An Overview of Protection Coordination Methods in Distribution Network with DGs Hadi Zayandehroodi*, Azah Mohamed**, Hussain Shareef *** and Marjan Mohammad Jafari**** *
Department of Electrical, University kebangsaan Malaysia, Selangor, Malaysia, Email:
[email protected] Department of Electrical, University kebangsaan Malaysia, Selangor, Malaysia, Email:
[email protected] ***Department of Electrical, University kebangsaan Malaysia, Selangor, Malaysia, Email:
[email protected] **** Department of Engineering, University of Malaya, KL, Malaysia, Email:
[email protected] **
Abstract—The recent changes in utility structures, development in renewable technologies and increased attention on environmental concerns have led to increasing installation of renewable energy based distributed generations (DGs) in distribution networks. Presence of such DG units in a distribution network increases the complexity of protection relay coordination, control and maintenance of power distribution systems. High penetration of DGs will have unfavorable impact on the traditional protection methods because the distribution system is no longer radial in nature and is not supplied by a single main power source. With DGs in a distribution network, it becomes more active and the power flows and fault currents may have new directions. To ensure safe and selective protection relay coordination, the impact of DGs should be taken into account when planning DG interconnection. This paper presents an overview of the impacts of DGs on system protection relay coordination particularly in cases where DGs are added to a LV distribution feeder. The main objectives of this paper are to address the protection issues that have been identified in the presence of DGs, to study the protection requirements in the presence of DGs and to discuss the possible innovative solutions in resolving the operation conflicts between distribution network and DGs. Keywords ü Protection Coordination Methods; Overview; Distribution Networks; Distributed Generation; DG
I. INTRODUCTION Deregulation of the electric power industry, advancements in technology and a desire of the customers for cheap and reliable electric power has led to an increased interest in distributed generation (DG). Compared with large generators and power plants, DG unit has smaller generation capacity and operate at lower operational costs in distribution networks. Besides, the application of DGs with renewable energy resources has many advantages such as reduced environmental pollution, high efficiency, distribution loss reduction, improvement of voltage profile and enhancement of network capacity [1, 2]. With the installation of DGs in a distribution system, many problems may arise such as false tripping in feeders and generation units, protection blinding, increasing and decreasing of short circuit levels, undesirable network islanding and asynchronous reclosing [3]. However, the impact of DGs depends on its penetration level, connection point in distribution systems and
characteristics of DG technology. In order to ensure correct distribution system operation, various technical issues have to be tackled and one important aspect that needs to be considered is the network protection scheme which needs to be changed. Such changes may be complicated because it requires modelling of the whole distribution system with the presence of DGs[4]. This paper presents an overview of research works related to the development of protection coordination methods in distribution networks with DGs. The operating issues that need to be addressed with regards to distribution protection and DG are also discussed. II.
