Distribution management at the smart grid frontier.
Alyssa Danigelis is a Fortnightly contributor based in Boulder, Colo. She also writes for Discovery News. Follow her on Twitter @adanigelis.
The computer bank at Oklahoma Gas & Electric isn’t quite HAL from 2001: A Space Odyssey, but it promises to change everything. Equipment racks loaded with 100 computer servers are running the software for a new distribution management system (DMS). The system is still in testing, but OG&E hopes that once it’s deployed, the DMS (developed by ABB Ventyx) will be able to translate data transmitted wirelessly from field equipment into timely, useful information for the control room. It will give the utility’s operators the ability to look at the entire system’s configuration when performing fault isolation and restoration processes. It will add intelligence, considering the risks of overload before closing switches. And it will automatically execute a volt-VAR (volt-ampere reactive) optimization routine on a wide scale.
Bringing these capabilities all into one interconnected system represents a substantial advancement in smart grid infrastructure. But when the OG&E project began, planners didn’t see it as being particularly revolutionary. “We were under the impression that more companies had this [type of system] already,” says Scott Milanowski, OG&E’s director of grid intelligence. “We’re finding out that we were a little more on the leading edge than we had initially realized.”
The DMS implementation is being driven by the utility’s corporate strategy to defer the need to build any new fossil power plants until after 2020. With a growing market of just under 800,000 customers across Oklahoma and a small part of Arkansas, OG&E is tackling an ambitious goal. Although public attention has tended to focus on the sexier aspects of OG&E’s strategy, such as its plan to dramatically increase reliance on wind power, the utility’s DMS represents a major milestone in the development of smart grid infrastructure—and a harbinger of what’s to come for the industry.
Smart Grid’s Changing Narrative
Over the past year, excitement about the smart grid seems to have shifted somewhat, away from customer-facing technologies like advanced metering infrastructure (AMI) and home energy management, and toward utility-centric distribution automation systems. Advanced DMS (ADMS) has become the hot new acronym in vendors’ marketing materials, and a recurring buzzword in companies’ presentations at trade shows. Many utilities, like OG&E, seem to have turned their focus away from smart meter rollouts and zeroed in on systems that optimize their distribution processes. ADMS is the core technology that can unite the various smart grid systems that have grabbed headlines in recent years, allowing utilities to start realizing benefits as soon as the technology is installed.
The advantages of a new distribution management system are clear for OG&E, but the challenge for many utilities is that ADMS represents a new technology that begs definition. Discussions about ADMS today easily wend into hyper-technical territory, or float into an abstract cloud that can make it difficult to understand what ADMS is supposed to do. Otherwise helpful analogies falter. Is it a heart? A brain? A backbone?
It’s actually a combination of all three.
Ken Geisler, vice president of business and product strategy in the smart grid division at Siemens, observes that advanced DMS can be confusing for many utilities. “Their business is to operate a utility, it’s not to be IT experts,” he says. But the need for an ADMS is becoming inevitable as companies invest in smart grid systems.
“There are so many external requirements that you’re going to have to deal with,” Geisler says. “An advanced distribution management system supports a broad variety of solution requirements.”
But like the word “smart” in smart grid, the definition of “advanced” DMS can be relative. Some vendors are developing systems that fully integrate distributed automation, asset management, smart metering, and eventually distributed energy resources, such as rooftop photovoltaics and electric vehicles. Others have simply decided to start calling their outage management systems “DMS.”
Nevertheless, the ADMS of the future will operate in real time and across multiple divisions within a utility. The stronger the DMS, the better its ability to process large amounts of data from different devices and systems. Success hinges on having the right level of integration and functionality, as well as collaboration among suppliers, integrators, and utilities. And of course, utilities will need to bring all of that to a scale that serves their entire systems.
The full magnitude of this effort is illustrated in an anecdote related by Avnaesh Jayantilal, global DMS activity director at Alstom. He won’t name any names, but recalls visiting a utility control room recently. Although operators worked in a beautiful space, he says, the utility used archaic technology: two-story paper maps accessible with a tall library ladder. Color-coded pins designated outages and trucks. Meanwhile, outside the control room, the people planning the grid had sophisticated software tools at their fingertips.
