1894 IEEE TRANSACTIONS ON POWER SYSTEMS, VOL. 21, NO. 4, NOVEMBER 2006

On Power System Controlled SeparationM. M. Adibi, Fellow, IEEE, R. J. Kafka, Fellow, IEEE, Sandeep Maram, Student Member, IEEE, and

Lamine M. Mili, Senior Member, IEEE

Abstract—This paper describes verification of five conjecturesrelated to power system controlled separation. It attempts to verifythat the location of uncontrolled separation (loss of synchronism orout-of-step operation) is independent of the location and severity(short-circuit duty or duration) of the initial faults, that the lo-cation depends on the prevailing network configuration and loadlevel, and that it takes place one operation at a time (cascades).Verification of these conjectures would allow controlled separationduring a disturbance in real-time, using the present communica-tion and protection systems, and results in a minimal load and gen-eration imbalance. Two actual power systems were used, a 50-bussystem to establish the procedure for controlled separation and a640-bus interconnection to apply the procedure. Data representingstatic and dynamic behavior of the two power systems were ob-tained from the operating utilities, and the many required simula-tions were conducted using EPRI Power System Analysis Package(including IPFLOW and ETMSP programs).

Index Terms—Controlled separation, graceful degradation,out-of-step blocking, system separation, transfer tripping.

I. BACKGROUND

MOST POWER system faults occur on high- and extra-high-voltage transmission lines due to their vulnerability

arising from their exposed lengths. The majority of these faults,such as those caused by lightning, are temporary and of short du-ration. These faults are cleared by rapidly opening and reclosingcircuit breakers at both ends of lines, leaving the power systemin an unfaulted condition. However, during the short fault du-ration, the electrical output of generators decreases, while themechanical input to the generators remains practically constant.The effect of the torque imbalance is for the groups of coherentgenerators to accelerate at different rates and to “swing” withrespect to one another. If not quickly corrected, they may losesynchronism, splitting the system into an imbalance load andgeneration parts, and consequently result in blackouts.

The recent major power disturbances have shown that the ini-tial and temporary system faults have been cleared in millisec-onds, and the uncontrolled system separation into unbalancedload and generation parts has occurred in seconds [1]. There-fore, it appears that between the clearance of the initial faultand formation of uncontrolled separation, there is ample time

Manuscript received September 6, 2005; revised May 8, 2006. This work wassupported by the National Science Foundation under Small Business InnovativeResearch Grant DMI 0439603. Paper no. TPWRS-00555-2005.

M. M. Adibi is with IRD Corporation, Bethesda, MD 20827 USA (e-mail:madibird@aol.com).

R. J. Kafka is with Pepco Holdings, Inc., Bethesda, MD 20827 USA (e-mail:rikafka@pepcoholdings.com).

S. Maram and L. M. Mili are with Virginia Polytechnic Institute and State Uni-versity, Blacksburg, VA 24061 USA (e-mail: maram@vt.edu; lmili@vt.edu).

Color versions of Figs. 4–6 and 8–15 are available online at http://ieeexplore.ieee.org.

Digital Object Identifier 10.1109/TPWRS.2006.881139

for real-time controlled separation using the present protectiveand communication systems.

The past controlled separations have been developed for elon-gated and isolated power systems, splitting the system alongpredetermined boundaries. They have been planned for a fore-casted load condition. Then in response to the resulting load andgeneration imbalance in the separated parts, they have invari-ably resorted to undesirable load shedding and generation cur-tailment [2]–[6].

In recent years, there have been several “response-driven”types of studies addressing the controlled islanding. Theirapproaches are based on availability of real-time system-widephasor measurements, accurate and extensive power systemmodeling, highly efficient computing, pattern recognition, or-dered binary decision diagrams, and other real-time analyticaltools to predict the instability of the power system and to deter-mine the locations, timing, and the need for system separation.The prediction of online real-time transient stability may wellbe a long-term solution [7]–[11].

It is believed that the simplicity in detection, control, andthe use of existing protective and communication systemsmakes the approach described in this paper very attractive.This “event-driven” approach, after the initial fault, blocks thesystem separation where load and generation is unbalanced“undesirable” and transfers the separation to where it is balanced“desirable” [12].

