wide-area protection and emergency control

Wide-Area Protection and Emergency Control

MIROSLAV BEGOVIC, FELLOW, IEEE, DAMIR NOVOSEL, FELLOW, IEEE,DANIEL KARLSSON, SENIOR MEMBER, IEEE, CHARLIE HENVILLE, FELLOW, IEEE,AND GARY MICHEL, SENIOR MEMBER, IEEE

Invited Paper

System-wide disturbances in power systems are a challengingproblem for the utility industry because of the large scale and thecomplexity of the power system. When a major power system dis-turbance occurs, protection and control actions are required to stopthe power system degradation, restore the system to a normal state,and minimize the impact of the disturbance. In some cases, thepresent control actions are not designed for a fast-developing dis-turbance and may be too slow. The report explores special protetionschemes and new technologies for advanced, wide-area protection.There seems to be a great potential for advanced wide-area protec-tion and control systems, based on powerful, flexible and reliablesystem protection terminals, high speed, communication, and GPSsynchronization in conjunction with careful and skilled engineeringby power system analysts and protection engineers in cooperation.

Keywords—Emergency control, power system protection, wide-area protection.

I. INTRODUCTION

From time to time, power systems are exposed to seriousdisturbances, which lead to the interruption of the powersupply to the customers [4], [37], [39], [40]. The plannersof the power system try to design reliable systems that areable to cope with probable contingencies. But even for thebest planned system, unpredictable events can stress thesystem beyond the planned limits. Some of the reasons whycompletely reliable operation cannot be achieved are thefollowing.

Manuscript received May 19, 2002; revised October 16, 2003.M. Begovic is with the School of Electrical and Computer Engineering,

Georgia Institute of Technology, Atlanta GA 30332-0250 USA (e-mail:[email protected]).

D. Novosel is with KEMA Inc., T&D Consulting, Raleigh NC 27607USA (e-mail: [email protected]).

D. Karlsson is with Gothia Power AB, Goteborg, Sweden (e-mail:[email protected]).

C. Henville is with Henville Consulting Inc., Delta, BC V4M 2N5,Canada (e-mail: [email protected]).

G. Michel is with Power System Consulting, Hialeah, FL 33013 USA(e-mail: [email protected]).

Digital Object Identifier 10.1109/JPROC.2005.847258

1) Practically an infinite number of possible oper-ating contingencies in modern, interconnected powersystems.

2) The evolving nature of power systems, generates un-predictable changes. Inevitably, the operation of thepower system is considerably different from the ex-pectation of the system designers, particularly duringan emergency. For example, deregulation provided fi-nancial motivation to transfer power from generation(e.g., independent power producers) to remote loads,As the existing power systems were not designed forthose transfers, additional stress is put on the system.

3) A combination of unusual and undesired events (forexample, human error combined with heavy weatherand scheduled or unscheduled maintenance outages ofthe important system element).

4) Reliability design philosophy that is pushing thesystem close to the limits brought about by economicand environmental pressures.

While reliability is the concern of system designers, oper-ators deal with system security. Security is an online, opera-tional characteristic which describes the ability of the powersystem to withstand different contingencies without serviceinterruptions. Security is closely related to reliability: an un-reliable system cannot be secure. The security level of thepower system (desired to be high enough to enable robustoperation) changes dynamically as the power system opera-tion changes and depends on the factors outside the controlof power system operators (e.g., weather).

The trend in power system planning utilizes tight oper-ating margins, with less redundancy, because of new con-straints placed by economical and environmental factors. Atthe same time, addition of nonutility generators and indepen-dent power producers, an interchange increase, an increas-ingly competitive environment, and introduction of flexibleac transmission (FACTS) devices make the power systemmore complex to operate and to control, and thus more vul-nerable to a disturbance. On the other hand, the advanced

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876 PROCEEDINGS OF THE IEEE, VOL. 93, NO. 5, MAY 2005

measurement and communication technology in wide-areamonitoring and control, FACTS devices (better tools to con-trol the disturbance), and new paradigms (fuzzy logic andneural networks) may provide better ways to detect and con-trol an emergency.

The modern energy management system (EMS) is sup-ported by supervisory control and data acquisition (SCADA)software; by numerous power system analysis tools such asstate estimation, power flow, optimal power flow, securityanalysis, transient stability analysis, midterm to long-termstability analysis; and by such optimization techniques aslinear and nonlinear programming. The available time forrunning these application programs is the limiting factor inapplying these tools in real time during an emergency, and atradeoff with accuracy is required. The real-time optimiza-tion software and security assessment and enhancementsoftware do not include dynamics. Further, propagation of amajor disturbance is difficult to incorporate into a suitablenumerical algorithm, and heuristic procedures may be re-quired. For example, unexpected hidden failures in relayingequipment may cause unexpected multiple contingencies.The experienced and well-trained operator can recognize thesituation and react properly given sufficient time, but oftennot reliably or quickly enough.

In modern interconnected networks, a fast-developingemergency may comprise a wide area. Since operator re-sponse may be too slow and inconsistent, fast automaticactions are implemented to minimize the impact of thedisturbance. These automatic actions may use local or cen-tralized intelligence, or a combination of both.

Currently, the local automatic actions are conservative,act independently from central control, and the prevailingstate of the whole affected area is not considered. Ac-tions incorporating centralized intelligence are limited tothe information anticipated to be relevant during foreseencontingencies. There are few schemes that are adaptiveto intelligence gathered from a wide area that respond tounforeseen disturbances or scenarios.

Furthermore, future power systems will encounter newcomponents (energy storage, load control, and solar power),new systems (FACTS elements and HVdc integration), aswell as regulatory changes (wheeling of power, nonutilitygenerators). An intelligent and adaptive control and protec-tion system for wide-area disturbance is needed to makepossible full utilization of the power network, which will beless vulnerable to a major disturbance.

Historically, only centralized control was able to applysophisticated analysis because only at this higher levelcould computers and communication support be technicallyand economically justified. However, with the increasedavailability of sophisticated computer, communication andmeasurement technologies, more intelligence can now beused at a local level. The possibility to close the gap betweencentral and local decisions and actions will depend on thedegree of intelligence put in the local subsystems. Decentral-ized subsystems that can make local decisions based on localmeasurements and remote information (system-wide dataand emergency control policies) and/or send preprocessed

information to higher hierarchical levels are an economicalsolution to the problem. A major component of system-widedisturbance protection is the ability to receive system-wideinformation and commands via the data communicationsystem and to send selected local information to the SCADAcenter. This information should reflect the prevailing stateof the power system.

II. DISTURBANCES: CAUSES AND REMEDIAL MEASURES

Phenomena that create wide-area power system dis-turbances are divided, among others, into the followingcategories: angular stability, voltage stability, overloads,power system cascading, etc. They are fought against usinga variety of protective relaying and emergency controlmeasures.

The angular instability, or loss of synchronism, conditionoccurs when generators in one part of the network acceleratewhile other generators somewhere else decelerate, therebycreating a situation where the system is likely to separateinto two parts. The conventional relaying approach for de-tecting loss of synchronism is by analyzing the variation inthe apparent impedance as viewed at a line or generator ter-minals. Following a disturbance, this impedance will vary asa function of the system voltages and the angular separationbetween the systems. Out of step, pole slip, or just loss of syn-chronism are equivalent designations for the condition wherethe impedance locus travels through the generator. When theimpedance goes through the transmission line the phenom-enon is also known as power swing. However, all of themrefer to the same event: loss of synchronism.

