1540-7977/10/$26.002010 IEEE34 IEEE power & energy magazine march/april 2010

The Future of Power

TransmissionTechnological Advances for Improved Performance

By Stanley H. Horowitz, Arun G. Phadke, and Bruce A. Renz Digital Object Identifi er 10.1109/MPE.2009.935554

TTHE ELECTRIC POWER SYSTEM IS ON THE VERGE of signifi cant transformation. For the past fi ve years or so, work has been under way to conceptualize the shape of a 21st-century grid that exploits the huge progress that has been made in digital technology and advanced materials. The National Energy Technology Laboratory (NETL) has identifi ed fi ve foundational key technology areas (KTAs), as shown in Figure 1.

Foremost among these KTAs will be integrated communi-cations. The communications requirements for transmission enhancement are clear. Broadband, secure, low-latency chan-nels connecting transmission stations to each other and to con-trol centers will enable advances in each of the other KTAs.

Sensing and measurements will include phasor mea-surement data streaming over high-speed channels. Advanced components, such as all forms of fl exible ac transmission system (FACTS) devices, HVDC, and new storage technologies will respond to control sig-nals sent to address perturbations occurring in mil-liseconds.

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34 IEEE power & energy magazine march/april 20101540-7977/10/$26.002010 IEEE

march/april 2010 IEEE power & energy magazine 35

Advanced control (and protection) methods will in- clude differential line relaying, adaptive settings, and various system integrity protection schemes that rely on low-latency communications. Improved interfaces and decision support will uti- lize instantaneous measurements from phasor mea-surement units (PMUs) and other sources to drive fast simulations and advanced visualization tools that can help system operators assess dynamic chal-lenges to system stability.

Each of these elements will be applied to the moderniza-tion of the grid, at both the distribution level and the transmis-sion level. Because it is clearly less advanced, distribution is receiving most of the initial focus. This is dramatically illus-trated by the American Recovery and Reinvestment Acts Smart Grid Investment Grants (SGIGs), announced in Octo-ber. Of the $3.4 billion awarded to 100 proposers (of the more than 400 that applied), only $148 million went to transmission applications; most of the rest was for distribution projects.

While the changes to distribution will be revolutionary, transmission will change in an evolutionary manner. Dis-tributed generation and storage, demand response, advanced metering infrastructure (SGIGs will fund the deployment of 18 million smart meters), distribution automation, two-way power fl ow, and differentiated power quality together rep-resent a sea change in distribution design that will require enormous fi nancial and intellectual capital.

The role of transmission will not be diminished, how-ever, by this new distribution paradigm. Large central power plants will continue to serve as our bulk power source, and many new ones will be fueled by renewable resources that would today be out of reach of the transmission grid. New lines will be built to connect these new plants, and new methods will be employed to accommodate their very dif-ferent performance characteristics. Addressing the result-ing greater variability of supply will be the job of the fi ve KTAs listed above. As KTA technology speeds increase, control of transmission will advance from quasi-steady-state to dynamic.

The traditional communications technologies capable of supporting these strict requirements are fi ber optics (e.g., optical ground wire) and microwave. Recently a third can-didate has appeared on the scene. Research funded by the U.S. Department of Energy (DOE) and American Electrical Power in conjunction with a small Massachusetts smart-grid communications company, Amperion, has demonstrated the viability of broadband over power line (BPL) for application on transmission lines. Currently, a fi ve-mile, 69-kV line is operating at megabit-per-second data rates with latency of less than 10 ms. The next step will be to extend this high-voltage BPL technology to 138 kV.

How We Got Here In 551 B.C., Confucius wrote, Study the past if you would know the future. The future of the electrical power trans-

mission system must be based on a study of the past con-sidering its successes and failures, on knowledge of the existing system and all of its component disciplines, and on a thorough understanding of the latest technologies and their possible applications. The electrical power system, and in particular its transmission and distribution network, is a vital and integral part of todays society. Because it is essential to all our endeavors, we must be prepared to integrate new, exciting, and highly innovative concepts to guarantee that it performs reliably, safely, economically, and cleanly.

