A Distance Based Protection Scheme for Distribution Systems with Distributed Generators V. C. Nikolaidis, C. Arsenopoulos, A. S. Safigianni Department of Electrical and Computer Engineering Democritus University of Thrace (DUTH) Xanthi, Greece {vnikolai, konsarse, asafig}@ee.duth.gr Costas D. Vournas School of Electrical and Computer Engineering National Technical University of Athens (NTUA) Athens, Greece vournas@power.ece.ntua.gr Abstract This paper investigates the application of distance relays in distribution systems with distributed generators. An analysis of the parameters that influence the effectiveness of distance relaying in distribution networks is performed. Protection coordination between the distance relays and the existing protection means on the line is studied with the help of a realistic distribution network. Coordination problems are identified and a simple distance-based protection scheme is proposed. Index Terms Distance protection, distributed generation, distribution systems, protection coordination. I. INTRODUCTION Protection of a distribution network, in the vast majority of cases, is based on the overcurrent protection principle [1]. In existing distribution feeders, this principle is applied by designing protection schemes that are based on the proper coordination of fuses, reclosers and overcurrent relays. The expected result is that each fault should be cleared sufficiently fast with minimum impact on the customers, even when a protection device will fail. Obtaining this goal in a distribution feeder is a complicated task because it requires coordination studies that have to include all possible system states and operating scenarios, taking also into consideration the specific protection equipment available. The penetration of Distributed Generation (DG) in distribution systems considerably reformed the operating practices in these networks. Among others, the bi-directionality in the fault current flow due to the connection of DG units and the contribution of the DG units to the fault current level cause significant impact on the protection system. If the existing overcurrent protection philosophy is applied then this could lead to various issues like not-expected fuse blowing or other protection misoperations [2]. It is obvious that changes in the overcurrent protection design are necessary to overcome the impacts [3]. In general, there is a rising need to address many incompatibility issues, as well as to review and implement suitable protection schemes. In this context, the application of the distance relaying principle to protect distribution systems with DG seems a promising option [4], [5], [6]. This paper examines the application of distance relays in radial distribution systems with DG. The organization of this paper is as follows. Section II includes a brief introduction to distance protection applications in distribution systems. Section III describes the proposed distance-based protection scheme. Section IV presents the simulation results and the effect of some influencing parameters on the distance relay performance, while the conclusions are drawn in Section V. II. DISTANCE PROTECTION IN DISTRIBUTION SYSTEMS A. Distance Protection Principles Distance relays are used for primary and/or backup protection for phase faults and/or ground faults on transmission, subtransmission and distribution lines. In principle, a distance relay determines the fault impedance from the measured voltage and current at the relay location [1]. Then the measured fault impedance is compared with the known line impedance to determine if a trip command should be issued to the circuit breaker. The intentional time delay before releasing the trip command is beforehand decided in accordance with the fault distance from the relay location. The protected line portion and the corresponding time delay define the zone settings of the relay, determined in the protection design stage. Usually, there are more than one distance zone settings determined in order to provide selectivity between the various protection means in the network. Moreover, the phase and ground elements of the relay are set separately, thus resulting in different zone characteristics. Each distance zone corresponds to a specific characteristic on the complex impedance plane. Fig. 1 depicts the most common characteristics encountered nowadays, which are the mho and the polygonal ones. In Fig. 1, the typical load encroachment characteristic of distance relays is also illustrated on the impedance plane. As long as the impedance measured from the distance relay lies inside the load encroachment area, the trip command of the three-phase element is blocked.
