Low-Cost Microcontroller-Based Phasor Measurement Units Improve Smart Grid Reliability

By European Editors

Contributed By Digi-Key's European Editors


On August 14th 2003, 50 million people across Ontario and eight northeastern U.S. states lost electric power. The combination of a hot afternoon and an unexpected breakdown of a coal-fired generating station near Cleveland set off a chain reaction that within 94 minutes left most of northeastern America in the dark. It took more than 24 hours to get power restored to most parts of the power grid, and fully restoring production capacity to meet demand in the region took almost two weeks. It will always be remembered as The Great Blackout of 2003.

It came as a surprise to most grid operators that a seemingly innocent event far away could cause the entire power grid to collapse. A situation in Cleveland was allowed to go undetected for just over 90 minutes when transmission lines were operating close to maximum capacity. The hot summer air was generating high demand for electric energy to power air conditioners across the region. When a coal-fired generating station went offline, a local transmission line overloaded, causing the wires of the line to extend and sink towards the ground. When the line touched a tree that had been allowed to grow below the transmission line, the line short-circuited to ground, causing the automatic circuit protection to break. This put more stress on the remaining lines. One hour later, three other lines failed, and a catastrophic surge of electric power rushed in through remaining lines in Ohio, triggering several other circuit breakers. As the remaining transmission lines had insufficient capacity to carry the required energy across the region, the entire grid collapsed within 90 seconds. This left power plants shut off from consumers. Unable to deliver the energy they were generating, several nuclear power plants were forced to follow emergency procedures and shut down their nuclear reactors. This is a procedure that causes harm to the nuclear reactors. It took almost four days to restore power on the grid, and nearly two weeks to bring all reactors back up to full capacity.

An investigation of The Great Blackout revealed that the power grid control systems were antiquated and largely unable to monitor and protect the health of the grid. Time was never an issue. It took 31 minutes from the moment the Cleveland power station failed until the first transmission line collapsed. The situation looked manageable for another 61 minutes, until more transmission lines started burning out. The men and women controlling the grid were caught completely off guard because they had no means to detect warning signals from the power grid. Without access to real time information, the power grid control rooms were unable to predict where the next error would occur and plan corrective actions. The investigation concluded that the disaster could have been avoided if the power grid had been equipped with better monitoring systems. The U.S. Department of Energy considers the US-Canada blackout in 2003 to be the single most important motivator behind the Smart Grid initiative.

Building a smarter power grid

Equipping the power grids of the world with the appropriate real-time monitoring systems is an enormous project. The power grid is a gigantic machine, consisting of hundreds of millions of parts and covering practically every populated area of the world. Even though governments have been quick to pass legislation that make better monitoring and control a regulatory requirement, the actual rollout of real-time monitoring and control systems has been slow. In 2010, there were still only 166 power-quality monitors installed in the entire U.S. power grid.

Monitoring the health of the power grid can be done in many ways. At the most basic level, it is useful to be notified when a transmission line or distribution transformer has failed. However, monitoring for loss of power will only detect and report an error after it has occurred, and by then it will be both inconvenient and usually far more expensive to fix the problem.

What power grid operators want to monitor is the overall health of the power-distribution system. They want to ensure that supply and demand is well balanced, and that all power stations are working in perfect synchronization. System operators also want to receive early warning about possible events that are unfolding so they can take preventative action before the error is given time to cause permanent damage to equipment within the grid.

In Figure 1 below, we can see the contrast between new and old monitoring systems. The blue line shows line voltage sampled every two minutes. It reveals some fluctuations, but in the sea of information flowing into a grid operating room, these fluctuations between 8:00 and 9:00 am would not trigger any alarm. The red curve, however, reveals how a dangerous situation is about to unfold. Sampling the line voltage at a much higher frequency of 1200 times per second reveals how the line voltage is not just varying, it is oscillating. This is symptomatic of a grid where two or more power plants are working out of frequency. In essence, when two power plants are operating out of phase, the least powerful power plant is acting as a resistance to the other, and the fight occurs within grid transmission lines and transformer stations where huge amounts of energy are being absorbed. Left undetected, this can cause a transformer station to overheat and catch fire. It is one of many examples of how a better monitoring system can help grid engineers visualize the health of their power grid, and make better-informed decisions.

Phasor Measurement Unit

Figure 1: The blue line shows how old equipment tracks seemingly innocent voltage variations, but the modern Phasor Measurement Unit reveals voltage oscillations that could be harmful to equipment in the power grid.

The Phasor Measurement Unit

An important grid power-quality monitor is the Phasor Measurement Unit, a versatile monitor that measures the instantaneous voltage, current, and frequency of the electrical transmission lines. In North America where the grid is operated at 60 Hz, AC signals are measured 30 times per electrical cycle, 1200 times per second. The Phasor Measurement Unit calculates phasors based on these measurements, typically 30 phasors or more per second. A phasor, short for “phase vector”, is a complex number representing a sine wave by its amplitude, frequency, and phase. Think of the phasor as a precise measurement of the “heart beat” of the electric grid at the measured location.