Such disparities are changing. Wade Malcolm, global lead for Accenture’s smart grid services operational technology practice, says he’s seeing significant global investment in hardware, such as upgrades to switchgear, fault detection, and protection for feeders and other elements of circuits. He notes that early distribution management systems were offshoots of SCADA and OMS. But as utilities invest in smarter systems, they’re discovering their legacy processes don’t necessarily work together efficiently. Products rooted in outage management focused on data collection and management, while those with SCADA heritage tended to be good at creating a static view of the network, managing the configurations, and driving electronic map boards and diagrams, Malcolm says.
Over time, distribution operators acquired better basic tools to measure and monitor what’s happening in certain parts of the grid, according to Jayantilal. “But they didn’t have advanced tools that would understand where the power was flowing, or how to optimize the grid,” he says.
In recent years, distribution operators gained SCADA tools, real-time planning tools for analytics, as well as volt-VAR control, fault location and isolation, and service restoration. Although some vendors call the union of those tools “ADMS,” Jayantilal says the most advanced systems allow utilities to track outages and optimize the grid simultaneously. Like many smart grid experts, Jayantilal equates “advanced” with “integrated”; Alstom calls its advanced DMS an integrated distribution management system or “IDMS.” But Siemens’ Geisler warns that the term can be misleading.
“The word ‘integration’ makes it sound straightforward,” he says. “Generally it’s not.”
One Step at a Time
OG&E’s DMS is part of a multi-phase smart grid project. The first two phases cover a three-year period Milanowski says the utility is calling its “DOE phase” for the $130 million Department of Energy investment grant the company was awarded in 2009. During that phase, OG&E aims to complete all of the AMI, the whole communication network, back office systems, and DMS. The third phase is a five-year span during which the utility plans to continue putting DA devices on the distribution system: reclosers, capacitor controllers, and communicating faulted circuit indicators—all subject to regulatory approval first.
OG&E’s DMS will communicate wirelessly with devices on the distribution network—ones there now, and any added during the second phase. Status information, alarms, and measurement data are sent from the devices to the DMS, which can process the information and in turn control the devices either through an operator or automatically at the operator’s discretion. “Integration is a challenge,” Milanowski says. “It’s something we’re doing, but this system doesn’t sit in a vacuum.”
With DMS, the entire distribution system is modeled with data that’s usually obtained from geospatial information systems (GIS) before it’s brought into the control center. A limited version of OG&E’s GIS model has been exported to the DMS, and ABB Ventyx’s optimization algorithm is working on the distribution feeder model, enabling the utility to lower the voltage at peak times.
“They are taking it step by step, which is the logical thing to do,” says Tim Taylor, an industry solutions executive with ABB Ventyx. OG&E has already done several pilot installations in advance of the DMS, putting distribution automation, automated switching, and fault detection-isolation-restoration capabilities on half a dozen circuits to familiarize workers with the system.
“Our operators were able to get some comfort with automated switching, with reclosers opening and closing by themselves without the operators being involved,” Milanowski says. “Our control center got a degree of comfort with automation before we proposed putting the DMS in.”
OG&E sees reducing outage minutes as a potential societal benefit that might far exceed the direct savings the utility calculates for itself. The company projects that putting automated reclosers on a circuit can reduce interruption minutes by approximately 60 percent on that circuit, Milanowski says. Over the course of its eight-year plan, the utility wants to install automated switching on its worst performing circuits.
If the utility deploys automated switching on 20 of its circuits, it anticipates potentially reducing its system average interruption duration (SAIDI) by 30 percent, Milanowski says. “With DMS, we’re expecting to be able to fix the problem a little faster because we can find it faster.”
Directing the Data Firehose
The potential of ADMS technology has become more evident in the past year, as record-breaking weather events and natural disasters have pummeled utilities in many parts of the country. In late August, for example, Hurricane Irene ripped through the territory of the Long Island Power Authority (LIPA), which serves 1.1 million residential and commercial customers on the highly urbanized New York island. At its height, the outage left half a million customers without power. Not long after the area had recovered, LIPA announced plans to invest in new distribution management technology from Efacec ACS, as part of its smart grid roadmap.