Out-of-step protection as it is applied to generators andsystems has the objective to eliminate the possibility ofdamage to generators as a result of an out-of-step condition.In case the power system separation is imminent, it shouldtake place along boundaries, which will form islands withmatching load and generation. Distance relays are oftenused to provide an out-of-step protection function, wherebythey are called upon to provide blocking or tripping signalsupon detecting an out-of-step condition.

The most common predictive scheme to combat loss ofsynchronism is the equal-area criterion and its variations.This method assumes that the power system behaves like atwo-machine model where one area oscillates against the restof the system. Whenever the underlying assumption holdstrue, the method has potential for fast detection.

Voltage stability [20]–[27] is defined by the SystemDynamic Performance Subcommittee of the IEEE PowerSystem Engineering Committee [29] as the ability of asystem to maintain voltage such that when load admittanceis increased, load power will increase, and so that bothpower and voltage are controllable. Also, voltage collapseis defined as being the process by which voltage instabilityleads to a very low voltage profile in a significant part of thesystem.

It is accepted that this instability is caused by the loadcharacteristics, as opposed to the angular instability, whichis caused by the rotor dynamics of generators.

BEGOVIC et al.: WIDE-AREA PROTECTION AND EMERGENCY CONTROL 877

The risk of voltage instability increases as the transmis-sion system becomes more heavily loaded [17], [18]. Thetypical scenario of these instabilities starts with a high systemloading, followed by a relay action due to either a fault, a lineoverload or hitting an excitation limit.

Voltage instability can be alleviated by a combination ofthe following remedial measures means: adding reactivecompensation near load centers, strengthening the transmis-sion lines, varying the operating conditions such as voltageprofile and generation dispatch, coordinating relays and con-trols, and load shedding. Most utilities rely on planning andoperation studies to guard against voltage instability. Manyutilities utilize localized voltage measurements in order toachieve load shedding as a measure against incipient voltageinstability [2], [41], [42].

Overloads frequently occur during wide-area distur-bances due to the increasingly high utilization of equipmentcapability. These overloads may result in faults (such aslines sagging into trees) or equipment damage if overloadprotection is not provided. On the other hand, overloadssometimes result in premature removal of equipment dueto short-circuit protection relays that do not allow the fullshort-time overload capability of the equipment to be uti-lized. Overloads are counteracted by applying monitoringand protection equipment that model the primary equipmentthermal capability given precontingency loading, ambienttemperature conditions, and other influencing factors. Formoderate overloads, the monitoring equipment allows oper-ators to take action to relieve the overload before equipmentdamage. For severe overloads, protection equipment couldbe applied to initiate controlled curative actions such astransmission reconfiguration or load shedding before theequipment becomes damaged.

Outage of one or more power system elements due to theoverload may result in overload of other elements in thesystem. If the overload is not alleviated in time, the processof power system cascading may start, leading to powersystem separation. Uncontrolled separation often occurs asa result of transmission line short-circuit protection systemsinterpreting power swings as short circuits. Controlled sepa-ration can be initiated by a special protection system (SPS)or out-of-step relaying.

When a power system separates, islands with an imbalancebetween generation and load are formed with a consequenceof frequency deviation from the nominal value. If the imbal-ance cannot be handled by the generators, load or generationshedding is necessary. A quick, simple, and reliable way toreestablish active power balance is to shed load by underfre-quency relays. There are a large variety of practices in de-signing load-shedding schemes based on the characteristicsof a particular system and the utility practices [3], [4].

While the system frequency is a final result of the powerdeficiency, the rate of change of frequency is an instanta-neous indicator of power deficiency and can enable incipientrecognition of the power imbalance. However, change of themachine speed is oscillatory by nature, due to the interactionamong generators. These oscillations depend on location ofthe sensors in the island and the response of the generators.

The issues and recommendation regarding the rate-of-changeof frequency function are as follows [5].

• A smaller system inertia causes a larger peak-to-peakvalue for rate-of-change of frequency oscillations.Large oscillations require that a rate-of-change offrequency relay needs sufficient time to reliably deter-mine the actual rate-of-change of frequency. Althoughas system inertia decreases a frequency of oscillationsincreases (enabling relays to faster detect averagevalue), it may still take too long to accurately detecta rate-of-change value. One example showed thatoscillations with Hz s peak-to-peak value havea frequency of oscillations of Hz ( s).Measurements at load buses close to the electricalcenter of the system are less susceptible to oscillations(smaller peak-to-peak values) and can be used inpractical applications.

• Even if rate of change of frequency relays measurethe average value throughout the network, it is diffi-cult to set them properly, unless typical system bound-aries and power imbalance can be predicted. If this isthe case (e.g., industrial and urban systems), the rate ofchange of frequency relays may improve a load-shed-ding scheme (the scheme can be more selective and/orfaster).

• Adaptive settings of frequency and frequency deriva-tive relays, based on actual system conditions, mayenable more effective and reliable implementation ofload-shedding schemes.

III. RELAY HIDDEN FAILURES

Failures or malfunctions in various protection systemsare very significant factor in the overall process of reportedwide-area disturbances. Of all the protection system fail-ures, the ones that remain dormant or hidden until someunusual system events occur are the most important [34],[35]. The abnormal power system states are usually due tofaults, heavy load, shortages in reactive power, etc. Theycan trigger the hidden failures to cause relay malfunction,which can worsen the situation, since the power systemsmay already be operated in an emergency state when thoseabnormal states occur, eventually leading to the wide-areadisturbances. Commonly used transmission relaying sys-tems have been studied to identify possible hidden failuresand their consequences on the power systems. A conceptof region of vulnerability associated with each mode ofhidden failure has been proposed. It is the region in whichthe hidden failure can cause a relay to incorrectly trip itsassociated circuit breaker. The relative importance of eachregion of vulnerability, called the vulnerability index, can becomputed using steady-state and transient stability criteria.A larger value of the vulnerability index indicates that therelay in which if that hidden failure mode exists is relativelymore important and can cause more serious wide-area distur-bances or has a higher possibility to cause the disturbancesthan the one with a smaller index. Therefore, more attention


should be paid to those key relays to prevent the hiddenfailure and its consequences.

It has been observed that of all the reported cases ofmajor system blackouts (wide-area disturbances) in NorthAmerica, about 70% of the cases have relay system con-tributing to the initiation or evolution of the disturbance. Oncloser examination, it became clear that one of the majorcomponents of relay system misoperations is the presenceof relays which have failed during service, and their failureis not known. Consequently, there is no alarm, and norepairs or replacements are possible. These hidden failuresare different from straight relay misoperations, or failureswhich lead to an immediate trip. The hidden failures remainundetected (and substantially undetectable), until the powersystem becomes stressed, leading to an operating conditionwhich exposes the hidden relay failures.

IV. TECHNOLOGY ISSUES IN WIDE-AREA PROTECTION

A. Monitoring and Protection for Wide-Area Disturbances

The disturbance in the power system usually developsgradually; however, some phenomena, such as transient in-stability, can develop in a fraction of a second. Regardless ofthe phenomena and available measures, any protection/con-trol procedure during an emergency should consist of thefollowing elements: identification and prediction, classifica-tion, decisions and actions, coordination, corrections, andtime scale.

