energy storage installations, and to end-use consumers and their thermostats, electric vehicles, appliances, and other household devices.”

That’s a mouthful, for sure, and it spans a plethora of communication and automation technologies. So it’s not surprising that the Smart Grid means different things to different individuals. “If you took a poll of people in the industry and asked them what the Smart Grid is, you’d get a different answer from every one,” observes Bob Gilligan, vice president, transmission and distribution, for GE Energy Co., Atlanta, a provider of Smart Grid technologies. “The Smart Grid is not a single product, but a set of solutions.”

When Automation World set out to provide coverage of the Smart Grid as part of the “Networks & Connectivity” focus for this issue, we decided to touch base with some of the end-users of Smart Grid technologies to find out what the Smart Grid means to them. We caught up with folks-in-the-know at three major utilities, and at a major U.S. military base. In the individual reports that follow, readers will get an idea of some of the elements needed to make the Smart Grid a reality, some of the considerations involved and some of the benefits to be achieved.

[Case #1] National Grid Sees Smart Grid “Data Explosion”

It’s a funny thing about the Adirondack pine trees found in upstate New York. They make it difficult to communicate via 900 megahertz (MHz) radio, says Vince Forte, principal engineer, Smart Grid, for National Grid, in Albany, N.Y., one of the nation’s largest utilities.

“When they’re fully grown, those long-needled pines happen to be a perfect fractional wavelength of 900 MHz,” Forte says. “They actually absorb the signal and round it out, so it’s like a black hole—you just can’t get through them. You either have to be above the trees with your antennas, or you need to find another technology,” he relates. And in the 6.1 million-acre Adirondack Park, a New York State-protected area, there are restrictions on tower height.

It’s a reality that National Grid confirmed during a Smart Grid distribution automation (DA) pilot test conducted recently by the utility, which supplies electricity to some 3.3 million customers in Massachusetts, New Hampshire, New York and Rhode Island. The company used 900 MHz spread spectrum radios for peer-to-peer communication of data between devices installed on its distribution feeder lines in the pilot test area, says Forte. But when National Grid tried using the same technology to send data gathered in the field back to its control centers for analysis, it ran into the piney communications problem. As a result, says Forte, “we’re exploring other communication options” for that portion of the network.

The experience points out the fact while robust, broadband two-way communications will be essential to effective Smart Grid operation, no single communication technology will do it all. “I don’t think that you will see one type of communication dominate around the country,” Forte observes. “I think you’ll see a mix, depending on the needs of particular utilities and the physical environments they operate in.”

Big pipe

One thing that is certain: For many applications, “a very large pipe” will be required to handle the huge anticipated volumes of Smart Grid-generated data, Forte says. That might mean anything from fiber optic or T1 communication lines to 900 Mz spread spectrum or WiMax (for Worldwide Interoperability for Microwave Access).

With the Smart Grid, “there’s going to be an explosion of data,” Forte predicts. Though utilities have long had the ability to control transmission-line devices from a central facility, the Smart Grid will extend that capability down to the distribution level. “So instead of hundreds of transmission lines, we’re talking about thousands of distribution lines and all the associated substations,” Forte points out. That means data from many more devices coming back to the control room.

Further, the amount of data transmitted for many of these “smart” devices will amount to orders of magnitude more than that seen in traditional grid communications. In a typical transmission supervisory control and data acquisition (SCADA) environment today, two-way communication for a device might be limited to a simple set of “open” or “close” data exchanges, Forte observes. But in the world of automated smart devices on the grid, a single switch, for example, might be sending back as many as 90 data points about itself, Forte says.

That intelligence will pay benefits. “It will allow us to increase the automation for the self-healing of the grid, so that we can find the faults, isolate them and restore as many customers as possible as fast as these devices can physically operate and the communications can transport the signals around for us,” says Forte. “So we expect to see improvements in reliability from this.”