B. Distribution Systems without DG Radial distribution systems are usually protected with overcurrent protection equipment. Overhead distribution lines are typically protected by a recloser located at the beginning of the feeder, which is coordinated with the downstream protection means (overcurrent relays, reclosers, and/or sectionalisers) on the main trunk and with the fuses on the laterals [1]. Radial cable lines are typically protected with overcurrent relays. In ring or meshed distribution networks, directional elements are used supplementary to the overcurrent relays in order to discriminate between the fault directions. Distance protection is not so commonly applied in distribution lines. Traditionally, this was because of the additional cost of the distance protection system due to the need of a voltage transformer together with the current transformer and the higher cost of the distance relay itself, which was more expensive than a simple overcurrent relay. Nowadays, distance protection begins more frequently to be applied in distribution networks, since the associated costs have been reduced and the benefits of the distance protection principle compared to the overcurrent one are obvious. Just to mention, the most pronounced benefits are its inherent directionality and the independency from the source impedance magnitude. In overhead line networks, the distance protection is in general implemented with automatic reclosing schemes [7]. In cable networks, if distance protection is applied as the main protection scheme, this is done with a permissive tripping arrangement via fiber optic communication. Since such schemes resemble the differential protection principle, this paper deals with application of distance protection in overhead line distribution networks. The simplest way to apply distance protection in radial overhead line distribution systems is to replace the recloser at the beginning of the feeder with a distance relay. Then, each relay setting corresponds to several fault locations, depending on the actual reach of the respective zone. For example, if Z set in Fig. 2 is the impedance reach of one of the zones, any fault within this zone will be sensed from the relay. Hence, it is the responsibility of the protection engineer to ensure selectivity between the distance relay (DR) and the protection equipment on the line that is included in this zone. C. Distribution Systems with DG When DG units are connected to distribution systems, the performance of the conventional overcurrent protection system is further affected by a number of critical factors. For instance, if the utility source is weak and the short-circuit capacity of the DG units approach that of the source, large variations in fault level will exist when the generation is in or out of service. This variation in fault level makes phase and ground overcurrent relay grading very difficult. The coordination of the overcurrent relays may also be distorted depending on the size and location of the DG units [2]. Furthermore, to maintain the stability of the distributed generators fault clearance times should be kept to a minimum. It should be noted that the above mentioned difficulties apply equally to radial circuits protected by non-directional relays and ring circuits protected by directional relays. Figure 1. Mho and polygonal characteristics. Figure 2. Reach of distance zone in radial feeders Distance protection in distribution networks with DG can improve the operating performance of the network as well as that of the protection system itself. However there are still some issues that should be dealt with efficiently. Special attention when designing distance protection in power systems with multiple intermediate sources should be given to the so called infeed effect [1]. The infeed effect results in an increase in the fault impedance measured by a distance relay if one or more generation sources are connected between the relay and the fault location. Then, the relay sees the fault at a greater distance and may only trip in a higher zone. Therefore, when there is at least one DG connected between the distance relay and the fault location, the additional fault current supplied by the DG unit must be taken into account for setting the relay properly. Consider, for example, the distribution line in Fig. 3, where a short-circuit occurs in the middle of the main trunk. Without the connection of the DG unit, the distance relay would measure the actual positive sequence impedance to the fault which is equal to Z A + Z B. When the intermediate current I B flows, the impedance appears to the distance relay as Z A + Z B + (I B /I A )Z B. The fraction between I B and I A is defined as the infeed constant K = I B /I A. The relay therefore sees an impedance of KZ B in addition to the impedance Z A + Z B, which implies that its reach is reduced. In other words, the fault appears to be farther away because of the current I B. A quite detailed guideline for extracting efficient setting rules for the distance protection in a radial distribution system with DG is given in [5]. The authors try to suggest generic rules in a way to resemble the traditional overcurrent protection philosophy. In many cases, the distance relay is used with its zone controlling the overcurrent element.