“We are building a new infrastructure, and installing and developing several new systems that are supposed to work together in an integrated way,” says Predrag Vujovic, LIPA’s director of transmission and distribution planning. Efacec ACS’s system, which LIPA plans to deploy in several phases over the next year, includes applications for power optimization and self-healing feeders, real-time storm damage and assessment management, as well as a distribution system simulator for research and analysis at a local university.
“This is a lot of technology, with pilots and phased implementation,” says Gary Ockwell, chief technology officer for Efacec ACS. “You need a planned approach, and you need an architecture that can expand and take the technology.” For LIPA, that means having a service-oriented architecture (SOA) that can readily support integration.
ADMS has its fingers in everything, so maintaining accuracy for the network on a daily basis is paramount. Without that, any solutions introduced won’t be accurate either. A key stumbling block is that an ADMS must be able to handle a barrage of data from disparate systems, including both non-urgent and urgent data. Failure to handle mission-critical data appropriately can be deadly—i.e., opening or closing the wrong switch at the wrong time could electrocute a worker in the field, or cut power in ways that create hazards for customers. “We’re talking about doing things—bang!—right away,” Geisler says. “It’s got to be done safely, efficiently, and it’s got to be done in such a way that you always track what you did.”
On Long Island, LIPA is investing in tools and processes to keep its ADMS data model synchronized with industry standards. “The whole concept is based on an assumption that [with] all data—especially when we’re installing new systems and replacing an old system with a new system—we’ll use the same model,” Vujovic says. Within that data model, consistency reigns. For example, transformers will have the same name structure throughout the system, linking all the data associated with it, such as loads and maintenance activity. The naming convention is expected to increase accuracy while reducing the cost of integration.
But as promising as advanced distribution management systems are in terms of providing greater distribution network control capabilities, they often remain grid-operation centric. “They’re not typically designed to manage things like demand-response, meter information, home area management, or asset management,” says Accenture’s Malcolm. This creates a challenge as utilities seek to provide customers with more timely and detailed information about things like outage restoration. LIPA hopes that its focus on a consistent and standards-compliant data model will facilitate better coordination among its operation, customer relations, maintenance, and planning groups, especially when the next major storm hits.
“It’s all about understanding close to real-time what’s going on, and having enough time to adjust and optimize well ahead of a projected event,” Vujovic says.
Being Kind to the Grid
Effective demand reduction and grid optimization are promising ADMS features. In the past, on summer days so hot that the pavement would seem to melt, utilities would see an overload on a circuit and transfer part of that circuit to an adjacent one nearby. But on such days all circuits might be near their peak capacity, so this practice could create a domino effect of overloads.
“We used to call it ‘chasing the amps around the system’ during those hottest days of the year,” says Brad Williams, vice president of products management for Oracle Utilities. Earlier in his career, Williams directed T&D asset management at PacifiCorp.
Instead of chasing amps, Williams says ADMS capabilities will allow utilities to simulate the optimal solution with the fewest number of switching operations needed to relieve an overload condition. “In some cases where there’s remote-controlled switchgear, we actually can carry it out automatically just by pushing a button,” he says.
The trick is using information technology to tie grid operations together quickly, efficiently, and effectively in real time, Geisler says. This can involve highly granular data, down to the level of individual transformers and circuits. On that hot summer day, for example, a transformer can be overloaded to about 150 percent of its design rating without blowing it up. After two hours, the load has come down, but the overload can have lasting consequences for equipment on the system. “I’m out of trouble, but I’ve just aged that transformer beyond its normal wear,” Geisler says. “That information is useful.” A truly advanced DMS would identify what’s happened to that particular transformer and push the information to both the utility’s maintenance centers and asset centers. The maintenance schedule for that piece of equipment would change accordingly. After the transformer is checked and an asset calculation done, it might become apparent that the temporary overload accelerated its degradation, and that information gets communicated to the operations side.
