Much of the developed world’s transmission grid is approaching the end of its design life and is subject to headline-grabbing failures. At the same time, the industry’s technical workforce is poised for retirement. These people built, operated and maintained the largest and most complex machine the world has yet to see. Regrettably, they will take with them intimate knowledge of exactly how it operates. Because so many utilities have underinvested in any type of succession plan, there is a loss in situational awareness of the power grid system. Combine this with the increasing demand for power, changing regulation and increasingly complex interconnections, and the stage has been set for more and bigger blackouts.
Fortunately, the development of technology that could automate, manipulate and monitor basic equipment, such as switches, capacitors and relays, began in the late 1980s. This technology is reaching the stage of deployment at a time when it will be a major player in the solution.
The technology is a highly intelligent combination of high-speed communications,information technology and process competency. Together, it forms a fast and reliable decision-making system to predict, prevent and mitigate disturbances.
Many years ago, Bonneville Power Authority (BPA) developed a monitoring system called the phasor measurement unit (PMU). It monitors voltage and current phase angles, which can be used to predict developing instability. Initially, the Western Electric Coordinating Council (WECC) and EPRI deployed the PMU as a real-time wide-area monitoring system (WAMS) with 21 PMUs at six utilities. Last year, there were 60 PMUs installed on eight utility systems with phasor data concentrators at control centers belonging to WECC members.
China started deploying WAMSs in 2002. Dr. Christian Rehtanz, ABB China vice president and director of corporate research, says that China is currently doing some of the most advanced work in this field developing applications to interpret basic PMU data. Today, China has installed 10 central computers with 200 to 300 PMUs in five regional and five provincial power systems. According to Rehtanz, the challenge facing researchers is to develop methods to analyze the millions of data points from the WAMS. The Eastern Interconnection Phasor Project (EIPP) is another PMU system that has deployed about 75 PMUs. EIPP is a Department of Energy (DOE) and Consortium for Electric Reliability Technology Solutions (CERTS) initiative that started in October 2003.
The 2003 blackout
The August 2003 blackout affected 10 million people in Canada and 40 million people in northeastern United States. Outage-related financial losses were estimated at approximately US$6 billion.
Robert Cummings, director of events analysis and information exchange for the North American Electric Reliability Council (NERC), reviewed some PMUs and other data from just prior to and during the August 2003 outage. Bus frequencies showed a fluctuation, and phase angles seen in Ohio and Michigan began to diverge from each other hours before the outage. He found that the phase angles continued to diverge from each other, indicating that stress was building on the interconnection.
One problem facing transmission system operators is system stability. Power transfers could be increased if stability was not a limiting condition. Psymetrix Ltd. has developed an oscillatory stability management system called the StormMinder. Dr. Douglas Wilson says that the StormMinder system uses a technology that monitors the small perturbations that are always on the power system. The operator is provided with real-time displays and alarms for system damping. According to Wilson, Psymetrix has installed its system on the Australian network. In 2004, the StormMinder system identified severe oscillations and their locations on the Australia network. Because operators were able to use this information, a serious blackout was prevented. The Psymetrix system has also been installed in Manitoba, Canada.
After some serious power interruptions in Europe and North America, AREVA T&D — working with a group of utilities (American Electric Power [AEP], Northeast Utilities, Ameren, TVA, Entergy and First Energy) — developed a software system called e-terravision to help system operators anticipate and avoid problems that could lead to brownouts and blackouts. The software is a decision-support system for the control center. It takes the accumulation of real-time data from supervisory control and data acquisition systems, energy management systems and WAMS, giving the operator a visualization of the systems, talk about being user friendly. The operator can develop dynamic dashboard displays, on the fly, of exactly the type of information needed for the conditions. They have the vital signs of the systems at their fingertips. In effect, e-terravision is a platform and methodology to develop applications that enhance situational awareness in the control center.
AREVA T&D and its utility partners continued to ask “what if” in the development of e-terravision and have outlined the basics for an e-terra suite. Why not have various decision-making capabilities built into the real-time visualization software? The suite combines elements of a browser for monitoring the grid behavior, an archive to store and analyze historical information, a modeler for energy management, a security environment for cyber protection, a centralized alarm management system, and substation automation to monitor, control and protect system operation.
Series capacitors are another way to increase the power flow down a transmission line, but they have some problems associated with them. As compensation levels are increased, subsynchronous resonance (SSR) and possible damage to generation resources become a problem. Add some intelligent power electronics in the form of thyristor controls, and the system operator doesn’t have to monitor for SSR in addition to the other system properties. SSR has gone away. Some call the thyristor-controlled series capacitor a “stealth” capacitor.
