EISSA et al.: A NOVEL BACK UP WIDE AREA PROTECTION TECHNIQUE FOR POWER TRANSMISSION GRIDS USING PHASOR MEASUREMENT UNIT 271Fig. 1. Three zones of operation for each stand alone relay.II. CONVENTIONAL PROBLEMSThe distance relays which are widely applied in the protec-tion today and involve the determination of impedance achieveoperating times of the order of a period of the power systemfrequency. A distance relay is designed to only operate forfaults occurring between the relay location and the selectedreach point, and remains stable for all faults outside thisregion or zone . The resistance of the fault arc takes thefault impedance outside the relay’s tripping characteristic and,hence, it does not detect this condition. Alternatively, it is onlypicked up either by zone 2 or zone 3 in which case tripping willbe unacceptably delayed . The distance relays are based onstand alone decision, while each relay operates independentlyaccording to three different zone of operation, see Fig. 1.The mal-operation or fail-to trip of protection is determinedas one of the origins to raise and propagate major power systemdisturbances . A vast majority of relay mal-operations is un-wanted trips and have been shown to propagate major distur-bances. Backup protections in fault clearance system have thetask to operate only when the primary protection fails to operateor when the primary protection is temporarily out of service. Therecent complexity and enlargement of power systems makesit difﬁcult to coordinate operation times and reaches amongrelays.In the areas of power system automation and substation au-tomation, there are two different trends: centralization and de-centralization. More and more dynamic functions are movingfrom local and regional control centers toward central or na-tional control centers. At the same time we also observe more“intelligence” and “decision power” moving closer towards theactual power system substations. Greater functional integrationis being enclosed in substation hardware.In view of global security of power systems, the action algo-rithms of conventional backup protections possibly are not bestchoices because the operations of individual relays are hardlycoordinated each other. Therefore, the principle of the protec-tion design needs innovation to overcome the above problem.Modern protection devices have sufﬁcient computing and com-munications capabilities to allow the implementation of manynovel sophisticated protection principles.Therefore, a novel wide-area backup protection system is re-ported in this paper. This system is capable of acting as thesubstitution of conventional distributed backup protections inFig. 2. The new protected zones of the proposed relay.substation. To ensure the fast responsibility of such a system tothe emergent events, the communication requirements are dis-cussed as well. Conclusively, the proposed system is designedby two ways. First, in substation, concentrate some conven-tional backup protection functions to an intelligent processingsystem; second, concentrate the coordinated and optimized pro-cessing and controlling arithmetic of all backup protection in aregion into a regional processing unit. The communication ofdata among them is carried via optic-ﬁber networks.The relay decision is based on collected and shared datathrough communication network. The suggested technique sat-isﬁes high degree of reliability and stability while it is based onshared decision rather than stand alone decision. The suggestedtechnique can see all the power system area and can deal withthe transmission lines as unit protection, see Fig. 2. The primarypurpose of these systems is to improve disturbance monitoringand system event analysis. These measurements have been sitedto monitor large generating sites, major transmission paths, andsigniﬁcant control points. Synchronized phasor measurementsprovide all signiﬁcant state measurements including voltagemagnitude, voltage phase angle, and frequency.III. COMPONENTS OF PHASOR MEASUREMENT UNITThe technology of synchronized phasor measurements iswell established. It provides an ideal measurement systemwith which to protect, monitor and control a power system, inparticular during conditions of stress. The essential feature ofthe technique is to measure positive sequence (negative andzero sequence quantities if needed) voltages and currents of apower system in a real time with precise time synchronization.This allows accurate comparison of measurements over widelyseparated locations as well as potential real-time measurementbased control actions. Very fast recursive discrete Fouriertransform (DFT) calculations are normally used in phasorcalculations. In the suggested technique, a positive sequencevoltage and phase angle of the positive sequence current isused.The DFT technique is a short-time variation of the Fourieranalysis. While the Fourier transform is applied to signals inthe continuous time domain, the DFT is applied to time-domainsignals represented by sequences of numbers. The basic phasormeasurement process is that of estimating a positive-sequence,fundamental frequency phasor representation from voltage orcurrent waveforms.