DISTRIBUTED GENERATION AND DISTRIBUTION SYSTEM PROTECTION DGs are a viable alternative for developing countries where grid supply has reliability below desirable levels. Since utilities are no longer embarking on building large generating plants, DG serves as an alternative to generating energy resources. As a possible scenario, utilities can subsidize the purchase of DG units by customers and provide maintenance services at a reasonable cost. In addition, utilities can also buy the excess energy generated by the customers. The customer DG units are usually directly connected to a distribution system, but in some cases, utility installed DGs are located at a distribution substation[5]. Some of the common technologies available for DG are wind turbine, solar system, micro-turbine, mini-hydro, engine gen-sets, biomass generators, combined heat and power sources, super magnetic energy storage and fuel cells [6]. Over the years, the cost associated with these technologies is decreasing along with increased capacity, improved efficiency and better power quality and reliability of distribution systems. The most common application of DGs is for situations where extremely high reliability of power supply is needed, especially for industries and buildings with critical loads. Automated electronic fabrication facilities, manufacturing facilities with computer-based controls, hospitals and data processing center are examples of such industries and buildings. There are many benefits from the installation of DG, but however, a great penetration of DGs in distribution systems would lead to conflicts with the current protection procedures operated in the present networks. This is due to the fact that the present distribution system is designed as a passive and radial network configuration. A typical
distribution system consists of single and three-phase line sections connected to various types of balanced and unbalanced loads and therefore distribution system analysis has to consider an unbalanced three-phase network fed by a single three-phase source. A typical distribution protection system consists of fuses, relays and reclosers. An inverse overcurrent relay is usually placed at the substation where a feeder originates. Reclosers are usually installed on main feeders with fuses on laterals. Reclosers are necessary in a distribution system since 80% of all faults taking place in distribution systems are temporary. It gives a temporary fault a chance to clear before letting a fuse to blow. The coordination between fuses, reclosers and relays is well established for radial systems but however, when DG units are connected to a distribution network, the system will no longer be radial and this means losing coordination among the network protection devices [7]. The extent in which a DG affects protection coordination depends on DGs' capacity, type and location [8-10]. III. EFFECT OF DG ON PROTECTIVE DEVICE COORDINATION IN DISTRIBUTION NETWORK Figure 1 shows a simple radial distribution network where S is the source, B1,B2,B3,B4 are the busbars and L1,L2,L3,L4 are the corresponding loads. Inverse overcurrent protection relays are usually used in which the setting and coordination curves of relays R1, R2, and R3 are shown in Figure 2.
Figure 1: Simple Distribution Network without DG
The protection philosophy is such that for a maximum fault current in line 3, the operating time of relay R2 is made greater than the operating time of relay R3 at least by a time interval, ǻt (Figure 2). ǻt depends on factors such as the circuit breaker opening time and delay and return time of the measuring element [11]. In case of electromechanical relays, overshoot is also considered. Similarly, relays R2 and R1 are coordinated for a maximum fault at line 2. The characteristic of inverse relay curves is such that R2 will back up R3 and R1 will back up R2 as shown in Figure 2.
Figure 2: Time Overcurrent Plot for Coordination between Relays
A. Effect of Penetration DG in Traditional Protection Figure 3 shows a distribution network with several DG units. Depending on the placement of DG on the feeder, different protection scenarios will arise as described below:
Figure 3: Simple Distribution Network with DG
1) If only DG1 is connected, for a downstream fault, e.g., a fault in line 3, relays R1, R2, and R3 will see the downstream fault current, which is greater than the fault current without DG1. Then, R3 will eliminate the fault and the sensitivity will be improved because of the larger fault current. The situation will be similar for a given fault in line 2 or line 1. For an upstream fault, that is to say, with a fault occurring before busbar B1, relays R1, R2, R3 will never see the upstream fault current and will not be activated. Meanwhile, the overcurrent relay of DG1 will sense a fault current and then act to separate DG1 from the utility system. So, the selectivity and coordination of R1, R2, and R3 will hold. 2) If only DG2 is connected, for a downstream fault, relays R1, R2, and R3 will sense downstream fault currents. The fault current seen by R2, R3 is greater than that without DG, while the current of R1 is less than before. For a fault in line 1, relays R2, R3 will never see the upstream fault current, while R1 will sense a downstream fault current and operate. With a fault before busbar B1, relay R1 will see a reversed fault current, acting when the fault current value is greater than the set value. Meanwhile, DG2 and the loads downstream will form an island. 3) If only DG3 is connected, for a downstream fault, relays R2 and R3 will sense downstream current for faults in line 3 and upstream current for faults in line 1. It is important to note here, that for any given fault downstream or upstream, these relays will sense the same fault current. This would create a conflict since these relays sense the same current for either of these faults and it is impossible to achieve coordination with the existing scheme. Since it is required to clear only the faulted section, R3 has to operate before R2 for any fault in line 3, and R2 has to operate before R3 for a fault in line 1. 4) If only DG1 and DG2 are connected, for a downstream fault of DG2, selectivity and coordination of R1, R2, and R3 will hold, for an upstream fault of DG1, relay R1 will