BPA, EPRI and GE Energy pioneered this technology in the early 1990s with the Slatt Substation thyristor-controlled series capacitor installation where, like capacitors, transformers, breakers, switches and other substation devices are not considered intelligent by themselves. But add monitors and the switchyard becomes smart. Today, however, there is a wide selection of intelligent electronic devices (IEDs) available for almost every piece of substation equipment. Southern States, LLC has developed a current monitoring device that clamps on stands below the substation bus. It uses electromagnetic fields to sense voltage and current levels without being physically placed in the circuit, making it handy to monitor in extremely tight spaces. ABB, GE Energy, AREVA and Siemens have developed systems to replace the labor-intensive station checks with real-time monitoring of station equipment and circuits.
Transformers can be smarter
The typical large power transformer is a $3 million to $5 million investment for a U.S. utility, and replacing it takes about two to three years. Yet few utilities have real-time monitoring systems installed on these critical pieces of equipment. It isn’t expensive to install, and transformer-monitoring equipment offers new advances in its data-collection abilities. Real-time monitoring of oil for gas chromatography is available, as is temperature detection for hot spots, oil temperatures, load tap changer temperatures and cooling efficiencies.
The real trick is converting the data into usable information. This information is important to utilities because it allows them to schedule work based on the condition of the equipment rather than basing maintenance on the calendar. The system operator can load transformers and receive real-time feedback about the actual condition of the transformer rather than an operating procedure based on conservative guesswork by an engineer sitting miles away from the actual unit.
GE Energy, Siemens/Serveron, ABB, Morgan Shaffer, Dynamic Ratings and Schweitzer are a few of the manufacturers developing complete monitoring systems to give operations and maintenance personnel a real understanding of how the equipment in the substation is performing and the true conditions under which they are operating.
Once the intelligence is in place to investigate loop flows, as well as resonance and low-frequency oscillations, tools are needed to counteract that instability. Otherwise, utilities are reduced to tripping generation and shedding load. Flexible AC Transmission System (FACTS), partially funded by EPRI and developed by GE Energy, Siemens, ABB, Mitsubishi and AREVA, meets these requirements with devices that make it possible to counteract electrical disturbances before they impact the end user, such as the phenomenon of voltage fluctuations, flicker and voltage sags. Examples include:
- Super VAR. Developed by Tennessee Valley Authority (TVA) and American Superconductor Corp., this high-temperature superconducting synchronous condenser corrects voltage sag immediately. It is rated at 10 MVAR. The first Super VAR went into service in 2005 on the TVA system. Since then, TVA has purchased five of the units.
- SVC light. ABB has developed a STATCOM device (static compensator) using voltage-source converter technology and insulated gate bipolar transistor technology to control reactive power.
- Advanced phase-shifting transformer. GE Energy developed the Variable Frequency Transformer (VFT), a continuous phase-shifting transformer based on rotating machine technology. It also has one power grid connected to the rotor and the other grid to the stator. In effect, it is a rotating machine that operates like a converter station, connecting two asynchronous systems without the hassle of a converter station. There are no harmonic filters and the control system uses programmable logic controllers based on ladder logic. It can be replaced easily when control technology needs to be upgraded, making it a true plug-and-play device relying on tested technology packaged for the 21st century. The first VFT was installed on the Hydro Quebec system. A second VFT is under construction on the AEP system between Texas and Mexico.
- High-voltage direct current. This technology continues to advance with the capacitor commutated converter for connection of weak networks. The voltage-source converter enables the connection to passive networks (no generation) and provides active and reactive power control while maintaining power quality.
The pieces needed to add intelligence to the bulk transmission system already exist. The electromechanical power system of the last millennium must be replaced. Intelligent technology can transform it into an intelligent power system. The intelligent bulk transmission grid is an ambitious undertaking whose time has come.
Increasing Grid Capacity with Superconducting Cable
High-temperature superconductors (HTSs) are now a reality. In August 2006, American Electric Power (AEP) has installed a 200-m (656-ft) HTS cable designed and manufactured by Ultera (a joint venture of Southwire and nkt cables) at its Bixby Substation. The Triax cable is energized at 13.2 kV and rated 3 kA and 69 MVA and incorporates all three phases of a power line through a single cable. This design reduces space requirements and uses one-half the quantity of superconducting materials.
Sumitomo, SuperPower Inc., the BOC Group and National Grid installed the world’s first in-grid HTS 350-m (1148-ft), 34.5-kV underground cable this year in Albany, New York. American Superconductor Corp. started production of HTS cable in 2005. The cable is able to carry 150 times the current as copper cable of the same dimensions. The U.S. Department of Energy has been working with manufacturers to develop the next generation of HTS 2G. In addition, Rockwell Automation and SuperPower Inc. are working on this technology.