V. AVAILABLE ACTIONS

The corrective and emergency actions are limited to afinite number of measures. A detailed description of thesemeasures will be provided as implementation issues fordifferent types of disturbances are analyzed. A set of avail-able measures includes out-of-step relaying, load shedding,controlled power system separation, generation dropping,fault clearing, fast turbine valving, FACTS control, dy-namic braking, generator voltage control, capacitor/reactorswitching and static VAR compensation, load control, su-pervision and control of key protection systems, voltagereduction, phase shifting, tie line rescheduling, reserve in-creasing, generation shifting, HVdc power modulation, etc.

As an emergency progresses and the state of the systemdegrades, less desirable measures may become necessary.All the above measures are suitable during in extremis crisis.However, “last resort” measures are acceptable only in an un-avoidable transition to in extremis crisis. Alternatively, pre-ventive measures, are usually only measures suitable in analert state.

The above measures are implemented in the emergencyprocedures for the power system. Every system has its ownemergency control practices and operating procedures de-pendent on the different operating conditions, characteristicsof the system, and engineering judgment. In other words, theoperating procedure for every system is unique and heuristicprocedures are extensively used, although the set of measuresis the same.

State of the system parameters and sensitivity of thesystem to certain measure are the factors that influence thechoice of the measure. Any one of the measures mentionedabove is usually helpful for different problems, havingdirect or indirect influence. From the problem perspective,different measures can help to overcome different problemswith some degree of sensitivity. Another important aspect inimplementing control actions is optimization with respect tosecurity and costs. For example, such a coarse measure asload shedding need not be executed if generation shifting issatisfactory (regarding speed and amount) in relieving over-loaded lines. Further, even when load shedding is necessaryto help alleviate overloads, less load is required to be shedif it can be determined that there is a generation shiftingcapability. Thus, appropriate coordination can optimizeactions.

A major component of adaptive protection systems is theirability to adapt to changing system conditions. Thus, relayswhich are going to participate in wide-area disturbance pro-tection and control must of necessity be adaptive. At thevery minimum, this implies a relay system design which al-lows for communication links with the outside world. Thecommunication links must be secure, and the possibility oftheir failure must be allowed for in the design of the adaptiverelays.

VI. TECHNOLOGY INFRASTRUCTURE

A. Phasor Measurement Technology

The technology of synchronized phasor measurements[38] is well established. It provides an ideal measurementsystem with which to monitor and control a power system,in particular during conditions of stress. A number of pub-lications are available on the subject. The essential featureof the technique is that it measures positive sequence (andnegative and zero sequence quantities, if needed) voltagesand currents of a power system in real time with precisetime synchronization. This allows accurate comparison ofmeasurements over widely separated locations as well aspotential real-time measurement based control actions. Veryfast recursive discrete Fourier transform (DFT) calculationsare normally used in phasor calculations.

The synchronization is achieved through a global posi-tioning satellite (GPS) system. GPS is a U.S. governmentsponsored program that provides worldwide position andtime broadcasts free of charge. It can provide continuousprecise timing at better than the 1-ms level. It is possible touse other synchronization signals, if these become availablein the future, provided that a sufficient accuracy of synchro-nization could be maintained. Local proprietary systems canbe used, such as a sync signal broadcast over microwaveor fiber optics. Two other precise positioning systems,GLONASS, a Russian system, and Galileo, a proposedEuropean system, are also capable of providing precise time.

Fig. 1 shows a typical synchronized phasor measurementsystem configuration. The GPS transmission is received bythe receiver section, which delivers a phase-locked samplingclock pulse to the analog-to-digital converter system. The


Fig. 1. Block diagram of the synchronized phasor measurement system (PMU).

sampled data are converted to a complex number which rep-resents the phasor of the sampled waveform. Phasors of thethree phases are combined to produce the positive sequencemeasurement.

Any computer-based relay which uses sampled data iscapable of developing the positive sequence measurement.By using an externally derived synchronizing pulse, suchas from a GPS receiver, the measurement could be placedon a common time reference. Thus, potentially all com-puter based relays could furnish the synchronized phasormeasurement. When currents are measured in this fashion,it is important to have a high enough resolution in theanalog-to-digital converter to achieve sufficient accuracy ofrepresentation at light loads. A 16-b converter (either a true16-b or a dynamic ranging converter with equivalent 16-bresolution) generally provides adequate resolution to readlight load currents, as well as fault currents.

For the most effective use of phasor measurements, somekind of a data concentrator is required. The simplest is asystem that will retrieve files recorded at the measurementsite and then correlate files from different sites by therecording time stamps. This allows doing system and eventanalysis utilizing the preciseness of phasor measurement.For real-time applications, from soft real time for SCADAto hard real time for response-based controls, continuousdata acquisition is required.

Several data concentrators have been implemented, in-cluding the phasor data concentrator (PDC) at the BonnevillePower Administration. This unit inputs phasor measurementdata broadcast from up to 32 PMUs at up to 60 measure-ments/s, and performs data checks, records disturbances,and rebroadcasts the combined data stream to other monitorand control applications. This type of unit fulfills the needfor both hard and soft real time applications as well assaving data for system analysis. Tests performed using thisPMU-PDC technology on the BPA and Southern CaliforniaEdison (SCE) systems have shown the time intervals frommeasurement to data availability at a central controller canbe as fast as 60 ms for a direct link and 200 ms for secondarylinks. These times meet the requirements for many types ofwide-area controls.

A broader effort is the Wide-Area Measurement System(WAMS) concept explored by the U.S. Department of En-ergy and several utility participants. WAMS includes alltypes of measurements that can be useful for system analysisover the wide area of an interconnected system. Real-timeperformance is not required for this type of application, but

is no disadvantage. The main elements are timetags withenough precision to unambiguously correlate data from mul-tiple sources and the ability to convert all data to a commonformat. Accuracy and timely access to data is importantas well. Certainly with its system-wide scope and precisetimetags, phasor measurements are a prime candidate forWAMS.

VII. COMMUNICATION TECHNOLOGY

Communications systems are a vital component of a wide-area relay system. These systems distribute and manage theinformation needed for operation of the wide-area relay andcontrol system. However, because of potential loss of com-munication, the relay system must be designed to detect andtolerate failures in the communication system. It is impor-tant also that the relay and communication systems be inde-pendent and subject as little as possible to the same failuremodes. This has been a serious source of problems in thepast.

To meet these difficult requirements, the communicationsnetwork will need to be designed for fast, robust, and reliableoperation. Among the most important factors to consider inachieving these objectives are type and topology of the com-munications network, communications protocols, and mediaused. These factors will in turn effect communication systembandwidth, usually expressed in bits per second (BPS), la-tency in data transmission, reliability, and communicationerror handling.

Currently, electrical utilities use a combination of analogand digital communications systems for their operations con-sisting of power line carrier, radio, microwave, leased phonelines, satellite systems, and fiber optics. Each of these sys-tems has applications where it is the best solution. The ad-vantages and disadvantages of each are briefly summarizedin the following paragraph.