Although not unique in world events involving power systems, two widely known outages in the United States and Canada serve as examples of the history, analysis, and reme-dies for blackouts and can provide a basis for future actions. Widely publicized, the blackouts of 9 November 1965 in the northeastern United States and 23 August 2003 in the northeastern United States and Canada are typical events that can help shape our planning and operating efforts for the future.

In 1965 we learned that cooperation and interaction between utilities were essential. In response to the blackout, utilities established the National Electric Reliability Cor-poration (NERC) in 1968, which began distributing recom-mendations and information. These communications formed the basis for more reliable and secure planning, operating, and protective activities. The decisions of the newly formed NERC were, however, only recommendations. Defi ciencies due to limitations in transmission planning, operations, and protection were recognized, and steps were taken to correct them. Transmission systems were strengthened considerably by the construction of 345-kV, 500-kV, and 765-kV lines. System planning studies were made cooperatively; operat-ing parameters and system problems were studied jointly. Underfrequency load shedding became universal, with spe-cifi c settings arrived at by agreement between utilities, and loss-of-fi eld relaying was recognized as a system phenom-enon and studied accordingly.

In 2003 another blackout of similar proportions affected the northeastern United States and parts of Canada. The

figure 1. NETLs five key technology areas.

AdvancedComponents

Sensing andMeasurements

AdvancedControl

Methods

Decision SupportIntegrated

Communications

36 IEEE power & energy magazine march/april 2010

causes of that event included not recognizing load and sta-bility restrictions and, unfortunately, human error, which suggested that improved systemwide monitoring, alarms, and power system state estimation programs would be useful and should be instituted. The ability of a distance relay to differentiate between faults and load, particularly when the system is stressed, has become a major concern. NERC requires that this condition be included in relay set-ting studies.

In 1920, Congress founded the Federal Power Com-mission (FPC) to coordinate hydroelectric power devel-opment. Fifty-seven years later, in response to the energy crisis, the DOE was formed. The DOE included the FPC, renamed the Federal Energy Regulatory Commission (FERC), whose mandate was primarily to conduct hear-ings and approve price control and related topics, including electric practices on bulk transmission systems. After the 2003 event, FERC also became a regulatory instrument, reviewing transmission line improvements and rights-of-way. FERC review and approval, as with NERC, has now become mandatory. The actions of FERC and NERC will, in the future, be major components of system decisions and practices.

Technologys Role Going ForwardWith the preceding as background, we can now review in greater detail some of the transmission enhancements that will be part of the 21st-century transmission system.

Advanced ControlIt is axiomatic that the fundamental basis for the reliable performance of the transmission system has to be the system itself. The primary components, system confi guration, line specifi cations, and design of high-voltage equipment must be consistent with the mission of the power system, i.e., to deliver electric energy safely, reliably, economically, and in a timely fashion. Furthermore, high-voltage, electronic-based power equipment such as bulk storage systems (e.g., fl ow batteries), FACTS devices (including unifi ed power fl ow controllers, static var compensators, and static synchronous compensators), and current-limiting devices (CLDs), which are based on high-temperature superconductivity, are now or will soon be available. Coupled with sophisticated com-munications and computing tools, these devices make the transmission system much more accommodating of varia-tions in load and/or voltage.

Of these advanced control devices, FACTS represents the most mature technology. It is in somewhat limited use at present but has the potential to be an increasingly impor-tant element in the future. FACTS can provide control of ac transmission system parameters and thus increase power transfer capability and improve voltage regulation. Changes in generation and load patterns may make such fl exibility extremely desirable. With the increased penetration of central renewable sources and with the continued variability of

electricity markets, the value of these various electronics-based power devices will only grow.

In addition to FACTS, bulk storage, and CLDs, vari-ous new aspects of the distribution system such as demand response, distributed generation, plug-in hybrid electric vehicles (PHEVs), and other forms of distributed storage can be centrally coordinated and integrated to function as a vir-tual power system that supports the transmission system in times of stress.

Advanced ProtectionRecognizing that protection of specifi c equipment and localized systems is inadequate in the face of systemwide stress, in 1966 a joint IEEE/CIGRE questionnaire was circulated. The results indicated that protection schemes had to encompass wider areas of the transmission system. This effort required communication and control center involvement. The effort was termed special protection sys-tems (SPS). The primary application of SPS at that time was for limited system events such as underfrequency and undervoltage, with some advanced generation controls. As system stress becomes a more common concern, the application of SPS takes on added importance and in fact becomes an important tool for protecting the grid against wide-area contingencies.