Let’s talk

An additional communications barrage will result from the millions of smart meters to be installed in customer homes and businesses. “Every meter will be telling us not only the kilowatt/hour usage for the customer, but also the voltage at the meter, whether the meter is connected properly, and the health of the meter itself,” Forte says. And that’s not to mention the two-way “conversations” that will take place between utilities and customer home automation systems regarding electricity pricing and the willingness of customers to participate in utility load shedding schemes, among other things.

As a way to handle anticipated Smart Grid requirements, National Grid is currently evaluating a variety of new systems, including a new transmission-level energy management system, a distribution management system, an outage management system and a meter data management system, Forte says. The utility is working with various vendors in a proof-of-concept environment, but has not yet selected the suppliers for upcoming Smart Grid initiatives.

That decision may have to come soon. National Grid in August applied for $200 million in federal stimulus money to help fund pilot projects involving “end-to-end” Smart Grid deployments that would include about 200,000 customers in New York, Massachusetts and Rhode Island. A decision on the application is expected this fall, and if approved, initial deployment could begin by next summer, says Bill Pratt, National Grid Smart Grid program director. 

[Case #2] Distributed Generation Key for Portland General Electric

No one was yet talking about a “Smart Grid” in the year 2000, when Portland General Electric Co. (PGE) hired Mark Osborn to head up a new demand-response program at the Portland, Ore.-based utility. But today, the distributed generation concept on which the system is based makes up an important component of Smart Grid initiatives at PGE and around the nation.

The PGE system provides electrical grid capacity by linking customer-owned generators as part of a “virtual power plant” for the utility’s Dispatchable Standby Generation (DSG) program. With the system, PGE can shave peak loads on the grid by using the available aggregated generation from customers’ emergency standby generators as part of its reserve capacity system.

Beginning with a single customer generator in 2000, the DSG system today has grown to incorporate agreements with 26 customers involving 40 generators. “Right now, we’ve got about 58 megawatts (MW) online and we’ve got another 13 MW under construction, so we’ll soon be over 70 MW,” says Osborn, PGE distributed resources manager. Participating customers include hospitals, data centers, industrial plants and wastewater treatment facilities, among others.

Sweet deal

Under the DSG program, customers allow PGE to use their generators for up to 400 hours a year during times of peak power demand. “We pay for the paralleling switch gear that goes in and makes their generators go seamlessly on and off the grid. We pay for the fuel for the generators, and we pay for all maintenance on the generators, including replacement if something happens,” says Osborn. “So they will basically have no more operating costs on their generators.”

In return, PGE gains the ability to avoid buying power from the Western grid at times when wholesale prices are skyrocketing, Osborn explains. He cites one West Coast summer hot spell in 2006, for example, when the wholesale price of power hit the federally regulated price cap of around $400 per megawatt hour (MWH). At the time, DSG operational costs were about half of that, at around $200 per MWH, enabling PGE to reap significant savings compared to buying power at market prices during the crisis, Osborn points out.

Operators at the PGE control center are able to turn on the DSG generators when needed using a system known as GenOnSys, which enables distributed real-time monitoring, live video cameras and alarming for the generators. Integrated with the center’s supervisory control and data acquisition (SCADA) system, the GenOnSys system is based on software supplied by Wonderware, the Lake Forest, Calif.-based unit of Invensys Operations Management (IOM).

The current version of the GenOnSys system takes advantage of features in the Wonderware ArchestrA platform that allow for easy integration with a variety of generators and systems supplied by different manufacturers, says Osborn. The ArchestrA structure for using software objects fits nicely with the communications model envisioned in the International Electrotechnical Commission’s IEC 61850 standard for electrical substation automation, he notes. It’s a standard that many believe will play an important role in national Smart Grid interoperability. Factory IQ Inc., a Portland, Ore., system integrator, was selected to develop the GenOnSys system.