Figure 3. Infeed effect III. PROPOSED DISTANCE PROTECTION SCHEME To illustrate the setting rules for the distance-based protection scheme, the radial overhead line distribution system depicted in Fig. 2 is considered again. The fuses F1-F4 protect the main laterals, while the fuses F1.r-F.4.r protect the remotest tapped distribution transformer in each lateral. We assume fuses at the laterals because they are the most encountered protection means in overhead distribution lines and because fuses are more difficult to coordinate with the main feeder protection (recloser/distance relay) than overcurrent relays due to their non-settable characteristic. A fuse-saving philosophy is further adopted. Coordination between the main fuse and the fuses at the primary of the tapped transformers is assumed. The distance relay DR is installed at the beginning of the line replacing the conventional overcurrent relay. The radial line is divided into protection zones each of them (except of the first) covers part of the main line and the whole length of one of the laterals. Attention should be given so that none of the protection zones of the distance relay will overreach the protection zone of any of the distribution transformers that are tapped on the laterals. To complete this fulfillment the positive sequence impedance seen by the DR for a fault at the remotest end of the lateral should be compared with the smallest possible positive sequence impedance seen for a fault on the secondary winding of any of the distribution transformers at this lateral. Most distance relay manufacturers provide the availability to choose between any possible combination of phase and ground elements in terms of a mho or a quadrilateral characteristic. However there are manufacturers that restrict the use of mho (resp. quadrilateral) characteristics only to phase or ground elements. For example, one well established manufacturer provides phase elements with a mho characteristic, while quadrilateral characteristics are provided only for the ground elements. Moreover, most manufacturers provide four independent phase/ground elements, whereas there are some special cases where five independent phase/ground distance elements are provided with the relay. In this paper, it is assumed that the DR provides four independent mho and four independent quadrilateral elements, which can interchangeably be used for phase and ground protection. Finally, each phase and ground element has been set with a quadrilateral characteristic. The quadrilateral characteristic has been selected over the mho one because of its advantages, especially in regard with the fault resistance coverage. The setting procedure concerns equally the phase and ground elements and takes into account the infeed effect. This procedure is described below in a detailed manner. Figure 4. Coordination in long radial distribution networks The first zone is set to instantaneously (t 1 0) clear faults occurring within the 85% of the distance between the DR location and the first lateral. Thus, the largest expected fault currents will be interrupted instantaneously and the equipment will be exposed to the worst through-fault damage for the shortest time duration. This is especial critical for the substation transformer which should not be exposed to large through-fault currents. The second zone is set to cover the total impedance (Z 2 ) up to the end of the first lateral. Since the first lateral is protected by the main fuse F1, the second zone is coordinated to operate with a time delay t 2 that is larger than the largest of the total clearing times of this fuse. An appropriate minimum Coordination Time Interval (CTI min ) is taken for this purpose. The third zone is set to cover the total impedance (Z 3 ) up to the end of the second lateral. Again, coordination must be guaranteed between the zone 3 element and the fuse F2. Hence, an appropriate time delay t 3 for the zone 3 operation must be specified. Finally, the fourth zone is set to protect the line up to the end of the third lateral with an appropriate time delay t 4. Note again that in all cases coordination between the main fuse and the fuses on the transformers is assumed at each lateral. If there is a short line section beyond the third lateral or a fourth lateral as in Fig. 2, zone 4 can be extended to cover the main line up to its remotest end including the fourth lateral. If the distribution line has more than four laterals, a second distance relay named DR2 should be installed in the main line, in the section immediately after the third lateral (Fig. 4). Then, DR2 should be coordinated following the same setting philosophy as described previously. Since the phase and ground short-circuits have smaller magnitudes as the fault location moves away from the substation, the clearing times of the downstream fuses will become larger. Thus, although coordination between the DR2 and the fuses beyond the third lateral can easily be achieved, coordination between the DR2 and the DR1 is not so straightforward. By determining the appropriate time delays of the phase and ground elements of the DR2, the required CTI min between the DR1 and DR2 should be preserved. In some cases, this leads to an additional increase of the time delay of a zone element. For example, in Fig. 4 the time delay t 1,4 of the DR1 should be increased to the value t 1,4 in order to keep coordination. However, according to our experience based on protection coordination studies for radial overhead lines in Greece, a sufficient CTI between the protection devices can be achieved even for long lines supplied from a weak external grid. It is obvious that the first distance relay is commanded to protect up to three laterals, while any downstream distance relay, if needed, can protect at maximum four laterals each.