The approach is based on verification of the following fiveconjectures.

1) The location of loss of synchronization (i.e., the out-of-stepoperation) causing uncontrolled separation is independentof the locations and severity (duration) of the initial faults.This implies that for many likely initial faults, there wouldbe only a few locations where out-of-step operation couldtake place.

2) The location of the out-of-step operation depends on thecurrent system topology and the prevailing operating con-dition. It infers that under a prevailing network configura-tion and load level, only a few out-of-step relays need to bearmed for possible out-of-step blocking and transfer trip-ping operations.

3) The out-of-step operations take place one operation at atime (cascading). It suggests that the loss of synchronismdoes not occur in several locations simultaneously and thatthe time interval between successive occurrences allowsblocking and transfer of the loss of synchronism to a de-sirable location.

4) During normal operation, at any given time, there are sev-eral locations that can split the power system into separateand desirable parts. Usually these locations are identifiedby light power flow lines.

0885-8950/$20.00 © 2006 IEEE

ADIBI et al.: POWER SYSTEM CONTROLLED SEPARATION 1895

5) The location(s) to which transfer tripping is (are) madewill have a “minimal” imbalance in load and generation,resulting in the least disruption of service.

Verification of the above conjectures together with the cur-rent knowledge of the system configuration and load condi-tion would allow arming certain relays for out-of-step blockingand transfer-tripping. Then within a second or two after a pos-sible initial fault, the controlled separation could take place. Thearming of specific relays will be updated from time to time orin response to significant changes occurring in the system con-figuration and load condition.

In order to verify the above conjectures, the out-of-step oper-ations have to be monitored at several likely locations for manypossible initial faults. This required that the relay characteris-tics and the apparent impedance representations be modified byexpressing the relay tripping zone and the apparent impedancein per unit on the basis of the impedance of the individual linethat is being protected. This process had to be further simpli-fied by monitoring the distance between the apparent impedanceposition and the center of the relay tripping zone, both in the

plane. Without these modifications and simplifications,it would have been difficult to conduct the many required sim-ulations efficiently.

In Section II, a reduced 50-bus system is used to establishthe procedure for verifying the five conjectures. Sections II-Ato II-D include identification of locations for the possible ini-tial faults locations for the likely system separations, timingsfor typical fault clearing, out-of-step blocking and transfer-trip-ping procedure, and the coherent generators’ dynamic responseto the three-phase faults. In Section II-E, representation and sim-plification of relay tripping zones and apparent impedances aredescribed.

In Section III, the procedure developed in Section II is appliedto a 640-bus interconnection, to verify the five conjectures. InSection III-A, the desirability/undesirability criteria for loca-tion of system separation is discussed. Sections III-Bto III-Gsimulate and demonstrate: sequential (cascading) operationof out-of-step relays, the effect of out-of-step blocking andsubsequent tripping, the independence of out-of-step locationvis-à-vis the initial fault intensity (duration) and location, andthe dependence of out-of-step operation on peak- and light-loadconditions. In Section III-H, the out-of-step blocking andtransfer-tripping procedure is demonstrated. The discussion ofthe results and concluding remarks are in Section IV.

II. PROCEDURE

A. Reduced 50-Bus System

Fig. 1 shows the reduced 50-bus system [13]. It is actually aninterconnection of two systems, one represented by buses 109and 135 through 142, operating at nominal 230 kV, whereas theother system operates at a nominal 110 kV. The two systemsare interconnected by a two-winding transformer between buses109 and 108 and a three-winding transformer between buses135 and 127. Two 30-MVAr synchronous condensers are con-nected to the tertiary winding of this transformer. The 110-kVtransmission loop encircles a metropolitan area, and the majorpart of the system load is concentrated here. Two of the steam

Fig. 1. Reduced 50-bus system.

TABLE IREDUCED 50-BUS SYSTEM DYNAMIC DATA

plants are located near this load center, but the high-head long-conduit hydro plants are remote. The 50-bus system is looselyconnected, and as such, it is prone to transient instability anduncontrolled separation.