The software allows for creation of objects for different manufacturers’ generators, control systems and switchgear sets, says Osborn. “Once we create an object, we don’t ever have to create it again, and you can tie graphics with it.” The result, according to Osborn, is that PGE can now add a new generator site to the DSG system within a day or less, compared to about three weeks that was required using an earlier version of the GenOnSys software.

Wind and solar

In addition to the customer-owned generators, the GenOnSys software has also been expanded to provide monitoring of various PGE solar power projects and meters. In the future, the DSG will have a major role to play in managing the utility’s Smart Grid assets, Osborn says. One scenario, for example, might involve a 450 MW wind farm currently being built by PGE that is scheduled for completion in 2010.

“The wind is great when it’s blowing, but it’s not so great when the wind dies down. So the concept is to be able to have a smart system that can react when the wind dies down to either shed load or bring on distributed generation,” Osborn explains. Besides the generators, other Smart Grid components might also include advanced storage systems such as batteries that could store power from solar arrays. If done in a big way, these storage systems could also be used to provide power to the grid at times of low wind.

As another alternative, Osborn adds, “you could also look at being able to do demand response—in other words, cutting off water heater elements or changing thermostat settings or maybe reducing lighting,” he notes. “So there’s a variety of Smart Grid methods that you could use.”

[Case #3] Oncor Works on Multiple Smart Grid Fronts

Say you’ve got a 180-mile long electric feeder line in a sparsely populated, rural area, and a problem occurs somewhere on the line. “If you’ve got enough technology to tell you which side of the river the fault is on, you just saved yourself a number of hours in looking for it,” points out Keith Hull, senior director, Distribution System Operations, for Oncor Electric Delivery Co. LLC, a Dallas-based electricity distribution and transmission utility.

Hull should know. Oncor’s 53,469-square mile service territory includes the highly populated Dallas/Fort Worth metropolitan area, but also stretches from the eastern “piney woods” area of Texas with its National Forests, all the way to the arid expanses of West Texas, where population centers are few and far between. And as Oncor continues to build out its Smart Grid technology, it expects to be able to pinpoint faults more tightly within its distribution network—in some cases down to just a few feet.  That’s valuable information when a work crew must be dispatched to fix the problem and restore power.

“Building out a Smart Grid system with all of the intelligence takes a long time, because there are a lot of different pieces that you have to put out in the field,” says Hull. “We’ve already got a large portion of it out there, but we’re going to continue with projects to add different types of technology as we get to them, and as new technologies become available.”

250,000 and counting

Indeed, Oncor has a variety of Smart Grid projects in the works. The company began replacing traditional analog customer meters in 2005, and currently has more than 250,000 advanced electronic meters in place, with plans to outfit a total of 3.4 million Oncor customers with the smart meters by 2012. The company also completed a four-month rollout of a new Mobile Workforce Management (MWM) system last December that enables automatic routing of thousands of customer service orders daily, says Hull.

Upcoming Oncor Smart Grid projects include a new outage management system (OMS); a distribution supervisory control and data acquisition (DSCADA) project; and installation of distribution automation (DA) equipment and distribution network analysis (DNA) technology to provide smart decision support, according to Hull.

As all of these pieces come together into a unified Smart Grid system, says Hull, a major objective is the integration of what will be terabytes of data into actionable information that Oncor can use to provide better and more reliable service to its customers.

Today, operators in the utility’s two distribution operation centers rely on six screens, running seven to 10 different applications, he says. But Oncor’s Smart Grid initiatives will enable “a single front end” for use by all personnel—including operators, dispatchers and mobile field staff—that will provide access to all needed applications. Using communications-equipped mobile personal computers (PCs), the company’s 1,500 to 2,000 outside construction, maintenance and operations workers will be able to see the same screens as those seen in the operations centers, Hull points out. By creating a single interface for all users, the company expects to reap gains through improved operations efficiency, simplified training and easier transfer of workforce knowledge.

