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adaptive protection scheme for distribution systems with high penetration of distributed generation


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IEEE TRANSACTIONS ON POWER DELIVERY, VOL. 19, NO. 1, JANUARY 2004

Development of Adaptive Protection Scheme for Distribution Systems With High Penetration of Distributed Generation
Sukumar M. Brahma, Student Member, IEEE, and Adly A. Girgis, Fellow, IEEE
Abstract—Conventional power distribution system is radial in nature, characterized by a single source feeding a network of downstream feeders. Protection scheme for distribution system, primarily consisting of fuses and reclosers and, in some cases, relays, has traditionally been designed assuming the system to be radial. After connecting distributed generation (DG), part of the system may no longer be radial, which means the coordination might not hold. The effect of DG on coordination will depend on size, type, and placement of DG. This paper explores the effect of high DG penetration on protective device coordination and suggests an adaptive protection scheme as a solution to the problems identified. Results of implementation of this scheme on a simulated actual distribution feeder are reported. Index Terms—Fuse, phasor measurement unit, power distribution system, protective device coordination, recloser, short-circuit analysis.
Transmission system

Load 5 Load 2 Load 1
DG1 DG3 DG4

Load 3
Fig. 1.

DG2

Load 6 Load 4

Distribution system of near future.

I. INTRODUCTION

T

HE NATURE of distribution system has traditionally been radial and unbalanced. It consists of a network of singlephase, two-phase and three-phase line sections. The load at the bus can also be unbalanced. Hence, all analysis of distribution system has been essentially the analysis of an unbalanced three-phase network fed by a single three-phase source. The protection system predominantly uses reclosers on main feeder coordinating with fuses on laterals. Each fuse coordinates with the immediate upstream and/or downstream section-fuse. Reclosers are necessary in a distribution system since 80% of all faults taking place in distribution system are temporary. Reclosers give a temporary fault a chance to clear before letting a fuse to blow. An inverse overcurrent relay is usually at the substation where the feeder originates. The coordination between fuses, reclosers and relays is well established and done assuming the system to be radial [1]–[5]. Distributed generation (DG) is by definition generation which is of limited size (few kilowatts to few megawatts) and interconnected at substation, distribution feeder or customer load level [6]–[10]. DG technologies include photovoltaics, wind turbines, fuel cells, micro turbines, gas turbines and internal combustion
Manuscript received October 7, 2002. This work was supported by The Clemson University Electric Power Research Association (CUEPRA). S. Brahma is with the Electrical Engineering Department, Widener University, Chester, PA 19013 USA (e-mail: sukumar.m.brahma@widener.edu). A. Girgis is with the Electrical and Computer Engineering Department, Clemson University, Clemson, SC 29634 USA (e-mail: adly.girgis@ces.clemson.edu). Digital Object Identifier 10.1109/TPWRD.2003.820204

engines [7], [8], [10]. Cost of transmission and distribution is rising, but the costs of DG technologies are falling. This makes it more economical to meet an increase of load by connecting DG to distribution feeders rather than expanding tansmission and distribution (T&D) facilities [9]. Therefore, these technologies are entering a period of rapid expansion and commercialization and studies have predicted that DG may account up to 20% of all new generation going on line by year 2010 [6]. This means that distribution system in the near future would look something like the one shown in Fig. 1. In such a system, DG would feed loads around its location, thus relieving the burden on the source. This clearly suggests that the basic assumption of distribution system being radial is not likely to hold in near future. One would then be looking at a multisource unbalanced system. It is a well-established fact that protection devices in a multisource system have to be direction sensitive [3]–[5]. Fuses and conventional reclosers do not have directional features, whereas relays can be easily made direction sensitive. It would be economically impractical to replace all fuses and reclosers by direction-sensitive protective devices (like relays) all through the distribution system. Therefore, a detailed analysis is required to identify exactly the problems in fuse-fuse and fuse-recloser coordination due to high penetration of DG. Once the problems are identified, solutions need to be sought which are practically acceptable and independent of size, number, and placement of DG in the distribution system. Hadjsaid et al. [11] show through a simple example that fault currents through protective devices would change after introduction of DG. They further suggest checking protection selectivity for each new connection of DG. However, this

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BRAHMA AND GIRGIS: DEVELOPMENT OF ADAPTIVE PROTECTION SCHEME FOR DISTRIBUTION SYSTEMS

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1 From Source F1

2

Z1 B1-2
Flt 2 3 DG
(a)

Z4 B4-5 B2-5 Z5 B5-6 Z6

Flt1

F2

S/S B S-1

Z2 B2-3 Z3

F3

B3-5

Main Distribution Line

Fig. 3. Distribution system divided in breaker-separated zones.

