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Simulation of Small Hydro Generators in Islanding Operation in weak Distribution Networks A. S. Dagoumas, A. G. Marinopoulos, G. K. Papagiannis, and P. S. Dokopoulos
Abstract— Recent trends have led to a reform of the power distribution network towards the penetration of small dispersed units. Although distributed generators provide a number of strategic benefits, their application may pose important technical concerns. One of these concerns is the islanding operation of a network branch. Such operational cases are examined in a 20kV distribution network containing 8 small synchronous and asynchronous hydro generators. The transient behavior of the DG units following circuit breaker auto reclosure operations is examined in this paper for different network loading conditions and for different network configurations. The influence of the network reactive power compensation is also investigated. Index Terms—Distributed generation, islanding operation, synchronous and asynchronous generator transients, transient stability.
E
I. INTRODUCTION
LECTRIC power systems were not initially designed and built for Distributed Generation (DG) connection [1]. This new kind of generation is a supplement to the large central power plants, improving reliability and efficiency and enabling the rationalisation of energy infrastructures. Distributed generation can offer strategic benefits regarding the use of modular units to adapt to the growing local peak loads with increased reliability and act as a solution to financial and technical constraints on the expansion of the transmission and distribution networks. Nevertheless, the application of DG may pose important technical and policy concerns [2-8]. One of the technical issues related to the distributed generation (DG) interconnection is the inadvertent islanding [9-13]. The phenomenon of islanding in the presence of distributed generation systems (DGs) requires considerable attention, as it can lead to potential hazards concerning the safety of the personnel of the system. Almost all utilities require that, in Manuscript received June 30, 2006. The financial support of this work by the Greek General Secretariat for Research and Technology, Project Number 03Ε∆947, is greatly acknowledged. A. S. Dagoumas, A. G. Marinopoulos, G. K. Papagiannis, and P. S. Dokopoulos are with the Laboratory of Power Systems, Faculty of Electrical and Computer Engineering, Aristotle University of Thessaloniki, GR 54124 Thessaloniki, Greece, P.O. Box 486 (tel: (+30)-2310-996388, fax: (+30)2310-996322, e-mail:
[email protected]).
case of islanding, all generators should disconnect from the grid as soon as possible. To prevent unintentional islanding, transfer trip is traditionally used, mostly for larger units in megawatt ranges. For smaller DG units connected at the distribution level, transfer trip is too expensive. Also, an increasing number of distribution systems are configured to provide multiple alternate feed points to a particular feeder section. Transfer trip can be exceedingly complicated and expensive to implement, when trip signals from multiple points need to be communicated, as well as the current status of the system configuration, to determine which trip signal is relevant at any given time. While several low-cost communication means and infrastructures are under development, it is always desirable for DG units to have local intelligence to detect islanding events. Another problem may occur when the DG units are not tripped during an autoreclosing operation of the circuit breakers (CBs). Automatic reclosing is a widely used and a very effective method of fault clearing in medium voltage overhead networks [14]. During the autoreclosure open time the DG units can either accelerate or decelerate, depending on the islanded network loading conditions. An out of phase reclosing can cause serious damage to the generators. Although there are few references of actual damages due to autoreclosing, the effects of such stresses are cumulative. The topic has drawn the attention of many researchers [15-17], as it is considered one of the most serious problems of unintended islanding of DG networks. The limits imposed by the IEEE1547 and EN50160 standards are considered [18], [19]. Scope of this paper is to examine the transient behaviour of small synchronous and asynchronous generators during the autoreclosure operation of circuit breakers. The network under consideration is a weak, radial distribution network at 20kV in Northern Greece. The islanding operation of two network branches is examined for different network loading conditions. Moreover, an analysis is carried out concerning the influence of the reactive power compensators during different islanding conditions. All operational cases are simulated and their impacts are evaluated using the NEPLAN© software [20].