A Phasor Measurement Unit is used to monitor the “heart beat”

Figure 2: A Phasor Measurement Unit is used to monitor the “heart beat” of power flowing through the electric grid.

A single Phasor Measurement Unit cannot detect many errors in the grid. However, measuring phasors simultaneously at strategically-selected positions in the grid can reveal many problems. Phasors measured at a synchronized time are called synchrophasors. The availability of a very accurate clock through the Global Positioning System has made it possible to synchronize phasor measurement units over a large area, and therefore detect early warning signals of larger grid problems.

Phasor Measurement Units installed at every transformer station

Figure 3: Phasor Measurement Units installed at every transformer station monitor the health of the power grid.

Designing a Phasor Measurement Unit

From a design perspective, a phasor measurement unit is a relatively simple data collection circuit. It consists of a microcontroller or microprocessor, surrounded by a 6-channel Analog-to-Digital Converter (ADC) capable of measuring each channel at 1200 ksps or more. There is also a GPS receiver providing a precise and universal time base, a local memory for storing the recorded synchrophasors, and a communication interface for communicating the measured data back to the grid operating room. The analog inputs will need to be protected from harmful voltages by an appropriate protection circuit. However, most of the design can be easily fitted into an embedded system powered at 3.3 V.

Phasor Measurement Unit block diagram

Figure 4: Simplified Phasor Measurement Unit block diagram.

Figure 4 above shows a simplified block diagram of a Phasor Measurement Unit. The basic design consists of a 6-channel A/D converter, a microcontroller, and a communications interface. The anti-aliasing filter is required to stop high-frequency components from entering the A/D converters. The GPS provides the clock synchronization at a 1 second time interval. Due to the long interval, a phase-locked oscillator is required to maintain accuracy between the 1 second synchronization signals.

Early Phasor Measurement Units were more complicated designs with local control panels and a large storage memory for recorded data. However, because historical data has limited value for predicting future errors, most grid operators prefer to buy more compact and less expensive Phasor Measurement Units that communicate the measured data back to the control room in real-time, eliminating the need for local storage and advanced user interface. All that is needed is a communication interface such as an Ethernet port or a wireless modem, as illustrated in Figure 4 above.

Early synchrophasors were based on large CPUs, typically designed on industrial PCs based on CPUs supplied by Intel, AMD, Renesas, or Freescale. The arrival of fast 32-bit microcontrollers based on the ARM® Cortex™-M4 core has allowed for a more compact and less expensive design. A microcontroller such as the LPC4078FBD208 from NXP Semiconductors is a good candidate from the Digi-Key catalog.

LPC4078FBD208 microcontroller from NXP Semiconductors

Figure 5: LPC4078FBD208 microcontroller from NXP Semiconductors is based on the ARM Cortex-M4 CPU.

The LPC4078FBD208 microcontroller from NXP is a member of the LPC408x/7x series, which is built around the Cortex-M4 CPU, the latest and highest-performance microcontroller core from ARM. The device packs 512 KB of Flash, 96 KB of SRAM, and 4 KB of EEPROM memory together with a 12-bit Analog-to-Digital Converter, Ethernet and full-speed USB port, SD card and LCD interface, and a number of other communication interfaces into a small 208-pin package.

NXP refers to the LPC408x/7X series as “digital signal controllers”, signaling how these components offer the peripheral features of a classic MCU combined with digital signal processing performance comparable to a low-end digital signal processor. The Cortex-M4 CPU does indeed offer very-high digital signal processing performance, including the ability to perform multiple arithmetic operations in parallel through the use of Single Issue, Multiple Data (SIMD) instructions. Many devices, including the LPC4078FBD208 from NXP, also feature a full floating point unit to accelerate advanced mathematical calculations.

The LPC4078FBD208 microcontroller does not include the GPS baseband receiver, so for this we need a dedicated component such as the R4 GPS receiver module from Linx Technologies. The R4 receiver is a complete RF + baseband module based on the Sirf Star IV chipset that can be dropped into any design without paying special attention to RF design rules. The receiver offers more than sufficient sensitivity, and supports a wide range of popular GPS antennas. The receiver will output one 200 ms pulse per second, and the rising edge of the pulse is perfectly synchronized to the universal GPS second. The NXP microcontroller is connected to the GPS module via UART, extracting the required data using the industry-standard NMEA-0183 or the proprietary SiRF Binary protocols.

One or more communication interfaces are required for extracting data from the Phasor Measurement Unit. Most units installed prior to 2014 have been installed at the high-voltage national grid level, near large power generators supplying 500 MW or more, and near high-voltage connection hubs. In these centralized locations, existing equipment is already connected, usually communicating across TCP/IP. That means Ethernet is a suitable interface. The LPC408x/7x series contain a Reduced Media Independent Interface (RMII)-compliant MAC. We just need a physical layer transceiver, and one alternative from the Digi-Key catalog is the KSZ8081RNA from Micrel, which is a highly-integrated and compact transceiver for 100 Mbit communication across CAT-5 unshielded twisted pair cables.