In this type of system, out-of-step operation where the systemseparation may take place is readily identifiable by simulationand actual instability experience. Using network reduction anddynamic equivalent techniques, the 50-bus system was reducedto 30 buses, three steam-electric stations, six hydro-electricplants, and one synchronous condenser.

The initial fault locations where judiciously selected. Eightthree-phase faults were placed on the system as indicated by Xon the one-line diagram. The locations where out-of-step oper-ations were suspected and monitored are indicated by M1, M2,M3, and M4. The dynamic data used for the generators, gover-nors, and excitation systems are listed in Table I.

B. Initial Fault Clearing

In general, on high- and extra-high-voltage transmissionlines, high-speed fault clearing is used [13], [14]. High-speedfault clearing requires simultaneous tripping and then simulta-neous reclosing of circuit breakers at both ends of a line suchas the 136-135 line in Fig. 1, for which high-speed relays andcommunication are used. These relays also distinguish whetherthe system fault is internal or external to the line.

The fault clearing time is the sum of fault detection time of1/4 to 1 cycle (on the basis of 60 Hz), signal transmission timeof 1/4 to 1 cycle, and the circuit breakers interruption (opening)time of 1 1/2 to 2 cycles. Thus, depending on the line voltagelevel and the type of relay and breaker used, the duration of theinitial fault is within two to four cycles (typically, the higher thevoltage level, the faster the relay/breaker and shorter the faultduration). The breakers are then simultaneously reclosed (onetime) about 10 to 15 cycles later. The lengthy interval betweenthe opening and reclosing of the circuit breakers is to allow time

1896 IEEE TRANSACTIONS ON POWER SYSTEMS, VOL. 21, NO. 4, NOVEMBER 2006

Fig. 2. Swing blocking relaying.

Fig. 3. Ohm unit relay.

for de-ionization of the arc at fault location and to prevent re-striking (typically, the higher the voltage level, the longer thereclosing interval).

C. Out-of-Step Blocking and Transfer Tripping

Following clearance of a fault, external to a given line,the line’s apparent impedance (bus voltage over line current)gradually moves toward the relay’s out-of-step tripping zone[15]–[17]. For example, in Fig. 1, the out-of-step relay indicatedby M2 on 136-135 line is such a location. By detecting that theout-of-step relay operation may occur at an undesirable loca-tion, ample time is available to block the relay from operationand transfer the tripping to a desirable location [18], [19].

Microprocessor-based relaying schemes with fiber-opticcommunication and electronic relays offer more options forout-of-step blocking and transfer tripping; however, the ohmunit relay of Figs. 2 and 3 that are in general industry usewill be described here. The ohm units that are also calledangle-impedance relays are used as “blinders” to control theangle range of tripping out-of-step or swing conditions.

As shown in Fig. 2, the angular range covered by the dis-tance relay element may be narrowed to any desired extent. The

fault-impedance locus is the shaded area between the two linesat angles 75 (line-impedance angle) and 60 . The apparentimpedance path or swing-impedance locus is drawn intersectingthe line-impedance and indicating the various swing angles. Thedistance relays without blinders would trip during swing in therange from 90 to 240 , whereas with the blinders, the range islimited to 135 to 195 . These blinders respond to impedancesat angles 75 and 60 , which are selected to make the character-istics of ohm relay unit parallel to the boundaries of the line’sfault area. Their “ohm settings” are adjusted to place the char-acteristic close to the boundaries.

During out-of-step conditions or heavy swing, a distancerelay may trip, depending on whether the prevailing swing-impedance locus passes through the tripping area. That is, therelay tripping is a function of

1) relay characteristics and position of its tripping area;2) position of the relay in the network with respect to the

operating generators.It is, however, desirable to control the locations where such

relay tripping occurs. This requires that during out-of-step con-ditions, those relays that may trip at undesirable locations beblocked and those relays that may not trip at the desirable loca-tions be allowed to tripped.

