The system had to be in place before the events started happening again.
GSE had to act fast. Stepping in to fund the project was the U.S. Agency for International Development (USAID). USAID contributed $115 million for a Power and Gas Infrastructure Project in the nation of Georgia from 2010–2015, and this became part of the smart grid component for the project.
GSE then hired a consultant, Dr. Victor Popescu of Fichtner—one of the world’s leading independent engineering, project management, and consultancy firms. Together with GSE, Dr. Popescu investigated Georgia’s power system operations, behaviors, and responses to various events and contingencies. Mostly, they were searching for a solution to control The Backbone.
After recreating the conditions of the August 26, 2010, blackout in a system study, GSE and Fichtner had their main requirements. They discovered there was a 200 ms window of time between the moment a fault occurred on The Backbone and the moment their system needed to take an action to prevent a blackout.
However, that 200 ms also included the time it takes the circuit breaker to open, which is what actually stops the power flow. So in reality, there was less than 100 ms left for the power system to detect a fault, generate a load-shedding decision, and send that decision to the mitigation device that operates the circuit breaker.
Less than 100 ms.
“We needed someone who could provide us with these fast signal delivery times between substations across the country,” said Didbaridze. “Dr. Popescu advised us to contact SEL first. And after looking into the company, we found that SEL could provide the technologies we needed for the delivery of that trip signal in a very short, fast period.”
SEL won the international competitive procurement process, which was comanaged by Tetra Tech, the USAID project contractor, and GSE. SEL is a company that invents, designs, and builds digital products and systems that protect power grids around the world. This technology prevents blackouts and enables customers to improve power system reliability and safety at a reduced cost.
At this point, it was already closing in on the end of February 2011. GSE had less than four months before summer arrived along with the potential for more blackouts.
“We had a very demanding time schedule,” said Rodas. “When summer begins, that’s when the blackouts really start to become an issue for Georgia. They didn’t have the luxury of waiting, the system had to be in place before the events started happening again. The deadline could not be moved.”
SEL assembled the Phase One team: Diego Rodas, Fernando Calero, and John Needs. Their plan was simple. It was time for emergency control.
“We threw ideas back and forth,” said Needs. “Then we’d modify them, send them back. And that’s how we eventually arrived at the concept for this particular emergency control system.”
An emergency control system meant breathing room for GSE. It was a simple solution that would provide immediate relief to the Georgian power system. It would prevent blackouts while giving GSE enough time to align resources and schedules for future expansion.
“We started small and kept things simple in the first phase because it was understood from the beginning that the system was going to be expanded in the future,” said Rodas.
Emergency control systems are fast. They are based on a concept called decentralized, or distributed, control. The idea is that you install decision-making relays at the most critical transmission line substations. These relays act like the “brains” or “controllers” of the power system; they constantly monitor their transmission lines, checking for faults. Each of these relays has its own logic programmed into it so that if a fault does occur, the relay can use that logic to make a quick decision to shed load, thereby preventing overload in other areas of the power system, maintaining stability, and saving the country from a total blackout.
But the key to their high speed is that the logic in the relays is distributed among individual substations, which is why it’s called distributed control. This means each relay can only act on the information from the transmission line it’s monitoring and information it receives from its immediate neighboring devices. Each controller is confined in what it can see in terms of loads, voltage levels, and power flow. It is unaware of the rest of the system.
Because the logic in an emergency control system is distributed among all the sites, it makes the best and fastest decision for that substation when there’s a fault. That decision might include shedding more load than necessary, simply because the system is not aware of alternate paths to reroute energy. The result is a power outage to one particular area.
But that’s still better than a total blackout.
“An emergency control system is a very real possibility for many developing countries where the worst thing that can happen is a blackout,” said Dolezilek. “Now, when you have the time and money, you can add more functionality to the system so it makes more refined decisions. But on a short timeframe and budget, the solution is an emergency control system. It does what it needs to do to prevent a blackout.”
It was the first big step that Georgia needed toward a complete management system.
The Phase One team used SEL-451 Protection, Automation, and Bay Control Systems as the main controllers at both the Zestaponi and Ksani substations. Their job was to constantly monitor the status of the key 500 kV transmission lines on The Backbone for changes in power flow, which indicate that a contingency event, such as a fault, just occurred.
The SEL-451 detects this event, generates a load-shedding decision, and sends this message to the mitigation device, an SEL-2440 DPAC Discrete Programmable Automation Controller. Several SEL-2440 mitigation devices were installed at strategic load-shedding substations along The Backbone. Their job was to receive messages from the SEL-451 Controllers, verify their accuracy, and send a trip signal to the appropriate circuit breaker to shed load.