Several types of communication protocols are used withoptical systems. Two of the most common are synchronousoptical networks (Sonet/SDH) and the asynchronous transfermode (ATM). Wide-band Ethernet is also gaining popularity,but is not often used for backbone systems. Sonet systems arechannel oriented, where each channel has a time slot whetherit is needed or not. If there is no data for a particular channelat a particular time, the system just stuffs in a null packet.ATM by contrast puts data on the system as it arrives inprivate packets. Channels are reconstructed from packets asthey come through. It is more efficient, as there are no nullpackets sent, but has the overhead of prioritizing packets and


Fig. 2. Architecture of SONET communication network.

sorting them. Each system has different system managementoptions for coping with problems.

Synchronous optical networks are well established inelectrical utilities throughout the world and are availableunder two similar standards: 1) Sonet is the Americansystem under ANSI T1.105 and Bellcore GR Standards,and 2) Synchronous Digital Hierarchy (SDH) under theInternational Telecommunications Union (ITU) standards.

The transmission rates of Sonet systems are de-fined as Optical Carrier (OC ); withOC Mb/s and OC Gb/s. Availablein the market and specially designed to meet the electricalutility environment are Sonet systems with bit rates ofOC Mb/s and OC Mb/s.

Sonet and SDH networks are based on a ring topology(Fig. 2) [12], [13]. This topology is a bidirectional ring witheach node capable of sending data either direction; data cantravel either direction around the ring to connect any twonodes. If the ring is broken at any point, the nodes detectwhere the break is relative to the other nodes and automat-ically reverse transmission direction if necessary. A typicalnetwork, however, may consist of a mix of tree, ring, andmesh topologies rather than strictly rings with only the mainbackbone being rings.

Self healing (or survivability) capability is a distinctivefeature of Sonet/SDH networks made possible because it isring topology. This means that if communication betweentwo nodes is lost, the traffic among them switches over tothe protected path of the ring. This switching to the pro-tected path is made as fast as 4 ms, perfectly acceptable toany wide-area protection and control.

Communication protocols are an intrinsic part of moderndigital communications. The most popular protocols foundin the electrical utility environment and suitable for wide-area relaying and control are the distributed network pro-tocol (DNP), Modbus, International Electrotechnical Com-mission Standard IEC870-5, and the Electric Power ResearchInstitute (EPRI) universal communications architecture/mul-tiple messaging system (UCA/MMS). TCP/IP is probablythe most extensively used protocol and will undoubtedly findapplications in wide-area relaying.

UCA/MMS protocol is the result of an effort betweenutilities and vendors (coordinated by EPRI). It addresses allcommunication needs of an electric utility. Of particular in-terest is its “peer-to-peer” communications capabilities thatallows any node to exchange real time control signals withany other node in a wide-area network. DNP and Modbusare also real-time type protocols suitable for relay applica-tions. TCP on Ethernet lacks a real-time type requirement,but over a system with low traffic performs as well as theother protocols. Other slower speed protocols like the InterControl Center Protocol (ICCP) (in America) or TASEII(in Europe) handle higher level but slower applications likeSCADA. Many other protocols are available but are notcommonly used in the utility industry.

VIII. REMEDIAL ACTIONS AGAINST WIDE-AREA

DISTURBANCES

A. SPSs

The following definition of an SPS comes from a NorthAmerican electric Reliability Council (NERC) planningstandard [31]: “A special protection system (SPS) or reme-dial action scheme (RAS) is designed to detect abnormalsystem conditions and take preplanned, corrective action(other than the isolation of faulted elements) to provideacceptable system performance.” Note that this definitionspecifically excludes the performance of protective systemsto detect faults or remove faulted elements. It is system ori-ented both in its inception and in its corrective action. Suchaction includes, among others, changes in demand (e.g., loadshedding), changes in generation or system configuration tomaintain system stability or integrity and specific actions tomaintain or restore acceptable voltage levels. One designparameter that sets these schemes apart is that many ofthem are “armed” and “disarmed” in response to systemconditions. For example, a watchdog type of scheme may berequired and armed at high load levels, but not at lower loadlevels. Some SPSs are armed automatically by the systemcontrol center computer, others require human operatoraction or approval, others are manually operated, and someare armed all the time [1], [11].


NERC further defines the standards to which an SPS shalladhere. In part, they are as follows.

• A SPS shall be designed so that cascading transmissionoutages or system instability do not occur for failureof a single component of a SPS which would result infailure of the SPS to operate when required.

• All SPS installations shall be coordinated with othersystem protection and control schemes.

• All SPS operations shall be analyzed for correctnessand documented.

Reference [1] reports on the experience of 111 SPSs and liststhe most common schemes being used as follows:

• generator rejection;• load rejection;• underfrequency load shedding [7], [8];• undervoltage load shedding;• system separation;• turbine valve control [6];• stabilizers [14];• load and generator rejection;• HVdc controls;• out-of step relaying [9], [10];• dynamic braking;• discrete excitation control;• generator runback;• VAR compensation;• combination of schemes;• others.

The popularity of the three schemes at the beginning of theabove list is not surprising. The fundamental cause of wide-area outages, almost by definition, is the unbalance betweengeneration and load following the loss of a line or gener-ator due to correct operation following a fault or incorrectoperation by human error, hidden failure, etc. Therefore, anSPS seeks to correct this unbalance by removing load or in-creasing generation. In this survey, a distinction was madebetween direct load rejection, i.e., removing preplanned cus-tomers through controls, and automatic underfrequency loadrejection if the unbalance results in decreasing frequency.The underfrequency tripping of load may not be consideredby everyone as an SPS, since it is installed by many utilitiesas a normal protective measure.

An increasingly popular SPS is the separation of thesystem into independent islands, leaving the faulted area tofend for itself, thus greatly reducing the impact of an outage.The use of the GPS to synchronize relays across the systemand adaptive digital relays makes this scenario particularlyattractive. The challenge lies in identification of key pa-rameters and settings that define the boundary between twoalternatives. Should the regions be kept interconnected toprovide support or separated to prevent a nonviable systemcondition from expanding? It is to answer this question thatsystem analysts and protection and communications engi-neers need to work together to develop robust, adaptive, andreliable SPS using advanced techniques to provide optimumsolutions.

The concept of out-of-step relaying has been known forsome time. However, the specific setting philosophy hasbeen a major problem in applying it. As noted in the discus-sion of the French EDF DRS and Syclopes schemes later inthis paper, there are significant limitations and difficulties inusing and setting out-of-step relaying to separate unstableinterconnected regions in a wide area with widely varyingoperating conditions.

Combining all of the schemes applied to the turbine gen-erator has become feasible by the introduction of reliableand fast-acting electronics. Fast valving and dynamic brakingare particularly noteworthy as methods to reduce generatoroutput without removing the unit from service and thus al-lowing for rapid restoration.

The reliability of SPS was addressed in [1] and indicatesthat the equipment and schemes perform very similarly totraditional protective schemes. System conditions requiringaction does not occur often, but when it does occur, the SPSusually performs its function correctly. The most commonfailure (43% of those responding) was hardware failures withhuman failure (20%) next. Inadequate design accounted forabout 12% of the failures and incorrect setting less than 10%.

In this section, all possible protective actions against wide-area disturbances that we have been able to find during thework have been listed, commented, and evaluated. The dis-cussion has mainly dealt with curative actions.