272 IEEE TRANSACTIONS ON POWER DELIVERY, VOL. 25, NO. 1, JANUARY 2010Fig. 3. Synchronized phasor measurement block diagram.Fig. 3 shows the analog power signal that converted intodigital data by the analog to digital converter. For example, ifthe voltage is needed to be measured, the samples are takenfor each cycle of the waveform and then the fundamentalfrequency component is calculated using (DFT). The ﬁgurealso shows a simple block diagram explaining the procedureof measured voltage or current analog signal. The sampleddata are converted to a complex number which represents thephasor of the sampled waveform. Phasors of the three phasesare combined to produce the positive sequence measurement.The ﬁgure includes a hardware low-pass ﬁlter (Hardware LPF)for antialiasing and an analog-to-digital (A/D) converter foranalog-to-digital conversion.The system of supervision permits capturing records of thesame event at different points in the power system with a uniquetime reference, the phasor measurement units at present are lo-cated strategically, with the purpose of capturing information onthe impact of contingencies at the local or system level. Fig. 4shows the electric system with the location of the PMUs. Thephasor measuring unit is represented by a discrete phase se-quence analyzer block which convert 3 phase signals (Vabc orIabc) to a positive, negative and zero sequence component mag-nitudes and angle. Each phase signal (Va, Vb and Vc) is con-verted to real and imaginary component using Discrete FourierTransform. The positive sequence component is calculated insequences analyzer by the following equation:where , the overall process to calculate positive,negative or zero sequence component using Matlab simulink.Fig. 4. The PMUs arrangement with phasor data concentration and system pro-tection center.IV. COMMUNICATION ISSUES AND BACK UP RELAYSThe application of the wide area in the protection is notstraight forward from the communication point of view. In suchcase the communication issues related to time delay is discussedhere. Standard communication systems are adequate for mostphasor data transmission. The issue for data communicationsincludes speed, latency and reliability. Communication speed(data rate) depends on the amount of phasor data being sent.A. Communication Options AvailableCommunication links used by WAPS include both wired(telephone lines, ﬁber-optics, power lines) and wireless (satel-lites) options. Delays associated with the link act as a crucialindicator to the amount of time-lag that takes place before ac-tion is initiated. The delays are an important aspect and shouldbe incorporated into any power system design or analysis, asexcess delays could ruin any control procedures adopted tostabilize the power grid.B. Communication Delay CausesAlthough more and more control systems are being imple-mented in a distributed fashion with networked communica-tion, the unavoidable time delays in such systems impact theachievable performance. Delays due to the use of PMUs and thecommunication link involved are due primarily to the followingreasons.Transducer Delays: Voltage transducers (VT) and currenttransducers (CT) are used to measure the RMS voltages and cur-rents respectively, at the instant of sampling.Window Size of the DFT: Window size of the DFT is thenumber of samples required to compute the phasors using DFT.