S

R

Source

Recloser
DG

Tapped Line Load Current

(b)

Fig. 2.

Typical cases affecting fuse-fuse and fuse-recloser coordination.

solution would work only if DG penetration is low. Girgis and Brahma [12] and Brahma and Girgis [13] look closely at the coordination problem between fuses. A typical case is shown and are coordinated for downstream in Fig. 2(a). Fuses faults on feeder 2–3 without DG. Now, if DG connects to the system as shown in Fig. 2(a), these fuses will see the same (downstream) or fault (upstream). current for fault , selectivity requires that operates before and for For , should operate before . References [12] and [13] show through coordination graphs that this cannot be achieved. Reference [13] analyzes part of an actual distribution system to identify some more potential cases of malcoordination that depend on size and placement of DG in system. It concludes that, in general, if protection scheme is not changed, the only way to maintain coordination in presence of arbitrary DG penetration is to disconnect all DG instantaneously in case of fault. This would enable the system to regain its radial nature and coordination would withhold. But this would mean that DG is disconnected even for temporary faults. Girgis and Brahma [12] and Brahma and Girgis [14] discuss fuse-recloser coordination in presence of DG. A typical case is shown in Fig. 2(b). Recloser and fuse are coordinated for a fault on tapped lateral without DG. Now DG is connected somewhere between the recloser and the fuse. In such a case, naturally, for a fault on lateral, fuse will see more current than recloser. This can result into coordination being lost between these devices. Moreover, the recloser would now see fault current for upstream faults too. Reference [14] discusses this situation in detail and concludes that the coordination in the presence of DG can be achieved with microprocessor-based reclosers available in the market. This recloser has to be made directional toward the downstream side of feeder. But in this case too, all DG down-

stream of the recloser has to be disconnected before the first reclose takes place to avoid connection without synchronism. These solutions are not practical. As mentioned earlier, DG is getting popular because it can serve the load without adding to T&D burden. Throwing off all DG from system every time a temporary fault occurs would make the system very unreliable. This paper offers a comprehensive, system-independent adaptive protection scheme for distribution systems with high DG penetration that would not undermine the system reliability after connecting DG. Sections II—IV describe the scheme and its implementation in detail. II. PROPOSED SCHEME A. Outline of Scheme The ideal situation for any protection scheme is to isolate only the faulted section from the system. In this case, this is impossible, since the section-controlling protective device is a fuse here and as explained in Section I, coordination between fuses is lost in presence of DG. Moreover, fuses cannot be controlled by an external signal. Therefore, they will not respond to some tripping signal generated by say, a relay. The next best approach is to divide the system into zones as shown in Fig. 3. A zone should be formed such that it has a reasonable balance of load and DG, DG capacity being a little more than the load. In addition to this, at least one DG (usually the biggest in the zone) should have load frequency control capability. As shown in Fig. 3, these zones should be separated by breakers. These breakers should be capable to repeatedly open or close on receiving a signal from a main relay located in the substation. Most manufacturers make breakers and reclosers with remote communication capability. The breakers should also be equipped with check-synchronization function. The main relay would be computer-based, capable of storing and analyzing large data and able to communicate with other devices like zone breakers and DG relays. The relay would sense a fault, identify the type of fault and the faulted section (and, hence, zone) on line, and isolate the faulted zone by tripping appropriate breakers and DG connected to this zone. This way, the remaining zones can still function as usual. Reclosing to take care of temporary faults would be performed by main relay itself as explained later in Section II-F. The following subsections explain the scheme in detail.