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II. DESCRIPTION OF THE TEST SYSTEM A. System Layout The power system examined in this work is part of the distribution network of the Greek Public Power Corporation (PPC) in Northern Greece. The greater distribution network in the area consists of two substations with two main transformers connected to the transmission system and a distribution network at 20 kV, having two independent lines, covering small urban and rural settlements with total load of about 20 MVA. The network consists of Aluminium Coated Steel Reinforced (ACSR) overhead distribution lines, with cross-sections of 95mm2 and 16mm2. Voltage Regulator 3-phase fault
CB1
BRANCH 1
CB2
Feeder
CB3
C1 U6
U5 U1
U2
U3
SM-1B SM-2B or ASM-1B
U4 C2
BRANCH 2 SM-1A
ASM-1A or SM-3A
ASM-2A or SM-4A
G2.11 G2.12
SM-2A
Fig. 1. Test system layout.
One of these lines is selected as a test system. It consists of a main substation with a 150/20kV transformer and a voltage regulator, to cover various loading conditions. The line length is 80 km, the maximum load is 11.17MVA. Six DG units are connected in the line. Two of these units, namely U1 and U4 consist of one Synchronous Generator (SG) each. The other two, U2 and U3 have one Asynchronous Generator (ASG) each and finally the last two, U5 and U6 consist of two SGs each. Unit 6 was initially planned to have one ASG, but in its final implementation was constructed having two SGs. Moreover, Units 2 and 3, are in the process of a reconstruction in order to implement SGs. Due to these TABLE I. VARIABLE NETWORK CONFIGURATIONS
Network Α
Network B
Network C
Unit 6
2 SGs
1 ASG
2 SGs
Unit 2
1 ASG
1 ASG
1 SG
Unit 3
1 ASG
1 ASG
1 SG
variations and in order to investigate the behavior of different types of generators the network options of Table I are examined. The actual network of Fig. 1 is characterized as network A.
B. Generators All generators are connected to the grid at 20 kV with stepup transformers. The ASGs have their own capacitor banks to compensate the reactive loads locally. Their loading varies from 1.70 MVA to 11.17 MVA. The different operational modes of the generators are: – PQ operation, where the generator produces a constant active P and a constant reactive power Q. – PV operation, where the generator produces a constant active power P and adapts the reactive power Q, in order to maintain a constant terminal voltage V. – PC operation, where the generator produces a constant active power P at a constant power factor. – Mload operation for asynchronous generators, where the generator operating point is calculated by means of the speed torque characteristic. The generated power depends on the load torque and the terminal voltage. C. Loads The dominant use of the electric power in the test case network is either domestic in small towns or rural mainly for water pumps. The demand fluctuates greatly, depending on the time of day and the season of the year. The maximum demand is recorded at summer noon, when the needs for airconditioning at domestic and for irrigation in rural areas are high. The minimum demand is recorded during the winter nights, when there is no need for water pumps and the domestic loads are at their minimum. The line impedance rises near the end of the line, as the conductor cross-sections become smaller. To ensure that the consumers at the remote end of the network are supplied within the specified voltage limits, the DNO regulates the substation output voltage, with OLTC, a few percent above the nominal voltage. Because of the load variation during the day and season, at maximum load the secondary voltage of each transformer is tapped at 1.07 p.u., while at the minimum loads the output voltage is regulated at 1.03 p.u.. The maximum and the minimum loads of the line are 11.17 and 1.7MVA respectively. The power factor for all loads is assumed to be 0.9 lagging. D. Circuit breakers The circuit breakers used in this network are three-phase oil or air-gap RVE, KFVE, or KFVME type manufactured by COOPER. These circuit breakers are able to trip very fast, within 2-3 cycles and also to reclose within 300-500 ms from first trip. III. SIMULATION METHODOLOGY The above network is simulated using the NEPLAN© software. The load flow module calculates the active and reactive power flow at each branch, the current through the lines and the voltages at each node using the extended Newton-Raphson method. The transient stability module is used for the computation of electromechanical transients. All network elements are simulated using proper transient models. The initial conditions for each simulation are determined by the steady-state load flow solution beforehand.