“Maybe we want to go back through the operations guys and tell them, ‘You need to de-rate this particular transformer, and we’re going to move it up in the queue for replacement,’” Geisler says. “That analysis and that information could be integrated. It could happen automatically.”
Capabilities at this level of granularity also can serve to raise system efficiency and reduce load overall. In advance of its full DMS rollout, OG&E installed ABB’s volt-VAR control module. The initial plan is to put volt-VAR optimization on 400 circuits with the goal of achieving a 75-MW demand reduction. In summer 2010, OG&E tested the system and saw demand fall by between 0.8 percent and 2.4 percent, depending on the circuit. “It doesn’t sound like a lot, but when you add it up, we’ve reached our goal,” Milanowski says, citing a 200-kW reduction on average per circuit. Multiply that times 400 circuits and the result is 80 MW.
“With the operational savings of smart grid combined with the deferred capital investment of the power plant that we were able to model through this demand reduction, it really made the business case for us,” Milanowski says.
Plugging in Renewables
DMS technology could pave the way for new energy resources coming onto the grid. Distributed renewables projects, such rooftop solar, will present a management challenge for utilities if those installations become significantly widespread. If a large percentage of customers in a given area add rooftop photovoltaics, for example, all those new two-way power flows will affect safety and require more monitoring. Milanowski says intensive integration is required to bring that kind of distributed resource into current systems, and adds that it might take a decade to get there.
“Fully integrated optimized dispatch of all potential sources of energy, and demand side controls to get the most optimal system we can have—that would be the killer application for smart grid,” he says. DMS technology would be a central component for “integrating demand response, load management, distributed resources, storage, solar panels, wind farms, and fossil fuel central power plants.”
And when electric vehicle adoption reaches a critical mass, ADMS will play a crucial role. Oracle’s Williams highlights the potential for the technology to model electric vehicle loads and to help utilities anticipate capacity constraints and overloads. “[We can] plan to increase capacity or encourage the customer to get on an off-peak electrical vehicle charging rate where they could save some money,” he says.
But while DMS technology might be well suited to serve these future possibilities, Geisler cautions that emphasizing them too much now could risk avoiding the basic challenges that distribution management systems still need to overcome before they can meet today’s requirements. Utilities need operational stability of the grid before they can add distributed resources in a managed progression, he says.
“It’s kind of like eating your dessert first,” Geisler says. “It places a huge responsibility and set of requirements in terms of applications, analysis, assessment, and proactive recommendations on the DMS to be able to address those kinds of issues.”
Over time, evolving needs will lead to progressively more advanced DMS technology. “In the future, as we start to see more of the home area networks and AMI, then they’ll be brought into the control system,” says Tim Taylor. “Right now it’s just not economic for utilities to monitor each and every small photovoltaic that’s out there.”
Securing the Future
As DMS technology evolves to address a wider scope of operational needs, it raises concerns about increasing reliance on an integrated system. Like the HAL 9000 computer’s disastrous breakdown in 2001: A Space Odyssey, failures with a sprawling control system like what’s envisioned for ADMS raise questions about stability and security.
To address those risks, vendors say they are building security into DMS technology from the start at multiple levels, from personnel and design architecture through implementation and process management. Milanowski says OG&E’s approach aims for high availability, with a hot standby system running in parallel at a remote disaster recovery site.
And in preparation for the DMS, the utility has imposed new security protocols in its IT department, and is putting the DMS through extensive testing before implementation. During the system’s delivery lifecycle, it will undergo numerous stages of documentation, review, approval, and change management. About 20 consoles, each one a PC with multiple monitors, will allow developers, engineers, and operators to configure and operate the system.
“We have a lot of smart people working on this,” Milanowski says. “You have to.”
With such a significant amount of integration, automation, and synchronization, utilities aren’t making any blind leaps when it comes to ADMS implementation. Instead they’re approaching advanced distribution management with caution—and with a sense of optimism that the right programming inside their racks of computers will pay off with tangible benefits.