IX. TRENDS AND ARCHITECTURES IN

WIDE-AREA PROTECTION

The meaning of wide-area protection, emergency con-trol, and power system optimization may vary dependanton people, utility, and part of the world. Therefore, stan-dardized and accepted terminology is important. Since therequirements for a wide-area protection system vary fromone utility to another, the architecture for such a system mustbe designed according to what technologies the utility pos-sesses at the given time. Also, to avoid becoming obsolete,the design must be chosen to fit the technology migrationpath that the utility in question will take. The solutionto counteract the same physical phenomenon might varyextensively for different applications and utility conditions.

The potential to improve power system performanceusing smart wide-area protection and control, and even deferhigh voltage equipment installations, seems to be great.The introduction of the phasor measurement unit (PMU)has greatly improved the observability of the power systemdynamics. Based on PMUs different kinds of wide-areaprotection, emergency control and optimization systems canbe designed. A great deal of engineering, such as powersystem studies and configuration and parameter settings,is required, since every wide-area protection installation isunique. Sometimes, the enhancements are obtained usingheuristic methods, such as fuzzy logic or neural networks[15], [16], [28], [30], [32], [33]. A cost effective solutioncould be based on standard products and standard systemdesigns.


Fig. 3. Multilayered network of GPS-synchronized PMUs, connected through LPCs and an SPC.

Tailor-made wide-area protection systems against largedisturbances, designed to improve power system reliabilityand/or to increase the transmission capacity, will thereforemost likely be common in the future. These systems will bebased on reliable high-speed communication and extremelyflexible protection devices, where power system engineeringwill become an integrated part of the final solution. Thistype of high-performance protection schemes will also beable to communicate with traditional SCADA systems toimprove functions like demand side management (DSM),distribution automation (DA), EMS, and state estimation.

As the electricity market is restructured all around theworld, the nature of utility companies is changed. In par-ticular, the downsizing of the staff makes it difficult orimpossible for the utility to perform many R&D functions.As a result, there is a trend in the industry where utilitiescollaborate with vendors to cope with issues related to thegrid. The utility can view its partnering vendor as a sub-stitute for its vanishing R&D department to perform tasksthat its existing staff cannot handle. The vendor sees thepartnering utility as the “sounding board” for its productdevelopment and the place to demonstrate its latest products.This closed-loop collaboration, which already exists in theform of pilot projects in wide-area protection, is found to befruitful to both parties.

A. Enhancements to SCADA/EMS

At one end of the spectrum, enhancements to the existingEMS/SCADA can be made. These enhancements are aimedat two key areas: information availability and informationinterpretation. Simply put, if the operator has all vital infor-mation at his fingertips and good analysis facilities, he canoperate the grid in an efficient way. For example, with better

analysis tool for voltage instability, the operator can accu-rately track the power margin across an interface, and thuscan confidently push the limit of transfer across an interface.

SCADA/EMS system capability has greatly improvedduring the last years, due to improved communication fa-cilities and highly extended data handling capability. Newtransducers such as PMUs can provide time-synchronizedmeasurements from all over the grid. Based on these mea-surements, improved state estimators can be derived.

Major problems during fast-developing disturbancesoccur due to:

• alarm bursts, as operator is not able to filter and analyzeimportant signals;

• unavailability of critical functions.Improved EMS/SCADA systems would require ability tofilter, display, and analyze only critical information and toincrease availability of critical functions to 99.99%.

Advanced algorithms and calculation programs that as-sist the operator can also be included in the SCADA system,such as “faster than real-time simulations” to calculate powertransfer margins based on contingencies.

The possibilities of extending the SCADA/EMS systemwith new functions tend to be limited. Therefore, it might berelevant to provide new SCADA/EMS functions as “standalone” solutions, more or less independent of the ordinarySCADA/EMS system. Such functions could be load shed-ding, due to lack of generation or due to market price.

B. Multilayered Architecture

A comprehensive solution, that integrates the two controldomains, protection devices and EMS, can be designed asin Fig. 3. There are up to three layers in this architecture.The bottom layer is made up of PMUs, or PMUs with ad-ditional protection functionality. The next layer up consists


Fig. 4. WAMS design.

of several local protection centers (LPCs), each of which in-terfaces directly with a number of PMUs. The top layer, thesystem protection center (SPC), acts as the coordinator forthe LPCs. Designing the three-layered architecture can takeplace in several steps. The first step should aim at achievingthe monitoring capability, e.g., a WAMS. WAMS is the mostcommon application, based on PMUs. These systems aremost frequent in North America, but are emerging all aroundthe world. The main purpose is to improve state estimation,postfault analysis, and operator information. In WAMS ap-plications a number of PMUs are connected to a data con-centrator, which basically is a mass storage, accessible fromthe control center, according to Fig. 4.

Starting from a WAMS design, a data concentrator can beturned into a hub-based LPC by implementing control andprotection functions in the data concentrator. A number ofsuch LPCs can then be integrated into a larger system widesolution with an SPC at the top. With this solution, the LPCforms a system protection scheme (SPS), while the intercon-nected coordinated system forms a defense plan.

C. “Flat Architecture” With System Protection Terminals

Protection devices or terminals are traditionally used inprotecting equipment (lines, transformers, etc.). Modernprotection devices have sufficient computing and commu-nication capabilities to be capable of performing beyondthe traditional functions. When connected together viacommunications links, these devices can process intelligentalgorithms based on data collected locally or shared withother devices.

Powerful, reliable, sensitive, and robust, wide-area protec-tion systems can be designed based on decentralized, espe-cially developed interconnected system protection terminals.These terminals are installed in substations, where actionsare to be made or measurements are to be taken. Actionsare preferably local, i.e., transfer trips should be minimized,to increase security. Relevant power system variable data is

transferred through the communication system that ties theterminals together. Different schemes, e.g., against voltageinstability and against frequency instability, can be imple-mented in the same hardware.

Using the communication system, between the terminals, avery sensitive system can be designed. If the communicationis partially or totally lost, actions can still be taken based onlocal criteria (fallback performance is not worse than withconventional local relaying). Different load-shedding stepsthat take the power system response into account—in ordernot to overshed—can easily be designed.

Based on time-synchronized measurements of voltage andcurrent by PMUs at different locations in the network, real-time values of angle differences in the system can be de-rived with a high accuracy. With this new type of real-timemeasurements, efficient emergency actions, such as PSS con-trol, based on system-wide data, load shedding, etc., can betaken to save the system stability in case of evolving poweroscillations.

D. System Protection Terminal

Traditionally, remedial action schemes have been hubbased, i.e., all measurements and indicators are sent to acentral position, e.g., a control center, for evaluation anddecision. From this central position, action orders are thensent to different parts of the power system. Such a central-ized system is very sensitive to disturbances in the centralpart. With the ring-based (or WAN) communication system,a more robust system can be achieved. One communica-tion channel can, for example, be lost without any loss offunctionality. If one system protection terminal fails in aflat decentralized solution, a sufficient level of redundancycan be implemented in the neighboring terminals. In othertechnological areas the decision power is moving closerto the process, with increasingly more powerful sensorsand actuators, for decisions based on rather simple criteria.Such an independent SPS, based on powerful terminals, can


Fig. 5. System protection terminal, design, and interfaces.

also serve as a backup supervision system that supplies theoperator with the most critical power system data, in case ofa SCADA system failure.

The system protection terminal will probably be designedfrom a protection terminal to fulfill all requirements con-cerning mechanical, thermal, EMC, and other environmentalrequirements for protection terminals. Design and interfacesof a system protection terminal are shown in Fig. 5.