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IEEE TRANSACTIONS ON POWER DELIVERY, VOL. 19, NO. 1, JANUARY 2004

B. Measurements The first requirement for a protection scheme is the actuating input. This comes through measurement. The following continuous measurements are recommended for this scheme: ? synchronized current vectors for all three phases from every DG in the system and from the main source; ? a signal indicating current direction in every zone-forming breakers. Synchronized vector measurement using a synchronizing clock pulse from global positioning system (GPS) receiver and phase measurement unit (PMU) is described and used by J. Jiang et al. [15]–[17]. It is possible to achieve a synchronization with this method. accuracy of better than 1 C. Off Line Calculations and Data Storage This method requires a load flow study and a complete shortcircuit analysis for all types of faults involving different phases. In addition to fault current for different types of faults at each bus, this analysis should also find out fault current contribution from each DG and from the main source. The method also requires the minimum melting (MM) characteristics of all fuses in the system to be stored in the relay database. From these characteristics and short-circuit analysis, the time before some fuse in the system gets damaged in case of fault can be determined. Significance of this time will be mentioned in Section II-F. However, as explained later in section III, this requirement can be avoided altogether. The load flow and the short-circuit analysis need to be updated after every significant change in load, DG, or the system configuration. Whereas a change in load and/or DG would require to merely run the load flow and the short-circuit analysis again, any change in the system configuration (say, taking off a line) would require to update the bus admittance and impedance matrices as well. These are routine procedures supported by software used by utilities. With modern computing power and memory, the off line calculations and data storage would not be a concern. D. Sensing Fault and Determining Fault Type On Line Current phasors from the main source and all DG are continuously available. In normal operating condition, the sum of all these phasors would be equal to the total load on system. In case of a fault on any part of system, this sum would exceed the total load substantially. This is how the relay would sense a fault in the distribution system. This in a way is similar to a current differential scheme. The monitored zone here is the distribution system itself. When there is a fault anywhere in the system, the sum of the current contributions from all sources (the main source and all DG) would be equal to the fault current. On the other hand, if there is a fault in a DG, since the DG is outside the monitored zone, the sum would be zero. This is how a fault in DG can be distinguished from a fault in the system. Once a fault in the system is sensed, total fault current in each phase can be determined using the following simple equation: (1)

is the total fault current (phasors) in three phases where is the fault current contribution (phasors) in and three phases from source . “ ” is the total number of sources (including the main source) in system. It should be noted here that this paper will count the main substation source and every DG simply as “source” henceforth. Since fault current magnitude can be found in each phase from (1), fault type and phases involved in fault can be immediately and easily determined on line. E. Identifying the Faulted Section On Line Determining the faulted section of a distribution network on line has traditionally been done with protective devices (mainly fuses). In this case, coordination between fuses is lost and there is a need to find the faulted section (and, hence, zone) before any fuse is damaged. Abe et al. [18] discuss the determination of the faulted section and fault location in a multisource transmission line. But this kind of system is only a small subset of a multisource unbalanced distribution network considered here. Cardozo et al. [19] and Girgis et al. [20] discuss methods to locate faults in interconnected transmission networks. The nature of such network is similar (except that transmission networks are balanced) to the nature of the system being considered here. But the methods deal with fault location after the protective devices have operated. Hence, these methods cannot be modified for on line fault location in unbalanced distribution system. Therefore, a method is required to quickly identify the faulted section in order for the relay to give tripping signals to appropriate breakers for isolating the faulted zone. It should be mentioned here that identification of the faulted zone is enough for this scheme to work. However, if the faulted section was not identified as accurately as possible, it would be a huge burden for the maintenance staff to locate the fault. Since the fault contribution from each source is available on line, it can be used for this purpose. Total fault current is the sum of fault contributions from all sources in the system. From the fault point, every source can be represented as a voltage source behind a Thevnin impedance. If the fault point shifts from one bus to the adjoining bus, for a given type of fault, Thevnin impedance to a given source can either increase or decrease. Thus, as shown in Fig. 4, if the fault point shifts over a section ( – ) from one bus ( ) to another ( ), for a given type of fault, the fault current contribution from any given source can either continuously increase (IFMIN to IFMAX) or continuously decrease (IFMAX to IFMIN ). Thus, the fault contribution from source “ ” for a given type of fault occurring at any point between bus and bus will always lie between the contributions from source “ ” to the same type of fault on bus and bus . This means that for a given type of fault on some section, the fault contribution from each source must lie between contributions from that source for same type of fault on buses connected to this section. Fault current contribution from each source for every type of fault for all buses is already known from off line short-circuit analysis. Using this network property and the results of short-circuit analysis, the faulted section can be identified as the section for which the measured fault contribution from each source is between the calculated fault contributions

i

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Fault contribution from source ‘k’(A)

start

IFMAX’

IFMAX

Read System Data Run Load Flow Run short circuit analysis for all types of faults Involving different phases Form a look-up table containing contribution form each source to each type of fault at each bus. (Select maximum current of three phases.)