operate. Then, DG1 will be disconnected from the system, while DG2 and the loads downstream will form an island running mode. 5) If only DG2 and DG3 are connected, for a downstream fault of DG3, selectivity and coordination of R1, R2, R3 will remain, for a fault in line 1, relay R1 will act, for a fault before line1 and relays R1, R2 will see the reversed fault currents contributed by DG2 and DG3. In this case, the upstream currents are proportional to the capacities of DG2 and DG3, so the corresponding operation time of R1, R2 is related to the fault injection capabilities of DG2 and DG3. Coordination is likely to be lost. 6) If DG1, DG2 and DG3 are all connected, for a fault downstream, the situation is similar. R2 will act for a fault in line 2 and R1 will operate with a fault in line1. For a fault before busbar B1, the operation time of R1, R2 depends on the sizes of DG2 and DG3. It is obvious that the operation time of R1, R2, and R3 will be related to the capacities of DG1, DG2 and DG3 if DG1 is connected at busbar B4. It can be concluded that for a downstream fault of DG, selectivity and coordination remains and sensitivity is improved. However, for an upstream fault of DG, coordination is likely to be lost. IV.
REVIEW OF DISTRIBUTION NETWORK PROTECTION IN THE PRESENCE OF DISTRIBUTED GENERATION
The nature of distribution network changes with multiple DG units and therefore directional relays are needed in the network. Fuses and old reclosers do not have directional nature, although it can be easily equipped with direction-sensitive units. However, when it comes to economic considerations, it will not be cost-effective to replace all fuses and reclosers with directional protection devices. When DGs are used, the problem of losing protection devices coordination must be solved regardless of capacity, number and location of DGs. For example, if the protection relays see the same fault current for a fault downstream as well as for a fault upstream, coordination will be lost. On the other hand, if it sees different current for a downstream or upstream fault, there is a margin available for coordination to remain valid. If the disparity in fault currents seen by devices is greater than the margin, then coordination still holds. Therefore, coordination is likely to hold if DG fault current injection is greater than the margin. A simple example was shown to demonstrate the changes in fault currents passing through protection devices when DGs are connected to the system and to suggest that protection coordination must be checked after connecting each DG to distribution network [12]. However, this approach is applicable only in the presence of low penetration of DGs into the system. A study was made on the fuse coordination problem and suggested a solution to disconnect all DGs when a fault occurs [13]. The disadvantage of this solution is that it leads to disconnection of all DGs even when transient faults occur. In addition, the recloser -fuse coordination in presence of DGs using microprocessor-based reclosers was also addressed. It was suggested that all DGs located in the
recloser downstream network must be disconnected first before reclosure takes place to avoid asynchronous connection. This solution will not be appropriate if DGs are widely applied in distribution networks [13]. An adaptive protection scheme for optimal coordination of over current relays was introduced to allow adaptation to system changes [14]. Here, new relays settings were implemented for changes in load, generation or systemtopology. An approach to avoid major changes in the protective devices so that the fuse based protection is not disturbed by DG was studied in ref [15]. However, theoretical studies of the impact of DG on the current seen by protective devices indicate that DGs may be blind for over current protection [3]. For example, short-circuit current fed by a synchronous generator can decrease the current seen by the feeder relay or fuse, preventing or retarding correct operation. Another adaptive protection scheme for distribution networks with high penetration of DGs was introduced based on online diagnosis of occurred faults [7]. From the fault point of view, every source was presented as a voltage source behind the Thevenin impedance. If a fault point shifts from one bus to the adjoining bus, for a given type of fault, the Thevenin impedance to a given source can even increase or decrease. Thus, if a fault point shifts over a section (i-j) from one bus (i) to another (j), for a given type of fault, the fault current contribution from any given source can either continuously increase (I Fmin, to I Fmax) or continuously decrease (l'Fmin, to l'Fmax). Thus, the fault contribution from source "k" for a given type of fault occurring at any point between