EISSA et al.: A NOVEL BACK UP WIDE AREA PROTECTION TECHNIQUE FOR POWER TRANSMISSION GRIDS USING PHASOR MEASUREMENT UNIT 273Processing Time: The processing time required in convertingthe transducer data into phasor information with the help ofDFT.Data Size of the PMU Output: Data size of the PMU messageis the size of the information bits contained in the data frame,header frame and the conﬁguration frame.Multiplexing and Transitions: Transitions between the com-munication link and the data processing equipment leads to de-lays that are caused at the instances when data is retrieved oremitted by the communication link.Communication Link Involved: The type of communicationlink and the physical distance involved in transmitting the PMUoutput to the central processing unit can add to the delay.Data Concentrators: Data concentrators are primarily datacollecting centers located at the central processing unit and areresponsible for collecting all the PMU data that is transmittedover the communication link.C. Delay CalculationsDelay calculations form an important aspect of WAMS;these delays indicate the viability of a particular communi-cation medium, since large communication delays amount toslower controller actions that can correct power grid instabili-ties and oscillations. Communication delay given in , can be expressed aswhere is the total link delay, is the ﬁxed delay associatedwith transducers used, DFT processing, data concentration andmultiplexing, is the link propagation delay, L is the amountof data transmitted, R is the data rate of the link, and is theassociated random delay jitter. Delay calculations can be madeon the assumptions that there are 10–12 phasor measurements,each 4 bytes in length, 10 input status channels, each 2 bytes inlength, and the combined delay caused by processing, concen-trators, multiplexing and transducers is estimated to be around75 msec. This is the ﬁxed delay and is independent of the com-munication medium used. The propagation delay is dependenton the medium and thus is a function of both the medium andthe physical distance separating the individual components ofWAMS. We have assumed that media like ﬁber-optic cables,power lines, and telephone lines, on an average, have a propaga-tion delay of around 25 ms. Considering the total length of thePMU packet, the delay caused due to the amount of data trans-mitted and the data rate can then be estimated to be around 125ms, considering a telephone line channel with an average ca-pacity of 33.6 kbps. In the case of substations, where isolationcircuits are required, the telephone line channel capacity coulddrop to as low as 9.6 kbps, creating a bottleneck, and therebyincreasing the delay to more than 200 ms. Even though powerlines can reach speeds of up to 4 Mbps.Standard communication systems are adequate for mostphasor data transmission. The issues for data communicationsinclude speed, latency, and reliability. Communication speed(data rate) depends on the amount of phasor data being sentand the number of messages. A PMU sending 10 phasors at 30messages has an actual data rate of about 17 kbps. Reliability inTABLE ITHE INTERCONNECTED AREASthis application includes both error rate and component failures.Such protection scheme suggested here needs to a very highmedia of communication system, the available data transfer canreach speed up to 2 Mpbs , .From above the proposed relay is evaluated as a backup relaysfrom the point of view data handling through the communicationchannels, in spite of the fast detection time estimated by 5 msecfor all fault cases.V. THE TECHNIQUE COMPONENTS BASED ON WIDE AREAMEASUREMENT SYSTEMThe primary purpose of these systems is to improvedisturbance monitoring and system event analysis. Thesemeasurements have been sited to monitor large generatingsites, major transmission paths, and signiﬁcant control points.Synchronized phasor measurements provide all signiﬁcant statemeasurements including voltage magnitude, voltage phaseangle, and frequency.Most of these phasor measurement systems have been imple-mented as real-time systems. With these systems, phasor mea-surement units (PMUs) installed at substations send data in realtime over dedicated communications channels to a data concen-trator at a utility control