The SPS concept is no longer considered special and is now commonly referred to as system integrity protection systems (SIPS), remedial action systems (RAS), or wide-area protection and control (WAPC). These schemes are intended to address widespread power system constraints or to be invoked when such constraints could occur as a result of increased transfer limits. The Power System Relaying Committee of the IEEE initiated a recent survey on power system integrity protective schemes that was distributed worldwide with cooperation from CIGRE, NERC, IEE, and other utility organizations. The survey revealed very wide-spread application, with more than 100 schemes of various complexity and purpose. Emerging technologies in high-speed communication, wide-area measurement, and phasor measurement are all employed and will be vital components of the transmission system in the future.

One of the most exciting features of the transmission sys-tem of the future involves power system protection. This is due in large measure to the advantages of digital technology for relays, communication, and operation. Relays now have the ability to perform previously unimaginable functions, made feasible by evaluating operating and fault parameters and coupling this data with high-speed communication and computer-driven applications within the power system con-trol center. With the ever-increasing restrictions on trans-mission line and generator construction and siting and the decreasing difference between normal and abnormal opera-tion, loading, and stability, the margins between the relay-ing reliability concepts of dependability and security are becoming blurred. Consequently, the criteria of traditional

march/april 2010 IEEE power & energy magazine 37

protection and control are being challenged. The hallmark of relays is the tradeoff between dependability (the ability to always trip when required) and security (the characteristic of never tripping when not required).

Traditionally, relays and relay schemes have been designed to be dependable. Losing a transmission line element must be tolerated, whether the loss is for an actual fault or for an inadvertent or incorrect trip. When the system is stressed, however, an incorrect trip is not allowable. With the system stressed, losing another element could be the fi nal step in bringing down the entire network. With digital logic and operations, it is possible to reorder protection priorities and require additional inputs before allowing a trip. This can be done with appropriate communication from a central center advising the relays.

Probably one of the most diffi cult decisions for a relay is to distinguish between heavy loads and faults. Heretofore, relays simply relied on the impedance measurement, with settings determined by off-line load studies using conditions based on experience. As in the two blackouts mentioned above, this criterion was not adequate for unusual system conditions that were not previously considered probable. Digital relays can now establish such parameters as power factor or voltage and remove the measured impedance from the tripping logic.

The bte noir of protection has traditionally been the multiterminal line. The current to the fault and the voltage at the fault defi nes the fault location. A relay designed to protect the system for this fault, however, sees only the cur-rent and voltage at that relays specifi c location. The advent of high-speed communication and digital logic remedies this condition and allows all involved relays to receive the appro-priate fault currents and voltages.

The increasing popularity of transmission line differen-tial relaying also provides both dependability and security for faults in a multiterminal confi guration. Although primar-ily a current-measuring relay, the digital construction allows far more protection, monitoring, and recording functions. Future applications will be available to accomplish the fea-tures mentioned above and in ways not yet implemented or even thought of.

One of the earliest advantages of the computer relay is its ability to monitor itself and either repair, replace, or report the problem. This feature is sure to be a major fea-ture in future transmission line protection. In addition, the information stored in each relay during both normal and abnormal conditions and the ability to analyze and trans-

fer this information to analyzers have made previously used oscillography and sequence-of-events recorders obsolete. Replacing these devices will result in very signifi cant sav-ings in both hardware and installation costs. AEP, in con-junction with Schweitzer Engineering and Tarigma Corp., has embarked on a revolutionary program that lets selected centers receive data from critical substations that will com-bine, display, and analyze fault data to a degree and in a time frame heretofore not possible. Combining the current, voltage, communication signals, and breaker performance from several stations on one record that can be analyzed at several control and engineering centers permits operations to be verifi ed and personnel to be alerted to potential prob-lems. A vital by-product of this advanced monitoring is the fact that it allows NERC requirements for monitoring and analysis to be met.