The out-of-step blocking can be accomplished by the useof an additional blinder as shown in Fig. 3. The apparentimpedance passes across the parallel blinders from normaloperating conditions to tripping areas gradually (i.e., a lowrate of change of impedance) for the out-of-step condition andinstantaneously (i.e., a high rate of change of impedance) for afault condition. If the elapsed time, between the crossing of theouter blinder and the inner blinder (the shaded area), is equalto or greater than the pick-up time of the auxiliary relayassociated with the out-of-step relay, then the auxiliary relayoperates, blocking the tripping operation.

The pick-up time of the blocking relay is about 1/4 to 1 cycle,signal transmission time for the transfer to the desirable loca-tion is also 1/4 to 1 cycle, and the simultaneous circuit breakersopening time at the transferred to locations is about 1 1/2 to 2cycles. Thus, within two to four cycles following the apparentimpedance crossing, the shaded area between the outer and theinner blinders, the out-of-step blocking, and transfer trippingcan be accomplished.

D. Generators Transient Response

Fig. 4 shows responses (swing curves) of several generatingplants after placing a three-phase fault adjacent to Bus 139 onone of the two parallel lines to Bus 140. It can be seen thatthe initial fault has been placed on the system at 0.1 s after thestart of simulation, cleared at 0.2 s by opening the two breakersat both ends of the faulted 139-140 line, and reclosed the twobreakers at 0.5 s later. During the 0.1 s (six cycles) of the initialfault duration, the electrical and mechanical torque imbalancehas caused the two groups of coherent generators to accelerateat different rates, swinging with respect to one another [15],[20]–[22].

It should be noted that following the placement of a numberof initial faults, as indicated by X in Fig. 1, the two generatingplants, Gen 138 Hydro and Gen 142 Hydro, have consistently

ADIBI et al.: POWER SYSTEM CONTROLLED SEPARATION 1897

Fig. 4. The 50-bus transient test results.

had a higher accelerating rates than the other “coherent” group.Subsequently, the two groups may lose synchronism at 136-135line, splitting the system into two parts, with unbalanced loadand generation that could lead to a blackout.

E. Relay and Apparent Impedance Representations

In Fig. 1, let line 136-135 be represented by bus voltages Eiand Ej, current Iij, and the line impedance Zij, all in per uniton 100 MVA base and line’s nominal kV level. The apparentimpedance Zi at i-bus is determined from

or (1)

Under normal operating conditions, Zi is much greater thanthe line impedance Zij. During swing conditions,path described by Zi can come into the vicinity of the relaytripping zone and may enter the tripping area, when ,and consequently open the unfaulted 136-135 line.

In order to monitor the out-of-step operations for a set of pos-sible three-phase initial fault locations (eight locations as se-lected and indicated by X in Fig. 1), at a set of likely out-of-steprelay locations (four locations indicated by M1, M2, M3, andM4 in Fig. 1), the 32 transient stability simulations required thatthe relay characteristics and the apparent impedance represen-tation be simplified by expressing the apparent impedance andthe relay tripping zone in per unit on the basis of individual lineimpedance, as follows:

or (2)

Thus, Zo position in the plane can be compared withline impedance Zij, approximately equal to 1.0 at all relay loca-tions without representing each relay separately, as illustrated inFig. 5. Although this approach is less accurate than full repre-sentation of the relay tripping zone, it does simplify the verifi-cation effort.

Fig. 5 shows movements of Zo in the plane atbus 136 for line 136-135 due to the three-phase fault adjacentto Bus 127 on one of the two parallel lines 127-129, as indi-cated by X in Fig. 1. After clearance of the initial fault, the ap-

Fig. 5. Apparent impedance for line 135-136.

Fig. 6. Apparent impedance for line 135-136.

parent impedance at the out-of-step relay location M2 graduallyvaries in magnitude and angle, so that it gradually moves to-ward its tripping zone that is close to the line impedance. In thiscase, it can be seen that the apparent impedance has not enteredthe out-of-step relay’s tripping zone (shown as a circle), andconsequently, line 136-135 does not trip due to the out-of-stepoperation.

In Fig. 6, the process has been further simplified by showingthe magnitude of apparent impedance Zo against time, under thesame condition. When an imminent tripping by the out-of-steprelay is detected, i.e., when , and the rate of change ofimpedance is greater than the preset value in Fig. 3, time isavailable to quickly block the relay (when armed) from opera-tion and transfer the tripping to a desirable locations by meansof the communication channel as described above [12], [13].