center. This approach allows the datato be used in System Protection Center (SPC) as well as beingrecorded for system analysis and monitored via SCADA systemas shown in Fig. 4.PMUs measure the bus voltage(s) and all the signiﬁcant linecurrents. These measurements are sent to a Phasor Data Con-centrator (PDC) at the control center. The PDC correlates thedata by time tag to create a system-wide measurement. The PDCexports these measurements as a data stream as soon as theyhave been received and correlated. System protection center(SPC) receive Data stream and make a wide area protection de-pending on wide area view. This principal of operation is usedin this paper. WAPS schemes are designed to detect abnormalsystem conditions, take pre-planned corrective actions intendedto minimize the risk of wide-area disruptions and isolate thefaulted segment from the over all power system. WAPS dependon WAMs to take hieratical action depending on wide area mon-itor of the over all network.VI. THE STUDIED NETWORKPart of the 500/220 kV Egyptian interconnected electricalnetwork is used for the study; ﬁve main buses that representﬁve different areas with 500 kV are selected to verify the sug-gested technique. The selected ﬁve different areas with busesare given in Table I. Fig. 5 shows the selected ﬁve areas from
274 IEEE TRANSACTIONS ON POWER DELIVERY, VOL. 25, NO. 1, JANUARY 2010Fig. 5. Single line diagram of the studied network.Fig. 6. Positive sequance current angles.TABLE IITHE LENGTHS AND ANGLESthe overall network. In the single line diagram, each bus repre-sents the selected area in the simulation that can connect the 500kV network with 220 kV network through three single phase500/220 kV power transformers. A sampling frequency of 20kHz for a system operating at a frequency of 50 Hz is used inthis study.Table II deﬁnes each transmission line that connecting twoneighboring areas. The lengths of the transmission lines aregiven in km. is deﬁned as the absolute difference be-tween positive sequence current angles measured at transmis-sion line terminals. Fig. 6 shows the positive sequence currentangles measured at transmission line terminals, from itsarea to the other connected area.VII. THE PROPOSED TECHNIQUEThe proposed technique is based mainly on two componentsto identify the faults on the transmission lines. The ﬁrst compo-nent is the voltage reduction due to fault occurrence. The secondcomponent is the power ﬂow direction after fault occurrence.The phase angle is used to determine the direction of fault cur-rent with respect to a reference quantity. The ability to differen-tiate between a fault in one direction or another is obtained bycomparing the phase angle of the operating voltage and current.The voltage is usually used as the reference polarizing quan-tity. The fault current phasor lies within two distinct forwardand backward regions with respect to the reference phasor, de-pending on the power system and fault conditions –.The normal power ﬂow in a given direction will result in thephase angle between the voltage and the current varying aroundits power factor angle . When power ﬂows in the oppositedirection, this angle will become . For a fault in thereverse direction, the phase angle of the current with respect tothe voltage will be .The main idea of the proposed technique is to identify thefaulted area. This can be achieved by comparing the measuredvalues of the positive sequence voltage magnitudes at the mainbus for each area. This can result in the minimum voltage valuethat indicates the nearest area to the fault. In addition to that, theabsolute differences of the positive sequence current angles arecalculated for all lines connected with the faulted area. Theseabsolute angles are compared to each other. The maximum ab-solute angle difference value is selected to identify the faultedline. The above two keys of operation can be mathematicallydescribed as follows:(1)where is the positive sequence voltage magnitude mea-sured by PMU and located at area “1”, “2”, “3” “m”, to “n”.For a fault occurred on the grid, the output from (1) is theminimum positive sequence voltage magnitude which indicatesthe nearest area to the fault. Suppose that the nearest area to the