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IV. GENERATOR MODELS AND DATA The software uses dynamic models for the calculation of voltages and currents during transients. For the synchronous generators the classical, transient and subtransient models are available. Two axis modeling is used and the coupling equations are analyzed in terms of direct (d) and quadrature (q) axis components. The sub-transient model has been used for this study where transient and sub-transient reactances are considered. Moreover: • The machine is considered to have damper windings in both d and q axes. Α further dumper winding is assumed in the q axis to account for the deep flowing rotor eddy currents. • The mutual inductances of d-axis are considered equal. • Stray losses and magnetic saturation are neglected. For the simulation of the asynchronous generators, the first, fifth or third order models are available. The latter has been adopted in this study in order to include rotor transients. The mechanical load is modeled using a constant quadratic, composite or random mechanical torque curve. The operational point of the asynchronous generator is defined by the combination of the load curve and the speed-torque characteristic of the generator. The inertia constants of the generators are assumed to be 2 s, in cases where manufacturer’s data are not available. V. TEST SCENARIOS During the preparation of this work a great number of different scenarios had been simulated in order to identify the most important ones to be presented and analyzed. In this paragraph a presentation of all the scenarios will be made. Nevertheless, just two of them were chosen for further analysis and their results are given in the next paragraph. A. Loading Conditions Three different loading conditions are simulated for each network configuration. Minimum loading with a total network load of 1.7 MVA, maximum loading with a total load of 11.17 MVA and a third loading condition, where the total load matches the 95% of the injected active and reactive power of the DGs. In all the above cases the power factor is considered to be 0.9 lagging. The loads are considered to be constant in the time range of the simulation. B. CB Operation Scenarios The combination of the different network configurations and loading conditions results in nine different test cases. For each of them a number of circuit breakers operations has been simulated. These scenarios are: 1
The main circuit breaker (CB1), which is located after the feeder, trips at time t1. No fault is assumed in the distribution network. After a small time interval between 0.3 – 1 s the breaker recloses at t2. The DG units are assumed to continue operation in the islanding mode until reclosure. The transient stability of the whole network after the reconnection of the islanded part is
2
examined (Test scenario TSC#1). A three phase fault occurs in the main line at time t1, causing the tripping of the three main circuit breakers (CB1, CB2, and CB3) at time t2, about 80 – 100 ms after the fault occurs. In this way the fault is isolated and the two parts of the network, branch 1 and branch 2, are islanded. The fault is cleared at t3 = 100ms and at t4 = 300ms CB1 recloses. Two distinct test scenarios assume that at the same time either CB2 (Test Scenario TSC#2.1) or CB3 (TSC #2.2) recloses. In these scenarios only one islanded branch reconnects to the main grid, whereas the other remains unconnected. Two further scenarios have been examined, namely TSC#2.1.2 and TSC#2.2.1, where CB3 or CB2 respectively reclose at t5 following the previous switching operation, so both islanded branches reconnect to the main grid, but at a different time.