III. APPLICATION

A. 640-Bus Interconnection

The 640-bus interconnection in contrast to the 50-bus systemis an all-thermal power system, with relatively short intertiepaths. The 640-bus interconnection is composed of several

1898 IEEE TRANSACTIONS ON POWER SYSTEMS, VOL. 21, NO. 4, NOVEMBER 2006

TABLE II640-BUS SYSTEM DYNAMIC DATA

power systems that over the years have been independentlydeveloped and are very closely net. They have later on beeninterconnected by relatively short tie-lines. The 640-bus in-terconnection is fairly stable and unlike the 50-bus systemhas seldom experienced instability or uncontrolled separation.Experience with blackouts of 1965, 1967, 1977, and 2003 hasshown that in this type of system, the out-of-step operation thatseparates the interconnection has taken place at the tie-linesbetween the individual systems and/or with the other intercon-nections [1], [23], [24], [29].

The 640-bus system is a 22 000-MW interconnection com-posed of four power systems tied together with relatively short500- and 345-kV transmission lines. It consists of 92 genera-tors in 24 power plants. Using the network reduction and dy-namic equivalent techniques, the interconnection was reducedto 517 buses and 38 generators of cross-compound, tandem, andcombustion turbine types. The dynamic data used in the EPRIETMSP for the generators, excitation systems, and governorsystems are listed in Table II. Due to space limitation, the staticdata and the one-line diagram for the 640-bus interconnectionare not included in this paper.

During different power system operating conditions such asthe peak-load and light-load or the heavy interchange of power,the four power systems each were either generation rich or loadrich. Accordingly, the tie-line flows also were different in dif-ferent simulation cases.

Fig. 7 shows the four power systems E, F, G, and H with thefour ties e-f, e-g, g-h, and f-h and the four out-of-step moni-toring points M1, M2, M3, and M4. Many cases were simulatedto illustrate different types of power system disturbance usingEPRI IPFlow and ETMSP programs. Attempts were made toverify the five conjectures regarding the effects of cascading,relay-blocking, fault-intensity, fault-location, load-levels, andnetwork-configuration on the out-of-step blocking and transfertripping that is the basis for controlled separation.

It is shown that for a given power system configuration andload level, the out-of-step location for the initial faults on anypart of the power system can be determined. For instance, theunfaulted e-f tie-line in Fig. 7 is such a location. The un-desirability of such a location for system separation dependson whether the power flow , across the out-of-step location(e.g., from e-bus to f-bus), is appreciably greater than the fre-quency regulation , of generators on the receiving F-System.In the event that is substantially greater than , then theblinder relay (ohm unit, angle impedance, or digital equiva-lent) is armed for out-of-step blocking and transfer tripping to

Fig. 7. The 640-bus interconnection.

those locations that meet the , criterion. Otherwise, a de-sirable system separation would be allowed to take place andsubsequently resynchronized, resulting in no or insignificantdisturbance.

Given a system configuration and a load level, a set of lineoutages needs to be selected that results in system separationwith the least between the two separated parts. Ifnecessary, this minimal can further be reduced byrescheduling the area generation in the separated parts [7], [25],[26]. In their daily normal operation, utilities often reschedulearea generation to provide sufficient area spinning and effective(dynamic) reserve to overcome loss of a significant area gen-eration. Typically, the area spinning reserves (area generationcapacity less output) are distributed in proportion to the areagenerators’ frequency response rates to maximize the arearegulation [20], [27], [28].

B. Cascading

The purpose of this simulation was to show that out-of-steprelay operations occur sequentially (cascading) and not simul-taneously. The distinction between the two types of operation iswhether control actions can take place in the time interval be-tween successive out-of-step operations.

In Fig. 8, a three-phase fault was placed adjacent to Bus 64on one of the 230-kV, 20-mile-long double circuit line 64-132.The line’s parameters are listed in Table III. Bus 64 has a rela-tively high short-circuit duty being the system bus for the PowerPlant 65 (450-MVA generators and the 500-MVA step-up trans-formers) in the E-System.