The terminal is connected to the substation control system,CTs, and VTs as any other protection terminal. For applica-tions that include phasors, i.e., phase angles for voltages orcurrents, a GPS antenna and synchronization functions arealso required. The system protection terminal comprises ahigh-speed communication interface to communicate powersystem data between the terminal databases. In the database,all measurements and binary signals recorded in that specificsubstation are stored and updated, together with data from theother terminals, used for actions in the present terminal. Theordinary substation control system is used for the input andoutput interfaces toward the power system process. The deci-sion making logic contains all the algorithms and configuredlogic necessary to derive appropriate output control signals,such as circuit-breaker trip, AVR-boosting, and tap-changeraction, to be performed in that substation. The input data tothe decision-making logic is taken from the database andreflects the overall power system conditions. A low-speedcommunication interface for SCADA communication andoperator interface should also be available. Via this interface,

phasors can be sent to the SCADA state estimator for im-proved state estimation. Any other value or status indicatorfrom the database could also be sent to the SCADA system.Actions ordered from SCADA/EMS functions, such as op-timal power flow, emergency load control, etc., could be ac-tivated via the system protection terminal. The power systemoperator should also have access to the terminal, for supervi-sion, maintenance, update, parameter setting, change of set-ting groups, disturbance recorder data collection, etc.

It can be concluded that there is a the great potentialfor wide-area protection and control systems, based onpowerful, flexible, and reliable system protection terminals,high-speed, communication, and GPS synchronization inconjunction with careful and skilled engineering by powersystem analysts and protection engineers in cooperation.

X. EXAMPLES OF WIDE-AREA PROTECTION SYSTEMS

In this section, a small number of wide-area protection sys-tems will be described.

A. Protection Against Voltage Collapse in theHydro-Québec System

The Hydro-Québec system is characterized by longdistances (up to 1000 km) between the northern main gen-eration centers and the southern main load area. The peakload is around 35 000 MW. The long EHV transmissionlines have high series reactances and shunt susceptances. At


Fig. 6. SCADA system network protection logic in the Swedish system.

low power transfers, the reactive power generation of EHVlines is compensated by connecting 330 Mvar shunt reactorsat the 735-kV substations. At peak load, most of the shuntreactors are disconnected while voltage control on the lowerside of transformers implies connection of shunt capacitors.Both effects contribute to a very capacitive characteristic ofthe system.

Automatic shunt reactor tripping was implemented in1990, providing an additional 2300-Mvar support near theload centers. The switching is triggered by low 735-kV busvoltages or high compensator reactive power productions.Another emergency control used is the automatic increase involtage set-points of shuntC capacitors.

B. SPS Against Voltage Collapse in Southern Sweden

The objective of the SPS is to avoid a voltage collapseafter a severe fault in a stressed operation situation. Thesystem can be used to increase the power transfer limitsfrom the north of Sweden or to increase the system securityor to a mixture of both increased transfer capability andincreased security. The SPS was commissioned in 1996.The system is designed to be in continuous operation andindependent of system operation conditions such as loaddispatch, switching state, etc. A number of indicators suchas low voltage level, high reactive power generation, andgenerator current limiters hitting limits are used as inputs toa logical decision-making process implemented in the Syd-kraft SCADA system. Local actions are then ordered fromthe SCADA system, such as switching of shunt reactors andshunt capacitors, start of gas turbines, request for emergencypower from neighboring areas, disconnection of low-priorityload, and, finally, load shedding. Shedding of high-priorityload also requires a local low-voltage criterion in order toincrease security. The logic is shown in Fig. 6.

The SPS is designed to have a high security, speciallyfor the load-shedding, and a high dependability. Therefore,

a number of indicators are used to derive the criteria for eachaction.

C. Wide-Area Undervoltage Load Shedding (BCHydro System)

BC Hydro has developed an automatic load sheddingremedial action scheme to protect the system against voltagecollapse. The voltage collapse may be caused by a second ormultiple sequential contingencies such as the forced outageof a critical major transmission line while the system is al-ready weakened by another outage. A closed-loop feedbackscheme will monitor the system condition, determine theneed of load shedding, shed appropriate blocks of prese-lected loads in 10–120 s with sequential time delays, andstop when proper system voltage and dynamic VAr reservesare restored.

The scheme is based on a centralized feedback systemwhich continually assesses the entire system condition usingthe actual dynamic response of the system voltages at keybuses and dynamic var reserves of two large reactive powersources in the load area to identify impending voltage in-stability and then sheds predetermined loads in steps recur-sively until the potential for voltage collapse is eliminated.The use of both low voltage and low var reserve providesan added security against possible voltage measurement er-rors and allows higher than usual undervoltage settings toprotect against conditions where collapse starts at near nor-mally acceptable operating voltage levels. The key voltagebuses are selected based on their sufficiently high fault levelsand having multiple low-impedance connections to load cen-ters so that local system outages or var equipment operationswill not affect the voltages significantly to cause misopera-tion. The var sources are selected based on their large ca-pacity relative to the total load area dynamic var capacity.In addition, they must have multiple connections to the loadcenter so that their reserves can be reliably used to reflect the


system reserves. Since the low voltage and low var reserveoccur for system voltage instability irrespective of the cause,such as different line outages, major reactive support equip-ment outages, increased loading and intertie flows, trans-former tap movement, or shifted generation patterns, thisscheme will provide a safety net against voltage collapsefrom such causes.

D. Ontario Hydro System

A coordinated undervoltage protection scheme is em-ployed consisting of the following.

a) Short-time automatic reclosure on major 230-kV linessupplying areas with voltage collapse risk.

b) Automatic load shedding of different areas in two timesteps. If in reference substations, the voltage measure-ment gives voltage drops below a certain referencevalue, the areas are shed in 10 s.

c) Automatic capacitor switching for maximum reactivepower infeed and voltage support.

d) Automatic OLTC blocking.

E. F1orida Power and Light (FPL) Fast Acting LoadShedding (FALS)

FPL installed an FALS system to protect against severesystem overloads not covered by conventional underfre-quency load shedding in 1985 [36].

System planning studies revealed that the addition of two500-kV lines had strengthened connections to neighboringutilities so much that system separation could not be assuredunder certain double contingency losses of FPL generation.This meant that existing underfrequency load sheddingwould not operate to keep the system stable under thesedouble contingencies. Simultaneous loss of two or morelarge generators (with more than 1200 MW total output)could result in excessive power import into the state ofFlorida which could result in what was called a “stablebut overloaded” system condition. That condition wouldleave the systems intact (without separation) but with severethermal and reactive overloads which could lead to voltagecollapse and uncontrolled system separations after approxi-mately 30 s.

The FALS program runs in the system control center(SCC) computers in Miami, FL, and uses statewide SCADAcommunications to recognize a “stable system overload”that results in lines operating above their ratings, low systemvoltages at predetermined key substations, and heavy reac-tive power demands upon generators. When this condition isdetected, FALS initiates a trip signal to shed a predeterminedamount of load by tripping subtransmission lines at certainstations to prevent loss of bulk transmission lines and/orgenerators that could cause a blackout.