IFMIN’ IFMIN 0 Length of a line section i-j (PU) bus i 1 bus j

Fig. 4. Nature of fault contribution from a source “k” to a given type of fault on a line section between bus i and bus j.

at the two buses connected to this section from that source for a given type of fault. As will be explained by an example system in Section III, when the number of DG increases in the system and system loses its radial nature in most parts, this method is very effective. F. Clearing and Restoring the Faulted Zone Once the faulted section is identified, the relay would send a trip signal to isolate the faulted zone and DG in this zone. The knowledge about the breakers to be tripped to isolate a particular zone is already in the database. For example, in Fig. 3, zone can be isolated by tripping breaker whereas breakers , , , would have to be tripped to isolate zone . This process is desired to be over before any fuse in the system is damaged. The method of calculating this safe time was discussed in Section II-C. The complete scheme operation, which consists of getting measurements, identifying the faulted section, and tripping the breakers should be complete before this time. Since scheme operation time can be estimated (explained in more detail in Section III), relay can implement this check on itself every time short-circuit analysis is updated. Once the faulted zone and the DG connected to it are isolated, the next step is to ensure restoration in case of temporary faults. The isolated zone is “dead,” so we can test if the fault persists or not by making one of the zone-forming breakers on. This would ensure there is no synchronization problem. One breaker for each zone should be identified in advance for this job. For example, let us identify a breaker for each zone that enables the main source to contribute to that zone. In Fig. 3, this would mean for , for , for , for , for , and for . Relay should perform reclosing action on one of these breakers depending on which zone is faulted. Since there is no fuse-recloser coordination here, the relay should open the breaker instantaneously in case the fault persists. Since relay monitors current contribution from main source continuously, it would immediately detect, after each reclosing action, whether fault persists or not (source current would substantially increase if fault persists). In case the fault disappears, relay would send closing signals one-by-one to each breaker. These breakers need to perform synchronized closing. This would be ensured by the check-synchronizing function incorporated with each breaker. Relay would sense the closing of each breaker by monitoring

Decide safe time before faulted zone must be isolated. Use short circuit results and fuse MM characteristics for this stop

Fig. 5.

Off line tasks to be performed by the proposed relay.

the current direction signal from that breaker. The next closing signal would be sent only after this confirmation. Finally, DG breaker would be closed and system restored to normal. In case of a permanent fault, the fault would have to be cleared by maintenance personnel before incorporating that zone back to the system. In such cases, relay will adapt to the new network configuration by running a load flow and short-circuit analysis again. There is a possibility here that some part of system may be islanded after disconnection of one zone. In Fig. 3, this would or are faulted. Since load and generhappen when either ation are balanced in each zone and at least one DG in each zone has load frequency control capability, such islands can continue to function. G. Sources and Handling of Error The source of error in this scheme can be fault resistance. Since the short-circuit analysis is made with zero fault resistance value, a fault with resistance may produce currents which would lead to the predicted section being adjacent to (or even farther than) the actual faulted section. If the adjacent section still lies in the same zone, relay would still operate correctly. In case this section lies in a different zone, there is a chance of mal-operation. Therefore, the relay should get a signal indicating current direction from each zone-forming breaker as explained in Section II-B. With the help of this signal, relay can crosscheck before tripping a zone. Flowcharts given in Figs. 5 and Fig. 6 sum up the off line and on line calculations, respectively. There is a reason to believe that the error due to fault resistance would be mostly negligible. Burke [21] reports a four-year fault study performed in the U.S. on 50 feeders from 13 utilities at various voltage levels. It is concluded by the closeness of actual and calculated values that there was essentially no fault resistance observed in the recorded faults. This reference also states that the readings could be even closer had there been

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start

J=1 J=J+1 Select section J

Get three phase current measurements from all sources and sum them up

K=1 K=K+1 Select measured contribution (maximum phase current) from source K. Call it IMK

Yes Fault is in DG. Let it clear.

Is the sum zero? From look-up table, find contributions from source K for this type of fault on buses connected to section J. Call these values IFRJ and ITOJ

No

Is the sum significantly greater than total load?

No

No

Is IMK between IFRJ and ITOJ?