This can be used as a guide for determining the quantity of the required distance relays in extremely long lines with a large number of laterals. There is only one limitation concerning the maximum permitted time delay for a fault to be cleared. This limit is imposed from the coordination requirements with the transmission system protection and is shown in Fig. 4 with a dashed-dotted line. This time delay cannot be violated. It should be noticed also that installing DR2 implies installing a new substation with its associated CTs, VTs, and switchgear which is costly at the distribution level. However, the cost of installing a new substation at every four laterals is considerable lower than that of installing directional/differential relays (two at each line section) or from that required to implement a fast and reliable communication network, solutions that may alternatively be applied in order to protect of a distribution system with distributed generators. Most modern distance relay manufacturers provide the load encroachment function. In order to avoid any false trip of the distance relay due to a symmetrical three-phase heavy loading condition, this function has been included in this work. Furthermore, in case that no DG unit is connected to the line, a reclosing operation can be assumed for the distance relay. The reclosing operation proposed in this paper applies the instantaneous disconnection of the whole line by opening the circuit breaker at the beginning of the line if a fault is sensed anywhere on the line. Then, a subsequent time-delayed reclosing is performed assuming that every DG unit has been disconnected in the meantime. IV. SIMULATION RESULTS A. Test System Description The proposed distance protection scheme has been tested on a typical overhead distribution line configuration in Greece, which consists of one radial 20 kv, 50 Hz, 25 km long overhead line shown in Fig. 5. ACSR conductor is used with a cross-section of 95 mm 2 on the first segment, which constantly decreases to 50 mm 2 and 35 mm 2 on the subsequent segments. In most of the laterals, a 16 mm 2 ACSR conductor is used. The total line load is 3.42 MW and 1.99 MVAR. The transmission grid is represented by an equivalent source, having a maximum short-circuit power of 2000 MVA at 150 kv. The feeder is supplied from the external grid through a 150/20 kv distribution transformer. A conventional 1.5 MVA, 20 kv, 50 Hz round-rotor synchronous machine has been assumed as a DG unit, operating with a unity power factor when gridconnected. Standard models available in DigSilent Power Factory 15 have been used for representing the described system. In addition, actual fuse links have been modeled at the laterals and at the primary side of the load transformers. B. Distance Relay Setting At first, the case without DG production has been examined. Phase and ground faults with zero fault resistance have been simulated at critical locations on the line and the maximum total clearing times of the fuses have been determined. Table I summarizes the maximum clearing times of all the main fuses in the network. In general, the single-phase (1Φ) short-circuit resulted to the maximum clearing times. Figure 5. Realistic distribution feeder Figure 6. Phase/ground elements of the DR without considering DG Four zones have been set to cover the line up to its remotest end. These zones are shown with the blue quadrilateral characteristics in the complex impedance plane of Fig. 6. The phase and ground elements have been set to have the same reach, whereas they have different time delays determined from the maximum fuse clearing times plus the minimum required CTI min which is equal to 0.3 s. The positive resistive reach (+R) of the quadrilateral characteristics has been selected to cover a fault resistance that is at maximum equal to four times the positive reactance reach (). This is a quite effective assumption [6] for considering fault resistances in medium voltage distribution systems. It is obvious that both the third and fourth zone reaches far inside the load encroachment area, illustrated with the red line in Fig. 6. Having in mind that the load encroachment holds only for symmetrical three-phase conditions, only three-phase fault conditions with a large fault resistance may not be cleared effectively by the relay. However, such conditions are rare and even smaller fault resistances cannot be sensed from common overcurrent relays without a sensitive earth-fault element. Since no DG production has been assumed up to now, the reclosing element of the distance relay can be set to perform a fast reclosing operation for faults occurring everywhere on the line. This reclosing element is represented by the mho characteristic, shown with the brown circle in Fig. 6, which encircles the whole network.