The FALS program is based on a six-by-six matrix ofalarm conditions of individually telemetered points. Eachmatrix cell shows (in order) the monitored point, the presentvalue and the alarm point setting. At least one point in eachrow must be in the alarm condition to set a flag for that row.All six rows must have their respective flag set to initiate a

load shed signal with no intentional delay. Load sheddingwithout delay is expected to occur within 20 s of a distur-bance that requires shedding. A delayed load shed is initiatedif four specific row flags are set and verified in the alarm con-dition for a specific time delay. The time delay is to allowoffline capacitor banks to switch in and mitigate those lesssevere overloads.

Each element in the matrix uses voltage or power mea-surements already available in the computer. Only onephase is monitored for voltage measurements, and two andone-half-element watt transducers are used for the powermeasurements.

The program must shed a minimum of 800 MW, indepen-dent of the system load. Since fewer transmission lines needto be shed at high loads to reject the 800 MW, the FALSprogram bases the number of lines to be shed on the currentsystem load.

To improve the security of the scheme, the FALS tripsignal received at each substation is supervised in a permis-sive mode by an underfrequency relay. These relays are setat 59.95 Hz, which will allow operation for most generationdisturbances in the state. The underfrequency relays’ outputsremain energized for 1 m to allow time for load shedding ifnecessary.

The matrix parameters are revised as the system changesso that the FALS program remains coordinated with thesystem response.

F. France, EDF: DRS Scheme Against Losses ofSynchronism

Principle of Operation: The French system can be de-composed in areas of dynamic coherence. When a loss ofsynchronism appears, all the units of the area lose synchro-nism together. Within these areas, generators are stronglyconnected to each other. Links between areas are weaker. Inthe case of loss of synchronism, tripping the faulted unitswith a pole slip relay protects the generator, but does not en-sure that the collapse will be completely stopped, especiallywhen the system is highly meshed. It is necessary to preventthe instability from propagating through the system, and thebest way to achieve it is to isolate the areas that have lostsynchronism so to rescue the system, before losses of syn-chronism are induced in other areas (neighboring or distant).

After several incidents in the 1970s, out-of-step relaysnamed “the DRS Plan” were installed at both ends of thelines crossing the borders of the dynamically coherent areas.Their aim is to open all the transmission lines borderingthe area so to isolate it. The out-of-step relay watches thevoltage locally, triggers when large voltage deviations aredetected (one of the effects of the loss of synchronism),and trips the line. The triggering criteria are the depth andthe number of swings. These criteria are set with the helpof simulation tools for each voltage level. This protectionscheme operates locally at only one voltage level and doesnot need communication with any other device.

The use of out-of-step relays implies that the distance re-lays of all lines do not trigger in the case of the loss of syn-chronism. Only the DRS schemes should trip the suitable


lines bordering the zones to avoid uncoordinated opening oflines. One solution that ensures that no unexpected line willtrip is to use out-of-step blocking scheme in the distance re-lays. The French system is divided into 19 areas, all equippedwith the DRS protective relays on the borderlines, includingthe lines connected to the systems of the neighboring coun-tries. These schemes have been in operation for more than15 years.

Limits of the Scheme: Even though it proved to be effi-cient, the out-of-step relay plan may lead to a nonoptimal is-landing of the faulted area. The potential weaknesses of theout-of-step relays scheme are inherent to its characteristics.

• The measurements are processed locally, whereas theloss of synchronism affects large areas.

• The voltage swings are only an effect of the loss ofsynchronism and is not the origin of it, which is angularinstability.

Suboptimal efficiency can be explained with the followingcriteria.

• Simultaneity: All the lines are not tripped simultane-ously, leading in some cases to delay the completedisolation of the unstable zone.

• Completion: Some lines may not be tripped, becausethe depth of the voltage swings stays under the criteriathreshold (for example if the relay is located at a nodeof swings) but they are still able to induce losses ofsynchronism.

• Selectivity: Consequently to the definition of thehomogeneous zones, when frequency instabilityoccurs, the largest swings are expected on the border-lines between two homogeneous areas. In multizoneprotection with out-of-step relays, the voltage swingsmay sometimes be observed in a wide area. As a result,unwanted or uncoordinated line tripping is possible.

G. France, EDF: Syclopes—Coordinated Scheme AgainstLosses of Synchronism

The advantages and weaknesses of the out-of-step relaysdefence plan (listed above) were highlighted by major con-tingencies in the early 1980s. System modeling and anal-ysis tools became available and allowed a more completeapproach.

To get accurate and quick information from the system, thescheme needs to come closer to the root of the instability: an-gular and frequency difference between two points. The bestway to get to it is to process the phasors of the generatorsof each homogeneous group of generators, and then to com-pare continuously the angle distance between the homoge-neous areas. This principle is used in the second generationof SPS against loss of synchronism developed by EDF, andcalled Syclopes (see Fig. 7). The functions that Syclopes re-alizes are:

• detection of the loss of synchronism;• tripping of all the lines bordering the homogeneous

areas that loses synchronism; and• order for load shedding if needed.

Fig. 7. Syclopes communication network diagram(PHM = Phase Measurements, AI = Area Islanding,LS = Load Shedding).

Fig. 8. Syclopes communication network.

The principle of operation of this new SPS is that the infor-mation of the whole power system is processed in one centralpoint, in a global and coordinated task:

• local measurements on the network are sent to the cen-tral point;

• information from the whole system is processed inthe central point computer, and the affected zone isdetected;

• the central point orders actions to local substations soto isolate the affected zone by opening all the borderlines of it; and

• if necessary, the central point orders actions to HV/MVsubstations for load shedding, so to prepare the activepower balance for the postislanding sequence and keepthe frequency within an acceptable range.

In the first step (see Fig. 8), Syclopes has been developed forthe isolation of two southeastern coherent areas in the Frenchsystem that were identified as critical toward the loss of syn-chronism. These areas are exporting large amounts of activepower and need loads to be shed most often when cut outfrom the rest of the system, to prevent induced loss of syn-chronism. When compared to the DRS plan, the coordinatedSPS Syclopes brings the following improvements.


• Phasor detection of the loss of synchronism is closerto the origin of the event and reduces the delay fordetection.

• Global processing gives selectivity and accuracy of theactions.

• Simultaneity and completion of the line trippingprocess with limited delay preserve the stability of thegenerators in remote areas.

• Simultaneity of the load shedding and the line trippingprocesses keep the rest of the system in a better state:higher frequency and robustness.

Every part of the SPS needs to be highly reliable and safeto guaranty that the probability of unwanted actions like linetripping or load shedding is acceptable and to ensure properaction in case of loss of synchronism, which includes:

• phasor measurements and local preprocessing;• information transmission to the central point;• real-time information process in central point;• order transmission; and• order application (line tripping, load shedding at

HV/MV substations).

Additionally, the speed of the phenomenon needs quick com-munication means for both ways (forth from local to the cen-tral point and back).

The SPS has been installed in two southeastern coherentareas and is currently operating in an open loop; that is to say,the action orders are locked. The closed loop operation wasstarted in the year 2000. In addition to the protection, the on-going operation in open loop provides information throughits synchronized phasor measurements. To achieve these re-quirements, a two-way communication network (wire/satel-lite) is used (see Fig. 8). Additional information is availablein [43]–[48]. Two other homogeneous areas are potential fu-ture application fields for the Syclopes-coordinated SPS.