Yes This is fault Determine type of fault

Yes

Is K= Total number of sources?

No

Perform reclosing operations on one breaker and determine if the fault is temporary or permanent

Yes Faulted section is J

Is fault temporary?

No Open breakers that isolate faulted zone Update system data

Cross-check with current-direction input Trip breakers to remove faulted zone and DG in this zone Open Yes substation breaker Stop

Yes

Close zone breakers one-by one and connect DG back Go to Start

No

Is fault still sensed?

Do off-line analysis

A

Fig. 6. On line tasks to be performed by the proposed relay.

no calculation error due to use of sequence component method on an essentially unbalanced distribution network. This is why three-phase fault analysis was used for fault calculations done on the system analyzed in Section III of this paper. The error in phasor estimation due to measurement, systemnoise as well as frequency fluctuation resulting from system unbalance and synchronizing would be insignificant with PMU implementation described in [17].

III. TEST SYSTEM AND SIMULATION RESULTS As it is clear from discussion in the previous section, this scheme needs current contributions from all sources for all types of faults involving different phases. Most conventional software

available in market take system data in terms of sequence impedances. This does not fulfill the requirements of an unbalanced and untransposed distribution network. Therefore, shortcircuit analysis software was developed based on three-phase analysis. This software was tested first on a 22-bus balanced multisource system. Results with conventional sequence component techniques matched exactly with results using the threephase algorithm. Then an actual 60-bus distribution feeder from a utility in the southeast U.S. was taken as a test system. Fig. 7 shows the single line diagram, locations of reclosers, fuses, and DG, as well as DG capacities. Load details are given in the Appendix. DG shown in Fig. 7 are assumed and their capacities are selected such that they feed some load around their location. The feeder load is 2.5 MVA and the total load fed by all DG is 45%.

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BRAHMA AND GIRGIS: DEVELOPMENT OF ADAPTIVE PROTECTION SCHEME FOR DISTRIBUTION SYSTEMS

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103

Co-ordination of 140A Recloser-1 and 30 A Fuse

102

30A TC 30A MM Coordination Range Without DG Coordination Range With DG

TIME (SEC)

101

100

Recloser 'C' Recloser 'A'

10-1

10-2 101

102

103 CURRENT (A)

104

105

(a)

Fig. 7. Single line diagram of an actual distribution feeder simulated to test the performance of the adaptive scheme.

103

Co-ordination of 25A Recloser-2 and 25A Fuse

DG were modeled as sources behind reactances and the interconnecting transformers were considered D/YG. DG and transformer reactances were chosen using [6] and [22]. As shown in Fig. 7, this system has two reclosers on main is 25 A) and laterals are protected feeder ( is 140 A and by fuses. In addition to fuses shown in this diagram, load on each bus is tapped off with a fuse. The section fuses coordinate coordinates with section fuses downwith these load fuses. and upstream of . coordinates with section stream of coordinates with for fuses downstream of . In addition, faults downstream of . After connecting DG to this system as shown, the fuse coordination between fuses protecting sections 56–59 and 59–60 is clearly lost as explained in Section I. Similar is the case with sections 35–36 and 36–37. Fig. 8(a) shows cowith 30-A fuse on section 8–16 and Fig. 8(b) ordination of shows coordination of with 25-A fuses on sections 35–36 and 35–42. Curve “A” is the fast curve and “C” the slow curve of reclosers. “MM” stands for minimum melting and “TC” for total clearing characteristics of fuse. Clearly, the coordination with the fast curve is lost after connecting DG. It is possible to get this coordination back using microprocessor-based recloser looking only in downstream direction [14]. But this would mean that for every temporary fault downstream of , DG1 and DG5 would be cut off and for every temporary fault downstream of and upstream of , all DG is cut off. This could not be an acceptable solution as explained in Section I. Success of implementation of the scheme described in Section II essentially depends on the ability of relay to accurately identify the faulted section and, hence, the faulted zone. As mentioned in Section II-E, the proposed method is very effective when the number of sources increases. This can be justified through a simple example on the test system. Thevnin impedance to main source for fault points on section 7–8 and 7–24 can be same. This means that the main source contribution to a given type of fault in these two sections could be identical. Thus, with only main source in this system, the proposed method would confuse between these sections. However, Thevnin impedances for such fault points to any of the five DG cannot be the same. Thus, these sections would be distinguished by checking contribution from any of the DG. Natural extension

102 25A MM TIME (SEC) 101 25A TC Coordination Range Without DG Coordination Range With DG

Recloser 'C' 100

10-1 Recloser 'A' 10-2 101

102

103 CURRENT (A)

104

105

(b)

Fig. 8.

