By Samuel Sciacca, CG Automation Systems USA
The massive 1965 outage that left tens of millions without power in Canada and the northeastern U.S. spurred myriad changes in the systems, processes and regulations undergirding electricity delivery. It can be said that the event was effectively the beginning of the smart grid—that electricity delivery has grown more intelligent in the years since.
Supervisory control and data acquisition (SCADA) and advanced analytical tools known collectively as energy management systems (EMS) were two of the innovations that grew out of the response to the 1965 outage. EMS/SCADA’s arrival was transformative for utilities, enabling remote monitoring and control of utility infrastructure and providing a better foundation of data on which to base generation allocation and network planning.
For the next 30 years, however, EMS/SCADA systems and how utilities employed them didn’t change much. It wasn’t for a lack of good ideas for using the information that SCADA might make available. Rather, more data couldn’t be pushed through the communications lines between substations and utility operations. A circular stagnation settled in. EMS/SCADA didn’t evolve dramatically because communications didn’t grow, and there wasn’t enough incentive to grow communications because SCADA was adequately performing the tasks expected.
The explosion of high-speed, cost-effective communications capabilities in the past 15 years and the contemporary smart grid movement promise development around EMS/SCADA. The introduction of more robust, secure, two-way communications will enable SCADA to extract a lot more data on what’s happening across the grid—and, in turn, allow utilities to get a lot more creative in how they use EMS that rely on SCADA for useful and reliable data to inform better decision-making.
What Took You So Long?
From an engineering standpoint, the electricity grid’s modernization has been an ongoing pursuit of the power industry over years. Electrical-mechanical relays, for example, have given way to solid-state devices with the intelligence to accept more and more inputs. Various monitors for transformers have emerged. And since the late 1970s, utilities have been deploying tremendous computing horsepower and algorithm capabilities to fuel EMS/SCADA systems.
SCADA’s issue is that it has been starved for incoming data.
Until the mid-1990s, the predominant interface for linking a utility’s operations center SCADA with remote substations was low-speed, 1200-baud communications. Meanwhile, complex data was being compiled on protective relays, voltage regulators and other intelligent electronic devices in substations. This enabled a utility to undertake a deep investigation into, for example, why a relay might have tripped, the precise moment and current level at which it tripped, whether it occurred out of proper sequence, etc. But because of the those 1200-baud communications lines’ limitations, developers of that substation data didn’t focus on shipping information to other locations and correlating it via SCADA with data from other points in the utility’s sphere of operations. The amount of information that could be pushed through the communications lines at frequent intervals was so limited that there was no point.
This is why today’s smart grid drive is different. Typically, SCADA has been limited to data that is between 2 and 5 seconds old. Planners and system integrators now ask, “What could be done with EMS/SCADA fueled by data that is only a quarter of a second old? Or 5 milliseconds old?” We are about to find out. Putting a two-way communications-and-control overlay fueled by real-time information flow on top of the power grid promises a host of innovations—not only in empowering a utility’s customers to make more intelligent decisions about energy use but also how EMS/SCADA interacts with the utility’s power generation, transmission and distribution systems.
Push and Pull
In the smart grid drive, a bootstrap relationship is taking shape between the data that is compiled on utility operations and how utilities leverage the data to improve operations.
We have seen examples already. Fault-record files providing significant detail on the nature and magnitude of a fault on the system have grown out of an increased ability to carry information from substations. Similarly, because of increased deployment of global positioning system (GPS) and time-synchronization technologies, SCADA can bring back more useful data files on what happened when and where, and then place the events in their proper sequence. This has precipitated EMS applications for better managing and optimizing a utility’s systems across a larger geographical area.
Synchrophasor deployment has picked up only recently; consequently, utilities’ don’t have a lot of real-time EMS applications that rely on the time-stamped current and voltage measurements from locations across the grid that synchrophasors produce. But the potential of that capability is revolutionary. Another area of development is the potential impact on real-time, dynamic rating of transmission lines. The capacities of transmission lines typically are rated for their worst-case limits, when a lot more power could be carried per line in extreme heat or cold when customer demands on a utility are highest. Deployment and improvements in other sensor and communications technologies could enable transmission lines to be rated and monitored dynamically. Utility assets and power flow could be managed more efficiently, and the likelihood of blackouts when customers need power most would be reduced dramatically.
In addition, with the ongoing build out of advanced metering infrastructure (AMI), a utility can create an increasingly granular profile of voltage measurements from across its entire service territory. This will free EMS application developers to be creative in using those measurements once they are fed back into SCADA. What could a utility do with high-quality, dependable phasor measurement unit (PMU) data for two points at opposite ends of its service territory? Or, what could a utility do with the capability to compare its measurements with those of another utility—between Los Angeles and New York, for example?
Until now, the lack of robust, reliable communications impeded the creativity with which utilities employ SCADA. In the contemporary smart grid movement, this is changing rapidly.
Standards work around the smart grid is focused on the unprecedented integration of power, communications and information technology. The IEEE’s P2030 Working Group, for example, is striving to uniformly define elements and functional requirements encompassed in the pursuit of enabling two-way communications and control over electricity generation and delivery, ubiquitously across markets. This process figures to illuminate a host of areas—AMI, cybersecurity, data networking, electric vehicle support, information modeling, renewable energy integration, sensor networking and wide-area situational awareness, among them—where new or improved standards are needed.
The introduction of more powerful, flexible, reliable and secure communications infrastructure across the power grid means big changes for EMS/SCADA, which utilities have relied upon for decades. As the quality and nonrepudiation of data flowing through SCADA improves, utilities will trust the system more and design new algorithms and EMS applications that use the data. Smart grid rollout points to innovation in ways utilities employ SCADA.
Samuel Sciacca is chairman of IEEE’s P2030 Working Group Task Force 1 on power engineering technology and chief executive officer of CG Automation Systems USA Inc.
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