It can be seen that fault had been placed at andcleared at , i.e., a fault duration of nine cycles on60-Hz basis. The breakers at both ends of the single circuit64-132 have opened and successfully reclosed at ,i.e., for a 15-cycle reclosing duration. As shown, the apparentimpedance at e-bus of the e-f tie-line has entered the relay trip-ping zone at and for the g-bus of the g-h tie-lineat or about 35 cycles later. Consequently, there

ADIBI et al.: POWER SYSTEM CONTROLLED SEPARATION 1899

Fig. 8. Tie-lines e-f and g-h cascading.

TABLE IIITHREE-PHASE INITIAL FAULT LOCATIONS

TABLLE IVINITIAL OPERATING CONDITIONS FOR THE CASCADING CASE

has been ample time available in the interval for relay blockingand transfer-tripping (i.e., the required two to four cycles). Thesimulation also confirms that under several system faults, therewere only two coherent groups of generators within the 38 gen-erators in the interconnection.

Table IV lists the tie-lines’ power flow and parameters for thecascading case.

C. Out-of-Step Blocking

Fig. 9 illustrates the effect of blocking the e-f tie-line fromtripping under the same initial operating condition and fault pro-cedure as in the previous (cascading) case. At , theapparent impedance for the e-f tie-line enters the relay trippingzone. The relay, having been armed, recognizes the out-of-stepoperation and blocks the relay from tripping. Subsequent to theout-of-step blocking of the e-f tie-line, the g-h tie-line, havingnot been armed, trips at time or about five cycleslater than in the cascading case, as expected.

Fig. 9. Tie-line e-f is blocked.

Fig. 10. Fault intensity (duration).

D. Fault Intensity (Duration)

Fig. 10 shows that two three-phase faults have been placedadjacent to Bus 64 on one of the two parallel lines to Bus 132,one fault with nine cycles and the second with 12 cycles faultclearing times. Examination of the logarithms of the apparentimpedance paths for the four tie-lines e-f, g-h, e-g, and f-gmonitored at M1, M2, M3, and M4 show that only the e-ftie-line is susceptible to out-of-step operation. This simulationcase shows that location of out-of-step operation, i.e., theuncontrolled power system separation, is independent of theintensity (duration) of the initial faults.

E. Initial Fault Locations

One of the conjectures to be verified was to demonstratethat the location of the out-of-step operation is independentof the locations of the initial faults. Fig. 11 shows the ap-parent impedance paths of the g-h tie-line under two identicalthree-phase faults, one adjacent to Bus 64 on one of the doublecircuit line to Bus 132 as described in Section III-B and the otheradjacent to Bus 47 on one of the 230-kV 30-mile-long double

1900 IEEE TRANSACTIONS ON POWER SYSTEMS, VOL. 21, NO. 4, NOVEMBER 2006

Fig. 11. Fault location.

Fig. 12. Peak and light load conditions.

TABLE VINITIAL OPERATING CONDITION FOR THE LIGHT-LOAD CASE

circuit line 47-32. The line’s parameters are listed in Table III.Bus 47 is the system bus for Power Plant 48 (1260-MVAgenerators and the 1465-MVA step-up transformers), also inthe E-System. It can be seen that under the same initial faultduration, but in two different locations, g-h tie-line is subject toout-of-step operations within four cycles of each other.

F. Load Condition

Fig. 12 shows that the out-of-step operation depends on powersystem load levels. This can be seen by comparison of the ap-parent impedance for g-h tie-line, under peak-load and light-load conditions without changing the number of generators orthe network configuration. Table IV lists the system load of21 630 MW for the peak-load, and Table V lists 17 300 MW

Fig. 13. Change in network configuration.

TABLE VIINITIAL OPERATING CONDITION FOR THE SECOND LIGHT-LOAD CASE

for the light-load condition. Under peak-load, g-h tie-line trips,whereas under light-load condition, it does not.