Coordination between reclosers and fuses with and without DG.

of this argument leads to a conclusion that if a section has fault current flowing from both the connecting buses, the proposed method would certainly identify this section correctly as faulted section. This means that in nonradial parts of the system, this method will never fail. In the parts of system which still remain radial despite the connection of DG, if two sections have different Thevnin impedances to at least one source, these two sections cannot be confused. For example, sections between buses 42–47 still remain radial. But Thevnin impedances of points in different sections to any of the sources are different. In other words, fault current flowing from any of the sources to any one of these sections would never be the same as that in another section. This means that confusion is possible only if a part of system is radial and there are taps. For example, points on sections 51–53 and 51–52 can have same value of Thevnin impedance to any source. The results of application of the proposed scheme to this test system confirm this reasoning. Test data were obtained by creating all types of faults (namely, L–L–L, L–L, L–L–G, L–G) involving different phases on three equidistant points on each section. Due to unbalance, the same type of fault involving different phases would give different values of fault currents. These test data were fed to the relay algorithm. The only sections confused were 4–5 with 4–6; 49–51 with 49–50; 51–53 with 51–52 and 51–53 with 43–44. The confusion between 51–53 and 43–44

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TABLE I DEPENDENCE OF ACCURACY OF PROPOSED METHOD ON NUMBER OF DG CONNECTED IN THE SYSTEM

IV. OBSERVATIONS There is always a chance of malfunction in any scheme. In this scheme, there is a chance that one of the breakers does not open after getting a command from the relay to isolate the faulted zone. In this case, since the fault is not isolated, the relay will continue to sense the fault. In such a case, the relay should disconnect the whole feeder by opening the breaker at the substation. The flowchart in Fig. 6 includes this possibility. In case the substation breaker fails to operate, the breaker on the high voltage side of the distribution transformer will open. The scheme covers all types of faults normally occurring in a distribution system. In case of two simultaneous faults in the same zone (very rare), the relay will still trip the zone using the current direction signal from breakers, but will fail to detect the faulted section. In case the faults occur simultaneously in different zones, after clearing one zone, the relay will still sense a fault. It will open the substation breaker in such a case. In case of open conductor fault, if the unbalance created is substantial, the relay can sense it (though it cannot sense the faulted zone) and isolate the feeder. Otherwise, such a fault would be undetected, as is the case in conventional protection schemes for distribution systems. Hart et al. [24] conclude that considering the operating cost and the connection speed, wire- or fiber-based systems are viable alternatives (telephone lines are too slow) for communication of data in PMU-based schemes. If such a connection already exists between DG and substation, part of the bandwidth can be used for relaying. The installation cost incurred by this scheme would certainly be higher because it introduces many new components in the system, but once installed, the maintenance cost would be quite reasonable. The installation of measuring and processing equipment can certainly be managed by utility engineers after training. The accuracy of fault sensing and section detection depends mainly on the accuracy of PMU and on the relay algorithm. The accuracy of PMU has been practically tested [17]. The relay algorithm, instead of being based on some heuristic method (e.g., neural network), is derived from simple and proven circuit fundamentals. Therefore, there is no apparent reason why the scheme cannot be successfully implemented. It should be noted here that many utilities model their distribution network as a single line network (assuming it balanced) for load flow and short-circuit analysis. This will increase the error in section identification but will not render the scheme useless. V. CONCLUSION Current trend and literature show that distributed generation is going to increase significantly in the coming years. Coordination between fuses and between fuses and reclosers in a distribution system can be disrupted with substantial penetration of distributed generation. The methods proposed in literature to solve the problem are not satisfactory from operational point of view. The adaptive scheme proposed here offers a practically acceptable solution to this problem that is independent of size, number, and placement of DG in the distribution system. The proposed scheme is adaptive to temporary as well as permanent changes