XI. CONCLUSION

There are numerous existing applications of wide-areaprotection and control systems, and some examples havebeen described and discussed. Existing implementations usesimple measurements. Sometimes the measurements arelocal only (e.g., out-of-step tripping or underfrequency loadshedding). In other cases, the measurements and actions usewide-area information and communications systems. Themore complex decision processes (e.g., southern Sweden’sSPS against voltage collapse, and Florida’s FALS) employSCADA for information gathering that allows a time frameonly of several seconds for actions. Higher speed wide-areaprotection systems required to prevent angular instabilityor fast voltage collapse (e.g., direct load or generator rejec-tion), respond primarily to contingencies identified in offlineplanning studies, and are limited in effectiveness againstunforeseen disturbances.

Better detection and control strategies through the con-cept of advanced wide-area disturbance protection offer abetter management (than existing) of the disturbances andsignificant opportunity for more reliable system performanceunder higher power transfers and operating economies. This

advanced protection is a concept of using system-wide infor-mation together with distributed local intelligence and com-municating selected information between separate locationsto counteract propagation of the major disturbances in thepower system.

With the increased availability of sophisticated computer,communication and measurement technologies, more “intel-ligent” equipment can be used at the local level to improvethe overall emergency response. There seems to be a greatpotential for wide-area protection and control systems, basedon powerful, flexible and reliable system protection termi-nals, high speed, communication, and GPS synchronizationin conjunction with careful and skilled engineering by powersystem analysts and protection engineers in cooperation. Ad-ditional information about the topics presented in this papercan be found in the companion papers [49] and [50], authoredby the members of the Working Group “Wide Area Protec-tion and Emergency Control” of the IEEE PES Power SystemRelaying Committee.

ACKNOWLEDGMENT

The content presented here is based on the IEEEPower Engineering Society Power System RelayingCommittee Working Group report “Wide Area Protec-tion and Emergency Control,” which was authored byA. Apostolov, E. Baumgartner, B. Beckwith, M. Begovic(Chairman), S. Borlase, H. Candia, P. Crossley, J. De LaRee Lopez, T. Domin, O. Faucon (corresponding member),A. Girgis, F. Griffin, C. Henville, S. Horowitz, M. Ibrahim,D. Karlsson (Corresponding Member), M. Kezunovic,K. Martin, G. Michel, J. Murphy, K. Narendra, D. Novosel(Vice Chairman), T. Seegers, P. Solanics, J. Thorp, andD. Tziouvaras. Their contribution to this paper is gratefullyacknowledged.

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Miroslav M. Begovic (Fellow, IEEE) receivedthe Ph.D. degree in electrical engineering fromVirginia Polytechnic Institute, Blacksburg, in1989

He is a Professor with the School of Electricaland Computer Engineering, Georgia Instituteof Technology, Atlanta. He authored a section,“System Protection,” for the monograph TheElectric Power Engineering Handbook (BocaRaton, FL: CRC, 2000). His research interestsare in the general area of computer applications

in power system monitoring, protection and control, and design and analysisof renewable energy sources.

Dr. Begovic is a member of Sigma Xi, Tau Beta Pi, Eta Kappa Nu, and PhiKappa Phi. He was a Chair of the Working Group “Wide Area Protectionand Emergency Control” and Vice-Chair of the Working Group “VoltageCollapse Mitigation” of the IEEE Power Engineering Society (PES) PowerSystem Relaying Committee. He was also a Contributing Member of theIEEE PES PSRC Working Group “Protective Aids to Voltage Stability,”which received the IEEE Working Group Recognition Award in 1997. Heis currently Vice-Chair of the Emerging Technologies Coordinating Com-mittee of the IEEE PES.

Damir Novosel (Fellow, IEEE) received thePh.D. in electrical engineering from MississippiState University, Mississippi State, where he wasa Fulbright Scholar.

Prior to joining KEMA in 2003, he has heldvarious positions with ABB, including VP ofglobal product management for automation prod-ucts and Manager of a power system consultinggroup. He is currently Senior Vice Presidentand General Manager for T&D Consultingat KEMA, Raleigh, NC. He has 21 years of

experience working with electric utilities and vendors. He has contributedto a large number of IEEE and CIGRE tutorials, guides, standards, reports,and other publications in the areas of power systems. He currently holds 16US and international patents. He has also published over 60 publications.His major contribution has been in the area of preventing power systemblackouts.

Dr. Novosel is the Vice-Chair of the IEEE Power System Relaying Com-mittee Subcommittee on System Protection and Adjunct Professor at NorthCarolina State University, Raleigh. His work has earned him internationalrecognition and reputation.

Daniel Karlsson (Senior Member, IEEE) re-ceived the Ph.D. degree in electrical engineeringfrom Chalmers University, Sweden, in 1992.

Between 1985 and April 1999, he worked asan Analysis Engineer in the Power System Anal-ysis Group within the Operation Department ofthe Sydkraft utility. From 1994 until he left Syd-kraft in 1999, he was Power System Expert andwas promoted to Chief Engineer. From 1999 to2005, Dr. Karlsson was Application Senior Spe-cialist at ABB Automation Technology Products.

He is currently a Consultant with Gothia Power AB, Goteborg, Sweden. Hiswork has been in the protection and power system analysis area and his re-search has been on voltage stability and collapse phenomena with emphasison the influence of loads, on-load tap-changers, and generator reactive powerlimitations. His work has comprised theoretical investigations at academiclevel, as well as extensive field measurements in power systems.

Dr. Karlsson is a Member of CIGRE. Through the years he has been ac-tive in several CIGRE and IEEE working groups. He has also supervised anumber of diploma-workers and Ph.D. students at Swedish universities.

Charlie Henville (Fellow, IEEE) received the B.A. and M.A. degrees fromCambridge University, Cambridge, U.K., in 1969 and 1974, respectively,and the M.Eng. degree from the University of British Columbia in 1996.

He has 26 years of experience with protection engineering and workeduntil 2005 as a Principal Engineer with BC Hydro, Delta, BC, Canada. Heis currently a Private Consultant in Vancouver, BC, Canada.

Mr. Henville was Chair of the IEEE PES PSRC Working Group “Pro-tective Aids to Voltage Stability,” which received the IEEE Working GroupRecognition Award in 1997. He is a Member of the IEEE Power EngineeringSociety (PES), the Power System Relay Committee (PSRC), and is activein several working groups. He is currently Secretary of the Power SystemRelaying Committee of IEEE PES.

Gary Michel (Senior Member, IEEE) received the B.S.E.E. degree from theUniversity of Miami, Coral Gables, FL, the MBA degree from Florida Inter-national University, Miami, and the diploma degree from the WestinghouseAdvanced Power Systems School, Pittsburgh, PA.

He managed and designed protection, communications, and control sys-tems at Florida Power and Light for more than 20 years, designed com-munications products at Motorola, and designed computers at RCA. He iscurrently President of Power System Consulting, Hialeah, FL, an R&D firmspecializing in power system protection, communications, and control. Heis author of several IEEE, Department of Energy, Electric Power ResearchInstitute, conference, and technical publications.

Mr. Michel is a Past IEEE Power Engineering Society Officer, a Memberof the IEEE Power System Relaying Committee (PSRC), IEEE PowerSystem Communications Committee (PSCC), and IEEE CommunicationsSociety, Past Chairman of several PSRC and PSCC Working Groups.


wide-area protection and emergency control

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