TABLE I. MAXIMUM TOTAL CLEARING TIME (NO DG) Fuse TC time Fault type F1 179 1Φ F2 264 1Φ F3 389 1Φ F4 537 1Φ Next, the setting procedure has been repeated by considering DG units connected to the line. Three different penetration levels have been examined; 42%, 83%, and 125%, meaning respectively one, two, or three fully rated DG units simultaneous in operation. The DG units have been assumed to produce their 100% rated power because they are conventional synchronous machines, thus the power production is fully controllable and independent from the weather conditions. Moreover, it will be seen in the next subsection that the influence of the penetration level on the distance relay settings is more pronounced as the penetration level gets larger, while the DG unit connection point plays also an important role. Now, the critical factor is how the infeeds affects the reach of the zones. It should be noted that for the DG units to be considered as infeeds, the DG protection should be very thoroughly taken into account meaning that it is important to know if the DG protection will instantaneously disconnect the units or not in case of a fault. The under/over-voltage and under/over-frequency settings suggested from various standards [8], indicate that even for the worst short-circuit conditions, the DG will remain connected for a minimum of 0.1 s. Definitely, there are also other DG protection functions (interconnection relay, overcurrent relay etc) that should be taken into consideration. Since this time delay is in general comparable with the total clearing time of most of the fuses for phase faults and because of the fact that not all the DG units in a distribution system are simultaneously exposed to the worst voltage/frequency/overcurrent conditions during a fault, we consider that the DG units contribute constantly to the fault within the time frame of the distance relay operation. In other words, DG units are considered as infeeds in the protection coordination procedure. The main difference observed when considering DG production in the coordination study is that the phase and ground elements of the distance relay must be set uniquely because of the different contribution of the DG units under different fault types. Table II summarizes the time-distance settings of all the phase (P) and ground (G) elements of the relay as determined based on the three different DG penetration levels. Only the positive reactance reach () is shown, since the resistive reach (+R) is taken equal to four times the reactance one. As a graphical example, Fig. 7 depicts the characteristics of the phase and ground characteristics for the case of two DG units connected to the network simultaneously. In this figure, the blue solid characteristics correspond to the phase elements and the dashed magenta ones to the ground elements. The phase and ground elements operate with different time delays determined from the maximum total clearing times of the main fuses. Table III shows the total clearing times of the main fuses for all the examined penetration levels. TABLE II. TIME-DISTANCE ZONE SETINGS (WITH DG) No DG 1 DG unit 2 DG units 3 DG units P1 1.42 55 1.42 55 1.42 55 1.42 55 P2 4.00 400 4.00 400 4.50 400 4.50 400 P3 6.00 500 6.00 500 6.50 500 7.00 400 P4 10.0 600 11.0 600 11.5 600 12.0 600 G1 1.42 55 1.42 55 1.42 55 1.42 55 G2 4.00 500 6.00 500 7.00 500 7.60 500 G3 6.00 700 10.0 600 12.5 500 14.0 500 G4 10.0 900 19.0 700 23.0 700 26.0 700 TABLE III. MAXIMUM TOTAL CLEARING TIME (WITH DG) 1 DG unit 2 DG units 3 DG units Fuse TC TC time TC time Fault type F1 133 129 127 1Φ F2 151 142 137 1Φ F3 365 345 388 1Φ F4 365 345 388 1Φ Figure 7. Phase and ground elements of DR with 2 DG units in operation Obviously, if an active management system was available for this distribution system, different setting groups could be beforehand programmed and stored inside the distance relay. Then, based on the information retrieved from the DG units through communications about their operating status (on/off), the appropriate setting group can be uploaded to the relay. C. Effect of Influencing Quantities In order to investigate the influence of the fault resistance on the performance of the distance relay, we subsequently simulated single-phase and three-phase faults at the end of each zone assuming different values of fault resistances from zero up to R F = 40 Ω. Again, the case with two DG units connected is assumed, to easily compare with the Fig. 7. Fig. 8 (resp. Fig 9) illustrates the modification required in the positive reactance reach setting () of the zone 4 phase (resp. ground) element depending on the fault resistance magnitude and the DG connection point. The resistive reach (+R) is always taken equal to four times the reactive one.
Figure 8. Influence of the fault resistance on the reactance reach setting of the phase element Figure 10. Influence of the DG penetration on the reactance reach setting of the phase element Figure 9. Influence of the fault resistance on the reactance reach setting of the ground element The straight horizontal line in both figures corresponds to the reactance reach setting of the zone 4 element, determined when zero DG production and zero fault resistance is assumed. In any other case, the two DG units have been assumed to be simultaneously in operation at various locations; namely from bus B1 to bus B4. As can be seen, there is a clear need to increase the reach setting of the relay when the DG units are connected close to the substation and the fault resistance increases. For DG unit connections away from the substation the reach setting determined for zero DG production and zero fault resistance has not to be increased. Fig. 10 (resp. Fig. 11) depicts the modification required in the positive reactance reach setting () of the zone 4 phase (resp. ground) element depending on the DG penetration level and the DG