Perhaps even more exciting is the possibility of predicting the instability of a power swing. Modern protection theory knows how to detect the swing using zones of stability and instability. The problem is how to set the zones. With accu-rate synchronized phasor measurements from several buses, the goal of real-time instability protection seems achievable. Out-of-step relays could then establish blocking or tripping functions at the appropriate stations.

The role of underfrequency load shedding has already been discussed. Future schemes, however, could use real-time measurements at system interconnection boundaries, compute a dynamic area control error, and limit any poten-tial widespread underfrequency by splitting the system.

Computer relays, if not already in universal use, will be in the near future. This will let utilities protect, monitor, and analyze system and equipment performance in ways and to a degree not possible before.

Synchronized Phasor MeasurementsIt has been recognized in recent years that synchronized phasor measurements are exceedingly versatile tools of modern power system protection, monitoring, and control. Future power systems are going to depend on making use of these measurements to an ever-increasing extent. The principal function of these systems is to measure positive sequence voltages and currents with a precise time stamp (to within a microsecond) of the instant when the measure-ment was made. The time stamps are directly traceable to the Coordinated Universal Time (UTC) standard and are achieved by using Global Positioning System (GPS) trans-missions for synchronization. Many PMUs also provide

While the changes to distribution will be revolutionary, transmission will change in an evolutionary manner.

38 IEEE power & energy magazine march/april 2010

other measurements, such as individual phase voltages and currents, harmonics, local frequency, and rate of change of frequency. These measurements can be obtained as often as once per power frequency cycle, although for a number of applications a slower measurement rate may be prefer-able. In well-designed systems, measurement latency (i.e., the delay between when the measurement is made and when it becomes available for use) can be limited to fewer than 50 ms. The performance requirements of the PMUs are embodied in the IEEE synchrophasor standard (C37.118). A measurement system that incorporates PMUs deployed over large portions of the power system has come to be known as a wide-area measurement system (WAMS), and a power sys-tem protection, monitoring, and control application that uti-lizes these measurements is often referred to as a wide-area measurement protection and control system (WAMPACS).

Automatic Calibration of Instrument Transformers It is well known that current and voltage transformers used on high-voltage networks have ratio and phase-angle errors that affect the accuracy of the measurements made on the secondary of these transformers. Capacitive volt-age transformers are known to have errors that change with ambient conditions as well as with the age of the capacitor elements. Inductive instrument transformers have errors that change when their secondary loading (burden) is manually changed. The PMU offers a unique opportunity for cali-bration of the instrument transformers in real time and as often as necessary. In simple terms, the technique is based on having some buses where a precise voltage transformer (with known calibration) is available and where a PMU is placed. Potential transformers used for revenue metering are an example of such a voltage source. Using measurements by the PMU at this location, the calibration at the remote end of a feeder connected to this bus can be found. This calibra-tion is not affected by current transformer (CT) errors when the system loading is light. It is thus possible to calibrate all voltage transformers using current measurements at light system load. Using the voltage transformer calibration thus obtained and additional measurements during heavy system load, the current transformers can be calibrated. In practice, it has been found (in simulated case studies) that by combin-ing several light and heavy load measurement sets a very accurate estimate of all the current and voltage transformers can be obtained. Although a single accurate voltage source is suffi cient in principle, having a number of them scattered throughout the network provides a more secure calibration.

Precise State Measurements and EstimatesState estimation of power systems using real-time measure-ments of active and reactive power fl ows in the network (supplemented with a few other measurements) was intro-duced in the late 1960s to improve the awareness among power system operators of the prevailing state of the power

grid and its ability to handle contingency conditions that may occur in the immediate future. This was a big step for-ward in intelligent operation of the power grid. The limita-tions of this technology (such as nonsimultaneity of system measurements across the network) were rooted in the tech-nology of that day. The fact that the data from a dynamically changing power system was not obtained simultaneously over a signifi cant time span meant that the estimated state was an approximation of the actual system state. Conse-quently, the system state and its response to contingencies could only be reasonably accurate when the power system was in a quasi-steady state. Indeed, when the power system was undergoing signifi cant changes due to evolving events, the state estimator could not always be counted on to con-verge to a usable solution.