Again, this whole process had to happen in less than 100 ms to prevent a blackout.
For the next few months, Rodas and Calero studied the specifications and logic requirements from GSE and began bringing the system design to life. Calero programmed the decision-making logic inside each SEL-451 while Rodas programmed load-shedding logic into each SEL-2440 to establish messaging links between the two. Rodas also set up the human-machine interface (HMI) that GSE operators would use to interact with these devices from the National Control Center.
Meanwhile, Needs spent two weeks in Georgia, traveling to different substations and setting up the customized communications network.
“We had devices that would trip at different locations, and we wanted to be able to access those products over the network,” said Needs. “I needed to set up the communications network so that Diego, Fernando, and GSE could access and communicate with those devices from the control center.”
Needs also verified the Ethernet switch installation, fiber-optic installation, and relay connections at each of the substations.
“Driving on those roads was like riding around on a Boneshaker bike all day long. After 14 hours, you actually felt it,” said Needs.
But after that, GSE operators could access the substations from a remote location, rather than having to make the drive out themselves.
When Rodas and Calero arrived in Georgia, they set up a two-hour presentation with GSE to discuss the specific details of their new system.
During these discussions, they reviewed the timing requirements and actual time budget for the power system to react to an event. The original specification was 200 ms for the entire process, with less than 100 ms allotted for the detection, decision, and mitigation actions performed by the emergency control system.
“When they saw our calculations, that we could do it in 20 to 24 milliseconds, I think they were very impressed,” said Rodas.
Less than four months after beginning the design, SEL had the emergency control system for The Backbone installed and ready to go.
“To specify, design, build, test, and install a new system in less than four months—it’s unheard of,” said Dolezilek.
That’s when GSE approached Rodas about putting the new system to the ultimate test.
“I was very surprised they wanted to test the system like that,” said Rodas. “But on the other hand, I suppose it gives them more confidence that it works.”
The risk was if something didn’t work. If trip signals weren’t sent. If something was wrong with the logic or the protection and control messages were compromised. If load wasn’t shed fast enough.
All of these were real possibilities that would lead to a blackout if the emergency control system didn’t work properly.
“Their generation plants shut down; it takes hours to restart a power plant and get it back online,” said Calero. “It’s expensive and a potentially vulnerable situation to be in, even for a short while.”
GSE scheduled the live test for June 16, 2011, at 3:00 a.m. Preparations began two days in advance to set up the scheme, plan the power flow, and get permission from everyone involved. Scheduling the test at night allowed for some measure of safety—load is lower because most people are sleeping—but it’s still a serious situation.
“We are, of course, always nervous when we do these tests too,” said Didbaridze. “There is always the possibility for testing to fail.”
Engineers from SEL and GSE were gathered in the National Control Center.
“The operator has arrived at Ksani substation,” said dispatch manager Ucha Uchaneishvili. “Begin final preparations to manually cut power.”
International Projects Technical Manager,
Rodas checked the logic again. He gave the okay.
“You start thinking about if you’ve made any mistakes and that it’s too late to fix it now,” said Calero.
All eyes were drawn to the control screens as Uchaneishvili gave the final instruction.
“Cut the power.”
The glowing line indicating 500 kV transmission line Kartli II vanished. Gone.
Instantly, the control screens lit up with activity. The emergency control system was shedding load in substations all over Georgia. And the lights were still on. They had power. All of Georgia had power.
“We did it!” said Rodas.
Several loud cheers followed as operators quickly began checking the status of the power system. Everything was stable. They checked the event report generated by the SEL-451. Everything had worked exactly as expected.
“With the SEL system, we have seen our last blackout,” said Uchaneishvili. Everyone in the control center celebrated a successful night and the turning point of reliable electric power in Georgia.
Besides showing that the new system prevented a blackout, the event report from the SEL-451 showed something else—and that was the speed. The initial requirement from GSE had been 100 ms. Rodas had quoted 20–24 ms.
“But Diego and his team were able to drive out complexity and drive the performance of that system down to 12 milliseconds,” said Dolezilek.
The simplicity of the emergency control system was proven that summer. In a two-week period during July, just after installation, the system was called upon five different times to shed load at 500 kV substations along The Backbone, protecting the country of Georgia from imminent blackouts.
Power system issues have the potential to easily introduce complexity. The solutions don't need to follow the same path.