Published In: Intelligent Utility Magazine September/October 2010
John R. Johnson
HERE AREN'T MANY TECHNOLOGIES THAT STICK AROUND long enough to improve with age. In today’s fast-paced digital world, technologies change rapidly and often become obsolete in months. Just witness the electronics market, where cell phone upgrades occur on what seems like a 24-7 basis.
But like a fine wine, SCADA—which stands for supervisory control and data acquisition—seems to get more robust with age. SCADA technology has been the backbone of many utility information systems for years and is still going strong. Many liken the technology to barcodes, a decades-old technology that has persevered despite the rising popularity of RFID technology, which has far greater capabilities than barcodes.
So while advanced metering infrastructure (AMI) technology and other high-tech solutions quickly transform the utility sector, SCADA has held its own as a crucial part of the utility IT infrastructure. Make no mistake, SCADA has changed over the years and will continue to evolve as AMI takes hold. But the technology shows no signs of fading into the sunset.
Holding its own
“We may not be the most advanced utility in terms of technology, but our SCADA system is pushing 30 years and is still an instrumental tool,” said Greg Williams, vice president of engineering and operations at Appalachian Electric Cooperative (AEC). “SCADA is an instrumental tool. It’s integrated into what we do every day and we would be blind without it. I don’t think SCADA will go away by any means.”
AEC is a nonprofit coop serving 45,000 members in East Tennessee. The Tennessee Valley Authority furnishes electric energy to the coop at wholesale rates. Despite AEC’s relative smallness, the coop prides itself on exploring and utilizing cutting-edge technology, and has a well-thoughtout wish list for how AMI technology can tie in with SCADA in the future.
By its very nature, SCADA requires rapid response times. The technology usually operates as a real-time communications system. When a command is issued to open a breaker in a substation, for example, the order needs to be carried out immediately.
“I need a response back that the breaker did open, and I’ve got to know that very quickly,” Williams said. “I’m looking at voltage readings, amp readings on feeders, and other status information on substation equipment, so any kind of delay built into it would actually degrade the system.”
Reaching farther
With that in mind, AEC has actually physically extended its SCADA system outside the fence of the substation by connecting substation breakers and transformers, and, in some cases, relay systems and by creating a local area network. Beyond the substation fence, AEC started to connect down-line three-phase reclosures and down-line single-phase regulators.
“We would like to communicate to capacitor stations and things of that nature, which may or may not require the speed of communications like a substation would,” Williams said. “For instance, I just need to monitor a capacitor station. In my opinion, that’s one place where AMI possibly could cross over into more of a SCADA or distributed automation type of function. But where speed of response is needed, I don’t envision the AMI system being able to produce that kind of speed just because of the nature of its communication structure.”
Williams notes that utilities that are installing fiber networks to the home will likely have the required speed and response time for that type of automation. However, if a power line carrier or an RF solution is utilized, the speed and throughput will be too slow.
“I think that in the future, AMI can still provide some kind of enhancement of SCADA, where you reach beyond the fence, so to speak, of SCADA opportunities,” Williams said. For example, he envisions an AMI vendor developing a “black box” that can be hung on a pole out in the field and used perhaps to communicate to a smart switch like a Goab or a motor-operated disconnect.
“Rather than putting in a remote terminal unit (RTU) that is connected directly to my SCADA, which is a very expensive alternative, maybe I can use my AMI system to communicate to it. But obviously there needs to be an interface,” he said. “This is the type of thing I see happening in the future. It’s not there yet, or at least I haven’t seen it yet. But I see some of those very low-level functions where there is not a lot of control or data being transported that could be done by using AMI.”
Speed not critical
In a substation environment, AEC and other utilities bring back hundreds of data points to its main system—everything from amps and volts to varied control information. The bulk of that information needs to be timely, essentially delivered in real time, whereas applications originating in the field may transport minimal data, such as one or two voltage levels, a single amp reading or control point.
“The amount of information is dramatically decreased so the speed by which that has to be responded to is not as critical by virtue of the fact that there are not as many bits of information,” Williams said. “That’s where I see AMI crossing over into the SCADA world. AMI will never replace it, but I feel that it can enhance it or broaden it.
“SCADA is changing. Early on, you used to hardwire contacts for status and hardwire into transducers to get analog values. All that has changed and it’s now all digital information coming out of a smart relay.”
Williams said that SCADA’s future will also be impacted by how AMI relates to distributed automation. “When I want to truly automate my distribution system and I’ve got multiple motor-operated disconnects and devices out there for automatic sectionalizing and fault isolation, how will I communicate that back to my headquarters? Well, I can use my SCADA system, which means I’ve got to use RTUs and radios, or can I do it using my AMI system, which is actually another communications system? I’m sure there are utilities out there dealing with this, and it’s something we’ll be looking into in the future,” he said.
Key in integrating renewables
Williams also sees SCADA technology playing a key role when it comes to integrating renewables into the grid as alternative energy from wind, solar and other sources continues to grow.
“This will be another opportunity to use SCADA for monitoring those types of installations,” he said, noting that a 2-megawatt methane gas landfill generation project is in the works in Tennessee. “If it happens, we’ll want to connect its ‘brain’ to our SCADA system because I want to know how much energy it is generating and what it is pushing back into my distribution system. That needs to be real-time data. I could not depend on my AMI to give me real-time information because it’s just not designed for that. We pull our AMI meters once an hour and our SCADA system is updated about every 10 seconds. Those amp readings are changing instantaneously.”
So too, it seems, are the use cases for SCADA.