The advent of wide-area measurements using GPS-synchronized PMUs led to a paradigm shift in the state estimation process. With this technology, the capability of directly measuring the state of the power system has become a reality. PMUs measure positive sequence voltages at net-work buses and positive sequence currents in transmission lines and transformers. Since the state of the power system is defi ned as a collection of positive sequence voltages at all network buses, it is clear that with suffi cient numbers of PMU installations in the system one can measure the sys-tem state directly: no estimation is necessary. In fact, the transmission line currents provide a direct estimate of volt-age at a remote bus in terms of the voltage at one end. It is therefore not necessary to install PMUs at all system buses. It has been found that by installing PMUs at about one-third of system buses with voltage and current measurements, it is possible to determine the complete system state vector. Feeding this information into the appropriate computers provides the information necessary for the adaptive protec-tive function described above. Of course, a larger number of PMUs provides redundancy of measurements, which is always a desirable feature of estimation processes.

Complete and Incomplete ObservabilityIn order to achieve a state estimate in the traditional way, i.e., by using unsynchronized supervisory control and data acquisition (SCADA) measurements, a complete network tree must be measured. With PMUs, however, it is suffi cient to measure isolated parts of the network, which provides islands of observable networks. This is possible since all phasors are synchronized to the same instant in time. The process has been described as PMU placement for incom-plete observability. The remaining network buses can be estimated from the observed islands using approximation techniques. This is, of course, not as accurate as providing a suffi cient number of PMUs in the fi rst place. But it has been shown that combining incomplete observations with such an approximation technique to estimate the unobserved parts provides surprisingly useful results. Incomplete observabil-ity estimators are a natural step in the progression towards

march/april 2010 IEEE power & energy magazine 39

complete observability and will be a feature in future trans-mission systems.

Figure 2 illustrates the principle of complete and incom-plete observability. In Figure 2(a), PMUs are placed at buses identifi ed by dark circles. By making use of the current mea-surements and the network impedance data, it is possible to calculate the voltages at the buses identifi ed by light blue circles. In this case, complete observability is achieved with two PMUs. Figure 2(b) illustrates the use of fewer PMUs than would be necessary for complete observability. Even with current measurements, it is not possible to determine the voltages at the buses identifi ed by the red circles. These buses form islands of incomplete observability. As men-tioned earlier, these bus voltages can be estimated fairly accurately using voltages at surrounding buses.

State Estimates of Interconnected SystemsA common problem faced by interconnected power systems is that various parts of the system may be under different control centers, with each part having its own state estimator. This, of course, implies that each partial state estimate has its own reference bus. To perform studies such as contingency analysis on the interconnected power system, it is necessary to have a single state estimate for the entire network. This requires either that 1) a new system state using data from

all partial control centers be determined or 2) an alternative must be found to modify the results of individual state esti-mates to put all states on a common reference. Option 1 is cumbersome and wasteful of computational effort. Option 2 becomes exceedingly simple with PMUs. At the simplest level, one can visualize putting a PMU at each of the ref-erence buses, thus obtaining the phase-angle relationships between all partial estimates. These phase-angle corrections may then be used to form a combined state estimate for the entire interconnected network on a single reference. It has been found in practice that the placement of a few PMUs in each partial system (rather than just one at the reference bus) leads to greater security and optimal performance. This principle is illustrated in Figure 3. Systems 1 and 2 are con-nected by tie lines and have state estimates S1 and S2 that are obtained independently, each with its own reference bus. With the use of PMU data from optimally selected buses (shown in red), it is possible to determine the angle differ-ence between the two references and obtain a single state estimate for the interconnected system.

Intelligent Visualization Techniques The traditional visualization techniques used in energy man-agement system (EMS) centers focus on showing network bus voltages and line fl ows, along with any constraint violations that may exist. It is, of course, possible to reproduce such displays using WAMS technology. Dynamic loading limits of transmission lines have been estimated with WAMS, and it would be relatively simple to show prevailing loading con-ditions and their proximity to the dynamic loading limits. Many PMUs offer the possibility of measuring system unbal-ances. It would then be possible to display unbalance cur-rents to determine their sources and mitigation techniques to correct the unbalance.

figure 3. Connecting adjacent state estimates with phasor data.