DG connected in system none one two three four five

Accuracy L-L-L % 30.5 61.8 77.8 94.4 95.1 97.9

Accuracy L-L % 26.6 52.7 65.5 83.0 86.1 93.9

Accuracy L-L-G % 26.6 52.7 65.5 83.0 86.1 93.9

Accuracy L-G % 26.6 52.7 65.5 83.0 86.1 93.9

was observed only for one data sample whereas for the other pairs, all three data samples gave wrong results. This confusion is not serious from the point of view of the relay scheme since such confused sections, being radial, cannot be parts of two different zones. Therefore, the relay would still trip the right zone. Moreover, such confusions can be predicted beforehand from network topology, thus making the maintenance task easier. Table I shows how accuracy of this method increased with more DG being added to the system. Accuracy in Table I is the successful identifications as percentage of total data samples. Essentially, the confused sections remain same as mentioned before, but since there is some confusion in two-phase sections where L–L–L fault data are not applicable, accuracy in case of L–L–L fault is higher. The algorithm to locate the faulted section was also tested on two more distribution systems with 21 and 47 buses, respectively. The results perfectly conformed to the observations made in the previous paragraphs. The data of these systems can be made available upon request. From the DG capacities given in Fig. 7 and loads given in the Appendix, this test system can be divided into four zones, each zone having one/more sources and adjoining buses (The guidelines followed here are described in Section II-A.) Zone 1 would include DG3, zone2 would have DG2, zone3 would have DG1 and DG5, and zone 4 would have main source and DG4. In this case, islands would be formed only when there is a fault in zone 4. From short-circuit analysis with DG and the minimum melting characteristic of fuses in the system, it was found that in the worst fault case, the time before a fuse can be damaged in the system was about 55 ms. Phasor identification in PMU can take between quarter of a cycle [23] to one cycle [17]. Time taken by the relay to sense a fault using measurements coming from PMU, identify the faulted section (it just involves referring to a lookup table) and send trip signal is insignificantly small. Hence, the zone breaker and DG breakers in the faulted zone can be tripped well before this time. This applies to opening the breaker after each reclosing too. In the above analysis, care is taken to make sure none of the fuses gets damaged during the operation of scheme. In fact, since fuses are no longer coordinated in an environment with DG, it is even possible (and recommended) to remove all fuses from the area covered by this scheme. This will no longer require the time constraint explained in the previous section and last step in the flowchart in Fig. 5.

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BRAHMA AND GIRGIS: DEVELOPMENT OF ADAPTIVE PROTECTION SCHEME FOR DISTRIBUTION SYSTEMS

63

TABLE II LOAD DATA FOR THE TEST SYSTEM USED

in distribution network and its region of implementation can be extended to more than one feeder. Loss of load in the distribution system in case of a permanent fault would reduce in most cases after the implementation of this scheme. The scheme will not work well for systems with low DG penetration, but coordination in such systems will not be lost in most cases, and even if it is lost, solutions already reported in the literature could be used since DG would not be crucial for reliability. APPENDIX Table II shows the load data of the test system considered in this paper. Phase details of the buses can be obtained from Fig. 7. REFERENCES
[1] Overcurrent Protection for Distribution Systems, Application manual GET-1751A, General Electric Company, 1962. [2] IEEE Power System Relaying Committee report, “Distribution line protection practices: Industry survey analysis,” IEEE Trans. Power App. Syst., vol. PAS-102, pp. 3279–3287, 1983. [3] M. A. Anthony, Electric Power System Protection and Coordination. New York: McGraw-Hill, 1995, pp. 109–121, 342-346. [4] J. L. Blackburn, Protective Relaying Principles and Applications. New York: Marcel Dekker, 1998, pp. 383–408. [5] P. M. Anderson, Power System Protection. New York: IEEE Press, 1999, pp. 201–240, 249-257. [6] P. Barker and R. W. de Mello, “Determining the impact of distributed generation on power systems: Part 1—Radial power systems,” in Proc. IEEE Power Eng. Soc. Summer Power Meeting, 2000, pp. 1645–1658. [7] U.S. Department of Energy’s distributed power program homepage, Online Available:, http://www.eren.doe.gov/der/basics.html. [8] Portfolio of DG Technologies. [Online]http://www.distributed-generation.com/technologies. html [9] H. L. Willis and W. G. Scott, Distributed Power Generation Planning and Evaluation. New York: Marcel Dekker, 2000. [10] “Role of distributed generation in competitive energy markets,” Gas Res. Inst., Rep. GRI-99/0054, Chicago, IL, http://griweb.gastechnology.org/pub/solutions/dg/distgen.pdf. [11] N. Hadjsaid, J. Canard, and F. Dumas, “Dispersed generation impact on distribution networks,” IEEE Comput. Appl. Power, vol. 12, pp. 22–28, Apr. 1999.