G. Network Configuration

In Fig. 13, two light-load operating conditions with differentconfigurations are compared. In the first case, the number ofgenerators is 38, the same as in the peak-load configuration ofTable IV, but load and generation have been reduced to 80%. Inthe second case as listed in Table VI, all the 12 peaking steamunits and combustion turbine units have been shut down, butthe load level has been kept to the same level as that of the firstcase. The logarithm of the apparent impedance path for the e-ftie-line for the second case with 24-generator configuration isquite different from the first case with 38-generator configura-tion, showing that out-of-step operation also depends on the net-work or generation configuration.

H. Out-of-Step Blocking and Transfer Tripping

Figs. 14 and 15 illustrate the out-of-step blocking andtransfer tripping. Under this operating condition, the E-Systemand G-System of Fig. 7 are by about 10% generation rich ascompared with the F-System and H-System. The differencesin the tie-line flows can be seen by comparing Tables IV andVII. In Fig. 14, a three-phase nine-cycle initial fault is placedadjacent to the Bus 64 on one of the two parallel lines to Bus132, as discussed earlier. The apparent impedance Zo for thee-f tie-line has moved and gradually entered the relay trippingzone at . If not blocked, as seen in earlier cases, theg-h tie-line will follow and trips about 35 cycles later. This isundesirable as it would separate the interconnection into twounbalanced parts. The E-System and G-System parts beinggeneration rich will accelerate, and the F-System and H-Systempart being load rich will decelerate. If these frequency rise

ADIBI et al.: POWER SYSTEM CONTROLLED SEPARATION 1901

Fig. 14. Out-of-step blocking.

Fig. 15. Transfer tripping.

TABLE VIIINITIAL OPERATING CONDITION FOR THE OUT-OF-STEP

BLOCKING AND TRANSFER-TRIPPING CASE

and decay are not arrested by proper load shedding and loadrejection, they could result in a blackout. However, as seen inFigs. 14 and 15, if the relays on e-f tie-line and g-h tie-line areblocked from operation and the tripping is transferred to e-gtie-line and f-h tie-line, the 640-bus interconnection separatesinto two balanced E-F and G-H parts.

Table VIII lists results of simulations that are similarto Sections III-D, III-E, and III-F supporting three of theconjectures.

IV. CONCLUDING REMARKS

The purpose of this paper was to verify certain conjecturesrelated to power system controlled separation. The five conjec-

TABLE VIIIAPPARENT IMPEDANCE PATHS

tures outlined in Section I were verified for the loosely con-nected 50-bus system and for the tightly net 640-bus intercon-nection. In these two systems, the locations of out-of-step oper-ations could be identified by simulation and were supported byfield experience.

The first conjecture is that the locations for out-of-step op-eration is highly system specific and determination of their lo-cations is a critical step in application of controlled separation.The other four conjectures, however, are generally applicable.

The 50-bus system is a dynamic equivalent of much largerpower system. This system was selected for establishing the re-search procedure because in practice, it was prone to transientinstability and uncontrolled separation.

The 640-bus system also has been reduced for this paper usingsimilar techniques. This system was selected because it had ahistory of preventing wide-area cascading in response to internaland external faults [1], [23], [24], [29].

Numerous simulation cases were conducted in an at-tempt to verify the five conjectures. Only eight cases inSections III-Dto III-G and in Figs. 8–15 were selected todescribe and illustrate the phenomena, including sequentialoperation (cascading) of out-of-step relays, the effect of out-of-step blocking, location and duration of the initial faults, thepower system load levels, and network configuration.

In general, power system faults are cleared without occur-rence of uncontrolled separation, yet it is noted that the great1965 blackout was initiated with a reactance relay operation ona 230-kV transmission line, resulting in several uncontrolled is-lands [1].

In order to monitor the out-of-step operations in a large powersystem, such as the 640-bus interconnection, the relay charac-teristic and the apparent impedance representations had to besimplified. Without this innovation, it would have been difficultto conduct the study efficiently.

