Embedded Technologies for the Smart Grid

Synchronized Embedded Intelligence Enables the Smart Grid

Getting maximum electric power from the industry’s limited capacity requires precisely synchronized and massively distributed intelligence embedded throughout the grid.


  • Page 1 of 1
    Bookmark and Share

Article Media

The electric power industry is moving to the Smart Grid because it needs as much power as possible from today’s power system. A grid is “smarter” to the extent that there is intelligence embedded within the devices that manage power, and also to the extent that these devices exchange data among themselves and grid-wide applications that improve the grid’s efficiency. To use their intelligence, however, these devices, including potential and current transformers, must sample and time order voltage and current measurements. Accurate sampling therefore requires that devices be precisely synchronized to a common substation clock. Without accurate and precisely timed information, the trip instructions these devices send to switches may be wrong, potentially causing “false tripping.” Additionally, the information they report upstream to time-sensitive applications will probably be wrong as well.

Precise, highly distributed timing was not always a priority. With today’s faster processors, more memory and more robust algorithms, devices can take more variables into account per unit of time and respond in a more granular and more intelligent way to out-of-spec conditions. But to do that they must know exactly when a unit of time begins and ends. As more data is sampled, the margin for timing error shrinks.

The increased capabilities of these devices multiplied by their sheer number has led utilities to innovate how intelligent devices communicate downward to switches and upward to management stations. Increasingly, Ethernet over fiber is replacing hard-to¬-maintain point-to-point copper cable. Utilities have also sought to streamline how they distribute timing. Efficiency dictates a centralized source, such as a GPS-synced grandmaster clock, that synchronizes devices over the same Ethernet network used for integrated control and protection. In the past, timing has typically been done over dedicated point-to-point copper wires, often with separate GPS clocks serving different applications and equipment. The more centralized packet-based approach synchronizes all devices to the same clock and allows applications the opportunity to gain a single unified view of timing of all events and measurements.

The updated timing topology fully leverages the grid’s intelligence to achieve multiple efficiencies. For example, accurate packet time stamping of parametric data helps avoid false tripping and enables faster, more meaningful cause-and-effect forensics. Phasor measurement and alignment of current and voltage waveforms to a prescribed offset in real time across a transmission line also helps maintain optimum grid operation. These and other timing applications wouldn’t be possible if devices controlling the network weren’t smart enough to support them. On the other hand, without precise and centrally distributed timing, much of that intelligence—along with grid capacity—would be wasted.

A Massively Distributed Multiprocessor Solution

Today’s smart gird is essentially a geographically dispersed embedded real-time control application employing thousands of processors synced over a network. Like other such applications, this one has a purpose, a topology, a networking protocol (actually two, one for control, the other for timing) and, of course, processors.

The purpose is what it has always been: to maintain a precise balance between supply and demand for power everywhere on the grid simultaneously. Absent sufficient grid “smarts,” a sudden surge in either supply or demand—say, because a circuit breaker inadvertently shuts off a town—could cause a widespread power outage like the one that blacked out most of the Northeast U.S. in August 2003. Maintaining this balance in recent years has become much more difficult—with much less room for error—due to increasing demand with no commensurate increase in supply. As a result, the grid now runs “closer to edge.” Thousands of substations exist across the grid and each must make almost instantaneous adjustments in supply for every local fluctuation in demand.

The topology actually includes three networks. There are the actual copper wires and switches (or “switchgear”) that carry electricity. There is a control network, including distributed intelligent electronic devices (IEDs) such as circuit breaker controllers, voltage regulators and digital protection relays. These are connected to each other, to the switchgear and to supervisory management stations via fiber optic Ethernet. And thirdly, there is a timing network running over the same fiber optic Ethernet that connects all these other devices to a central clock. All this equipment is located in geographically dispersed substations (Figure 1). Each of these is responsible for distributing power within an area such as a town. This involves three basic functions: 1) voltage conversion, 2) line switching and connectivity, and 3) line protection (relaying).

Figure 1
A substation is the grid interconnect consisting of a switch yard (where voltage conversion, line switching and line protection occur) and a control building, lower right, that houses electronics for substation control and timing.

Within the substation, the switchgear is located outdoors in a switchyard while the IEDs and clock are located in the relay room of a control building, where there are also typically two other rooms—a communications room and a battery room. The communications room houses systems for voice and data communications with other substations and with grid operations centers. That includes supervisory control and data acquisition (SCADA) metrics on how substation devices are performing. Local and remote operators view SCADA data at human machine interface (HMI) consoles.  

The network protocols connecting these devices run on the same Ethernet fiber optic cable—with one protocol for control (IEC 61850) and the other for timing (IEEE C37.238), as in Figure 2. IEC stands for the International Electro Technical Commission, the organization that prepares and publishes international standards for all electrical, electronic and related technologies.

Figure 2
A smart substation with all control and timing elements interoperating over Ethernet.

IEC 61850 replaces vendor-specific protocols such as LON, Profibus and Modbus for inter-device data exchange and control within power substations. IEEE C37.238 is a power industry-specific flavor of the Precision Time Protocol (PTP) described in IEEE 1588. PTP’s value is that it enables an inherently asynchronous medium (Ethernet packets) to deliver timing synchronized to 1µs.