EISSA et al.: A NOVEL BACK UP WIDE AREA PROTECTION TECHNIQUE FOR POWER TRANSMISSION GRIDS USING PHASOR MEASUREMENT UNIT 275Fig. 7. The logic implementation of the technique.fault is indicated by number “m”. The next step is to comparethe absolute differences of positive sequence current angles forall lines connecting area “m” with all other neighboring areasand then selecting the max one. This can be explained as(2)where is the absolute difference of positive sequencecurrent angle for a transmission line connecting area “m” witharea “n”. This can be described by the following equation:(3)The above process can be implemented logically in Fig. 7.The output of the logic action is the faulted line. The followingsub-sections will explain the stages of the proposed technique.VIII. OVERALL STAGES OF THE PROPOSED TECHNIQUEThe studied conﬁguration system is classiﬁed into 5 differentareas, the following section explain the main components of theproposed technique. Fig. 8 shows more details about the ele-ments used in the protection technique.A. Data Preparation (Bay Level)Each area contains one PMU which receives analog signalsfrom (CTs) and (VTs) in bay level.• Voltage transformers (VTs) on the main bus for each areareceive 3 phase voltage (Vabc) to the PMU.• Current transformers (CTs) on each line terminal receive3 phase current (Iabc) to the PMU.• PMU converts the analog voltage and current signals todigital samples synchronized in time of measuring, the Dis-crete Fourier Transform method inside PMU calculates thepositive sequence voltage and current phasors.Fig. 8. Matlab simulink block daigram.B. Output From PMUThe output signal from the PMU is the positive sequencevoltage and the positive sequence currents &nm nm respectively, wherePositive sequence voltage magnitude for area # n.: Positive sequence voltage angles for area # n.Positive sequence current magnitude for intercon-nected line between area # n and area # m.Positive sequence current angle for intercon-nected line between area # n and area # m.For the proposed technique, only positive sequence voltagemagnitudes and positive sequence current angles nmare selected.C. Phasor Data Concentrator PDCThe PDC is considered as a computer database that containsdata from ﬁve phasor measurement units (PMUs). Each PMUsends measuring data through fast communication system toPDC which correlates the data by time tag to create a system-wide measurement.D. System Protection Center SPCIn WAMs, the PMUs are strategically placed throughout awide coverage area. The PMUs form part of local devices calledsystem protection terminals (SPT). SPTs are able to run com-plete or parts of distributed control algorithms and can com-municate directly with other SPTs, substation equipment andsystem protection centers (SPC) which is responsible for pro-tection, monitoring and control of the power grid.E. Data Manipulation in SPCSPC receives data stream from PDC and provides a wide areaprotection depending on wide area view. In the SPC unit, themeasuring values of positive sequence voltage magnitudes are
276 IEEE TRANSACTIONS ON POWER DELIVERY, VOL. 25, NO. 1, JANUARY 2010Fig. 9. Three phase voltage signals at each area.compared, the minimum voltage magnitude is selected, and thenearest area to the fault is detected.IX. THRESHOLD BOUNDARYThe ﬁnal performance of the technique is identiﬁed by satis-fying two criteria. The ﬁrst criterion concerns the comparisonof the positive sequence voltage magnitudes at the bus and thenselecting the minimum voltage value that indicates the faultedarea. The voltage magnitude should go lower than setting valueamounted by 0.95 of the operating voltage. The second crite-rion is used to compare of the absolute difference of the positivesequence current angles and selecting the maximum one. Thisvalue should go higher than some positive threshold boundaryamounted by 100 . A trip output is produced when the abovetwo conditions are met. The ﬁnal trip logic combines the deci-sions using the AND gate logic shown in Fig. 7.X. CASE STUDYAn extensive series of study is examined on the power systemgiven in Fig. 8. All fault events are studied and a sample of theresults is given here. More details about the different cases offaults can be given in . As mentioned above, the studiednetwork is classiﬁed into 5 neighboring