Traditional SE Result: E1 Traditional SE Result: E2

Reference Reference

Optimal Placement of PMUs

A common problem faced by interconnected power systems is that various parts of the system may be under different control centers, with each part having its own state estimator.

figure 2. (a) Complete observability. (b) Incomplete observability.

IndirectPMU

PMUIndirectlyObservedUnobserved

(a)

(b)

40 IEEE power & energy magazine march/april 2010

With direct measurement of synchronized phasors, many more display options become possible. For example, a geographical display with phase angles at all network buses shown at the physical location of busesand perhaps fi tted with a surface in order to provide a hilly contourwould immediately show the distribution of positive sequence volt-age phase angles.

Figure 4 shows such a visualization of a hypothetical net-work state for the entire United States. The map colors iden-tify the magnitude and sign of the positive sequence voltage phase angle with respect to a center of angle reference. The lower plot is a footprint of equiangle loci from the map. Since the positive sequence voltage phase-angle profi le of a net-work conveys a great deal of information regarding its power fl ow and loading conditions, such visualizations can instantly show the quality of the prevailing system state and its dis-tance from a normal state. High-speed dynamic phenomena can be represented by animations of such visualizations.

Such a display would instantly show the general dispo-sition of generation surplus and load surplus areas. Such a picture can be updated at scan rates of a few cycles, leading to visualization of dynamic conditions on the network. If thresholds for phase-angle differences between key buses have been established for secure operation of the network, then violation of those thresholds could lead to important alarms for the operator. Similarly, when islands are formed following a catastrophic event, the boundaries of those islands could be displayed for the operator. Several protec-tion and control principles are being developed to make use of wide-area measurements provided by PMUs. Adap-tive relaying decisions made in this manner could also be displayed for the use of protection and control engineers. The technology of visualization using WAMS schemes is in its infancy. As we gain greater experience with these systems, more interesting display ideas will undoubtedly be forthcoming.

ConclusionModernizing the U.S. power grid has become a national pri-ority. Unprecedented levels of governmental funding have been committed in order to achieve this goal. The initial focus has been on the fundamental transformation of the distribution system. This is in itself a huge technical chal-lenge that will be measured not in years but in decades. The end result is expected to be higher effi ciency, reduced envi-ronmental impact, improved reliability, and lower exposure to terrorism.

The revolution in distribution must be accompanied by the continued evolution of the transmission system. Events like the 2003 blackoutmore the result of human shortcom-ings than technological breakdownscan be eliminated by exploiting the huge progress made in recent years in the digital and material sciences. Other industries have already harvested these opportunities; now it is our turn.

Technological development is an engineering challenge. This nation has time and again demonstrated its ability to meet such challenges whenever they have been clearly focused. But there is another challenge that may actually be more diffi cult. It is to fi nd the political alignment that is needed to accept the vision and move forward aggressively. For transmission, that means recognizing that new lines, not just better lines, will be needed. It is simply not acceptable to wait ten or more years for a new line to move from con-cept to reality. Unlike many other parts of the world, the United States has allowed fragmented responsibility for transmission additions to slow the process to an unaccept-able extent.

With the intense focus now on energy in general and electricity in particular, it should be possible to overcome both the technical and the political obstacles and to reestab-lish U.S. leadership in this vital arena. Doing so is a matter of huge national signifi cance that will affect the lifestyle of all Americans in this new century.

For Further ReadingV. Madani and D. Novosel, Getting a grip on the grid, IEEE Spectr., pp. 4247, Dec. 2005.

P. Anderson and B. K. LeReverend, Industry experience with special protection schemes, IEEE Trans. Power Syst., vol. 2, no.3 , pp. 11661179, Aug. 1996.

Global Industry Experiences with System Integrity Pro-tection Schemes, Survey of Industry Practices, IEEE Power System Relaying Committee, submitted for publication.

Biographies Stanley H. Horowitz is a former consulting electrical engi-neer at AEP and former editor-in-chief of IEEE Computer Applications in Power magazine.

Arun G. Phadke is the University Distinguished Profes-sor Emeritus at Virginia Tech.

Bruce A. Renz is president of Renz Consulting, LLC. p&e

figure 4. U.S. Phasor contour map.

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