[12] A. A. Girgis and S. M. Brahma, “Effect of distributed generation on protective device coordination in distribution system,” in Proc. Large Eng. Syst. Conf., Halifax, NS, Canada, 2001, pp. 115–119. [13] S. M. Brahma and A. A. Girgis, “Impact of distributed generation on fuse and relay coordination: analysis and remedies,” in Proc. Int. Assoc. Sci. Technol. Develop., Clearwater, FL, 2001, pp. 384–389. [14] , “Microprocessor-based reclosing to coordinate fuse and recloser in a system with high penetration of distributed generation,” in Proc. IEEE Power Eng. Soc. Winter Meeting, vol. 1, 2002, pp. 453–458. [15] J.-A. Jiang, Y.-H. Liu, C.-W. Liu, J.-Z. Yang, and T.-M. Too, “An adaptive fault locator system for transmission lines,” in Proc. IEEE Power Eng. Soc. Summer Meeting, vol. 2, 1999, pp. 930–936. [16] J.-A. Jiang, J.-Z. Yang, Y.-H. Lin, C.-W. Liu, and J.-C. Ma, “An adaptive PMU based fault detection/location technique for transmission lines part I: theory and algorithms,” IEEE Trans. Power Delivery, vol. 15, pp. 486–493, Apr. 2000. [17] J.-A. Jiang, Y.-H. Lin, J.-Z. Yang, T.-M. Too, and C.-W. Liu, “An adaptive PMU based fault detection/location technique for transmission lines part II: PMU implementation and performance evaluation,” IEEE Trans. Power Delivery, vol. 15, pp. 1136–1146, Oct. 2000. [18] M. Abe, N. Otsuzuki, T. Emura, and M. Takeuchi, “Development of a new fault location system for multi-terminal single transmission lines,” IEEE Trans. Power Delivery, vol. 10, pp. 159–168, Jan. 1995. [19] E. Cardozo and S. N. Talukdar, “A distributed expert system for fault diagnosis,” in Proc. Power Ind. Comput. Applicat., 1987, pp. 101–106. [20] A. A. Girgis and M. B. Jones, “A hybrid system for faulted section identification, fault type classification and selection of fault location algorithms,” IEEE Trans. Power Delivery, vol. 4-2, pp. 978–985, Apr. 1989. [21] J. J. Burke, Power Distribution Engineering. New York: Marcel Dekker. [22] Electric Utility Engineering Reference Book, Vol. 3: Distribution Systems. Pittsburgh, PA: Westinghouse Electric Corporation, 1959. [23] A. A. Girgis and E. B. Makram, “Application of adaptive Kalman filtering in fault classification, distance protection, and fault location using microprocessors,” IEEE Trans. Power Syst., vol. 3-1, pp. 301–309, Feb. 1988. [24] D. G. Hart, D. Novocel, M. Subramanian, and M. Ingram, “Real-time wide area measurement for adaptive protection and control,” in Proc. Nat. Sci. Found./Dept. of Energy/Elect. Power Res. Inst.-Sponsored Workshop on Future Res. Directions for Complex Interactive Electric Networks, Washington DC, 2000.

Sukumar M. Brahma (S’00) received the B.Eng. degree in electrical engineering from Lalbhai Dalpatbhai College of Engineering, Ahmedabad, India, in 1989, the M.Tech. degree in electrical engineering from the Indian Institute of Technology, Bombay, in 1997, and the Ph.D. degree in electrical engineering in 2003 from Clemson University, Clemson, SC. Currently, he is an Assistant Professor at Widener University, Chester, PA. From 1990 to 1999, he was a Lecturer in the Electrical Engineering Department at Birla Vishvakarma Mahavidyalaya (B.V.M.) Engineering College, Vallabh Vidyanagar, India.

Adly A. Girgis (F’92) received the B.Sc. and M.Sc. degrees in electrical engineering from Assiut University, Assiut, Egypt, and the Ph.D. degree from Iowa State University, Ames. Currently, he is Duke Power Distinguished Professor in the Electrical and Computer Engineering Department and is Director of the Electric Power Research Association (CUEPRA) at Clemson University, Clemson, SC.

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