areas. The 5 areas areconnected with each others by six lines. Three phases to groundfault are located on line 1 which connecting area “1” with area“2”, see Fig. 8.Fault location is placed away from area “1” and area “2” by100 and 45 km respectively. The three phase voltage signals ateach area are recorded and displayed in Fig. 9. The three phasecurrent signals for all lines connected to the faulted area arerecorded and displayed in Fig. 10 as:• line 1 connecting area 2 with area 1;• line 3 connecting area 2 with area 3;• Line 5 connecting area 2 with area 4.Fig. 10. Three phase current signals for all lines connected to the faulted area(area “2”).Fig. 11. Positive sequence voltage magnitudes.Fig. 11 shows the output from the ﬁve PMUs, the graphshows the ﬁve positive sequence voltage magnitudes (PSVM)for ﬁve different areas during fault. The minimum value isselected which indicates the nearest area to the fault (area “2”).The next step is used to identify the faulted line. Fig. 12 showsthe absolute diffrences of positive sequance current angles(PSCA) for all lines connecting the faulted area (area “2”) withall other neighboring areas (areas “1”, “3”, “4”). The graphshows the maximum absolute difference of positive sequencecurrrent angle (about 175 ) that refers to line 1. The time takento reach the threshold voltage is about 4 ms. While the timetaken to reach the threshold angle is 3 ms, then the fault canbe detected in about 4 ms. A single phase to ground fault islocated on transmission line TL3, see Fig. 8, which connectingarea “2” (Kurimat) with area “3” (Cairo 500). The distancebetween fault location on the transmission line and the nearest
EISSA et al.: A NOVEL BACK UP WIDE AREA PROTECTION TECHNIQUE FOR POWER TRANSMISSION GRIDS USING PHASOR MEASUREMENT UNIT 277Fig. 12. Positive sequance current angle absolute differences for all lines con-nected to the faulted area (area “2”).Fig. 13. Positive sequence voltage magnitudes measured from ﬁve places onthe network.Kurimat bus is 20 km. The 3-phase voltage signals measuredfrom Kurimat bus are recorded. The 3-phase current signals forall transmission lines connected to Kurimat are also recorded.Fig. 13 shows the ﬁve PSVM (Positive Sequence VoltageMagnitudes). The minimum value is selected to indicate thatthe nearest area to the fault is area “2”. Fig. 14 shows the ab-solute differences of PSCA (Positive Sequence Current Angles)for all lines connecting the faulted area “2” with all other neigh-boring areas “1”, “3” and “4”. The angles difference of TL3 isthe maximum value given by 160 . This means that the currentis reversed from one terminal only. It is clear that the fault isinternal and this transmission line must be isolated. The ﬁguresalso show the threshold boundary.A double-phase to ground fault is located on transmissionline TL1, see Fig. 8. The distance between the fault point on thetransmission line and the nearest bus “Samalout” is 45 km. The3-phase voltage signals measured from area “1” are recorded.The 3-phase current signals for all transmission lines connectedwith “Samalout” are also recorded. Fig. 15 shows the ﬁvePSVM for ﬁve different areas during the fault. The minimumFig. 14. Positive sequence current angles (absolute difference) for all lines con-nected to area “2”.Fig. 15. Positive sequence voltage magnitudes measured from ﬁve places onthe network.Fig. 16. Positive sequence current angles (absolute difference) for all lines con-nected to area “1”.value is selected to identify the nearest area to the fault as area“1”. Fig. 16 shows the absolute differences of PSCAs for alllines connecting area “1” with all other neighboring areas (area“2” and area “3”). The angles difference measured at the trans-mission line terminals (TL1) recorded maximum difference by
