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Distribution management at the smart grid frontier.
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