Ethernet is the preferred communication interface for Phasor Measurement Units fitted at locations that are already connected to the command center via TCP/IP. However, the vast majority of transmission lines and distribution transformers are not connected to the Internet. For a Phasor Measurement Unit fitted at a remote location, a wireless communication interface would be a better alternative. In some populated areas, transmission line operators have already started installing smart energy meters at houses and businesses. These smart meters are transmitting their data wirelessly back to the grid operator via data concentrators using the ZigBee Smart Energy protocol. It would be cost effective to use this network of data concentrators to pull data from Phasor Measurement Units as well.

In order to transfer measured data back to the operator using the smart meter data concentrators, we need an RF modem. ZigBee is based on the IEEE802.15.4 standard, for which there is a wide range of transceiver options. An alternative from the Digi-Key catalog is the ZigBit ATZB-A24-U0R module from Atmel. This is a complete, FCC-certified module that does not require any RF design skills. Atmel will also be happy to provide a certified ZigBee smart energy software stack for free.

If no smart meter data concentrator is available, the 3G/4G cellular networks will be the last remaining option for transmitting data from a Phasor Measurement Unit back to the grid control centers. Major cellular network operators, including AT&T, Deutsche Telekom, and Huawei are investing heavily in machine-to-machine (M2M) communication, and fierce competition in this sector has brought the cost of using the 3G and 4G networks to transmit data down to attractive levels.

An alternative cellular modem is the MTCBA-G2 from MultiTech Systems. This is a standalone GPRS modem, designed specifically for industrial applications, and it connects easily to a Phasor Measurement Unit via a standard RS232 or RS422 connection.

With these components, we can build a low-cost Phasor Measurement Unit that can be installed at a large number of locations throughout the grid to make the grid smarter. Figure 6 below shows the signal processing performed by the microcontroller or microprocessor.

Signal processing

Figure 6: Signal processing performed by a Phasor Measurement Unit.

The microcontroller receives a filtered analog signal as input to the A/D. These signals are converted at a minimum sample rate of 1200 ksps. The resulting samples are fed into a digital low-pass filter before the phasor calculation starts. The phasor calculation uses a DFT to calculate the magnitude and phase of the signals. This is applied for each phase. Typically, one period of data is used, to reduce the effect of measurement noise. The resulting phasors are then time-stamped using a synchronized time-reference obtained by the GPS system.

The digital signal processing is repeated 6 x 30 times per second, which means most ARM Cortex-M4-based microcontrollers have sufficient processing power to handle both the signal processing and the communication stacks. Earlier in the article we focused on the LPC4078FBD208 device from NXP Semiconductors. There are several alternatives to the device from NXP, including the SAM4E8CA from Atmel, the K60 ZLL10 from Freescale, the XMC4500-F100 from Infineon, and the STM32F407 from STMicroelectronics.

How does a Phasor Measurement Unit make the power grid smarter?

In August 2013, 10 years after The Great Blackout, the U.S. Department of Energy released a status report showing how Phasor Measurement Units are being used by grid operators to monitor the health of the power distribution system.

Synchrophasor data provide alerts to indicate possible levels of stress in the grid, such as areas of low voltage, frequency oscillations, or rapidly changing phase angles between two locations on the grid. For example, real-time monitoring reveals power generators that operate out of phase with other power stations on the grid. Detecting and isolating such power generators is useful, especially in areas where a large number of renewable wind and sun-powered generators are connected to the grid. A small power plant operating out of phase with the grid can cause oscillations in the phase-locked loop of a much larger power generator, causing the whole grid to oscillate uncontrollably. It is very important to dampen such oscillations, or the whole power generation system can become unstable.

It is also useful to monitor frequency, as frequency fluctuations indicate imbalance between supply and demand. Frequency will decrease when demand decreases and rise when demand picks up. A rapid change in frequency is the first indicator of an unexpected loss of a generator or load. These sudden events can cause harmful oscillations on the grid and lead to a blackout. Early and correct response from grid operators is required to prevent a disaster.

The report from the U.S. Department of Energy outlines nine additional benefits that Phasor Measurement Units bring to grid operators. Their usefulness has been thoroughly demonstrated, and they are rapidly becoming one of the most important building blocks in the Smart Grid. Between 2010 and 2013, the number of installed Phasor Measurement Units within the U.S. power grid grew from 166 to 1043. However, grid operators are still far away from the goal of monitoring every major transmission line. Grid operators are waiting for vendors to introduce a less expensive Phasor Measurement unit, making installation at all transformer stations an affordable option.

References:
  1. John Spears article “Blackout 2003: How Ontario went dark”, The Star, August 2013
  2. U.S. Department of Energy report “Synchrophasor Technologies and their Deployment in the Recovery Act Smart Grid Systems”, August 2013

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