It is recognized that after an initiating event, the rise and decayin system frequency are automatically arrested by a number ofcorrective and complementary actions, including load rejec-tion, controlled separation, load shedding, and low-frequencyisolation scheme, in that order. An IEEE survey shows thatover 100 utilities are practicing one or more of these corrective

1902 IEEE TRANSACTIONS ON POWER SYSTEMS, VOL. 21, NO. 4, NOVEMBER 2006

actions with an average success rate of about 50%. This paperdeals with one of such corrective actions—that of controlledseparation—and it is an attempt to improve its success rate.

The five conjectures were conceived on the basis of analysisof the past major power system disturbances and on the obser-vations of the actual system instabilities. It is believed that theverification of these conjectures together with knowledge of theprevailing system topology and load condition would allow con-trolled separation of power systems.

The proposed conjectures are controversial, but the resultsshould be of interest, precisely because in the blackout ofAugust 14, 2003, one of the questions raised was “Why theBlackout Stopped Where It Did” [31]. The same phenomenoncan be noted in the 1965, 1967, and 1977 blackouts.

ACKNOWLEDGMENT

The first author would like to thank Potomac Electric PowerCompany for providing partial network, dynamic, and opera-tional data. He also would like to thank Prof. V. Vittal of ASU,Prof. M. Pavella of University of Liege, Mr. C. Taylor of BPA,Mr. D. Milanicz, System Protection and Control (SP&C) ofBG&E, and Mr. A. Depew, SP&C of Pepco, for the discussionheld regarding the five conjectures.

REFERENCES

[1] Prevention of Power Failures U.S. Federal Power Commission, vol.I–III, U.S. Printing Office, 1967.

[2] A. S. Shahnavaz et al., “A scheme for controlled islanding to pre-vent subsequent blackout,” IEEE Trans. Power Syst., vol. 18, no. 1, p.136-13, February 2003.

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M. M. Adibi (M’56–SM’72–F’95) received the B.Sc. degree in electrical en-gineering in 1950 from the University of Birmingham, Birmingham, U.K., andthe M.E.E. degree in 1960 from Polytechnic Institute of Brooklyn, Brooklyn,NY.

In 1967, as a Program Manager at IBM, he investigated the 1965 NortheastBlackout for the Department of Public Service of the State of New York, and in1969 and following the PJM blackout of 1967, as an IBM Industry Consultantin the IBM Research Division, he investigated Bulk Power Security Assess-ment for Edison Electric Institute. Since 1979 and in the aftermath of the NewYork Blackout of 1977, he has chaired the Power System Restoration WorkingGroup, publishing Power System Restoration—Methodologies & Implementa-tion Strategies (Piscataway, NJ: IEEE/Wiley, 2000).

Mr. Adibi is a Registered Professional Engineer in the state of Maryland.

R. J. Kafka (M’73–SM’88–F’00) received the B.S. degree in physics fromRegis College, Denver, CO, in 1970 and the M.S degree from Purdue Univer-sity, West Lafayette, IN, in 1972.

He has been employed by the Potomac Electric Power Company (Pepco)since 1973. He was assigned to Pepco’s system restoration study team in1979, which produced one of the first formal power flow studies for a systemrestoration plan. He is Transmission Policy Manager of Pepco Holdings, Inc.,Bethesda, MD.

Mr. Kafka is a charter member of the Power System Restoration WorkingGroup, Secretary of the Power System Operations Committee, and a RegisteredProfessional Engineer in the state of Maryland.

Sandeep Maram (S’05) was born in Hyderabad, India. He received the B.Eng.degree in electronics and communication engineering from Visveswariah Uni-verrsity, Belgaum, India, in 2004. He is currently pursuing the M.E.E. degree atVirginia Polytechnic Institute and State University, Blacksburg.

Lamine M. Mili (SM’90) received the electrical engineering diploma fromEPFL, Lausanne, Switzerland, in 1976, and the Ph.D. degree from the Univer-sity of Liege, Liege, Belgium in 1987.

He is a Professor of electrical and computer engineering at the ARI, VirginiaPolytechnic Institute and State University. He recently organized a NSF work-shop on the “Mitigation of the Vulnerability of Critical Infrastructures to Cata-strophic Events.”

Dr. Mili is the recipient of the NSF Research Initiation Award (1990) and theNSF Young Investigator Award (1992).