Oncor is working with Intergraph Corp., Huntsville, Ala., to supply the front-end graphics for Smart Grid
network-and-distribution management, according to Hull. Siemens Energy Inc., Orlando, will provide “the back-end smart stuff, making the engine run to control all the pieces of equipment out there,” as Hull puts it.

“The really hard part,” says Hull, will involve the software algorithms and number crunching needed to convert the large amounts of real-time data produced as a result of Oncor’s Smart Grid initiatives into useful information that can be used by its staff.

Terabytes on terabytes

Oncor already has 1,200 distribution-controllable devices such as switchgears and reclosers in the field, as well as 3,200 controllable capacitors. Plans call for building this distribution device count out to as many as 30,000 points, says Hull, and each of these points may supply some 12 to 15 pieces of data on a real-time basis back to the control system. Add to this the data coming in from the planned 3.4 million advanced customer meters—which will each provide readings every 15 minutes—Hull notes, “and we’re talking about terabytes on terabytes of data.” 

[Case #4] Marine Base Looks Toward Microgrid for Savings

The world’s largest Marine Corps base is about to join the Smart Grid movement. In a project set to begin in January, Twentynine Palms Base—a premier Marine training facility in the California Mojave Desert east of Los Angeles—will be the site for a “smart microgrid” demonstration project funded by $2 million in Federal stimulus money. The project is intended to serve as a model for other military bases, and also to demonstrate how other types of facilities, such as industrial complexes, can take advantage of a smarter electrical grid.

The microgrid project was awarded this summer to General Electric Co. (GE), Fairfield, Conn., by the U.S. Department of Defense (DOD). Under terms of the two-year contract, GE will design and demonstrate a smart energy management system that enables installations to more optimally manage on-site power generation and energy storage, while interacting with the regional electrical grid in a more intelligent and efficient way.

On-site generation

Like many military bases, Twentynine Palms generates its own local power on site—in the form of a natural gas-fired co-generation plant and a solar array. The base is also connected to the larger U.S. electrical grid, getting power from Southern California Edison (SCE), based in the Los Angeles county city of Rosemead, Calif.

Together, the co-gen plant and solar array can provide about 60 percent of the base electric power load, which averages 22 megawatts (MW) during the summer, says Gary L. Morrissett, branch head, Utilities/Energy Managment, for the Twentynine Palms Base Public Works Department. Additional projects planned will bring on-site generation capacity up to 80 percent to 90 percent of base need in the future, Morrissett adds.

Today, when Twentynine Palms occasionally loses power from the outside grid—most commonly in the high-demand summer months—the base has the ability to manually restore power to its critical infrastructure using power from the co-generator and solar array. But the transition is abrupt, notes Lieutenant Commander Yvonne R. Lyda, Twentynine Palms Base Public Works officer. “Everything goes down,” she says, while an operator initiates an “island mode”—by closing the breaker to the outside grid—and then brings up available on-site power to the base critical infrastructure.

The new microgrid control system to be supplied by GE Digital Energy is expected to smooth this process through automation, while also providing optimum energy management during normal operations. “The Smart Grid should be able to look at our load, look at the cost of power to meet that load, and come up with either the one or the mixture of power sources to supply that load so that theoretically, we’re paying less for energy at any given point in time,” says Lyda. “This grid will literally be able to think,” adds Marques Russell, electrical engineer at the base Public Works Department.

Problem spotting

The system will be linked for two-way communication and control to multiple base facilities, including seven electrical substations and numerous building energy management control systems (EMCS), to instigate load shedding schemes as needed. The increased integration is expected to pay benefits in improved reliability, says Morrissett. “We’ll be able to see where the loads actually are, so if we have a problem—maybe a transformer that’s taking too much load—we’ll be able to react to that before there’s a larger problem.”

In the end, Morrissett says he is hoping that the smart microgrid project will lead to energy system savings in the range of 10 percent for the base. “And as our system grows, we’ll be incorporating it into whatever new generation that we get into,” he adds, “so it’s going to be a very well-used system.” 

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