Smart Grid

Getting utility systems to play well with each other

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Utility automation has made great strides, but is it possible to have too much of a good thing?

The great variety of software available for utility systems, and the number of vendors selling that software, has created the potential for failure in communication.

Utility control technologies have proliferated. They started with simple supervisory control and data acquisition systems that allow operators to monitor and control remote substations from a power plant’s control room and moved on to systems for everything from economic dispatch and automatic generation control to energy management systems and distribution management systems.

Now, most modern utilities can have systems that include engineering analysis software to model and analyze the operation and planning of their grid; a geographic information system (GIS) to collect and map the location of key resources on their grid, an outage management system (OMS) to collect outage data; a communications system (or IVR for interactive voice response) that bundles voice, Internet, email, and texting capabilities into a single software package; and a field engineering system (also known as staking) for designing and documenting projects such as power line extensions.

Recently, utility software has evolved even further as utilities move toward smart grid technologies and more responsive and resilient systems with use of tools such as advanced metering infrastructure.

All these software tools can be useful, but the proliferation of software from a variety of vendors can also cause confusion and, worst case, conflicts.

Pulaski Electric System, which serves just over 14,000 customers in an area south of Nashville, Tennessee, uses Environmental Systems Research Institute’s geographic information system mapping software. “It is the backbone of our operational suite,” David Kelley, mapping director at Pulaski Electric System, says. “ESRI’s GIS software is a repository for everything geographic in the system.”

But Pulaski Electric System also uses software from Milsoft Utility Solutions, on top of ESRI’s GIS software. The ESRI system is very broad, but Milsoft’s WindMilMap ESRI extension allows Pulaski Electric System to customize the GIS, ensuring that their electrical model is maintained accurately by validating connectivity and providing specific tools for editing electrical components.  With a correct electrical model, the utility can add map viewers and incorporate other software packages, such as an outage management system and staking software.

Pulaski Electric System also uses Milsoft’s DisSPatch outage management and Field Engineering systems, which both seamlessly integrate with the accurate electrical model maintained in the WindMilMap GIS system.

On top of all that, Pulaski Electric System runs a customer information system, or CIS, from National Information Solutions Cooperative (NISC) to collect and update information about customers and their bills. The CIS collects all the new information and sends real-time updates to the Milsoft software so the system always has up-to-date information.

Getting all those pieces to work together was not always easy, but Kelley has found that the Milsoft software interfaces well with every vendor the utility uses. “They have always been great, even with the competition,” he says.

Pulaski Electric System is now able to use its staking software when designing new lines. “We can shoot the GPS points in the field and pull it into the GIS system, but we can also bring it into the NISC accounting software,” Kelley says.

The CIS system “also interfaces with the OMS system, so if a customer is cut off for non-payment, we can pull it up on the OMS,” Kelley says.

On the customer side, Pulaski Electric System uses advanced meters and AMI software from Tantalus. That software works directly with Pulaski’s outage management system.

“There were some hiccups when the AMI system was first put in place; it was reporting outages too quickly. It was too sensitive,” says Kelley. But that was resolved, he says. And in some cases, such as a vacation home, the problem can be fixed and the customer would not even know there was an outage except that their clocks are blinking, Kelley says.

The City of Concord Electric Department in North Carolina also uses an array of software to help monitor its electric system and interact with customers. The utility uses an IVR system to take customer phone calls and perform customer notifications, an outage management system, a CIS, and a mapping system.

The first level interface with customers is the IVR software. The City of Concord uses Milsoft’s IVR to handle customer calls and perform customer notifications.  “We use it for answering a majority of customer phone calls,” Andrea Cline, SCADA and substation coordinator in city’s electric systems department, says.

In the case of an outage, the IVR creates an entry and sends it to the outage management system, in this case Milsoft’s DisSPatch software. The DisSPatch software has a map that identifies the equipment on the system, the customer, and the customer’s information and address.

As outage calls come in, they are populated on the map. The software can look at the pattern of outage calls and predict what location is the source of the outage and predict what upstream devices might also be effected.

“I could do that,” says Cline, “but I can’t talk to 24 people at one time.” The IVR has 24 phone lines. “It can process them and put them on the map and make predictions very quickly.” A dispatcher looking at the map assigns the outage to a worker, and that information goes into the outage management system.

The outage management system also retains historical data the utility can use to compile reliability reports. And the system can also be used as a customer interface so a customer can see a version of what is visible internally at the utility in terms of outage locations and how many people are out, but without the detailed customer information.

As the outages get handled and put into the system, the IVR automatically updates the information that customers hear when they call in. An updated message could tell a customer, “We are aware of the outage, please give us time to correct the problem,” or, “We are aware of the outage and crews are working on the problem. Your estimated time of restoration is 4:00 PM on Tuesday, May 8th.”

The City of Concord also uses a control program that monitors workers as they are dispatched to deal with outages. And when power is restored, the system has the ability to call customers back to confirm that their power is restored.

In case of scheduled outages, the City of Concord uses the IVR system to make phone calls that inform customers about an upcoming outage.

When these systems are really put to the test, however, is not when there is a single outage, but when extreme weather blows through resulting in multiple outages. Even a place far from the ocean, like Pulaski, can be affected by tropical storms and hurricanes. In 2004, the remnants of Hurricane Ivan swept as far inland as Tennessee, dumping torrential rain and causing flooding.

By coordinating all the pieces of its control software, Kelley says the utility is much better prepared and able to respond to those kinds of events. “Now we can say with high certainty exactly where an outage is before sending a truck. That is a game changer,” he says.

That is particularly important as the utility workforce continues to age and is replaced with younger workers with less experience. The older workers, using their knowledge and experience, were able to more quickly identify the source of an outage.

Now the combination of advanced meters and sophisticated outage software helps bridge that knowledge gap. “The OMS is invaluable,” says Kelley.

Cline recalls that when she first started at the City of Concord, the utility was hit by a big ice storm. That was before they had an IVR system to field customer phone calls.

“We had thousands of people out,” she says.

Cline says she and her colleagues were trying to capture all those phone calls and outages and sort them and categorize them. “We were trying to keep up with paper and a white board. It was a very big job.”

Now, the OMS system “does so much of the work for you so quickly. It can talk to 24 people at a time. I was amazed at what it could do for us.”

At the end of the day, utilities will increasingly need -- and benefit from -- tools that help them maximize the effectiveness of a growing number of different software applications in a seamless manner.

Put another way, utilities will ultimately benefit from being able to allow utility systems to play well with each other.

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