connection point. Zero fault resistance is assumed now. It can be seen that the reach of the phase element should be increased as the penetration level of the DG units connected close to the beginning of the line increases. The reverse effect holds when the DG units are connected away from the substation. Figure 11. Influence of the DG penetration on the reactance reach setting of the ground element D. Investigation of the Combined Effect An interesting conclusion drawn from the analysis presented in this section is that the infeed effect and the influence of the fault resistance on the relay settings come not so uniformly up as defined in the theory. For example, the underreaching effect due to the intermediate infeeds does not appear when the DG units are connected close to remotest end of the line. A critical reason for that is that the pre-fault load transfer plays a significant role (as in the transmission lines) and this effect is especially pronounced in medium voltage overhead lines with different cross section segments. Additionally, if a considerable DG penetration level and a wide dispersion of generators are assumed, the increased fault resistance combined with the pre-fault load current contribution results to a considerable rotation of the fault impedance in the complex impedance plane. Next, we try to explain the abovementioned combined effect with a simple theoretical analysis based on the circuit shown in Fig. 12. Note that this circuit consists of segments similar with that of the distribution system examined in the previous subsection. The impedance Z seen by the distance relay installed at the location 0 for a fault at the end of the line is given by: Z Z ( 1 1 ) Z ( 1 2) Z (1) 01 12 23
where K1 and K2 are the infeed constants: 1 IL1 / IA A 2 I I / I B L1 B A By expressing the impedance of the two line segments in a polar form, we get: Z12 C t (3) Z23 D k Then, the infeed related terms of (1) can be calculated as follows: K1 Z12 A C ( t) (4) K2 Z23 B D ( k) Since the apparent impedance Z is a vector defined by (1), its angle is dominantly dependent on the sign of the angles θ+t and φ+k. In distribution systems these angles are mostly positive, thus resulting to an impedance vector tilted up, as shown in Fig. 13. If the fault resistance R F is added in the analysis, the impedance seen by the relay for a fault at end of the line is given by: Z Z01 ( 1 1) Z12 ( 1 2 ) ( Z23 RF ) (5) Now, the term Z 23 +R F is critical, which in polar form can be defined as: Z R E j (6) 23 F If the angle j has a smaller magnitude than φ, then the term K2( Z23 RF ) F ( j+ ) is a vector that when added to the vector of the apparent impedance, it tilts it down. This is shown, in Fig. 14. To conclude, it is understood that the rotation of the apparent vector is strongly dependent on the magnitude of the fault resistance R F. and on the infeed constants. V. CONCLUSIONS The application of distance relays in distribution systems with distributed generators has been examined in this paper to take advantage of the inherent directionality of the distance protection principle and its independency from the source impedance magnitude. On the other hand, the infeed effect and the influence of the fault resistance on the performance of the distance relay have been analyzed. Some interesting particularities that raised by investigating those effects on the application in distributions systems initiated a theoretical analysis of the phenomena. A simple distance-based protection scheme has been proposed for radial overhead lines. The scheme is intended to preserve the fuse-saving philosophy of the traditional protection system. The methodology has been applied effectively to a realistic distribution system with DG production. An extension of this scheme to be applied on extremely long radial lines has been further proposed. (2) Figure 12. Simple illustrative system Figure 13. Infeed effect projected on the relay characteristic Figure 14. Combined infeed anf fault resistance effect REFERENCES [1] J. M. Gers, E. J. Holmes. Protection of Electricity Distribution Networks. London: IET, 2004, p. 342. [2] M. Geidl, Protection of Power Systems with Distributed Generation - State of the Art. ETH Technical Report. [3] V. C. Nikolaidis, E. Papanikolaou, A. S. Safigianni, "A Communication-Assisted Overcurrent Protection Scheme for Radial Distribution Systems With Distributed Generation," IEEE Trans.Smart Grid, Vol. 7, Issue 1, pg.114-123, Jan. 2016. [4] I. Chilvers, N. Jenkins and P. Crossley, Distance relaying of 11kV circuits to increase the installed capacity of distributed generation, IEE Proc.-Gener. Transm. Distrib., Vol. 152, No. 1, Jan. 2005 [5] A. Sinclair, D. Finney, D. Martin, and P. Sharma, Distance protection in distribution systems: How it assists with integrating distributed resources, in 65th Annual Conference for Protective Relay Engineers, 2012. [6] J. Chang, L. Gara, Y. Kyosev, P. Fong, Application of a Multifunctional Distance Protective IED in a 15KV Distribution Network, 66th Annual Conference for Protective Relay Engineers, CPRE 2013, pp. 150-171. [7] G. Ziegler. Numerical Distance Protection. Principles and Applications. Siemens, 2011. [8] W. Hartmann. Distributed Generation Protection & Control. Including IEEE 1547, Green Energy and Microgrids. IEEE PES San Fransisco Technical Report.