bus i and bus j will always lie between the contributions from source "k" to the same type of fault on bus i and bus j [7]. To maximize the amount of generation which can be connected to a distribution network and to avoid unacceptable high fault clearing times, a new protection coordination strategy was proposed [16]. Here, the over current principle and time depending characteristics of current was used. Such a scheme gives the additional advantage of being able to run extensive radial circuits or closed ring structures. It minimises the number of customer outages for fault conditions and fault clearing times and fulfill the requirements of a deregulated multiowner energy market consequently [16]. Computational intelligence techniques have been used in protection relay coordination. For instance, genetic algorithm was used to optimize coordination of directional over current relays [17]. This method determines optimal operation characteristic, current setting multiplier and time setting multiplier of directional over current relays simultaneously. The advantages of the method are such as the ability to apply on large networks and the ability to consider both linear and non-linear characteristics of relays. An expert system was used for protective relay coordination in radial distribution network with small power producers [18]. The method is very useful for setting numerous protective relays in a distribution system [18]. A protection scheme for distribution network with DG was developed by the dividing the network into several zones [19]. Zoning was made by considering locations, generation capacities of DGs and loads, with one zone for each DG. Starting from the beginning of a feeder, each zone extends to the end of the feeder as long as the DG within that zone is capable of supplying peak load of that
zone. When peak load of substations located in the zone exceeds generation capacity of zone's DG, zone border finishes, and two circuit breakers were installed in the beginning and in the end of zone points. In the case, there exists a second DG located within the supplying limit of first zone's DG. As long as zone's peak load does not exceed generation capacity of the first DG, while moving towards end of feeder, the second DG is regarded within the same zone and zone border extends as far as the zone's peak load does not exceed summation of two DG's capacity. The reason to consider zoning procedure from the beginning feeder toward its end is to allow more loads to be supplied through upstream network. After network zoning and determining zones' boundaries, some switches which are capable of operating quickly and receive remote signals, are placed between each two zones of the system. These switches are also equipped with check synchronization relays. To implement the protection scheme, a computer-based relay with high processing power and large storage capacity is installed at the subtransmission substation of the distribution network [20]. The computer-based relay holds the main responsibility of system protection and operates through steady monitoring of the currents flowing through some specific points of network. A multi agent approach to power system protection coordination is also presented [21]. The proposed multiagent system takes the substation as one Java Agent Development (JADE) framework which consists of a substation management agent and a number of relay agents, DG agents and equipment agents. Coordination strategy is embedded both in substation management agent and relay agent to facilitate the relay agents to be coordinated. In the coordination strategy, relay settings and time will not be the only parameters that will decide the relay coordination. Relay agents communicate with other agents such as substation management agent, DG agents and equipment agents in order to obtain a successful coordination. The validity and effectiveness of the proposed multi-agent system have been demonstrated by applying it to an agent-based platform. The communication simulation shows that the successful communication information has been achieved not only between agents within one JADE container but also between different JADE containers, indicating that the proposed multi-agent system is a feasible approach in protection coordination [21]. The effect of DG on reclosing operation was investigated and showed that the presence of DG caused inefficiency in reclosing operation of distribution networks where transient faults were not properly cleared [13]. Moreover, islanding operation was shown to lead in loss of network synchronism and when reclosing operation was carried out in an asynchronous network, heavy damages can be imposed on distribution devices. V.
OPERATING ISSUES OF DISTRIBUTION PROTECTION WITH DISTRIBUTED GENERATION Participation of DGs in the energy network can cause various problems related to incorrect operation of system protections. Conflicts between DG and protection schemes are typically due to unforeseen increase in short circuit currents, lack of coordination in the protection system, ineffectiveness of line reclosing after a fault, undesired islanding and untimely tripping of generator interface
protection. Conflicts between DG and protection schemes have been discussed in the literature, but effective and practical methods to solve protection malfunction due to the presence of DG have to be further investigated. Some practical cases related to the aforesaid issues in a typical LV distribution network will be discussed in the following sections. A.