PTP thus has a major advantage over point-to-point timing protocols, such as the Inter-Range Instrumentation Group – Time Code Format B (IRIG-B), which is how substation devices have traditionally been synced. IRIG-B is a serial binary coded decimal encoding that transmits one data frame of time information (year, day of the year, hours, minutes and seconds) every second—with precision in the 1 ms range. Replacing IRIG-B with PTP (while also implementing IEC 61850) removes the need for hundreds of copper cables, each one connecting a different substation device to a timing source. Not only are all these cables expensive and difficult to install and maintain; in power substations they’re also an electrical hazard. Furthermore, a single timing network enables a unified timing architecture. That reduces the number of timing sources required. Compare that to the multiple clocks of a traditional substation—each one supporting different equipment or applications—with multiple GPS antennas all mounted outdoors on control building rooftops and exposed to the elements.

Unified management offers a single view of the substation’s timing infrastructure and the ability to drill down into infrastructure performance parameters such as the variation in timing packet delay across the network. That in turn alerts operators to timing issues so they can be addressed prior to failure rather than only after a failure—as they likely would be with unmanaged multiple autonomous clocks.

Where Timing Syncs Control at the IED

The “processor” at the heart of this distributed multiprocessor application is an intelligent electronic device (IED). An IED is a firmware-programmable microprocessor-based controller that can serve any one of multiple functions such as a circuit breaker controller, digital protection relay or voltage controller. In a smart substation, for example, when a circuit breaker trips, it’s because an IED monitoring conditions on a substation bay told that circuit breaker to trip. A state-of-the-art IED takes continuous “snapshots” of voltage and current, with a 4.6 µs sample timing accuracy.

“Next-gen” IEDs replace a previous generation of substation control hardware comprised of analog electromechanical relays, circuit breakers, voltage regulators and IEDs with less robust capabilities. Current IED architectures offer three key advantages: more functions, better control and less cabling.

The first advantage of having a single device that can be assigned multiple roles is that it reduces costs and simplifies operation and maintenance. Its increased intelligence also enables better control. With the previous generation, often the only “control” option was to shut off a circuit when an out-of-range threshold was reached. Devices and operators were limited in the types of information sampled, different ways to respond, or the level of response short of a complete power shut-off. Now both supervisory control and electric power can be applied much more fluidly. Power can be shifted to where it is needed (or away from where it is not) more dynamically with less stress on generators, substation equipment, transmission lines and other assets. Conditions requiring a millisecond response (or faster) may be handled automatically. And both operators and supervisory software have a much wider and deeper view of potential issues as they develop.

IEDs that support IEC 61850 for control and IEEE C37.238 for timing enable a fiber optic Ethernet to replace hundreds of point-to-point copper cables between the substation control building and switchyard equipment. To preserve investments in older switchgear and other legacy equipment, most current IEDs still also support IRIG-B. Adaptor solutions—or “merging units”—serve a similar purpose. As previously noted, removing lots of copper in a high-voltage power substation makes the substation a much safer, easier to maintain and less costly environment.

Precise Timing Matters

These benefits are possible because control elements like IEDs and timing sources no longer operate autonomously. It’s that synchronized distributed intelligence, again, that enables the grid to accomplish its purpose: to precisely and dynamically match supply and demand anywhere and everywhere simultaneously—so that the grid can more reliably operate closer to the edge of its capacity.

Three applications in particular illustrate the importance of precise synchronization. The first is the ability to take precisely timed and accurate sampled values. IEDs receive current and voltage in IEC 61850 packets either directly from “next-gen” switchyard equipment such as circuit breakers or indirectly from legacy equipment via merging units that packetize those legacy outputs. In order for IEDs to process this information correctly the IEDs must know when samples were taken. If the IED receives badly timed samples without knowing it, the IED may shut off power to customers. An even more severe consequence happens when the IED cannot interpret the data—it will default to the safe state and trip the breaker, perhaps inadvertently. To properly order the packets and process the sample values, the sampled value applications demand that the timestamps be accurate to within 4.6 µs, with a clock source accuracy of 1 µs.

The second application is the ability to quickly locate a fault. When a fault occurs somewhere on a power transmission line, the event sets off an energy wave that travels along the line back to the substation. This phenomenon is very useful for repair crews who otherwise would need to “ride the line” potentially over hundreds of miles of countryside looking for the fault. Instead, the affected IED can simply time the arrival of the wave and multiply by the speed of light to determine the distance to the fault. Again, this requires 1 µs precision.

The third time-critical application is phasor measurement. One of the key ways grid operators recognize an issue and take corrective action before the issue gets worse is to measure the phase alignment between voltage and current—optimally 120 degrees. This application requires a time precision of 5 µs (for an optimal TVE), and a clock accuracy of 1 µs precision is needed to support the synchrophasor applications.

Measurements like these occur thousands of times a second on each IED—of which there are potentially hundreds in a single substation—with each measurement potentially requiring action by this or other IEDs or by operations personnel sitting at central consoles. Unless everything happens to the beat of a single, UTC-synced, PTP-¬compliant, centrally managed 1 µs-timing source, there would be chaos.

Power companies today meet this challenge by implementing comprehensive timing strategies that fully take into account the precision, networking, management and reliability requirements of their timing infrastructures. The old ad hoc approach—simply adding another box wherever and whenever an application needs GPS timing—defeats the purpose of today’s Smart Grid. Like any other distributed processing application, this one also requires unified synchronized intelligence.  

San Jose, CA.
(408) 433-0910.