This article written by John R. Johnson. Source:www.intelligentutility.com
John R. Johnson
HERE AREN'T MANY TECHNOLOGIES THAT STICK AROUND long enough to improve with age. In today’s fast-paced digital world, technologies change rapidly and often become obsolete in months. Just witness the electronics market, where cell phone upgrades occur on what seems like a 24-7 basis.
But like a fine wine, SCADA—which stands for supervisory control and data acquisition—seems to get more robust with age. SCADA technology has been the backbone of many utility information systems for years and is still going strong. Many liken the technology to barcodes, a decades-old technology that has persevered despite the rising popularity of RFID technology, which has far greater capabilities than barcodes.
So while advanced metering infrastructure (AMI) technology and other high-tech solutions quickly transform the utility sector, SCADA has held its own as a crucial part of the utility IT infrastructure. Make no mistake, SCADA has changed over the years and will continue to evolve as AMI takes hold. But the technology shows no signs of fading into the sunset.
Holding its own
“We may not be the most advanced utility in terms of technology, but our SCADA system is pushing 30 years and is still an instrumental tool,” said Greg Williams, vice president of engineering and operations at Appalachian Electric Cooperative (AEC). “SCADA is an instrumental tool. It’s integrated into what we do every day and we would be blind without it. I don’t think SCADA will go away by any means.”
AEC is a nonprofit coop serving 45,000 members in East Tennessee. The Tennessee Valley Authority furnishes electric energy to the coop at wholesale rates. Despite AEC’s relative smallness, the coop prides itself on exploring and utilizing cutting-edge technology, and has a well-thoughtout wish list for how AMI technology can tie in with SCADA in the future.
By its very nature, SCADA requires rapid response times. The technology usually operates as a real-time communications system. When a command is issued to open a breaker in a substation, for example, the order needs to be carried out immediately.
“I need a response back that the breaker did open, and I’ve got to know that very quickly,” Williams said. “I’m looking at voltage readings, amp readings on feeders, and other status information on substation equipment, so any kind of delay built into it would actually degrade the system.”
Reaching farther
With that in mind, AEC has actually physically extended its SCADA system outside the fence of the substation by connecting substation breakers and transformers, and, in some cases, relay systems and by creating a local area network. Beyond the substation fence, AEC started to connect down-line three-phase reclosures and down-line single-phase regulators.
“We would like to communicate to capacitor stations and things of that nature, which may or may not require the speed of communications like a substation would,” Williams said. “For instance, I just need to monitor a capacitor station. In my opinion, that’s one place where AMI possibly could cross over into more of a SCADA or distributed automation type of function. But where speed of response is needed, I don’t envision the AMI system being able to produce that kind of speed just because of the nature of its communication structure.”
Williams notes that utilities that are installing fiber networks to the home will likely have the required speed and response time for that type of automation. However, if a power line carrier or an RF solution is utilized, the speed and throughput will be too slow.
“I think that in the future, AMI can still provide some kind of enhancement of SCADA, where you reach beyond the fence, so to speak, of SCADA opportunities,” Williams said. For example, he envisions an AMI vendor developing a “black box” that can be hung on a pole out in the field and used perhaps to communicate to a smart switch like a Goab or a motor-operated disconnect.
“Rather than putting in a remote terminal unit (RTU) that is connected directly to my SCADA, which is a very expensive alternative, maybe I can use my AMI system to communicate to it. But obviously there needs to be an interface,” he said. “This is the type of thing I see happening in the future. It’s not there yet, or at least I haven’t seen it yet. But I see some of those very low-level functions where there is not a lot of control or data being transported that could be done by using AMI.”
Speed not critical
In a substation environment, AEC and other utilities bring back hundreds of data points to its main system—everything from amps and volts to varied control information. The bulk of that information needs to be timely, essentially delivered in real time, whereas applications originating in the field may transport minimal data, such as one or two voltage levels, a single amp reading or control point.
“The amount of information is dramatically decreased so the speed by which that has to be responded to is not as critical by virtue of the fact that there are not as many bits of information,” Williams said. “That’s where I see AMI crossing over into the SCADA world. AMI will never replace it, but I feel that it can enhance it or broaden it.
“SCADA is changing. Early on, you used to hardwire contacts for status and hardwire into transducers to get analog values. All that has changed and it’s now all digital information coming out of a smart relay.”
Williams said that SCADA’s future will also be impacted by how AMI relates to distributed automation. “When I want to truly automate my distribution system and I’ve got multiple motor-operated disconnects and devices out there for automatic sectionalizing and fault isolation, how will I communicate that back to my headquarters? Well, I can use my SCADA system, which means I’ve got to use RTUs and radios, or can I do it using my AMI system, which is actually another communications system? I’m sure there are utilities out there dealing with this, and it’s something we’ll be looking into in the future,” he said.
Key in integrating renewables
Williams also sees SCADA technology playing a key role when it comes to integrating renewables into the grid as alternative energy from wind, solar and other sources continues to grow.
“This will be another opportunity to use SCADA for monitoring those types of installations,” he said, noting that a 2-megawatt methane gas landfill generation project is in the works in Tennessee. “If it happens, we’ll want to connect its ‘brain’ to our SCADA system because I want to know how much energy it is generating and what it is pushing back into my distribution system. That needs to be real-time data. I could not depend on my AMI to give me real-time information because it’s just not designed for that. We pull our AMI meters once an hour and our SCADA system is updated about every 10 seconds. Those amp readings are changing instantaneously.”
So too, it seems, are the use cases for SCADA.
This article written by John R. Johnson. Source:www.intelligentutility.com