C. Simulation Assumptions When referring to system stability we mean that the system recovers the transient state and returns to its previous condition. The fluctuations of the frequency and voltage are recorded for each case. The DG units are assumed to be equipped with proper under-/overvoltage an under/overfrequency relays. These protection devices are not included in the models, but according to the simulation results it is checked in each case, whether the DG units are tripped. In cases where the generators in the islanded branch are not disconnected, the overall stability of the network after the reclosure of the CBs is investigated. VI. RESULTS AND DISCUSSION A. Test Scenario 1 All possible combinations of network configurations and loading conditions have been simulated for TSC#1. Results show that with minimum loading conditions the system does not remain stable in any case. The DG units accelerate in the island mode and are tripped by the overfrequency relays, which are set to +/- 1%, in less than 100ms, a time considerably smaller than the reclosure open time. With maximum loading conditions in the configuration of network A, which is the present configuration, the DG units cannot retain stability and are tripped by their frequency relays during the CB1 open time. However, in the cases of networks B and C the units remain in synchronism for an open time before reclosure t =300 ms. In these cases, during the CB1 reclosure, the DG units are reconnected to the main grid out of phase. This causes oscillations which trip the DG units after reconnection in both networks. One noticeable case, though, is the one with load matching conditions. In this case the DG units supply almost the exact local active power, while the reactive power of the distribution branch is compensated locally. In this case all DG units remain stable in all 3 network configurations for a CB1 open time of 300 ms. After the out of phase reconnection at the CB
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reclosure, they oscillate but within the voltage and frequency set points of their protection devices. This is a typical case of unintended and sustained islanding, which after CB reclosure remains in synchronism. In Fig. 2 the diagrams for the above case are shown. In Fig. 2a the frequency fluctuation of the SGs is shown together with the speed change in the ASGs. The changes in the generated active and reactive power of SM-2 are shown together with the change of the electromagnetic torque of ASM-2A are shown in Fig. 2b. The changes are very small due to the load match condition in the islanded branch. Finally the frequency fluctuation for the case of network C is shown in Fig. 2c. Two more option were checked for this case. First, the performance of the DG units was investigated for the case of longer open times for the CB before reclosure. For open times of 500 ms and 700 ms the DG units do not disconnect during the islanding operation, but they oscillate highly after reconnection and are tripped by their frequency protection relays. It is also shown that the SGs have a smoother behavior and can sustain stability more easily compared to the ASGs. Next a case of a reactive power mismatch was examined. It is assumed that the DG units once again supply all the necessary active power but there is a lack of the reactive power and 50% of the reactive load is supplied by the main grid through the feeder. In this case when the CB opens, the terminal voltage of all DG units falls rapidly and they are all tripped by their undervoltage protection relays. The peak values for frequency fluctuation for the TCS#1 are shown in Table II for the three network configurations. For the ASGs, the speed fluctuation reaches 101.43%, and 100.8% of the nominal speed for network configurations A and B, respectively.
a)
b)
B. Test Scenarios 2.1 and 2.2 The next test cases to be examined are TSC#2.1 and TSC#2.2. Both cases assume that a 3phase fault occurs in the main line at time t1=1sec. All the circuit breakers trip TABLE II. FLUCTUATION OF THE FREQUENCY FOR LOAD MATCHING CONDITIONS. TEST CASE SCENARIO #1, RECLOSING OF CB1 AT T1=1.3S Network A SM-1A
G2.12
SM-2A
G2.11
SM-1B SM-2B
fmin (Hz)
49,90
49,89
49,90
49,89
49,89
49,89
fmax (Hz)
50,15
50,05
50,14
50,15
50,11
50,11 c)
Network B
SM-1A
G2.12
SM-2A
G2.11
fmin (Hz)
49,97
49,97
49,97
49,97
fmax (Hz)
50,03
50,01
50,02
50,03
Network SM-1A G2.12 SM-2A G2.11 SM-3A SM-4A SM-1B SM-2B C fmin (Hz) 49,79 49,79 49,79 49,73 49,79 49,79 49,78 49,78 fmax (Hz) 50,36 50,17 50,36 50,35 50,34 50,36 50,26 50,26
Fig. 2. Diagrams for TSC#1, with Load Matching conditions. Reclosing of CB1 at t1=1.3s. a) SG frequency, ASG speed, network A, b) Power and torque deviation, network A c) SG frequency, network C.