Increase in short circuit currents The consequence of incorporating DG may result the mal-operation of existing distribution networks by providing flows of fault currents which were not expected when protections get originally designed. Generally, fault current increase largely depends on number of factors, such as capacity, penetration, technology, interface and connection point of DG, besides other parameters such as system voltage prior to the fault, etc. [22]. B.
Protection coordination Protection of power systems is typically tuned in such a way that only the faulted part of the system gets removed when a fault happens. This tuning is called protection coordination and this becomes worse when DGs are connected because they can negatively affect the system coordination. By connecting DGs into the grid, the issues related to system protection turns to be very significant. For instance, the protection devices downstream of the last DG will never see fault current for an upstream fault. If these devices can see the increased fault current due to penetration of DG, there will be no problem in coordinating them. However, if the protection devices observe fault currents for upstream faults, there are two possibilities: firstly, if they see the same fault current for a fault downstream as well as for a fault upstream, then coordination will be lost. Secondly, if they see different current for a downstream or upstream fault, there is a margin available for coordination to remain valid. If disparity in fault currents seen by devices is greater than the margin, then coordination holds. Therefore, coordination is likely to hold if DG fault injection is excessive. In the case of fuse-recloser coordination, there is also a margin available for coordination to remain valid. In this case, if the disparity in fault currents seen by these devices is less than the margin, then coordination holds. Therefore, coordination is likely to hold if DG fault injection is small [4]. C. Temporary faults In radial systems, fault clearing requires the opening of only one device because there is only one source contributing current to the fault. In contrast, meshed transmission systems require breakers at both ends of a faulted line to open. Obviously, when DG is present, there are multiple power sources and opening only the utility breaker does not guarantee that the fault will clear quickly. Therefore, DG will be required to disconnect from the system when a fault is suspected, before the fast reclosing time has elapsed, so that the system reverts to a true radial system and the normal fault clearing process may proceed. Actually, there is the possibility that DG will disconnect either too quickly or too slowly with a detrimental impact on the distribution system. This creates numerous potential operating conflicts with respect to overcurrent protection and voltage restrictions. In this perspective DG seems to be rather incompatible especially with fast
reclosing during temporary faults. This procedure may not allow the DG units to have enough time to be disconnected from the network. In this case DG units may sustain the voltage and fault arc, preventing successful reclosing in case of temporary faults. From the above consideration, it seems that the reliability of the power delivery system may be worsened due to the presence of DG, unless anti-islanding philosophy and protection schemes are revised to ensure timely DG disconnection. However, changes in the present procedures will also be required to locate and isolate a fault, to determine whether it is sustained or not and, finally, to restore power to customers [23]. D. Undesired islanding and untimely tripping for faults on different feeders For islanding, distribution operators require DG units to be equipped with additional protective devices, called generator’s interface protection, often referred to as antiislanding protection using voltage relays, frequency relays and maximum zero-sequence voltage relays. This protection is required to disconnect the generator from the network when a feeder is trip during abnormal system conditions. Anti islanding protection operation prevents network portions from working in islanded mode with the DGs since, in general, islanding is not allowed by standards in the majority of the developed countries as it would cause safety and reliability problems. If islanding takes places, usually each generator is allowed to supply the preferential loads of a privately owned plant, after disconnection from the network. VI. CONCLUSION The existing technologies involved with development of the DG have been reviewed and the impacts of DGs on protection relay coordination are discussed, particularly in cases where DGs are added to a LV distribution feeder. Several protection issues have been identified when DGs are connected in a distribution system. The protection requirements in the presence of DGs and some possible innovative solutions in resolving the operation conflicts between distribution network and DGs are also discussed. REFERENCES [1]
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