278 IEEE TRANSACTIONS ON POWER DELIVERY, VOL. 25, NO. 1, JANUARY 2010170 . This means that the current is reversed from one terminalonly. It is clear that the fault is internal and the transmissionline must be isolated. Figs. 15 and 16 show also the thresholdboundary with time estimated by 3 msec.XI. CONCLUSIONThe paper presents a new protection technique for transmis-sion grids using phasor synchronized measuring technique in awide area system. The protection scheme has successfully iden-tiﬁed the faulted line allover the interconnect system. The relaydescried in this paper represents a new state-of-art in the ﬁeldof interconnected grid protection for many reasons.• The relay is based on sharing data from all areas.• One relay is used instead of many stand alone relays withdifferent complexity coordination.• The relay has the feature of unit protection in identifyingthe faulted zone.• One and only one trip decision is issued from the protectioncenter.The relay has a very fast detection time estimated by 5 msecfor all fault cases. In the near future and with a very fast com-munication links the relay can be considered as a main relay onthe interconnected grids.REFERENCES Wide Area Protection and Emergency Control, 2002, IEEE Members,Working Group C-6. U. Serizawa, M. Myoujin, K. Kitamura, and N. Sugaya, “Wide areacurrent differential backup protection employing broadband commu-nication and time transfer systems,” IEEE Trans. Power Del., vol. 13,no. 4, pp. 427–433, Oct. 1998. C.-S. Chen, C.-W. Liu, and J.-A. Jiang, “A new adaptive PMU basedprotection scheme for transposed/untransposed parallel transmissionlines,” IEEE Trans. Power Del., vol. 17, no. 2, pp. 395–404, Apr. 2002. Y.-H. Lin, C.-W. Liu, and C.-S. Chen, “A new PMU-based faultdetection/location technique for transmission lines with considerationof arcing fault discrimination—Part I: Theory and algorithms,” IEEETrans. Power Del., vol. 19, no. 4, pp. 1587–1593, Oct. 2004. C.-S. Yu, C.-W. Liu, S.-L. Yu, and J.-A. Jiang, “A new PMU-basedfault location algorithm for series compensated lines,” IEEE Trans.Power Del., vol. 17, no. 1, pp. 33–46, Jan. 2002. J. Tang and P. G. McLaren, “A wide area differential backup protectionscheme for Shipboard application,” IEEE Trans. Power Del., vol. 21,no. 3, Jul. 2006. S. H. Horowitz and A. G. Phake, Power System Relaying. Taunton,Somerset, U.K.: Research Studies Press, 1992. M. M. Eissa, “New principle for transmission line protection usingphase portrait plane,” IET Gener. Transm. Distrib., vol. 3, no. 1, pp.49–56, 2009. D.-Q. Wang, S.-H. Miao, X.-N. Lin, P. Liu, Y.-X. Wu, and D. Yang,“Design of a novel wide-area backup protection system,” in Proc.IEEE/PES Transm. Distrib. Conf. Exhib.: Asia Pac. Dalian, China,2005, pp. 1–6. B. Naduvathuparambil, M. C. Valenti, and A. Feliachi, Communicationdelays in wide area measurement systems Lane Dept. of Comp. Sci. &Elect. Eng., West Virginia University, Morgantown, WV, 26506-6109,2002. R. Klump and R. E. Wilson, “Visualizing real-time security threatsusing hybrid SCADA/PMU measurement displays,” in Proc. 38thHawaii Int. Conf. System Sci., 2005, p. 55c. M. M. Eissa, “Development and investigation of a new high-speed di-rectional relay using ﬁeld data,” IEEE Trans. Power Del., vol. 23, no.3, pp. 1302–1309, Jul. 2008. M. M. Eissa, “A new digital feed circuit protection using directionalelement,” IEEE Trans. Power Del., vol. 24, no. 2, pp. 531–537, Apr.2009. M. M. Eissa, “Evaluation of a new current directional protection tech-nique using ﬁeld data,” IEEE Trans. Power Del., vol. 20, no. 2, pp.566–572, Jul. 2005. , “Protection of Interconnected Electrical Networks Using Phasor Syn-chronized Measuring Technique,” Ph.D. dissertation, Helwan Univer-sity-Faculty of Engineering at Helwan, Cairo, Egypt.M. M. Eissa (M’96–SM’01) was born in Helwan, Cairo, Egypt, on May 17,1963. He received the B.Sc. and M.Sc. degrees in electrical engineering fromHelwan University, Cairo, Egypt, in 1986 and 1992, respectively, and the Ph.D.degree from the Research Institute for Measurements and Computing Tech-niques, Hungarian Academy of Science, Budapest, Hungary, in 1997.He is a Professor at Helwan University. In 1999, he was invited to be a Vis-iting Research Fellow at the University of Calgary, Calgary, AB, Canada. Hisresearch interests include digital relaying, application of widearea networkingto power systems, power quality and energy management, and wide-areaprotection.Dr. Eissa received the Egyptian State Encouragement Prize in advancedscience in 2002 and the Best Research in advanced engineering science fromHelwan University in 2005.M. E. Masoud, photograph and biography not available at the time ofpublication.M. M. M. Elanwar, photograph and biography not available at the time ofpublication.