simultaneously at time t2=1.083 s, which is the fastest possible for these CBs, causing the islanding of the two branches. The fault is cleared after 100 ms, i.e. at time t3=1.1sec. CB1 and either CB2 or CB3 reclose 300ms after the first trip, at time t4=1.383s and only one of the islanded branches, either #1 or
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#2, reconnects to the main grid, while the other remains islanded and is not further examined. The results from both tests were practically identical and therefore only the first one will be analyzed next. Once again in the case of minimum loading all DG units are accelerated and they are almost instantly disconnected. In the case of maximum loading and network configurations A and B, the DG units show a frequency drop above the set point limit and are tripped during the CB open time. However, in the case of network C, where all DG units are SGs, only the small G2.12 runs out of synchronism, while all others remain in synchronism. Synchronism is retained also after reclosure, following some transient oscillations. This case is shown in Fig. 3a, for the network A configuration, together with the fluctuation of the generated active and reactive power for the generator G2.11. In Fig. 3b the frequency deviation for the network C configuration is shown, together with the terminal voltage fluctuation for generators G2.11 and SM-1B. The steep voltage dip during the fault does not trip the undervoltage protection, while the long term terminal voltage drop is less than 10%. It should be noted however, that in this case the system is very sensitive to the CB settings, since during the fault, in the first 83 ms, all DG units feed the fault. Therefore even a small increase in the idle time of the CB leads to instability. Next the case of an active and reactive load match was examined. For all network configurations all DG units are tripped during the CB open time, as they oscillate over the frequency limits of their protective relays. This is also the case when there is a lack of reactive power in the islanded branches. Table III shows the voltage fluctuation for the TSC#2.1 TABLE III. TEST CASE SCENARIO 2.1. FLUCTUATION OF FREQUENCY FOR MAXIMUM LOADING CONDITIONS. RECLOSING OF BOTH CB1 AND CB2 AT T1=1.383S Network A
G2.12
G2.11
SM-1B
SM-2B
fmin (Hz)
49,79
49,61
49,65
49,65
fmax (Hz)
52,40
50,47
50,55
50,55
Network C
G2.12
G2.11
SM-1B
SM-2B
fmin (Hz)
49,82
49,50
49,51
49,49
fmax (Hz)
52,45
50,50
50,51
50,51
and for maximum loading conditions. The maximum rotor speed for ASGs in networks A and B was 103.44% and 104.38% of the nominal speed, respectively. C. Test Scenarios 2.1.2 and 2.2.1 Two further test cases have been examined TSC#2.1.2 and TSC#2.2.1. They are practically the continuation cases of TSC#2.1 and TSC#2.2, where following a successful reconnection of an islanded branch, either branch #1 or branch #2, the other one is also connected to the grid at time t5. This
a)
b) Fig. 3. Diagrams for SC#2.1, with maximum loading conditions. Reclosing of CB1 and CB2 at t1=1.383s. a) Network A configuration b) Network C configuration.
test case is of practical interest only for the case of maximum loading where it is possible for the system to remain stable after an out of phase reconnection at CB reclosure. As expected in both cases the system does not remain stable after the reconnection of the second islanded branch. This is due to the fact that during islanding each branch maintains a different operational state and the succeeding out of phase reconnection of both branches leads to system instability ans subsequently in a DG unit trip. VII. CONCLUSIONS The problem of inadvertent islanding in a distribution network with distributed generation is investigated in this paper. It is shown that during the automatic reclosure operation of the circuit breakers, the branches containing DG units may remain in synchronism, causing an out-of-phase reclosing. The simulation results verify that the islanding detection and the necessary DG unit tripping using the local protection devices is not ensured. The cases of maximum loading and of load match are the most possible to sustain unintended islanding. Asynchronous
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generators are more sensitive in transients and tend to trip earlier, while the synchronous generators show a more stable behavior. The out-of-phase reconnection of the islanded branches stresses the equipment and leads, in most cases, to instability and subsequent tripping of the DG units. Therefore, no distinct advantages for the reliability of the power supply are to be expected by the islanding operation of the DG. The use of prolonged open times before reclosure in the circuit breakers may lead to detection of the islanding in some cases. However, since this could result in reduced power quality for the passive customers in the network, it is an unacceptable option. It is also shown that the reactive power control in the network can improve islanding detection, especially when static compensators can be tripped simultaneously with the circuit breakers.
[12]
ACKNOWLEDGMENT
[20]
The authors would like to thank Messrs A. Zafirakis and S. Fachouridis, of the Greek PPC, Development & Operation department of Macedonia-Thrace region, for their valuable contribution in the modeling of the system. REFERENCES [1] [2]
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